Unassociated Document
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE
SECURITIES EXCHANGE ACT OF 1934
For The
Quarterly Period Ended June 30,
2008
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE
SECURITIES EXCHANGE ACT OF 1934
For The
Transition Period from ____ to ____
Commission
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Registrant,
State of Incorporation,
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I.R.S.
Employer
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File Number
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Address of Principal Executive Offices, and
Telephone Number
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Identification No.
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1-3525
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AMERICAN
ELECTRIC POWER COMPANY, INC. (A New York Corporation)
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13-4922640
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1-3457
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APPALACHIAN
POWER COMPANY (A Virginia Corporation)
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54-0124790
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1-2680
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COLUMBUS
SOUTHERN POWER COMPANY (An Ohio Corporation)
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31-4154203
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1-3570
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INDIANA
MICHIGAN POWER COMPANY (An Indiana Corporation)
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35-0410455
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1-6543
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OHIO
POWER COMPANY (An Ohio Corporation)
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31-4271000
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0-343
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PUBLIC
SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)
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73-0410895
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1-3146
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SOUTHWESTERN
ELECTRIC POWER COMPANY (A Delaware Corporation)
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72-0323455
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All
Registrants
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1
Riverside Plaza, Columbus, Ohio 43215-2373
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Telephone
(614) 716-1000
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Indicate
by check mark whether the registrants (1) have filed all reports required
to be filed by Section 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.
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Yes X
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No
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Indicate
by check mark whether American Electric Power Company, Inc. is a large
accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting company. See the definitions of ‘large
accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in
Rule 12b-2 of the Exchange Act.
|
Large
accelerated filer X
Accelerated
filer _____
Non-accelerated
filer _____ Smaller
reporting company ______
|
Indicate
by check mark whether Appalachian Power Company, Columbus Southern Power
Company, Indiana Michigan Power Company, Ohio Power Company, Public
Service Company of Oklahoma and Southwestern Electric Power Company are
large accelerated filers, accelerated filers, non-accelerated filers or
smaller reporting companies. See the definitions of ‘large
accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in
Rule 12b-2 of the Exchange Act.
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Large
accelerated
filer _____ Accelerated
filer _______
Non-accelerated
filer X Smaller
reporting company _______
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Indicate
by check mark whether the registrants are shell companies (as defined in
Rule 12b-2 of the Exchange Act).
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Yes
____
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No X
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Columbus
Southern Power Company and Indiana Michigan Power 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.
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Number
of shares of common stock outstanding of the registrants at
July
31, 2008
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American
Electric Power Company, Inc.
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402,258,849
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($6.50
par value)
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Appalachian
Power Company
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13,499,500
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(no
par value)
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Columbus
Southern Power Company
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16,410,426
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(no
par value)
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Indiana
Michigan Power Company
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1,400,000
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(no
par value)
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Ohio
Power Company
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27,952,473
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(no
par value)
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Public
Service Company of Oklahoma
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9,013,000
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($15
par value)
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Southwestern
Electric Power Company
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7,536,640
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($18
par value)
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AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX
TO QUARTERLY REPORTS ON FORM 10-Q
June
30, 2008
Glossary
of Terms
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Forward-Looking
Information
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Part
I. FINANCIAL INFORMATION
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Items
1, 2 and 3 - Financial Statements, Management’s Financial Discussion and
Analysis and Quantitative and Qualitative Disclosures About Risk
Management Activities:
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American
Electric Power Company, Inc. and Subsidiary Companies:
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Management’s
Financial Discussion and Analysis of Results of Operations
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Consolidated Financial
Statements
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Appalachian
Power Company and Subsidiaries:
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Management’s
Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Columbus
Southern Power Company and Subsidiaries:
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Management’s
Narrative Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Indiana
Michigan Power Company and Subsidiaries:
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Management’s
Narrative Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Ohio
Power Company Consolidated:
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Management’s
Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Public
Service Company of Oklahoma:
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Management’s
Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Southwestern
Electric Power Company Consolidated:
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Management’s
Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Condensed
Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Combined
Management’s Discussion and Analysis of Registrant
Subsidiaries
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Controls
and Procedures
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Part
II. OTHER INFORMATION
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Item
1.
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Legal
Proceedings
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Item
1A.
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Risk
Factors
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Item
2.
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Unregistered
Sales of Equity Securities and Use of Proceeds
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Item
4.
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Submission
of Matters to a Vote of Security Holders
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Item
5.
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Other
Information
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Item
6.
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Exhibits:
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Exhibit
3(a) (PSO, SWEPCo) |
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Exhibit
3(b) (CSPCo, OPCo) |
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Exhibit
12 (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
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Exhibit
31(a) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
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Exhibit
31(b) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
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Exhibit
32(a) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
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Exhibit
32(b) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
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SIGNATURE
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This
combined Form 10-Q is separately filed by American Electric Power Company,
Inc., Appalachian Power Company, Columbus Southern Power Company, Indiana
Michigan Power Company, Ohio Power Company, Public Service Company of
Oklahoma and Southwestern Electric Power 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.
|
When
the following terms and abbreviations appear in the text of this report, they
have the meanings indicated below.
AEGCo
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AEP
Generating Company, an AEP electric utility subsidiary.
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AEP
or Parent
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American
Electric Power Company, Inc.
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AEP
Consolidated
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AEP
and its majority owned consolidated subsidiaries and consolidated
affiliates.
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AEP
Credit
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AEP
Credit, Inc., a subsidiary of AEP which factors accounts receivable and
accrued utility revenues for affiliated electric utility
companies.
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AEP
East companies
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APCo,
CSPCo, I&M, KPCo and OPCo.
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AEPSC
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American
Electric Power Service Corporation, a service subsidiary providing
management and professional services to AEP and its
subsidiaries.
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AEP
System or the System
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American
Electric Power System, an integrated electric utility system, owned and
operated by AEP’s electric utility subsidiaries.
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AEP
West companies
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PSO,
SWEPCo, TCC and TNC.
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AFUDC
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Allowance
for Funds Used During Construction.
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ALJ
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Administrative
Law Judge.
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AOCI
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Accumulated
Other Comprehensive Income.
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APCo
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Appalachian
Power Company, an AEP electric utility subsidiary.
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APSC
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Arkansas
Public Service Commission.
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CAA
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Clean
Air Act.
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CO2
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Carbon
Dioxide.
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CSPCo
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Columbus
Southern Power Company, an AEP electric utility
subsidiary.
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CSW
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Central
and South West Corporation, a subsidiary of AEP (Effective January 21,
2003, the legal name of Central and South West Corporation was changed to
AEP Utilities, Inc.).
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CTC
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Competition
Transition Charge.
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CWIP
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Construction
Work in Progress.
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DETM
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Duke
Energy Trading and Marketing L.L.C., a risk management
counterparty.
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DOE
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United
States Department of Energy.
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E&R
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Environmental
compliance and transmission and distribution system
reliability.
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EaR
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Earnings
at Risk, a method to quantify risk exposure.
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EITF
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Financial
Accounting Standards Board’s Emerging Issues Task
Force.
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EITF
06-10
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EITF
Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life
Insurance Arrangements.”
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EPS
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Earnings
Per Share.
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ERCOT
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Electric
Reliability Council of Texas.
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FASB
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Financial
Accounting Standards Board.
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Federal
EPA
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United
States Environmental Protection Agency.
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FERC
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Federal
Energy Regulatory Commission.
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FIN
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FASB
Interpretation No.
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FIN
46R
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FIN
46R, “Consolidation of Variable Interest Entities.”
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FIN
48
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FIN
48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position
FIN 48-1 “Definition of Settlement in
FASB
Interpretation No. 48.”
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FSP
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FASB
Staff Position.
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FTR
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Financial
Transmission Right.
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GAAP
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Accounting
Principles Generally Accepted in the United States of
America.
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HPL
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Houston
Pipeline Company, a former AEP
subsidiary.
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IGCC
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Integrated
Gasification Combined Cycle, technology that turns coal into a
cleaner-burning gas.
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Interconnection
Agreement
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Agreement,
dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo
and OPCo, defining the sharing of costs and benefits associated with their
respective generating plants.
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IRS
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Internal
Revenue Service.
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IURC
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Indiana
Utility Regulatory Commission.
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I&M
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Indiana
Michigan Power Company, an AEP electric utility
subsidiary.
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JMG
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JMG
Funding LP.
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KPCo
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Kentucky
Power Company, an AEP electric utility subsidiary.
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KPSC
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Kentucky
Public Service Commission.
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kV
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Kilovolt.
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KWH
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Kilowatthour.
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LPSC
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Louisiana
Public Service Commission.
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MISO
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Midwest
Independent Transmission System Operator.
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MTM
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Mark-to-Market.
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MW
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Megawatt.
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MWH
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Megawatthour.
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NOx
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Nitrogen
oxide.
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Nonutility
Money Pool
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AEP
System’s Nonutility Money Pool.
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NSR
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New
Source Review.
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NYMEX
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New
York Mercantile Exchange.
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OCC
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Corporation
Commission of the State of Oklahoma.
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OPCo
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Ohio
Power Company, an AEP electric utility subsidiary.
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OPEB
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Other
Postretirement Benefit Plans.
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OTC
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Over-the-counter.
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PJM
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Pennsylvania
– New Jersey – Maryland regional transmission
organization.
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PSO
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Public
Service Company of Oklahoma, an AEP electric utility
subsidiary.
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PUCO
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Public
Utilities Commission of Ohio.
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PUCT
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Public
Utility Commission of Texas.
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Registrant
Subsidiaries
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AEP
subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO
and SWEPCo.
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REP
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Texas
Retail Electric Provider.
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Risk
Management Contracts
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Trading
and nontrading derivatives, including those derivatives designated as cash
flow and fair value hedges.
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Rockport
Plant
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A
generating plant, consisting of two 1,300 MW coal-fired generating units
near Rockport, Indiana, owned by AEGCo and I&M.
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RSP
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Rate
Stabilization Plan.
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RTO
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Regional
Transmission Organization.
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S&P
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Standard
and Poor’s.
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SCR
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Selective
Catalytic Reduction.
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SEC
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United
States Securities and Exchange Commission.
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SECA
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Seams
Elimination Cost Allocation.
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SFAS
|
|
Statement
of Financial Accounting Standards issued by the Financial Accounting
Standards Board.
|
SFAS
71
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Statement
of Financial Accounting Standards No. 71, “Accounting for the Effects of
Certain Types of Regulation.”
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SFAS
133
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Statement
of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities.”
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SFAS
157
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Statement
of Financial Accounting Standards No. 157, “Fair Value
Measurements.”
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SIA
|
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System
Integration Agreement.
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SNF
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Spent
Nuclear Fuel.
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SO2
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Sulfur
Dioxide.
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SPP
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Southwest
Power Pool.
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Stall
Unit
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J.
Lamar Stall Unit at Arsenal Hill Plant.
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Sweeny
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Sweeny
Cogeneration Limited Partnership, owner and operator of a four unit, 480
MW gas-fired generation facility, owned 50% by AEP. AEP’s 50%
interest in Sweeny was sold in October 2007.
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SWEPCo
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Southwestern
Electric Power Company, an AEP electric utility
subsidiary.
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TCC
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AEP
Texas Central Company, an AEP electric utility
subsidiary.
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TEM
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SUEZ
Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing,
Inc.).
|
Texas
Restructuring Legislation
|
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Legislation
enacted in 1999 to restructure the electric utility industry in
Texas.
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TNC
|
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AEP
Texas North Company, an AEP electric utility
subsidiary.
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True-up
Proceeding
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A
filing made under the Texas Restructuring Legislation to finalize the
amount of stranded costs and other true-up items and the recovery of such
amounts.
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Turk
Plant
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John
W. Turk, Jr. Plant.
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Utility
Money Pool
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AEP
System’s Utility Money Pool.
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VaR
|
|
Value
at Risk, a method to quantify risk exposure.
|
Virginia
SCC
|
|
Virginia
State Corporation Commission.
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WPCo
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Wheeling
Power Company, an AEP electric distribution subsidiary.
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WVPSC
|
|
Public
Service Commission of West
Virginia.
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This
report made by AEP and its Registrant Subsidiaries contains forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934. Although AEP and each of its Registrant 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:
·
|
Electric
load and customer growth.
|
·
|
Weather
conditions, including storms.
|
·
|
Available
sources and costs of, and transportation for, fuels and the
creditworthiness and performance of fuel suppliers and
transporters.
|
·
|
Availability
of generating capacity and the performance of our generating
plants.
|
·
|
Our
ability to recover regulatory assets and stranded costs in connection with
deregulation.
|
·
|
Our
ability to recover increases in fuel and other energy costs through
regulated or competitive electric rates.
|
·
|
Our
ability to build or acquire generating capacity (including our ability to
obtain any necessary regulatory approvals and permits) when needed at
acceptable prices and terms and to recover those costs (including the
costs of projects that are canceled) through applicable rate cases or
competitive rates.
|
·
|
New
legislation, litigation and government regulation including requirements
for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or
particulate matter and other substances.
|
·
|
Timing
and resolution of pending and future rate cases, negotiations and other
regulatory decisions (including rate or other recovery of new investments
in generation, distribution and transmission service and environmental
compliance).
|
·
|
Resolution
of litigation (including disputes arising from the bankruptcy of Enron
Corp. and related matters).
|
·
|
Our
ability to constrain operation and maintenance costs.
|
·
|
The
economic climate and growth in our service territory and changes in market
demand and demographic patterns.
|
·
|
Inflationary
and interest rate trends.
|
·
|
Volatility
in the financial markets, particularly developments affecting the
availability of capital on reasonable terms and developments impairing our
ability to refinance existing debt at attractive rates.
|
·
|
Our
ability to develop and execute a strategy based on a view regarding prices
of electricity, natural gas and other energy-related
commodities.
|
·
|
Changes
in the creditworthiness of the counterparties with whom we have
contractual arrangements, including participants in the energy trading
market.
|
·
|
Actions
of rating agencies, including changes in the ratings of
debt.
|
·
|
Volatility
and changes in markets for electricity, natural gas, coal, nuclear fuel
and other energy-related commodities.
|
·
|
Changes
in utility regulation, including the implementation of the recently-passed
utility law in Ohio and the allocation of costs within
RTOs.
|
·
|
Accounting
pronouncements periodically issued by accounting standard-setting
bodies.
|
·
|
The
impact of volatility in the capital markets on the value of the
investments held by our pension, other postretirement benefit plans and
nuclear decommissioning trust.
|
·
|
Prices
for power that we generate and sell at wholesale.
|
·
|
Changes
in technology, particularly with respect to new, developing or alternative
sources of generation.
|
·
|
Other
risks and unforeseen events, including wars, the effects of terrorism
(including increased security costs), embargoes and other catastrophic
events.
|
The
registrants expressly disclaim any obligation to update any
forward-looking information.
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
EXECUTIVE
OVERVIEW
Base
Rate Filings
Our
significant base rate filings include:
Operating
Company
|
|
Jurisdiction
|
|
Revised
Annual Rate Increase Request
|
|
Projected
Effective Date of Rate Increase
|
|
|
|
|
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(in
millions)
|
|
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|
APCo
|
|
Virginia
|
|
$
|
208
|
|
November
2008
|
(a)
|
PSO
|
|
Oklahoma
|
|
|
117
|
(b)
|
February
2009
|
|
I&M
|
|
Indiana
|
|
|
80
|
|
June
2009
|
|
(a)
|
Subject
to refund.
|
(b)
|
Net
of estimated amounts that PSO expects to recover through a generation cost
recovery rider which will terminate upon implementation of the new base
rates.
|
Ohio
Electric Security Plan Filings
In April
2008, the Ohio legislature passed Senate Bill 221, which amends the
restructuring law effective July 31, 2008 and requires electric utilities to
adjust their rates by filing an Electric Security Plan (ESP). In July
2008, within the parameters of the ESPs, CSPCo and OPCo each requested an annual
rate increase for 2009 through 2011 that would not exceed approximately 15% per
year. A significant portion of the requested increases results
from the implementation of a fuel cost recovery mechanism.
Turk
Plant
In July
2008, the PUCT approved a certificate of convenience and necessity for
construction of the plant. We expect a written order in August 2008
which will also provide for the conditions of the PUCT’s
approval. SWEPCo has received approvals from all of the state
commissions that regulate its retail rates and services. However, the
APSC approval has been appealed to the Arkansas State Court of
Appeals. SWEPCo is working with the Arkansas Department of
Environmental Quality and the U.S. Army Corps of Engineers for approval later
this year. Through June 30, 2008, SWEPCo capitalized $407 million in
expenditures related to the Turk Plant.
IGCC
Plants
We have
delayed construction of the West Virginia and Ohio IGCC plants. In
May 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia
SCC's previous denial of APCo’s request to recover initial costs associated with
a proposed IGCC plant in West Virginia. In July 2008, the WVPSC
issued a notice seeking comments from parties on how the WVPSC should proceed
regarding its earlier approval of the IGCC plant. In Ohio, CSPCo and
OPCo await the result of an Ohio Supreme Court remand to the PUCO regarding
recovery of IGCC pre-construction costs.
Fuel
Costs
We
currently estimate 2008 coal prices to increase by about 20% due to escalating
domestic prices and increased needs, primarily in the east. We had
expected coal costs to increase by 13% in 2008. We
continue to see increases in prices due to expiring lower priced coal and
transportation contracts being replaced with higher priced
contracts. Prices for fuel oil are at record highs and remain
volatile. We have limited exposure to price risk related to our open
positions for coal, natural gas and fuel oil especially since we do not
currently have an active fuel cost recovery adjustment mechanism in Ohio, which
represents approximately 20% of our fuel costs. However, under Ohio’s
amended restructuring law, we have requested the PUCO to reinstate a fuel cost
recovery mechanism effective January 1, 2009. Fuel cost adjustment
rate clauses in our other jurisdictions will help offset future negative impacts
of fuel price increases on our gross margins.
Capital
Expenditures
We
reduced our projections for capital expenditures to approximately $6.75 billion
from $7.35 billion for 2009 through 2010.
RESULTS
OF OPERATIONS
Segments
Our
principal operating business segments and their related business activities are
as follows:
Utility
Operations
·
|
Generation
of electricity for sale to U.S. retail and wholesale
customers.
|
·
|
Electricity
transmission and distribution in the
U.S.
|
MEMCO
Operations
·
|
Barging
operations that annually transport approximately 35 million tons of coal
and dry bulk commodities primarily on the Ohio, Illinois and Lower
Mississippi Rivers. Approximately 39% of the barging is for the
transportation of agricultural products, 30% for coal, 14% for steel and
17% for other commodities. Effective July 30, 2008, AEP MEMCO LLC's
name was changed to AEP River Operations,
LLC.
|
Generation
and Marketing
·
|
Wind
farms and marketing and risk management activities primarily in
ERCOT.
|
The table
below presents our consolidated Income Before Discontinued Operations and
Extraordinary Loss by segment for the three and six months ended June 30, 2008
and 2007.
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Utility
Operations
|
|
$ |
263 |
|
|
$ |
238 |
|
|
$ |
673 |
|
|
$ |
491 |
|
MEMCO
Operations
|
|
|
3 |
|
|
|
7 |
|
|
|
10 |
|
|
|
22 |
|
Generation
and Marketing
|
|
|
26 |
|
|
|
15 |
|
|
|
27 |
|
|
|
14 |
|
All
Other (a)
|
|
|
(12
|
) |
|
|
(3
|
) |
|
|
143 |
|
|
|
1 |
|
Income
Before Discontinued Operations
and
Extraordinary Loss
|
|
$ |
280 |
|
|
$ |
257 |
|
|
$ |
853 |
|
|
$ |
528 |
|
(a)
|
All
Other includes:
|
|
·
|
Parent’s
guarantee revenue received from affiliates, investment income, interest
income and interest expense and other nonallocated
costs.
|
|
·
|
Forward
natural gas contracts that were not sold with our natural gas pipeline and
storage operations in 2004 and 2005. These contracts are
financial derivatives which will gradually liquidate and completely expire
in 2011.
|
|
·
|
The
first quarter 2008 cash settlement of a purchase power and sale agreement
with TEM related to the Plaquemine Cogeneration Facility which was sold in
the fourth quarter of 2006. The cash settlement of $255 million
($163 million, net of tax) is included in Net Income.
|
|
·
|
Revenue
sharing related to the Plaquemine Cogeneration
Facility.
|
AEP
Consolidated
Second Quarter of 2008
Compared to Second Quarter of 2007
Income
Before Discontinued Operations and Extraordinary Loss in 2008 increased $23
million compared to 2007 primarily due to an increase in Utility Operations
segment earnings of $25 million. The increase in Utility Operations
segment earnings primarily relates to rate increases implemented since the
second quarter of 2007 in Ohio, Virginia, West Virginia, Texas and Oklahoma,
higher off-system sales and unfavorable regulatory provisions recorded in the
prior year related to our Virginia and Texas jurisdictions, partially offset by
higher operation and maintenance expenses system-wide and higher fuel expenses
in Ohio.
Average
basic shares outstanding increased to 402 million in 2008 from 399 million in
2007 primarily due to the issuance of shares under our incentive compensation
and dividend reinvestment plans. Actual shares outstanding were 402
million as of June 30, 2008.
Six Months Ended June 30,
2008 Compared to Six Months Ended June 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss in 2008 increased $325
million compared to 2007 primarily due to an increase in Utility Operations
segment earnings of $182 million and income of $163 million (net of tax) from
the cash settlement of a power purchase-and-sale agreement with TEM related to
the Plaquemine Cogeneration Facility which was sold in the fourth quarter of
2006. The increase in Utility Operations segment earnings primarily
relates to rate increases implemented since the second quarter of 2007 in Ohio,
Virginia, West Virginia, Texas and Oklahoma, higher off-system sales and lower
operation and maintenance expenses as a result of a favorable Oklahoma ice storm
settlement partially offset by higher interest expense.
Average
basic shares outstanding increased to 401 million in 2008 from 398 million in
2007 primarily due to the issuance of shares under our incentive compensation
and dividend reinvestment plans. Actual shares outstanding were 402
million as of June 30, 2008.
Utility
Operations
Our
Utility Operations segment includes primarily regulated revenues with direct and
variable offsetting expenses and net reported commodity trading
operations. We believe that a discussion of the results from our
Utility Operations segment on a gross margin basis is most appropriate in order
to further understand the key drivers of the segment. Gross margin
represents utility operating revenues less the related direct cost of fuel,
including consumption of chemicals and emissions allowances, and purchased
power.
Utility
Operations Income Summary
For
the Three and Six Months Ended June 30, 2008 and 2007
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Revenues
|
$
|
3,313
|
|
$
|
2,954
|
|
$
|
6,607
|
|
$
|
5,987
|
|
Fuel
and Purchased Power
|
|
1,374
|
|
|
1,109
|
|
|
2,587
|
|
|
2,228
|
|
Gross
Margin
|
|
1,939
|
|
|
1,845
|
|
|
4,020
|
|
|
3,759
|
|
Depreciation
and Amortization
|
|
365
|
|
|
365
|
|
|
720
|
|
|
748
|
|
Other
Operating Expenses
|
|
1,026
|
|
|
957
|
|
|
1,967
|
|
|
1,948
|
|
Operating
Income
|
|
548
|
|
|
523
|
|
|
1,333
|
|
|
1,063
|
|
Other
Income, Net
|
|
47
|
|
|
27
|
|
|
89
|
|
|
45
|
|
Interest
Charges and Preferred Stock Dividend Requirements
|
|
218
|
|
|
207
|
|
|
428
|
|
|
386
|
|
Income
Tax Expense
|
|
114
|
|
|
105
|
|
|
321
|
|
|
231
|
|
Income
Before Discontinued Operations and Extraordinary
Loss
|
$
|
263
|
|
$
|
238
|
|
$
|
673
|
|
$
|
491
|
|
Summary
of Selected Sales and Weather Data
For
Utility Operations
For
the Three and Six Months Ended June 30, 2008 and 2007
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
Energy/Delivery Summary
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions of KWH)
|
Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
9,829
|
|
|
10,127
|
|
|
24,329
|
|
|
24,267
|
|
|
Commercial
|
|
9,909
|
|
|
10,227
|
|
|
19,456
|
|
|
19,586
|
|
|
Industrial
|
|
15,060
|
|
|
14,848
|
|
|
29,410
|
|
|
28,413
|
|
|
Miscellaneous
|
|
639
|
|
|
632
|
|
|
1,248
|
|
|
1,245
|
|
Total
Retail
|
|
35,437
|
|
|
35,834
|
|
|
74,443
|
|
|
73,511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
10,932
|
|
|
9,376
|
|
|
22,597
|
|
|
18,154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivery
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
Wires – Energy delivered to customers served
by
AEP’s Texas Wires Companies
|
|
7,132
|
|
|
6,746
|
|
|
12,955
|
|
|
12,577
|
|
Total
KWHs
|
|
53,501
|
|
|
51,956
|
|
|
109,995
|
|
|
104,242
|
|
Cooling
degree days and heating degree days are metrics commonly used in the utility
industry as a measure of the impact of weather on results of
operations. In general, degree day changes in our eastern region have
a larger effect on results of operations than changes in our western region due
to the relative size of the two regions and the associated number of customers
within each.
Summary
of Heating and Cooling Degree Days for Utility Operations
For
the Three and Six Months Ended June 30, 2008 and 2007
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
degree days)
|
Weather
Summary
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Heating (a)
|
|
136
|
|
|
222
|
|
|
1,960
|
|
|
2,039
|
|
Normal
– Heating (b)
|
|
175
|
|
|
174
|
|
|
1,943
|
|
|
1,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Cooling (c)
|
|
272
|
|
|
367
|
|
|
272
|
|
|
382
|
|
Normal
– Cooling (b)
|
|
278
|
|
|
275
|
|
|
281
|
|
|
278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Region (d)
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Heating (a)
|
|
40
|
|
|
92
|
|
|
989
|
|
|
994
|
|
Normal
– Heating (b)
|
|
35
|
|
|
33
|
|
|
966
|
|
|
991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Cooling (c)
|
|
675
|
|
|
622
|
|
|
700
|
|
|
678
|
|
Normal
– Cooling (b)
|
|
652
|
|
|
656
|
|
|
672
|
|
|
674
|
|
(a)
|
Eastern
region and western region heating degree days are calculated on a 55
degree temperature base.
|
(b)
|
Normal
Heating/Cooling represents the thirty-year average of degree
days.
|
(c)
|
Eastern
region and western region cooling degree days are calculated on a 65
degree temperature base.
|
(d)
|
Western
region statistics represent PSO/SWEPCo customer base
only.
|
Second Quarter of 2008
Compared to Second Quarter of 2007
Reconciliation
of Second Quarter of 2007 to Second Quarter of 2008
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss
(in
millions)
Second
Quarter of 2007
|
|
|
|
|
|
|
|
|
|
|
$
|
238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
|
|
|
|
|
|
47
|
|
|
|
|
Off-system
Sales
|
|
|
|
|
|
|
|
|
40
|
|
|
|
|
Transmission
Revenues
|
|
|
|
|
|
|
|
|
11
|
|
|
|
|
Other
Revenues
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
|
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
|
|
|
|
|
|
(70
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
|
|
|
|
|
|
-
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
Carrying
Costs Income
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
Interest
Income
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
Other
Income, Net
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
Interest
and Other Charges
|
|
|
|
|
|
|
|
|
(11
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
|
|
|
|
|
(60
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second
Quarter of 2008
|
|
|
|
|
|
|
|
|
|
|
$
|
263
|
|
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss increased $25 million to $263 million in 2008. The key
drivers of the increase were a $94 million increase in Gross Margin offset by a
$60 million increase in Operating Expenses and Other and a $9 million increase
in Income Tax Expense.
The major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $47 million primarily due to the
following:
|
|
·
|
A
$39 million increase related to net rate increases implemented in our Ohio
jurisdictions, a $17 million increase related to recovery of E&R costs
in Virginia and the construction financing costs rider in West Virginia, a
$3 million increase in base rates in Texas and a $6 million increase in
base rates in Oklahoma.
|
|
·
|
A
$38 million net increase due to adjustments recorded in the prior year
related to the 2007 Virginia base rate case which included a second
quarter 2007 provision for revenue refund.
|
|
·
|
A
$25 million increase due to a second quarter 2007 provision related to a
SWEPCo Texas fuel reconciliation proceeding.
|
|
·
|
A
$12 million increase related to increased usage by Ormet, an industrial
customer in Ohio. See “Ormet” section of Note
3.
|
|
·
|
An
$11 million increase primarily related to higher revenues under formula
rate plans at I&M.
|
|
These
increases were partially offset by:
|
|
·
|
A
$90 million decrease related to increased fuel, consumable and PJM costs
in Ohio which included a $29 million expense resulting from a coal
contract amendment.
|
|
·
|
A
$20 million decrease in usage related to weather primarily from a 26%
decrease in cooling degree days and a 39% decrease in heating degree days
in our eastern region.
|
·
|
Margins
from Off-system Sales increased $40 million primarily due to higher east
physical off-system sales margins mostly due to higher volumes and
stronger prices, partially offset by lower trading
margins.
|
·
|
Transmission
Revenues increased $11 million primarily due to increased usage in the SPP
and ERCOT regions and increased rates in the SPP
region.
|
Utility
Operating Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $70 million primarily due to
increases in generation expenses for non-outage maintenance at Cook plant
and outage expenses at other plants, transmission reliability expenses,
recoverable PJM and customer account expenses in Ohio and administrative
and general expenses primarily related to employee
benefits.
|
·
|
Depreciation
and Amortization expense was flat primarily due to lower
commission-approved depreciation rates in Indiana, Michigan, Oklahoma and
Texas and lower Ohio regulatory asset amortization, offset by higher
depreciable property balances and prior year adjustments related to the
2007 Virginia base rate case.
|
·
|
Carrying
Costs Income increased $10 million primarily due to increased carrying
cost income on cost deferrals in Virginia and Oklahoma.
|
·
|
Interest
and Other Charges increased $11 million primarily due to additional debt
issued and higher interest rates on variable rate debt.
|
·
|
Income
Tax Expense increased $9 million due to an increase in pretax
income.
|
Six Months Ended June 30,
2008 Compared to Six Months Ended June 30, 2007
Reconciliation
of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss
(in
millions)
Six
Months Ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
$
|
491
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
|
|
|
|
|
|
162
|
|
|
|
|
Off-system
Sales
|
|
|
|
|
|
|
|
|
80
|
|
|
|
|
Transmission
Revenues
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
|
|
|
|
|
261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
|
|
|
|
|
|
11
|
|
|
|
|
Gain
on Dispositions of Assets, Net
|
|
|
|
|
|
|
|
|
(19
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
|
|
|
|
|
|
28
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
|
|
|
|
|
|
(11
|
)
|
|
|
|
Carrying
Costs Income
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
Interest
Income
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
Other
Income, Net
|
|
|
|
|
|
|
|
|
8
|
|
|
|
|
Interest
and Other Charges
|
|
|
|
|
|
|
|
|
(42
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
(90
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
$
|
673
|
|
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss increased $182 million to $673 million in 2008. The key
drivers of the increase were a $261 million increase in Gross Margin and an $11
million decrease in Operating Expenses and Other offset by a $90 million
increase in Income Tax Expense.
The major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $162 million primarily due to the
following:
|
|
·
|
An
$83 million increase related to net rate increases implemented in our Ohio
jurisdictions, a $31 million increase related to recovery of E&R costs
in Virginia and the construction financing costs rider in West Virginia, a
$12 million increase in base rates in Texas and a $14 million increase in
base rates in Oklahoma.
|
|
·
|
A
$33 million increase related to increased usage by Ormet, an industrial
customer in Ohio. See “Ormet” section of Note
3.
|
|
·
|
A
$29 million increase related to coal contract amendments in
2008.
|
|
·
|
A
$28 million increase related to increased residential and commercial usage
and customer growth.
|
|
·
|
A
$25 million increase due to a second quarter 2007 provision related to a
SWEPCo Texas fuel reconciliation proceeding.
|
|
·
|
A
$21 million increase related to increased sales to municipal, cooperative
and other customers primarily a result of new power supply contracts and
higher revenues under formula rate plans at I&M.
|
|
These
increases were partially offset by:
|
|
·
|
A
$79 million decrease related to increased fuel, consumable and PJM costs
in Ohio.
|
|
·
|
A
$23 million decrease in usage related to weather primarily from a 29%
decrease in cooling degree days in our eastern region.
|
·
|
Margins
from Off-system Sales increased $80 million primarily due to higher east
physical off-system sales margins mostly due to higher volumes and
stronger prices, partially offset by lower trading
margins.
|
·
|
Transmission
Revenues increased $19 million primarily due to increased usage in the SPP
and ERCOT regions and increased rates in the SPP
region.
|
Utility
Operating Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses decreased $11 million primarily due to
deferral of storm restoration costs, net of amortization, of $63 million
in Oklahoma as a result of a rate settlement to recover 2007 storm
restoration costs partially offset by an increase in generation expenses
at Cook plant, the write-off of unrecoverable pre-construction costs for
PSO’s canceled Red Rock Generating Facility, recoverable PJM and customer
account expenses in Ohio and increases in administrative and general
expenses primarily related to employee benefits.
|
·
|
Gain
on Disposition of Assets, Net decreased $19 million primarily due to the
cessation of the earnings sharing agreement with Centrica from the sale of
our Texas REPs in 2002. In 2007, we received the final earnings
sharing payment of $20 million.
|
·
|
Depreciation
and Amortization expense decreased $28 million primarily due to lower
commission-approved depreciation rates in Indiana, Michigan, Oklahoma and
Texas and lower Ohio regulatory asset amortization, partially offset by
higher depreciable property balances and prior year adjustments related to
the Virginia base rate case.
|
·
|
Taxes
Other Than Income Taxes increased $11 million primarily due to favorable
adjustments to property tax returns recorded in the prior
year.
|
·
|
Carrying
Costs Income increased $19 million primarily due to increased carrying
cost income on cost deferrals in Virginia and Oklahoma.
|
·
|
Interest
Income increased $17 million primarily due to the favorable effect of
claims for refund filed with the IRS.
|
·
|
Interest
and Other Charges increased $42 million primarily due to additional debt
issued and higher interest rates on variable rate debt.
|
·
|
Income
Tax Expense increased $90 million due to an increase in pretax
income.
|
MEMCO
Operations
Second Quarter of 2008
Compared to Second Quarter of 2007
Income
Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations
segment decreased to $3 million in 2008 from $7 million in 2007 primarily due to
high water conditions and reduced northbound loadings. Fuel
consumption and other operating costs were higher due to the sustained high
water conditions on all major rivers on which we operate. Northbound
loadings continue to be depressed as a result of reduced imports through the
Gulf of Mexico.
Six Months Ended June 30,
2008 Compared to Six Months Ended June 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations
segment decreased to $10 million in 2008 from $22 million in 2007 primarily due
to high water conditions and reduced northbound loadings. Fuel
consumption and other operating costs were higher due to the sustained high
water conditions on all major rivers on which we operate. Northbound
loadings continue to be depressed as a result of reduced imports through the
Gulf of Mexico.
Generation and
Marketing
Second Quarter of 2008
Compared to Second Quarter of 2007
Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment increased to $26 million in 2008 from $15 million in 2007
primarily due to favorable marketing contracts in ERCOT, higher gross margins at
the Oklaunion plant from optimization activities and an increase in income from
wind farm operations.
Six Months Ended June 30,
2008 Compared to Six Months Ended June 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment increased to $27 million in 2008 from $14 million in 2007
primarily due to favorable marketing contracts in ERCOT, higher gross margins at
the Oklaunion plant from optimization activities and an increase in
income from wind farm operations.
All
Other
Second Quarter of 2008
Compared to Second Quarter of 2007
Loss
Before Discontinued Operations and Extraordinary Loss from All Other increased
to $12 million in 2008 from $3 million in 2007. The increase in the
loss primarily relates to lower cash balances yielding lower interest income and
higher interest expense due to the AEP Junior Subordinated Debentures issued in
March 2008 and increased short-term borrowings.
Six Months Ended June 30,
2008 Compared to Six Months Ended June 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss from All Other increased
to $143 million in 2008 from $1 million in 2007. In 2008, we had
after-tax income of $163 million from a litigation settlement of a power
purchase and sale agreement with TEM related to the Plaquemine Cogeneration
Facility which was sold in the fourth quarter of 2006. The settlement
was recorded as a pretax credit to Asset Impairments and Other Related Items of
$255 million in the accompanying Condensed Consolidated Statements of
Income. In 2007, we had a $16 million pretax gain ($10 million, net
of tax) on the sale of a portion of our investment in Intercontinental Exchange,
Inc. (ICE).
AEP System Income
Taxes
Income
Tax Expense increased $15 million in the second quarter of 2008 compared to the
second quarter of 2007 primarily due to an increase in pretax
income.
Income
Tax Expense increased $178 million in the six-month period ended June 30, 2008
compared to the six-month period ended June 30, 2007 primarily due to an
increase in pretax income.
FINANCIAL
CONDITION
We
measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.
Debt and Equity
Capitalization
|
|
June
30, 2008
|
|
December
31, 2007
|
|
|
|
($
in millions)
|
|
Long-term
Debt, including amounts due within one year
|
|
$
|
15,753
|
|
58.0
|
%
|
$
|
14,994
|
|
58.1
|
%
|
Short-term
Debt
|
|
|
705
|
|
2.6
|
|
|
660
|
|
2.6
|
|
Total
Debt
|
|
|
16,458
|
|
60.6
|
|
|
15,654
|
|
60.7
|
|
Common
Equity
|
|
|
10,631
|
|
39.2
|
|
|
10,079
|
|
39.1
|
|
Preferred
Stock
|
|
|
61
|
|
0.2
|
|
|
61
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt and Equity Capitalization
|
|
$
|
27,150
|
|
100.0
|
%
|
$
|
25,794
|
|
100.0
|
%
|
Our ratio
of debt to total capital decreased from 60.7% to 60.6% in 2008 due to our net
earnings and increased common equity from stock issuances through stock
compensation and dividend reinvestment plans.
Liquidity
Liquidity,
or access to cash, is an important factor in determining our financial
stability. We are committed to maintaining adequate
liquidity. We generally use short-term borrowings to fund working
capital needs, property acquisitions and construction until long-term funding is
arranged. Sources of long-term funding include issuance
of long-term debt, sale-leaseback or leasing agreements and common
stock.
Credit
Markets
We
believe we have adequate liquidity under our credit facilities and the ability
to issue long-term debt in the current credit markets. As of June 30,
2008, we had $313 million outstanding of tax-exempt long-term debt sold at
auction rates that reset every 35 days. This debt is insured by bond
insurers previously AAA-rated, namely Ambac Assurance Corporation and Financial
Guaranty Insurance Co. Due to the exposure that these bond insurers
have in connection with developments in the subprime credit market, the credit
ratings of these insurers have been downgraded or placed on negative
outlook. These market factors have contributed to higher interest
rates in successful auctions and increasing occurrences of failed auctions,
including many of the auctions of our tax-exempt long-term debt. The
instruments under which the bonds are issued allow us to convert to other
short-term variable-rate structures, term-put structures and fixed-rate
structures. Through June 30, 2008, we reduced our outstanding auction
rate securities by $1.2 billion. We plan to continue the conversion
and refunding process for the remaining $313 million to other permitted modes,
including term-put structures, variable-rate and fixed-rate structures, during
the second half of 2008 to lower our interest rates as such opportunities
arise.
As of
June 30, 2008, $367 million of the prior auction rate debt was issued in a
weekly variable rate mode supported by letters of credit at variable rates
ranging from 1.45% to 1.68% and $384 million was issued at fixed rates ranging
from 4.85% to 5.625%. As of June 30, 2008, trustees held, on our
behalf, approximately $400 million of our reacquired auction rate tax-exempt
long-term debt which we plan to reissue to the public as market conditions
permit.
Credit
Facilities
We manage
our liquidity by maintaining adequate external financing
commitments. At June 30, 2008, our available liquidity was
approximately $3.1 billion as illustrated in the table below:
|
|
|
Amount
|
|
Maturity
|
|
|
|
(in
millions)
|
|
|
Commercial
Paper Backup:
|
|
|
|
|
|
|
|
Revolving
Credit Facility
|
|
|
$
|
1,500
|
|
March
2011
|
|
Revolving
Credit Facility
|
|
|
|
1,500
|
|
April
2012
|
Revolving
Credit Facility
|
|
|
|
650
|
|
April
2011
|
Revolving
Credit Facility
|
|
|
|
350
|
|
April
2009
|
Total
|
|
|
|
4,000
|
|
|
Cash
and Cash Equivalents
|
|
|
|
218
|
|
|
Total
Liquidity Sources
|
|
|
|
4,218
|
|
|
Less:
AEP Commercial Paper Outstanding
|
|
|
|
698
|
|
|
Letters of Credit Drawn
|
|
|
|
429
|
|
|
|
|
|
|
|
|
|
Net
Available Liquidity
|
|
|
$
|
3,091
|
|
|
The
revolving credit facilities for commercial paper backup are structured as two
$1.5 billion credit facilities. In March 2008, the credit facilities
were amended so that $750 million may be issued under each credit facility as
letters of credit.
We use
our corporate borrowing program to meet the short-term borrowing needs of our
subsidiaries. The corporate borrowing program includes a Utility
Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool,
which funds the majority of the nonutility subsidiaries. In addition,
we also fund, as direct borrowers, the short-term debt requirements of other
subsidiaries that are not participants in either money pool for regulatory or
operational reasons. As of June 30, 2008, we had credit facilities
totaling $3 billion to support our commercial paper program. The
maximum amount of commercial paper outstanding during the first six months of
2008 was $1.2 billion. The weighted-average interest rate of our
commercial paper during the first six months of 2008 was 3.22%.
In April
2008, we entered into a $650 million 3-year credit agreement and a $350 million
364-day credit agreement. Under the facilities, we may issue letters
of credit. As of June 30, 2008, $371 million of letters of credit
were issued under the 3-year credit agreement to support variable rate demand
notes.
Investments
in Auction-Rate Securities
During
the first six months of 2008, we sold all of our investment in auction-rate
securities at par.
Debt
Covenants and Borrowing Limitations
Our
revolving credit agreements, including the new agreements entered into in April
2008, contain certain covenants and require us to maintain our percentage of
debt to total capitalization at a level that does not exceed
67.5%. The method for calculating our outstanding debt and other
capital is contractually defined. At June 30, 2008, this contractually-defined
percentage was 55.9%. Nonperformance of these covenants could result
in an event of default under these credit agreements. At June 30,
2008, we complied with all of the covenants contained in these credit
agreements. In addition, the acceleration of our payment obligations,
or the obligations of certain of our major subsidiaries, prior to maturity under
any other agreement or instrument relating to debt outstanding in excess of $50
million, would cause an event of default under these credit agreements and
permit the lenders to declare the outstanding amounts payable.
Our
revolving credit facilities do not permit the lenders to refuse a draw on any
facility if a material adverse change occurs.
Utility
Money Pool borrowings and external borrowings may not exceed amounts authorized
by regulatory orders. At June 30, 2008, we had not exceeded those
authorized limits.
Dividend
Policy and Restrictions
We have
declared common stock dividends payable in cash in each quarter since July
1910. The Board of Directors declared a quarterly dividend of $0.41
per share in July 2008. Future dividends may vary depending upon our
profit levels, operating cash flow levels and capital requirements, as well as
financial and other business conditions existing at the time. We have
the option to defer interest payments on the $315 million of AEP Junior
Subordinated Debentures issued in March 2008 for one or more periods of up to 10
consecutive years per period. During any period in which we defer
interest payments, we may not declare or pay any dividends or distributions on,
or redeem, repurchase or acquire, our common stock. We believe that
these restrictions will not have a material effect on our results of operations,
cash flows, financial condition or limit any dividend payments in the
foreseeable future.
Credit
Ratings
In the
first quarter of 2008, Moody’s changed its outlook from stable to negative for
APCo, SWEPCo, OPCo and TCC and affirmed its stable outlook for AEP and our other
subsidiaries. Also in the first quarter, Fitch downgraded PSO and
SWEPCo from A- to BBB+ for senior unsecured debt. In May 2008, Fitch
revised APCo’s outlook from stable to negative. Our current credit
ratings are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Moody’s
|
|
|
S&P
|
|
|
Fitch
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AEP
Short Term Debt
|
P-2
|
|
|
A-2
|
|
|
F-2
|
AEP
Senior Unsecured Debt
|
Baa2
|
|
|
BBB
|
|
|
BBB
|
If we or
any of our rated subsidiaries receive an upgrade from any of the rating agencies
listed above, our borrowing costs could decrease. If we receive a
downgrade in our credit ratings by one of the rating agencies listed above, our
borrowing costs could increase and access to borrowed funds could be negatively
affected.
Cash
Flow
Managing
our cash flows is a major factor in maintaining our liquidity
strength.
|
Six
Months Ended
|
|
|
June
30,
|
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$ |
178 |
|
|
$ |
301 |
|
Net
Cash Flows from Operating Activities
|
|
|
1,197 |
|
|
|
969 |
|
Net
Cash Flows Used for Investing Activities
|
|
|
(1,645
|
) |
|
|
(2,127 |
) |
Net
Cash Flows from Financing Activities
|
|
|
488 |
|
|
|
1,029 |
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
40 |
|
|
|
(129 |
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
218 |
|
|
$ |
172 |
|
Cash from
operations, combined with a bank-sponsored receivables purchase agreement and
short-term borrowings, provides working capital and allows us to meet other
short-term cash needs.
Operating
Activities
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2008
|
|
2007
|
|
|
|
(in
millions)
|
|
Net
Income
|
|
$
|
854
|
|
$
|
451
|
|
Less Discontinued
Operations, Net of Tax
|
|
|
(1
|
)
|
|
(2
|
)
|
Income
Before Discontinued Operations
|
|
|
853
|
|
|
449
|
|
Depreciation
and Amortization
|
|
|
736
|
|
|
763
|
|
Other
|
|
|
(392
|
)
|
|
(243
|
)
|
Net
Cash Flows from Operating Activities
|
|
$
|
1,197
|
|
$
|
969
|
|
Net Cash
Flows from Operating Activities increased in 2008 primarily due to the TEM
settlement.
Net Cash
Flows from Operating Activities were $1.2 billion in 2008 consisting primarily
of Income Before Discontinued Operations of $853 million and $736 million of
noncash depreciation and amortization. Other represents items that
had a current period cash flow impact, such as changes in working capital, as
well as items that represent future rights or obligations to receive or pay
cash, such as regulatory assets and liabilities. Significant changes
in other items include an increase in under-recovered fuel reflecting higher
natural gas prices.
Net Cash
Flows from Operating Activities were $1 billion in 2007 consisting primarily of
Income Before Discontinued Operations of $449 million and $763 million of
noncash depreciation and amortization. Other represents items that
had a prior period cash flow impact, such as changes in working capital, as well
as items that represent future rights or obligations to receive or pay cash,
such as regulatory assets and liabilities. Significant changes in
other items resulted in lower cash from operations due to a number of items, the
most significant of which relates primarily to the Texas CTC refund of fuel
over-recovery.
Investing
Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Construction
Expenditures
|
$
|
(1,608
|
)
|
$
|
(1,823
|
)
|
Acquisition
of Darby and Lawrenceburg Plants
|
|
-
|
|
|
(427
|
)
|
Acquisition
of Other Assets
|
|
(81
|
)
|
|
-
|
|
Proceeds
from Sales of Assets
|
|
69
|
|
|
74
|
|
Other
|
|
(25
|
)
|
|
49
|
|
Net
Cash Flows Used for Investing Activities
|
$
|
(1,645
|
)
|
$
|
(2,127
|
)
|
Net Cash
Flows Used for Investing Activities were $1.6 billion in 2008 primarily due to
Construction Expenditures for our environmental, distribution and new generation
investment plan. Construction expenditures decreased compared to 2007
due to a decline in environmental, fossil, hydro and nuclear projects partially
offset by increased expenditures for new generation and transmission
projects.
Net Cash
Flows Used for Investing Activities were $2.1 billion in 2007 primarily due to
Construction Expenditures for our environmental, distribution and new generation
investment plan. We paid $427 million to purchase gas-fired
generating units to acquire capacity at a cost below that of building a new,
comparable plant.
In our
normal course of business, we purchase and sell investment securities with cash
available for short-term investments. We also purchase and sell investment
securities within our nuclear trusts. The net amount of these
activities is included in Other.
We
forecast approximately $2.2 billion of construction expenditures for the
remainder of 2008. Estimated construction expenditures are subject to
periodic review and modification and may vary based on the ongoing effects of
regulatory constraints, environmental regulations, business opportunities,
market volatility, economic trends, weather, legal reviews and the ability to
access capital. These construction expenditures will be funded
through results of operations and financing activities.
Financing
Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Issuance
of Common Stock
|
$
|
72
|
|
$
|
90
|
|
Issuance/Retirement
of Debt, Net
|
|
777
|
|
|
1,294
|
|
Dividends
Paid on Common Stock
|
|
(330
|
)
|
|
(311
|
)
|
Other
|
|
(31
|
)
|
|
(44
|
)
|
Net
Cash Flows from Financing Activities
|
$
|
488
|
|
$
|
1,029
|
|
Net Cash
Flows from Financing Activities in 2008 were $488 million primarily due to the
issuance of additional debt including $315 million of junior subordinated
debentures and a net increase of $1 billion in outstanding senior unsecured
notes partially offset by the reacquisition of a net $440 million of pollution
control bonds and retirements of $53 million of mortgage notes and $75 million
of securitization bonds. See Note 9 – Financing Activities for a
complete discussion of long-term debt issuances and retirements.
Net Cash
Flows from Financing Activities in 2007 were $1 billion primarily due to issuing
$1.1 billion of debt securities including $1 billion of new debt for plant
acquisitions and construction and increasing short-term commercial paper
borrowings. We paid common stock dividends of $311
million.
Our
capital investment plans for 2008 will require additional funding from the
capital markets.
Off-balance Sheet
Arrangements
Under a
limited set of circumstances, we enter into off-balance sheet arrangements to
accelerate cash collections, reduce operational expenses and spread risk of loss
to third parties. Our current guidelines restrict the use of
off-balance sheet financing entities or structures to traditional operating
lease arrangements and sales of customer accounts receivable that we enter in
the normal course of business. Our significant off-balance sheet
arrangements are as follows:
|
June
30,
2008
|
|
December
31,
2007
|
|
|
(in
millions)
|
AEP
Credit Accounts Receivable Purchase Commitments
|
$
|
564
|
|
$
|
507
|
|
Rockport
Plant Unit 2 Future Minimum Lease Payments
|
|
2,142
|
|
|
2,216
|
|
Railcars
Maximum Potential Loss From Lease Agreement
|
|
26
|
|
|
30
|
|
For
complete information on each of these off-balance sheet arrangements see the
“Off-balance Sheet Arrangements” section of “Management’s Financial Discussion
and Analysis of Results of Operations” in the 2007 Annual Report.
Summary Obligation
Information
A summary
of our contractual obligations is included in our 2007 Annual Report and has not
changed significantly from year-end other than the debt issuances and
retirements discussed in “Cash Flow” above and standby letters of credit
discussed in “Liquidity” above.
SIGNIFICANT
FACTORS
We
continue to be involved in various matters described in the “Significant
Factors” section of “Management’s Financial Discussion and Analysis of Results
of Operations” in our 2007 Annual Report. The 2007 Annual Report
should be read in conjunction with this report in order to understand
significant factors which have not materially changed in status since the
issuance of our 2007 Annual Report, but may have a material impact on our future
results of operations, cash flows and financial condition.
Ohio Electric Security Plan
Filings
In April
2008, the Ohio legislature passed Senate Bill 221, which amends the
restructuring law effective July 31, 2008 and requires electric utilities to
adjust their rates by filing an Electric Security Plan
(ESP). Electric utilities may file an ESP with a fuel cost recovery
mechanism. Electric utilities also have an option to file a Market
Rate Offer (MRO) for generation pricing. A MRO, from the date of its
commencement, could transition CSPCo and OPCo to full market rates no sooner
than six years and no later than ten years. The PUCO has the
authority to approve or modify the utilities’ ESP request. The PUCO
is required to approve an ESP if, in the aggregate, the ESP is more favorable to
ratepayers than the MRO. Both alternatives involve a “substantially
excessive earnings” test based on what public companies, including other
utilities with similar risk profiles, earn on equity. Management has
preliminarily concluded, pending the issuance of final rules by the PUCO and the
outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply
operations are not subject to cost-based rate regulation
accounting. However, if a fuel cost recovery mechanism is implemented
within the ESP, CSPCo’s and OPCo’s fuel operations would be subject to
cost-based rate regulation accounting. Management is unable to
predict the financial statement impact of the restructuring legislation until
the PUCO acts on specific proposals made by CSPCo and OPCo in their
ESPs.
In July
2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to
establish rates for 2009 through 2011. CSPCo and OPCo did not file
MROs. CSPCo and
OPCo each requested an annual rate increase for 2009 through 2011 that would not
exceed approximately 15% per year. A significant portion of
the requested increases results from the implementation of a fuel cost recovery
mechanism that primarily includes fuel costs, purchased power costs including
mandated renewable energy, consumables such as urea, other variable production
costs and gains and losses on sales of emission allowances. The
increases in customer bills related to the fuel cost recovery mechanism would be
phased-in over the three year period from 2009 through
2011. Effective January 1, 2009, CSPCo and OPCo will defer the fuel
cost under-recoveries and related carrying costs for future recovery over seven
years from 2012 through 2018. In addition to the fuel cost recovery
mechanisms, the requested increases would also recover incremental carrying
costs associated with environmental costs, Provider of Last Resort (POLR)
charges to compensate for the risk of customers changing electric suppliers,
automatic increases for unexpected costs and reliability costs. The filings also
include programs for smart metering initiatives and economic development
and mandated energy efficiency and peak demand reduction
programs. Management expects a PUCO decision on the ESP filings in
the fourth quarter of 2008.
Within
the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $45
million and $36 million, respectively, for customer choice implementation and
line extension carrying costs. In addition, CSPCo and OPCo would
recover related unrecorded equity carrying costs of $28 million and $19 million,
respectively. Such costs would be recovered over an 8 year
period beginning January 2011. Failure of the PUCO to ultimately approve
the recovery of the regulatory assets would have an adverse effect on future
results of operations and cash flows.
Texas
Restructuring Appeals
Pursuant
to PUCT orders, TCC securitized its net recoverable stranded generation costs of
$2.5 billion and is recovering such costs over a period ending in
2020. TCC has refunded its net other true-up items of $375
million during the period October 2006 through June 2008 via a CTC credit rate
rider. Cash paid for CTC refunds for the six months ended June 30,
2008 and 2007 was $68 million and $170 million, respectively. TCC appealed
the PUCT stranded costs true-up and related orders seeking relief in both state
and federal court on the grounds that certain aspects of the orders are contrary
to the Texas Restructuring Legislation, PUCT rulemakings and federal law and
fail to fully compensate TCC for its net stranded cost and other true-up
items. Municipal customers and other intervenors also appealed the
PUCT true-up and related orders seeking to further reduce TCC’s true-up
recoveries. In March 2007, the Texas District Court judge hearing the appeal of
the true-up order affirmed the PUCT’s April 2006 final true-up order for TCC
with two significant exceptions. The judge determined that the PUCT
erred by applying an invalid rule to determine the carrying cost rate for the
true-up of stranded costs and remanded this matter to the PUCT for further
consideration. The District Court judge also determined that the PUCT
improperly reduced TCC’s net stranded plant costs for commercial
unreasonableness.
TCC, the
PUCT and intervenors appealed the District Court decision to the Texas Court of
Appeals. In May 2008, the Texas Court of Appeals affirmed the
District Court decision in all but one major respect. It reversed the
District Court’s decision finding that the PUCT erred by applying an invalid
rule to determine the carrying cost rate. The Texas Court of Appeals
denied intervenors’ motion for rehearing. Management expects
intervenors to appeal the decision to the Texas Supreme Court. If
upheld on appeal, this ruling could have a favorable effect on TCC’s results of
operations and cash flows.
Management
cannot predict the outcome of these court proceedings and PUCT remand
decisions. If TCC ultimately succeeds in its appeals, it could have a
favorable effect on future results of operations, cash flows and financial
condition. If municipal customers and other intervenors succeed in
their appeals it could have a substantial adverse effect on future results of
operations, cash flows and financial condition.
FERC Market Power
Mitigation
FERC
allows utilities to sell wholesale power at market-based rates if they can
demonstrate that they lack market power in the markets in which they
participate. Sellers with market rate authority must, at least every
three years, update their studies demonstrating lack of market
power. In December 2007, AEP filed its most recent triennial
update. In March and May 2008, the PUCO filed comments suggesting
that FERC should further investigate whether AEP continues to pass FERC’s
indicative screens for the lack of market power in PJM. Certain
industrial retail customers also urged FERC to further investigate this
matter. AEP responded that its market power studies were performed in
accordance with FERC’s guidelines, and continue to demonstrate lack of market
power. Management is unable to predict the outcome of this proceeding; however,
if a further investigation by the FERC limits AEP’s ability to sell power at
market based rates in PJM, it would result in an adverse effect on future
off-system sales margins, results of operations and cash flows.
New
Generation
In 2008,
AEP completed or is in various stages of construction of the following
generation facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
Nominal
|
|
Operation
|
Operating
|
|
Project
|
|
|
|
Projected
|
|
|
|
|
|
|
|
|
MW
|
|
Date
|
Company
|
|
Name
|
|
Location
|
|
Cost
(a)
|
|
CWIP
(b)
|
|
Fuel
Type
|
|
Plant
Type
|
|
Capacity
|
|
(Projected)
|
|
|
|
|
|
|
(in
millions)
|
|
(in
millions)
|
|
|
|
|
|
|
|
|
PSO
|
|
Southwestern
|
(c)
|
Oklahoma
|
|
$
|
56
|
|
$
|
-
|
|
Gas
|
|
Simple-cycle
|
|
150
|
|
2008
|
PSO
|
|
Riverside
|
(d)
|
Oklahoma
|
|
|
58
|
|
|
-
|
|
Gas
|
|
Simple-cycle
|
|
150
|
|
2008
|
AEGCo
|
|
Dresden
|
(e)
|
Ohio
|
|
|
309
|
(e)
|
|
119
|
|
Gas
|
|
Combined-cycle
|
|
580
|
|
2010
|
SWEPCo
|
|
Stall
|
|
Louisiana
|
|
|
378
|
|
|
106
|
|
Gas
|
|
Combined-cycle
|
|
500
|
|
2010
|
SWEPCo
|
|
Turk
|
(f)
|
Arkansas
|
|
|
1,522
|
(f)
|
|
407
|
|
Coal
|
|
Ultra-supercritical
|
|
600
|
(f)
|
2012
|
APCo
|
|
Mountaineer
|
(g)
|
West
Virginia
|
|
|
2,230
|
(g)
|
|
-
|
|
Coal
|
|
IGCC
|
|
629
|
|
2012(g)
|
CSPCo/OPCo
|
|
Great
Bend
|
(g)
|
Ohio
|
|
|
2,700
|
(g)
|
|
-
|
|
Coal
|
|
IGCC
|
|
629
|
|
2017(g)
|
(a)
|
Amount
excludes AFUDC.
|
(b)
|
Amount
includes AFUDC. Turk’s CWIP includes joint owners’
share.
|
(c)
|
Southwestern
Units were placed in service on February 29, 2008.
|
(d)
|
The
final Riverside Unit was placed in service on June 15,
2008.
|
(e)
|
In
September 2007, AEGCo purchased the partially completed Dresden plant from
Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85
million, which is included in the “Total Projected Cost” section
above.
|
(f)
|
SWEPCo
plans to own approximately 73%, or 440 MW, totaling $1,110 million in
capital investment. The increase in the cost estimate disclosed
in the 2007 Annual Report relates to cost escalations due to the delay in
receipt of permits and approvals. See “Turk Plant” section
below.
|
(g)
|
Subject
to revision; construction of IGCC plants deferred pending regulatory
approval. See “IGCC Plants” section
below.
|
Turk
Plant
In
November 2007, the APSC granted approval to build the Turk
Plant. Certain landowners filed a notice of appeal to the Arkansas
State Court of Appeals. In March 2008, the LPSC approved the
application to construct the Turk Plant. In July 2008, the PUCT
approved a certificate of convenience and necessity for construction of the
plant. We expect a written order in August 2008 which will also
provide for the conditions of the PUCT’s approval.
SWEPCo is
working with the Arkansas Department of Environmental Quality and the U.S. Army
Corps of Engineers for approval later this year. A request to stop
pre-construction activities at the site was filed in Federal court by the same
Arkansas landowners who appealed the APSC decision to the Arkansas State Court
of Appeals. In July 2008, the Federal court denied the request and
the Arkansas landowners appealed the denial to the U.S. Court of
Appeals.
If SWEPCo
does not receive appropriate authorizations and permits to build the Turk Plant,
SWEPCo could incur significant cancellation fees to terminate its commitments
and would be responsible to reimburse the joint owners for their share of paid
costs. If that occurred, SWEPCo would seek recovery of its
capitalized costs including any cancellation fees and joint owner
reimbursements. As of June 30, 2008, including the joint owners’
share, SWEPCo has capitalized approximately $407 million of expenditures and has
significant contractual construction commitments for an additional $815
million. As of June 30, 2008, if the plant had been canceled,
cancellation fees of $60 million would have been required in order to terminate
these construction commitments. If SWEPCo cannot recover its costs,
it would have an adverse effect on future results of operations, cash flows and
possibly financial condition.
IGCC
Plants
We have
delayed construction of the West Virginia and Ohio IGCC plants. In
May 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia
SCC's previous denial of APCo’s request to recover initial costs associated with
a proposed IGCC plant in West Virginia. In July 2008, the WVPSC
issued a notice seeking comments from parties on how the WVPSC should proceed
regarding its earlier approval of the IGCC plant. In July 2008, the
IRS awarded $134 million in future tax credits for the IGCC
plant. Management continues to pursue the ultimate construction of
the IGCC plant. If the West Virginia IGCC plant is canceled, APCo
plans to seek recovery of its prudently incurred deferred pre-construction costs
of $19 million. If the plant is canceled and the deferred costs are
not recoverable, it would have an adverse effect on future results of operations
and cash flows.
In Ohio,
CSPCo and OPCo continue to pursue the ultimate construction of the IGCC plant,
but await the result of an Ohio Supreme Court remand to the PUCO regarding
recovery of IGCC pre-construction costs. If CSPCo and OPCo were
required to refund $24 million collected for IGCC pre-construction costs and
those costs were not recoverable in another jurisdiction in connection with the
construction of an IGCC plant, it would have an adverse effect on future results
of operations and cash flows.
Litigation
In the
ordinary course of business, we, along with our subsidiaries, are involved in
employment, commercial, environmental and regulatory
litigation. Since it is difficult to predict the outcome of these
proceedings, we cannot state what the eventual outcome will be, or what the
timing of the amount of any loss, fine or penalty may be. Management
does, however, assess the probability of loss for such contingencies and accrues
a liability for cases that have a probable likelihood of loss and if the loss
amount can be estimated. For details on our regulatory proceedings
and pending litigation see Note 4 – Rate Matters, Note 6 – Commitments,
Guarantees and Contingencies and the “Litigation” section of “Management’s
Financial Discussion and Analysis of Results of Operations” in the 2007 Annual
Report. Additionally, see Note 3 – Rate Matters and Note 4 –
Commitments, Guarantees and Contingencies included herein. Adverse
results in these proceedings have the potential to materially affect our results
of operations.
Environmental
Litigation
New Source Review (NSR)
Litigation: The Federal EPA, a number of states and certain
special interest groups filed complaints alleging that APCo, CSPCo, I&M,
OPCo and other nonaffiliated utilities, including Cincinnati Gas & Electric
Company, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc.
(Duke), modified certain units at coal-fired generating plants in violation of
the NSR requirements of the CAA.
In 2007,
the AEP System settled their complaints under a consent decree. CSPCo
jointly-owns Beckjord and Stuart Stations with Duke and DP&L. A
jury trial in May 2008 returned a verdict of no liability at the jointly-owned
Beckjord unit. Settlement discussions are ongoing in the citizen suit
action filed by Sierra Club against the jointly-owned units at Stuart
Station. We believe we can recover any capital and operating costs of
additional pollution control equipment that may be required through future
regulated rates or market prices for electricity. If we are unable to
recover such costs or if material penalties are imposed, it would adversely
affect future results of operations and cash flows.
Environmental
Matters
We are
implementing a substantial capital investment program and incurring additional
operational costs to comply with new environmental control
requirements. The sources of these requirements include:
·
|
Requirements
under CAA to reduce emissions of SO2,
NOx,
particulate matter (PM) and mercury from fossil fuel-fired power plants;
and
|
·
|
Requirements
under the Clean Water Act (CWA) to reduce the impacts of water intake
structures on aquatic species at certain of our power
plants.
|
In
addition, we are engaged in litigation with respect to certain environmental
matters, have been notified of potential responsibility for the clean-up of
contaminated sites and incur costs for disposal of spent nuclear fuel and future
decommissioning of our nuclear units. We are also engaged in the
development of possible future requirements to reduce CO2 and other
greenhouse gases (GHG) emissions to address concerns about global climate
change. All of these matters are discussed in the “Environmental
Matters” section of “Management’s Financial Discussion and Analysis of Results
of Operations” in the 2007 Annual Report.
Clean
Air Act Requirements
As
discussed in the 2007 Annual Report under “Clean Air Act Requirements,” various
states and environmental organizations challenged the Clean Air Mercury Rule
(CAMR) in the D. C. Circuit Court of Appeals. The Court ruled that
the Federal EPA’s action delisting fossil fuel-fired power plants did not
conform to the procedures specified in the CAA. The Court vacated and
remanded the model federal rules for both new and existing coal-fired power
plants to the Federal EPA. We are unable to predict how the Federal
EPA will respond to the remand. In addition, in 2005, the Federal EPA
issued a final rule, the Clean Air Interstate Rule (CAIR), that requires further
reductions in SO2 and
NOx
emissions and assists states developing new state implementation plans to meet
1997 national ambient air quality standards (NAAQS). CAIR reduces
regional emissions of SO2 and
NOx
(which can be transformed into PM and ozone) from power plants in the Eastern
U.S. (29 states and the District of Columbia). CAIR requires power
plants within these states to reduce emissions of SO2 by 50
percent by 2010, and by 65 percent by 2015. NOx emissions
will be subject to additional limits beginning in 2009, and will be reduced by a
total of 70 percent from current levels by 2015. Reduction of both
SO2
and NOx would be
achieved through a cap-and-trade program. In July 2008, the D.C.
Circuit Court of Appeals vacated the CAIR and remanded the rule to the Federal
EPA. We are unable to predict how the Federal EPA will respond to the
remand which could be stayed or appealed to the U.S. Supreme
Court. The Federal EPA also issued revised NAAQS for both ozone and
PM 2.5
that are more stringent than the 1997 standards used to establish CAIR, which
could increase the levels of SO2 and
NOx
reductions required from our facilities.
In
anticipation of compliance with CAIR in 2009, I&M purchased $8 million of
annual CAIR NOx allowances
which are included in inventory as of June 30, 2008. The market value
of annual CAIR NOx allowances
decreased in the weeks following this court decision. Management
intends to seek recovery of the cost of purchased allowances. If the
recovery is denied, it would have an adverse effect on future results of
operations and cash flows. None of AEP’s other subsidiaries purchased
any significant number of CAIR allowances. SO2 and
seasonal NOx allowances
allocated to our facilities under the Acid Rain Program and the NOx SIP Call
will still be required to comply with existing CAA programs that were not
affected by the court’s decision.
It is too
early to determine the full implication of these decisions on our environmental
compliance strategy. However, independent obligations under the CAA,
including obligations under future state implementation plan submittals, and
actions taken pursuant to our recent settlement of the NSR enforcement action,
are consistent with the actions included in our least-cost CAIR compliance
plan. Consequently, we do not anticipate making any immediate
changes in our near-term compliance plans as a result of these court
decisions.
Global
Climate Change
In July
2008, the Federal EPA issued an advance notice of proposed rulemaking (ANPR)
that requests comments on a wide variety of issues the agency is considering in
formulating its response to the U.S. Supreme Court’s decision in Massachusetts v.
EPA. In that case, the Court determined that CO2 is an “air
pollutant” and that the Federal EPA has authority to regulate mobile sources of
CO2
emissions under the CAA if appropriate findings are made. The Federal
EPA has identified a number of issues that could affect stationary sources, such
as electric generating plants, if the necessary findings are made for mobile
sources, including the potential regulation of CO2 emissions
for both new and existing stationary sources under the NSR programs of the
CAA. We plan to submit comments and participate in any subsequent
regulatory development processes, but are unable to predict the outcome of the
Federal EPA’s administrative process or its impact on our
business. Also, additional legislative measures to address CO2 and other
GHGs have been introduced in Congress, and such legislative actions could impact
future decisions by the Federal EPA on CO2
regulation.
In
addition, the Federal EPA issued a proposed rule for the underground injection
and storage of CO2 captured
from industrial processes, including electric generating facilities, under the
Safe Drinking Water Act’s Underground Injection Control (UIC)
program. The proposed rules provide a comprehensive set of well
siting, design, construction, operation, closure and post-closure care
requirements. We plan to submit comments and participate in any
subsequent regulatory development process, but are unable to predict the outcome
of the Federal EPA’s administrative process or its impact on our
business. Permitting for our demonstration project at the Mountaineer
Plant will proceed under the existing UIC rules.
Clean
Water Act Regulations
In 2004,
the Federal EPA issued a final rule requiring all large existing power plants
with once-through cooling water systems to meet certain standards to reduce
mortality of aquatic organisms pinned against the plant’s cooling water intake
screen or entrained in the cooling water. The standards vary based on
the water bodies from which the plants draw their cooling water. We
expected additional capital and operating expenses, which the Federal EPA
estimated could be $193 million for our plants. We undertook
site-specific studies and have been evaluating site-specific compliance or
mitigation measures that could significantly change these cost
estimates.
In
January 2007, the Second Circuit Court of Appeals issued a decision remanding
significant portions of the rule to the Federal EPA. In July 2007,
the Federal EPA suspended the 2004 rule, except for the requirement that
permitting agencies develop best professional judgment (BPJ) controls for
existing facility cooling water intake structures that reflect the best
technology available for minimizing adverse environmental impact. The
result is that the BPJ control standard for cooling water intake structures in
effect prior to the 2004 rule is the applicable standard for permitting agencies
pending finalization of revised rules by the Federal EPA. We cannot
predict further action of the Federal EPA or what effect it may have on similar
requirements adopted by the states. We sought further review and
filed for relief from the schedules included in our permits.
In April
2008, the U.S. Supreme Court agreed to review decisions from the Second Circuit
Court of Appeals that limit the Federal EPA’s ability to weigh the retrofitting
costs against environmental benefits. Management is unable to predict
the outcome of this appeal.
Critical Accounting
Estimates
See the
“Critical Accounting Estimates” section of “Management’s Financial Discussion
and Analysis of Results of Operations” in the 2007 Annual Report for a
discussion of the estimates and judgments required for regulatory accounting,
revenue recognition, the valuation of long-lived assets, the accounting for
pension and other postretirement benefits and the impact of new accounting
pronouncements.
Adoption of New Accounting
Pronouncements
In
September 2006, the FASB issued SFAS 157 “Fair Value Measurements” (SFAS 157),
enhancing existing guidance for fair value measurement of assets and liabilities
and instruments measured at fair value that are classified in shareholders’
equity. The statement defines fair value, establishes a fair value
measurement framework and expands fair value disclosures. It
emphasizes that fair value is market-based with the highest measurement
hierarchy level being market prices in active markets. The standard
requires fair value measurements be disclosed by hierarchy level, an entity
includes its own credit standing in the measurement of its liabilities and
modifies the transaction price presumption. The standard also
nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that
prohibited the recognition of trading gains or losses at the inception of a
derivative contract, unless the fair value of such derivative is supported by
observable market data. In February 2008, the FASB issued FSP FAS
157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other
Accounting Pronouncements That Address Fair Value Measurements for Purposes of
Lease Classification or Measurement under Statement 13” which amends SFAS 157 to
exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that
address fair value measurements for purposes of lease classification or
measurement under SFAS 13. In February 2008, the FASB issued FSP FAS
157-2 “Effective Date of FASB Statement No. 157” which delays the effective date
of SFAS 157 to fiscal years beginning after November 15, 2008 for all
nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually). The provisions of SFAS
157 are applied prospectively, except for a) changes in fair value measurements
of existing derivative financial instruments measured initially using the
transaction price under EITF 02-3, b) existing hybrid financial instruments
measured initially at fair value using the transaction price and c) blockage
discount factors. Although the statement is applied prospectively
upon adoption, in accordance with the provisions of SFAS 157 related to EITF
02-3, we recorded an immaterial transition adjustment to beginning retained
earnings. The impact of considering our own credit risk when
measuring the fair value of liabilities, including derivatives, had an
immaterial impact on fair value measurements upon adoption. We
partially adopted SFAS 157 effective January 1, 2008. We will fully
adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP FAS
157-2. See “SFAS 157 “Fair Value Measurements” (SFAS 157)” section of
Note 2.
In
February 2007, the FASB issued SFAS 159 “The Fair Value Option for Financial
Assets and Financial Liabilities” (SFAS 159), permitting entities to choose to
measure many financial instruments and certain other items at fair
value. The standard also establishes presentation and disclosure
requirements designed to facilitate comparison between entities that choose
different measurement attributes for similar types of assets and
liabilities. If the fair value option is elected, the effect of the
first remeasurement to fair value is reported as a cumulative effect adjustment
to the opening balance of retained earnings. The statement is applied
prospectively upon adoption. We adopted SFAS 159 effective January 1,
2008. At adoption, we did not elect the fair value option for any
assets or liabilities.
In March
2007, the FASB ratified EITF Issue No. 06-10 “Accounting for Collateral
Assignment Split-Dollar Life Insurance Arrangements” (EITF 06-10), a consensus
on collateral
assignment split-dollar life insurance arrangements in which an employee owns
and controls the insurance policy. Under EITF 06-10, an employer
should recognize a liability for the postretirement benefit related to a
collateral assignment split-dollar life insurance arrangement in accordance with
SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension”
or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the
employer has agreed to maintain a life insurance policy during the employee's
retirement or to provide the employee with a death benefit based on a
substantive arrangement with the employee. In addition, an employer
should recognize and measure an asset based on the nature and substance of the
collateral assignment split-dollar life insurance arrangement. EITF
06-10 requires recognition of the effects of its application as either (a) a
change in accounting principle through a cumulative effect adjustment to
retained earnings or other components of equity or net assets in the statement
of financial position at the beginning of the year of adoption or (b) a change
in accounting principle through retrospective application to all prior
periods. We adopted EITF 06-10 effective January 1, 2008 with a
cumulative effect reduction of $16 million ($10 million, net of tax) to
beginning retained earnings.
In June
2007, the FASB ratified the EITF Issue No. 06-11 “Accounting for Income Tax
Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11), consensus on
the treatment of income tax benefits of dividends on employee share-based
compensation. The issue is how a company should recognize the income
tax benefit received on dividends that are paid to employees holding
equity-classified nonvested shares, equity-classified nonvested share units or
equity-classified outstanding share options and charged to retained earnings
under SFAS 123R, “Share-Based Payments.” Under EITF 06-11, a realized
income tax benefit from dividends or dividend equivalents that are charged to
retained earnings and are paid to employees for equity-classified nonvested
equity shares, nonvested equity share units and outstanding equity share options
should be recognized as an increase to additional paid-in capital. We adopted
EITF 06-11 effective January 1, 2008. EITF 06-11 is applied
prospectively to the income tax benefits of dividends on equity-classified
employee share-based payment awards that are declared in fiscal years after
December 15, 2007. The adoption of this standard had an immaterial
impact on our financial statements.
In April
2007, the FASB issued FSP FIN 39-1 “Amendment of FASB Interpretation No. 39”
(FIN 39-1). It amends FASB Interpretation No. 39 “Offsetting of
Amounts Related to Certain Contracts” by replacing the interpretation’s
definition of contracts with the definition of derivative instruments per SFAS
133. It also requires entities that offset fair values of derivatives
with the same party under a netting agreement to net the fair values (or
approximate fair values) of related cash collateral. The entities
must disclose whether or not they offset fair values of derivatives and related
cash collateral and amounts recognized for cash collateral payables and
receivables at the end of each reporting period. We adopted FIN 39-1 effective
January 1, 2008. This standard changed our method of netting certain
balance sheet amounts and reduced assets and liabilities. It requires
retrospective application as a change in accounting
principle. Consequently, we reduced total assets and liabilities on
the December 31, 2007 balance sheet by $47 million each. See “FSP FIN
39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note
2.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market
Risks
Our
Utility Operations segment is exposed to certain market risks as a major power
producer and marketer of wholesale electricity, coal and emission
allowances. These risks include commodity price risk, interest rate
risk and credit risk. In addition, we may be exposed to foreign
currency exchange risk because occasionally we procure various services and
materials used in our energy business from foreign suppliers. These
risks represent the risk of loss that may impact us due to changes in the
underlying market prices or rates.
Our
Generation and Marketing segment, operating primarily within ERCOT, transacts in
wholesale energy trading and marketing contracts. This segment is
exposed to certain market risks as a marketer of wholesale
electricity. These risks include commodity price risk, interest rate
risk and credit risk. These risks represent the risk of loss that may
impact us due to changes in the underlying market prices or rates.
All Other
includes natural gas operations which holds forward natural gas contracts that
were not sold with the natural gas pipeline and storage assets. These
contracts are financial derivatives, which will gradually liquidate and
completely expire in 2011. Our risk objective is to keep these
positions generally risk neutral through maturity.
We employ
risk management contracts including physical forward purchase and sale contracts
and financial forward purchase and sale contracts. We engage in risk
management of electricity, natural gas, coal, and emissions and to a lesser
degree other commodities associated with our energy business. As a
result, we are subject to price risk. The amount of risk taken is
determined by the commercial operations group in accordance with the market risk
policy approved by the Finance Committee of our Board of
Directors. Our market risk oversight staff independently monitors our
risk policies, procedures and risk levels and provides members of the Commercial
Operations Risk Committee (CORC) various daily, weekly and/or monthly reports
regarding compliance with policies, limits and procedures. The CORC
consists of our President – AEP Utilities, Chief Financial Officer, Senior Vice
President of Commercial Operations and Chief Risk Officer. When
commercial activities exceed predetermined limits, we modify the positions to
reduce the risk to be within the limits unless specifically approved by the
CORC.
We
actively participate in the Committee of Chief Risk Officers (CCRO) to develop
standard disclosures for risk management activities around risk management
contracts. The CCRO adopted disclosure standards for risk management
contracts to improve clarity, understanding and consistency of information
reported. We support the work of the CCRO and embrace the disclosure
standards applicable to our business activities. The following tables
provide information on our risk management activities.
Mark-to-Market Risk
Management Contract Net Assets (Liabilities)
The
following two tables summarize the various mark-to-market (MTM) positions
included on our Condensed Consolidated Balance Sheet as of June 30, 2008 and the
reasons for changes in our total MTM value included on our Condensed
Consolidated Balance Sheet as compared to December 31, 2007.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
June
30, 2008
(in
millions)
|
Utility
Operations
|
|
Generation
and
Marketing
|
|
All
Other
|
|
Sub-Total
MTM
Risk Management Contracts
|
|
MTM
of
Cash Flow and Fair Value Hedges
|
|
Collateral
Deposits
|
|
Total
|
|
Current
Assets
|
$
|
653
|
|
$
|
201
|
|
$
|
121
|
|
$
|
975
|
|
$
|
34
|
|
$
|
(118
|
)
|
$
|
891
|
|
Noncurrent
Assets
|
|
309
|
|
|
144
|
|
|
86
|
|
|
539
|
|
|
14
|
|
|
(64
|
)
|
|
489
|
|
Total
Assets
|
|
962
|
|
|
345
|
|
|
207
|
|
|
1,514
|
|
|
48
|
|
|
(182
|
)
|
|
1,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
(660
|
)
|
|
(203
|
)
|
|
(124
|
)
|
|
(987
|
)
|
|
(101
|
)
|
|
97
|
|
|
(991
|
)
|
Noncurrent
Liabilities
|
|
(202
|
)
|
|
(75
|
)
|
|
(90
|
)
|
|
(367
|
)
|
|
(5
|
)
|
|
24
|
|
|
(348
|
)
|
Total
Liabilities
|
|
(862
|
)
|
|
(278
|
)
|
|
(214
|
)
|
|
(1,354
|
)
|
|
(106
|
)
|
|
121
|
|
|
(1,339
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MTM Derivative
Contract
Net Assets
(Liabilities)
|
$
|
100
|
|
$
|
67
|
|
$
|
(7
|
)
|
$
|
160
|
|
$
|
(58
|
)
|
$
|
(61
|
)
|
$
|
41
|
|
MTM
Risk Management Contract Net Assets (Liabilities)
Six
Months Ended June 30, 2008
(in
millions)
|
|
Utility
Operations
|
|
Generation
and
Marketing
|
|
All
Other
|
|
Total
|
|
Total
MTM Risk Management Contract Net Assets (Liabilities)
at December 31, 2007
|
|
$
|
156
|
|
$
|
43
|
|
$
|
(8
|
)
|
$
|
191
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and
Entered in a Prior Period
|
|
|
(36
|
)
|
|
4
|
|
|
-
|
|
|
(32
|
)
|
Fair
Value of New Contracts at Inception When Entered
During
the Period (a)
|
|
|
2
|
|
|
16
|
|
|
-
|
|
|
18
|
|
Changes
in Fair Value Due to Valuation Methodology
Changes
on Forward Contracts (b)
|
|
|
6
|
|
|
3
|
|
|
1
|
|
|
10
|
|
Changes
in Fair Value Due to Market Fluctuations During
the
Period (c)
|
|
|
6
|
|
|
1
|
|
|
-
|
|
|
7
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions
(d)
|
|
|
(34
|
)
|
|
-
|
|
|
-
|
|
|
(34
|
)
|
Total
MTM Risk Management Contract Net Assets
(Liabilities) at June 30, 2008
|
|
$
|
100
|
|
$
|
67
|
|
$
|
(7
|
)
|
|
160
|
|
Net
Cash Flow and Fair Value Hedge Contracts
|
|
|
|
|
|
|
|
|
|
|
|
(58
|
)
|
Collateral
Deposits
|
|
|
|
|
|
|
|
|
|
|
|
(61
|
)
|
Ending
Net Risk Management Assets at June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
$
|
41
|
|
(a)
|
Reflects
fair value on long-term contracts which are typically with customers that
seek fixed pricing to limit their risk against fluctuating energy
prices. The contract prices are valued against market curves
associated with the delivery location and delivery
term.
|
(b)
|
Represents
the impact of applying AEP’s credit risk when measuring the fair value of
derivative liabilities according to SFAS 157.
|
(c)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(d)
|
“Change
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected on the Condensed
Consolidated Statements of Income. These net gains (losses) are
recorded as regulatory assets/liabilities for those subsidiaries that
operate in regulated jurisdictions.
|
Maturity and Source of Fair
Value of MTM Risk Management Contract Net Assets
(Liabilities)
The
following table presents the maturity, by year, of our net assets/liabilities,
to give an indication of when these MTM amounts will settle and generate
cash:
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets (Liabilities)
Fair
Value of Contracts as of June 30, 2008
(in
millions)
|
|
Remainder
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
After
2012
(f)
|
|
|
Total
|
|
Utility
Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1 (a)
|
|
$ |
(6 |
) |
|
$ |
1 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(5 |
) |
Level
2 (b)
|
|
|
8 |
|
|
|
47 |
|
|
|
40 |
|
|
|
16 |
|
|
|
6 |
|
|
|
- |
|
|
|
117 |
|
Level
3 (c)
|
|
|
(29
|
) |
|
|
(5
|
) |
|
|
(12
|
) |
|
|
(8
|
) |
|
|
(4
|
) |
|
|
- |
|
|
|
(58
|
) |
Total
|
|
|
(27
|
) |
|
|
43 |
|
|
|
28 |
|
|
|
8 |
|
|
|
2 |
|
|
|
- |
|
|
|
54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
and Marketing:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1 (a)
|
|
|
(36
|
) |
|
|
13 |
|
|
|
(1
|
) |
|
|
(1
|
) |
|
|
- |
|
|
|
- |
|
|
|
(25
|
) |
Level
2 (b)
|
|
|
31 |
|
|
|
(8
|
) |
|
|
6 |
|
|
|
5 |
|
|
|
5 |
|
|
|
3 |
|
|
|
42 |
|
Level
3 (c)
|
|
|
(2
|
) |
|
|
- |
|
|
|
8 |
|
|
|
9 |
|
|
|
9 |
|
|
|
26 |
|
|
|
50 |
|
Total
|
|
|
(7
|
) |
|
|
5 |
|
|
|
13 |
|
|
|
13 |
|
|
|
14 |
|
|
|
29 |
|
|
|
67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1 (a)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Level
2 (b)
|
|
|
(1
|
) |
|
|
(4
|
) |
|
|
(4
|
) |
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
(7
|
) |
Level
3 (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
|
|
|
(1
|
) |
|
|
(4
|
) |
|
|
(4
|
) |
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
(7
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1 (a)
|
|
|
(42
|
) |
|
|
14 |
|
|
|
(1
|
) |
|
|
(1
|
) |
|
|
- |
|
|
|
- |
|
|
|
(30
|
) |
Level
2 (b)
|
|
|
38 |
|
|
|
35 |
|
|
|
42 |
|
|
|
23 |
|
|
|
11 |
|
|
|
3 |
|
|
|
152 |
|
Level
3 (c) (d)
|
|
|
(31
|
) |
|
|
(5
|
) |
|
|
(4
|
) |
|
|
1 |
|
|
|
5 |
|
|
|
26 |
|
|
|
(8
|
) |
Total
|
|
|
(35
|
) |
|
|
44 |
|
|
|
37 |
|
|
|
23 |
|
|
|
16 |
|
|
|
29 |
|
|
|
114 |
|
Dedesignated
Risk Management
Contracts (e)
|
|
|
7 |
|
|
|
14 |
|
|
|
14 |
|
|
|
6 |
|
|
|
5 |
|
|
|
- |
|
|
|
46 |
|
Total
MTM Risk Management
Contract Net Assets (Liabilities)
|
|
$ |
(28 |
) |
|
$ |
58 |
|
|
$ |
51 |
|
|
$ |
29 |
|
|
$ |
21 |
|
|
$ |
29 |
|
|
$ |
160 |
|
(a)
|
Level
1 inputs are quoted prices (unadjusted) in active markets for identical
assets or liabilities that the reporting entity has the ability to access
at the measurement date. Level 1 inputs primarily consist of
exchange traded contracts that exhibit sufficient frequency and volume to
provide pricing information on an ongoing basis.
|
(b)
|
Level
2 inputs are inputs other than quoted prices included within Level 1 that
are observable for the asset or liability, either directly or
indirectly. If the asset or liability has a specified
(contractual) term, a Level 2 input must be observable for substantially
the full term of the asset or liability. Level 2 inputs
primarily consist of OTC broker quotes in moderately active or less active
markets, exchange traded contracts where there was not sufficient market
activity to warrant inclusion in Level 1, and OTC broker quotes that are
corroborated by the same or similar transactions that have occurred in the
market.
|
(c)
|
Level
3 inputs are unobservable inputs for the asset or
liability. Unobservable inputs shall be used to measure fair
value to the extent that the observable inputs are not available, thereby
allowing for situations in which there is little, if any, market activity
for the asset or liability at the measurement date. Level 3
inputs primarily consist of unobservable market data or are valued based
on models and/or assumptions.
|
(d)
|
A
significant portion of the total volumetric position within the
consolidated level 3 balance has been economically
hedged.
|
(e)
|
Dedesignated
Risk Management Contracts are contracts that were originally MTM but were
subsequently elected as normal under SFAS 133. At the time of
the normal election the MTM value was frozen and no longer fair
valued. This will be amortized within Utility Operations
Revenues over the remaining life of the contract.
|
(f)
|
There
is mark-to-market value of $29 million in individual periods beyond
2012. $13 million of this mark-to-market value is in 2013, $8
million is in 2014, $3 million is in 2015, $3 million is in 2016 and $2
million is in 2017.
|
The
following table reports an estimate of the maximum tenors (contract maturities)
of the liquid portion of each energy market.
Maximum
Tenor of AEP’s Liquid Portion of Risk Management Contracts
As
of June 30, 2008
Commodity
|
|
Transaction
Class
|
|
Market/Region
|
|
Tenor
|
|
|
|
|
|
|
(in
Months)
|
Natural
Gas
|
|
Futures
|
|
NYMEX
/ Henry Hub
|
|
60
|
|
|
Physical
Forwards
|
|
Gulf
Coast, Texas
|
|
30
|
|
|
Swaps
|
|
Gas
East, Mid-Continent, Gulf Coast, Texas
|
|
30
|
|
|
Exchange
Option Volatility
|
|
NYMEX
/ Henry Hub
|
|
12
|
Power
|
|
Futures
|
|
Power
East – PJM
|
|
36
|
|
|
Physical
Forwards
|
|
Power
East – Cinergy
|
|
54
|
|
|
Physical
Forwards
|
|
Power
East – PJM West
|
|
54
|
|
|
Physical
Forwards
|
|
Power
East – AEP Dayton (PJM)
|
|
54
|
|
|
Physical
Forwards
|
|
Power
East – ERCOT
|
|
42
|
|
|
Physical
Forwards
|
|
Power
East – Entergy
|
|
30
|
|
|
Physical
Forwards
|
|
Power
West – PV, NP15, SP15, MidC, Mead
|
|
42
|
|
|
Peak
Power Volatility (Options)
|
Cinergy,
PJM
|
|
12
|
Emissions
|
|
Credits
|
|
SO2,
NOx
|
|
42
|
Coal
|
|
Physical
Forwards
|
|
PRB,
NYMEX, CSX
|
|
42
|
Cash Flow Hedges Included in
Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed
Consolidated Balance Sheets
We are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may
use various commodity derivative instruments designated in qualifying cash flow
hedge strategies to mitigate the impact of these fluctuations on the future cash
flows. We do not hedge all commodity price risk.
We use
interest rate derivative transactions to manage interest rate risk related to
existing variable rate debt and to manage interest rate exposure on anticipated
borrowings of fixed-rate debt. We do not hedge all interest rate
exposure.
We use
foreign currency derivatives to lock in prices on certain forecasted
transactions denominated in foreign currencies where deemed necessary, and
designate qualifying instruments as cash flow hedges. We do not hedge
all foreign currency exposure.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on our Condensed Consolidated Balance Sheets and the reasons
for changes in cash flow hedges from December 31, 2007 to June 30,
2008. The following table also indicates what portion of designated,
effective hedges are expected to be reclassified into net income in the next 12
months. Only contracts designated as cash flow hedges are recorded in
AOCI. Therefore, economic hedge contracts which are not designated as
effective cash flow hedges are marked-to-market and are included in the previous
risk management tables.
Total
Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow
Hedges
Six
Months Ended June 30, 2008
(in
millions)
|
|
Power
|
|
|
Interest
Rate
and
Foreign
Currency
|
|
|
Total
|
|
Beginning
Balance in AOCI, December 31, 2007
|
|
$ |
(1 |
) |
|
$ |
(25 |
) |
|
$ |
(26 |
) |
Changes
in Fair Value
|
|
|
(32
|
) |
|
|
(4
|
) |
|
|
(36
|
) |
Reclassifications
from AOCI for Cash Flow Hedges
Settled
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
Ending
Balance in AOCI, June 30, 2008
|
|
$ |
(32 |
) |
|
$ |
(28 |
) |
|
$ |
(60 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
After
Tax Portion Expected to be Reclassified to
Earnings During Next 12 Months
|
|
$ |
(38 |
) |
|
$ |
(6 |
) |
|
$ |
(44 |
) |
Credit
Risk
We limit
credit risk in our wholesale marketing and trading activities by assessing
creditworthiness of potential counterparties before entering into transactions
with them and continuing to evaluate their creditworthiness after transactions
have been initiated. We use Moody’s Investors Service, Standard &
Poor’s and qualitative and quantitative data to assess the financial health of
counterparties on an ongoing basis. If an external rating is not
available, an internal rating is generated utilizing a quantitative tool
developed by Moody’s to estimate probability of default that corresponds to an
implied external agency credit rating. Based on our analysis, we set
appropriate risk parameters for each internally-graded
counterparty. We may also require cash deposits, letters of credit
and parental/affiliate guarantees as security from counterparties in order to
mitigate credit risk.
We have
risk management contracts with numerous counterparties. Since open
risk management contracts are valued based on changes in market prices of the
related commodities, our exposures change daily. At June 30, 2008,
our credit exposure net of collateral to sub investment grade counterparties was
approximately 20.1%, expressed in terms of net MTM assets, net receivables and
the net open positions for contracts not subject to MTM (representing economic
risk even though there may not be risk of accounting loss). The
increase from 5.4% at December 31, 2007 is primarily related to an increase in
exposure with coal counterparties due to escalating coal
prices. Approximately 55% of our credit exposure net of collateral to
sub investment grade counterparties is short-term exposure of less than one
year. As of June 30, 2008, the following table approximates our
counterparty credit quality and exposure based on netting across commodities,
instruments and legal entities where applicable (in millions, except number of
counterparties):
Counterparty
Credit Quality
|
|
Exposure
Before Credit Collateral
|
|
|
Credit
Collateral
|
|
|
Net
Exposure
|
|
|
Number
of Counterparties >10% of
Net
Exposure
|
|
|
Net
Exposure
of
Counterparties >10%
|
|
Investment
Grade
|
|
$ |
873 |
|
|
$ |
184 |
|
|
$ |
689 |
|
|
|
2 |
|
|
$ |
181 |
|
Split
Rating
|
|
|
36 |
|
|
|
7 |
|
|
|
29 |
|
|
|
4 |
|
|
|
27 |
|
Noninvestment
Grade
|
|
|
185 |
|
|
|
49 |
|
|
|
136 |
|
|
|
1 |
|
|
|
112 |
|
No
External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internal
Investment Grade
|
|
|
89 |
|
|
|
- |
|
|
|
89 |
|
|
|
2 |
|
|
|
63 |
|
Internal
Noninvestment Grade
|
|
|
68 |
|
|
|
1 |
|
|
|
67 |
|
|
|
2 |
|
|
|
61 |
|
Total
as of June 30, 2008
|
|
$ |
1,251 |
|
|
$ |
241 |
|
|
$ |
1,010 |
|
|
|
11 |
|
|
$ |
444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
as of December 31, 2007
|
|
$ |
673 |
|
|
$ |
42 |
|
|
$ |
631 |
|
|
|
6 |
|
|
$ |
74 |
|
Generation Plant Hedging
Information
This
table provides information on operating measures regarding the proportion of
output of our generation facilities (based on economic availability projections)
economically hedged, including both contracts designated as cash flow hedges
under SFAS 133 and contracts not designated as cash flow hedges. This
information is forward-looking and provided on a prospective basis through
December 31, 2010. This table is a point-in-time estimate, subject to
changes in market conditions and our decisions on how to manage operations and
risk. “Estimated Plant Output Hedged” represents the portion of MWHs
of future generation/production, taking into consideration scheduled plant
outages, for which we have sales commitments or estimated requirement
obligations to customers.
Generation
Plant Hedging Information
Estimated
Next Three Years
As
of June 30, 2008
|
Remainder
|
|
|
|
|
|
2008
|
|
2009
|
|
2010
|
Estimated
Plant Output Hedged
|
90%
|
|
89%
|
|
91%
|
VaR Associated with Risk
Management Contracts
We use a
risk measurement model, which calculates Value at Risk (VaR) to measure our
commodity price risk in the risk management portfolio. The VaR is based on the
variance-covariance method using historical prices to estimate volatilities and
correlations and assumes a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at June 30, 2008, 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 end, high, average and low market risk as measured by
VaR for the periods indicated:
VaR
Model
Six
Months Ended
June
30, 2008
|
|
|
|
|
Twelve
Months Ended
December
31, 2007
|
(in
millions)
|
|
|
|
|
(in
millions)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$2
|
|
$2
|
|
$1
|
|
$1
|
|
|
|
|
$1
|
|
$6
|
|
$2
|
|
$1
|
We
back-test our VaR results against performance due to actual price
moves. Based on the assumed 95% confidence interval, the performance
due to actual price moves would be expected to exceed the VaR at least once
every 20 trading days. Our backtesting results show that our actual
performance exceeded VaR far fewer than once every 20 trading
days. As a result, we believe our VaR calculation is
conservative.
As our
VaR calculation captures recent price moves, we also perform regular stress
testing of the portfolio to understand our exposure to extreme price
moves. We employ a historically-based method whereby the current
portfolio is subjected to actual, observed price moves from the last three years
in order to ascertain which historical price moves translates into the largest
potential mark-to-market loss. We then research the underlying
positions, price moves and market events that created the most significant
exposure.
Interest
Rate Risk
We
utilize an Earnings at Risk (EaR) model to measure interest rate market risk
exposure. EaR statistically quantifies the extent to which AEP’s interest
expense could vary over the next twelve months and gives a probabilistic
estimate of different levels of interest expense. The resulting EaR
is interpreted as the dollar amount by which actual interest expense for the
next twelve months could exceed expected interest expense with a one-in-twenty
chance of occurrence. The primary drivers of EaR are from the
existing floating rate debt (including short-term debt) as well as long-term
debt issuances in the next twelve months. The estimated EaR on our
debt portfolio was $32 million.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Six Months Ended June 30, 2008 and 2007
(in
millions, except per-share amounts and shares outstanding)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
$ |
3,200 |
|
|
$ |
2,818 |
|
|
$ |
6,210 |
|
|
$ |
5,704 |
|
Other
|
|
|
346 |
|
|
|
328 |
|
|
|
803 |
|
|
|
611 |
|
TOTAL
|
|
|
3,546 |
|
|
|
3,146 |
|
|
|
7,013 |
|
|
|
6,315 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
1,053 |
|
|
|
868 |
|
|
|
2,033 |
|
|
|
1,754 |
|
Purchased
Energy for Resale
|
|
|
366 |
|
|
|
291 |
|
|
|
629 |
|
|
|
537 |
|
Other
Operation and Maintenance
|
|
|
982 |
|
|
|
881 |
|
|
|
1,860 |
|
|
|
1,819 |
|
Gain
on Disposition of Assets, Net
|
|
|
(5
|
) |
|
|
(3
|
) |
|
|
(8
|
) |
|
|
(26
|
) |
Asset
Impairments and Other Related Items
|
|
|
- |
|
|
|
- |
|
|
|
(255
|
) |
|
|
- |
|
Depreciation
and Amortization
|
|
|
373 |
|
|
|
372 |
|
|
|
736 |
|
|
|
763 |
|
Taxes
Other Than Income Taxes
|
|
|
191 |
|
|
|
188 |
|
|
|
389 |
|
|
|
374 |
|
TOTAL
|
|
|
2,960 |
|
|
|
2,597 |
|
|
|
5,384 |
|
|
|
5,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
586 |
|
|
|
549 |
|
|
|
1,629 |
|
|
|
1,094 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
and Investment Income
|
|
|
15 |
|
|
|
8 |
|
|
|
31 |
|
|
|
31 |
|
Carrying
Costs Income
|
|
|
26 |
|
|
|
16 |
|
|
|
43 |
|
|
|
24 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
11 |
|
|
|
6 |
|
|
|
21 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST
AND OTHER CHARGES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
|
234 |
|
|
|
213 |
|
|
|
454 |
|
|
|
399 |
|
Preferred
Stock Dividend Requirements of Subsidiaries
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
TOTAL
|
|
|
234 |
|
|
|
213 |
|
|
|
455 |
|
|
|
400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE, MINORITY
INTEREST
EXPENSE AND EQUITY EARNINGS (LOSS)
|
|
|
404 |
|
|
|
366 |
|
|
|
1,269 |
|
|
|
763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
123 |
|
|
|
108 |
|
|
|
416 |
|
|
|
238 |
|
Minority
Interest Expense
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
2 |
|
Equity
Earnings of Unconsolidated Subsidiaries
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS AND EXTRAORDINARY
LOSS
|
|
|
280 |
|
|
|
257 |
|
|
|
853 |
|
|
|
528 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DISCONTINUED
OPERATIONS, NET OF TAX
|
|
|
1 |
|
|
|
2 |
|
|
|
1 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE EXTRAORDINARY LOSS
|
|
|
281 |
|
|
|
259 |
|
|
|
854 |
|
|
|
530 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXTRAORDINARY
LOSS, NET OF TAX
|
|
|
- |
|
|
|
(79
|
) |
|
|
- |
|
|
|
(79
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
281 |
|
|
$ |
180 |
|
|
$ |
854 |
|
|
$ |
451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
|
|
401,513,958 |
|
|
|
398,679,242 |
|
|
|
401,155,975 |
|
|
|
398,000,712 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$ |
0.70 |
|
|
$ |
0.64 |
|
|
$ |
2.13 |
|
|
$ |
1.33 |
|
Discontinued
Operations, Net of Tax
|
|
|
- |
|
|
|
0.01 |
|
|
|
- |
|
|
|
- |
|
Income
Before Extraordinary Loss
|
|
|
0.70 |
|
|
|
0.65 |
|
|
|
2.13 |
|
|
|
1.33 |
|
Extraordinary
Loss, Net of Tax
|
|
|
- |
|
|
|
(0.20
|
) |
|
|
- |
|
|
|
(0.20
|
) |
TOTAL
BASIC EARNINGS PER SHARE
|
|
$ |
0.70 |
|
|
$ |
0.45 |
|
|
$ |
2.13 |
|
|
$ |
1.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING
|
|
|
402,785,942 |
|
|
|
399,868,900 |
|
|
|
402,429,019 |
|
|
|
399,214,277 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$ |
0.70 |
|
|
$ |
0.64 |
|
|
$ |
2.12 |
|
|
$ |
1.32 |
|
Discontinued
Operations, Net of Tax
|
|
|
- |
|
|
|
0.01 |
|
|
|
- |
|
|
|
0.01 |
|
Income
Before Extraordinary Loss
|
|
|
0.70 |
|
|
|
0.65 |
|
|
|
2.12 |
|
|
|
1.33 |
|
Extraordinary
Loss, Net of Tax
|
|
|
- |
|
|
|
(0.20
|
) |
|
|
- |
|
|
|
(0.20
|
) |
TOTAL
DILUTED EARNINGS PER SHARE
|
|
$ |
0.70 |
|
|
$ |
0.45 |
|
|
$ |
2.12 |
|
|
$ |
1.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
DIVIDENDS PAID PER SHARE
|
|
$ |
0.41 |
|
|
$ |
0.39 |
|
|
$ |
0.82 |
|
|
$ |
0.78 |
|
See
Condensed Notes to Condensed Consolidated Financial Statements.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2008 and December 31, 2007
(in
millions)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
218 |
|
|
$ |
178 |
|
Other
Temporary Investments
|
|
|
243 |
|
|
|
365 |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
795 |
|
|
|
730 |
|
Accrued Unbilled Revenues
|
|
|
400 |
|
|
|
379 |
|
Miscellaneous
|
|
|
85 |
|
|
|
60 |
|
Allowance for Uncollectible Accounts
|
|
|
(45
|
) |
|
|
(52 |
) |
Total Accounts Receivable
|
|
|
1,235 |
|
|
|
1,117 |
|
Fuel,
Materials and Supplies
|
|
|
1,049 |
|
|
|
967 |
|
Risk
Management Assets
|
|
|
891 |
|
|
|
271 |
|
Margin
Deposits
|
|
|
63 |
|
|
|
47 |
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
202 |
|
|
|
11 |
|
Prepayments
and Other
|
|
|
105 |
|
|
|
70 |
|
TOTAL
|
|
|
4,006 |
|
|
|
3,026 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
20,675 |
|
|
|
20,233 |
|
Transmission
|
|
|
7,651 |
|
|
|
7,392 |
|
Distribution
|
|
|
12,389 |
|
|
|
12,056 |
|
Other
(including coal mining and nuclear fuel)
|
|
|
3,479 |
|
|
|
3,445 |
|
Construction
Work in Progress
|
|
|
3,257 |
|
|
|
3,019 |
|
Total
|
|
|
47,451 |
|
|
|
46,145 |
|
Accumulated
Depreciation and Amortization
|
|
|
16,447 |
|
|
|
16,275 |
|
TOTAL
- NET
|
|
|
31,004 |
|
|
|
29,870 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
2,234 |
|
|
|
2,199 |
|
Securitized
Transition Assets
|
|
|
2,121 |
|
|
|
2,108 |
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,362 |
|
|
|
1,347 |
|
Goodwill
|
|
|
76 |
|
|
|
76 |
|
Long-term
Risk Management Assets
|
|
|
489 |
|
|
|
319 |
|
Employee
Benefits and Pension Assets
|
|
|
481 |
|
|
|
486 |
|
Deferred
Charges and Other
|
|
|
923 |
|
|
|
888 |
|
TOTAL
|
|
|
7,686 |
|
|
|
7,423 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
42,696 |
|
|
$ |
40,319 |
|
See
Condensed Notes to Condensed Consolidated Financial Statements.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
June
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
millions)
|
|
Accounts
Payable
|
|
$ |
1,414 |
|
|
$ |
1,324 |
|
Short-term
Debt
|
|
|
705 |
|
|
|
660 |
|
Long-term
Debt Due Within One Year
|
|
|
569 |
|
|
|
792 |
|
Risk
Management Liabilities
|
|
|
991 |
|
|
|
240 |
|
Customer
Deposits
|
|
|
319 |
|
|
|
301 |
|
Accrued
Taxes
|
|
|
555 |
|
|
|
601 |
|
Accrued
Interest
|
|
|
256 |
|
|
|
235 |
|
Other
|
|
|
817 |
|
|
|
1,008 |
|
TOTAL
|
|
|
5,626 |
|
|
|
5,161 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt
|
|
|
15,184 |
|
|
|
14,202 |
|
Long-term
Risk Management Liabilities
|
|
|
348 |
|
|
|
188 |
|
Deferred
Income Taxes
|
|
|
5,021 |
|
|
|
4,730 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
2,895 |
|
|
|
2,952 |
|
Asset
Retirement Obligations
|
|
|
1,081 |
|
|
|
1,075 |
|
Employee
Benefits and Pension Obligations
|
|
|
677 |
|
|
|
712 |
|
Deferred
Gain on Sale and Leaseback – Rockport Plant Unit 2
|
|
|
134 |
|
|
|
139 |
|
Deferred
Credits and Other
|
|
|
1,038 |
|
|
|
1,020 |
|
TOTAL
|
|
|
26,378 |
|
|
|
25,018 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
32,004 |
|
|
|
30,179 |
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
61 |
|
|
|
61 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
Common
Stock – $6.50 Par Value Per Share:
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
Shares
Authorized
|
|
|
600,000,000 |
|
|
|
600,000,000 |
|
|
|
|
|
|
|
|
|
Shares
Issued
|
|
|
423,634,828 |
|
|
|
421,926,696 |
|
|
|
|
|
|
|
|
|
(21,499,992
shares were held in treasury at June 30, 2008 and December 31, 2007,
respectively)
|
|
|
2,754 |
|
|
|
2,743 |
|
Paid-in
Capital
|
|
|
4,415 |
|
|
|
4,352 |
|
Retained
Earnings
|
|
|
3,651 |
|
|
|
3,138 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(189
|
) |
|
|
(154
|
) |
TOTAL
|
|
|
10,631 |
|
|
|
10,079 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
42,696 |
|
|
$ |
40,319 |
|
See
Condensed Notes to Condensed Consolidated Financial Statements.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Six Months Ended June 30, 2008 and 2007
(in
millions)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
854 |
|
|
$ |
451 |
|
Less: Discontinued
Operations, Net of Tax
|
|
|
(1
|
) |
|
|
(2 |
) |
Income
Before Discontinued Operations
|
|
|
853 |
|
|
|
449 |
|
Adjustments
to Reconcile Net Income to Net Cash Flow from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
736 |
|
|
|
763 |
|
Deferred
Income Taxes
|
|
|
316 |
|
|
|
(24 |
) |
Deferred
Investment Tax Credits
|
|
|
(10
|
) |
|
|
(13 |
) |
Extraordinary
Loss, Net of Tax
|
|
|
- |
|
|
|
79 |
|
Regulatory
Provision
|
|
|
- |
|
|
|
105 |
|
Carrying
Costs Income
|
|
|
(43
|
) |
|
|
(24 |
) |
Allowance
for Equity Funds Used During Construction
|
|
|
(21
|
) |
|
|
(14 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
66 |
|
|
|
22 |
|
Amortization
of Nuclear Fuel
|
|
|
45 |
|
|
|
33 |
|
Deferred
Property Taxes
|
|
|
36 |
|
|
|
24 |
|
Fuel
Over/Under-Recovery, Net
|
|
|
(245
|
) |
|
|
(101 |
) |
Gain
on Sales of Assets and Equity Investments, Net
|
|
|
(8
|
) |
|
|
(26 |
) |
Change
in Other Noncurrent Assets
|
|
|
(195
|
) |
|
|
(39 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
(80
|
) |
|
|
23 |
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts Receivable, Net
|
|
|
(123
|
) |
|
|
(81 |
) |
Fuel, Materials and Supplies
|
|
|
(82
|
) |
|
|
(90 |
) |
Margin Deposits
|
|
|
(16
|
) |
|
|
32 |
|
Accounts Payable
|
|
|
188 |
|
|
|
(58 |
) |
Customer Deposits
|
|
|
18 |
|
|
|
24 |
|
Accrued Taxes, Net
|
|
|
(61
|
) |
|
|
49 |
|
Accrued Interest
|
|
|
16 |
|
|
|
67 |
|
Other Current Assets
|
|
|
(13
|
) |
|
|
(21 |
) |
Other Current Liabilities
|
|
|
(180
|
) |
|
|
(210 |
) |
Net
Cash Flows From Operating Activities
|
|
|
1,197 |
|
|
|
969 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(1,608
|
) |
|
|
(1,823 |
) |
Change
in Other Temporary Investments, Net
|
|
|
48 |
|
|
|
(129 |
) |
Purchases
of Investment Securities
|
|
|
(635
|
) |
|
|
(6,827 |
) |
Sales
of Investment Securities
|
|
|
666 |
|
|
|
7,035 |
|
Acquisition
of Nuclear Fuel
|
|
|
(99
|
) |
|
|
(30 |
) |
Acquisition
of Darby and Lawrenceburg Plants
|
|
|
- |
|
|
|
(427 |
) |
Acquisition
of Other Assets
|
|
|
(81
|
) |
|
|
- |
|
Proceeds
from Sales of Assets
|
|
|
69 |
|
|
|
74 |
|
Other
|
|
|
(5
|
) |
|
|
- |
|
Net
Cash Flows Used For Investing Activities
|
|
|
(1,645
|
) |
|
|
(2,127 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Common Stock
|
|
|
72 |
|
|
|
90 |
|
Change
in Short-term Debt, Net
|
|
|
45 |
|
|
|
420 |
|
Issuance
of Long-term Debt
|
|
|
2,204 |
|
|
|
1,064 |
|
Retirement
of Long-term Debt
|
|
|
(1,472
|
) |
|
|
(190 |
) |
Dividends
Paid on Common Stock
|
|
|
(330
|
) |
|
|
(311 |
) |
Other
|
|
|
(31
|
) |
|
|
(44 |
) |
Net
Cash Flows From Financing Activities
|
|
|
488 |
|
|
|
1,029 |
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
40 |
|
|
|
(129 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
178 |
|
|
|
301 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
218 |
|
|
$ |
172 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
412 |
|
|
$ |
304 |
|
Net
Cash Paid for Income Taxes
|
|
|
131 |
|
|
|
128 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
35 |
|
|
|
23 |
|
Noncash
Acquisition of Land/Mineral Rights
|
|
|
42 |
|
|
|
- |
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
328 |
|
|
|
295 |
|
Acquisition
of Nuclear Fuel in Accounts Payable at June 30,
|
|
|
- |
|
|
|
31 |
|
Noncash
Assumption of Liabilities Related to Acquisitions
|
|
|
- |
|
|
|
5 |
|
See
Condensed Notes to Condensed Consolidated Financial
Statements.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’ EQUITY
AND
COMPREHENSIVE
INCOME (LOSS)
For
the Six Months Ended June 30, 2008 and 2007
(in
millions)
(Unaudited)
|
|
Common
Stock
|
|
|
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
|
|
|
Shares
|
|
Amount
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
|
Total
|
|
DECEMBER
31, 2006
|
|
|
418
|
|
$
|
2,718
|
|
$
|
4,221
|
|
$
|
2,696
|
|
$
|
(223
|
)
|
$
|
9,412
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
|
(17
|
)
|
|
|
|
|
(17
|
)
|
Issuance
of Common Stock
|
|
|
3
|
|
|
16
|
|
|
74
|
|
|
|
|
|
|
|
|
90
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
(311
|
)
|
|
|
|
|
(311
|
)
|
Other
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
10
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
15
|
|
|
Securities
Available for Sale, Net of Tax of $3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
(5
|
)
|
|
SFAS
158 Costs Established as a Regulatory Asset for the
Reapplication of SFAS 71, Net of Tax of $6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
11
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
451
|
|
|
|
|
|
451
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
472
|
|
JUNE
30, 2007
|
|
|
421
|
|
$
|
2,734
|
|
$
|
4,305
|
|
$
|
2,819
|
|
$
|
(202
|
)
|
$
|
9,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2007
|
|
|
422
|
|
$
|
2,743
|
|
$
|
4,352
|
|
$
|
3,138
|
|
$
|
(154
|
)
|
$
|
10,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EITF
06-10 Adoption, Net of Tax of $6
|
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
|
|
|
|
(10
|
)
|
SFAS
157 Adoption, Net of Tax of $0
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
(1
|
)
|
Issuance
of Common Stock
|
|
|
2
|
|
|
11
|
|
|
61
|
|
|
|
|
|
|
|
|
72
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
(330
|
)
|
|
|
|
|
(330
|
)
|
Other
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
2
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,812
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(34
|
)
|
|
(34
|
)
|
|
Securities
Available for Sale, Net of Tax of $4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7
|
)
|
|
(7
|
)
|
|
Amortization
of Pension and OPEB Deferred Costs,
Net
of Tax of $3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
6
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
854
|
|
|
|
|
|
854
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
819
|
|
JUNE
30, 2008
|
|
|
424
|
|
$
|
2,754
|
|
$
|
4,415
|
|
$
|
3,651
|
|
$
|
(189
|
)
|
$
|
10,631
|
|
See Condensed Notes to Condensed Consolidated Financial
Statements.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX
TO CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
1.
|
Significant
Accounting Matters
|
2.
|
New
Accounting Pronouncements and Extraordinary Item
|
3.
|
Rate
Matters
|
4.
|
Commitments,
Guarantees and Contingencies
|
5.
|
Acquisitions,
Dispositions and Discontinued Operations
|
6.
|
Benefit
Plans
|
7.
|
Business
Segments
|
8.
|
Income
Taxes
|
9.
|
Financing
Activities
|
10.
|
Subsequent
Event
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
|
1.
|
SIGNIFICANT ACCOUNTING
MATTERS
|
General
The
accompanying unaudited condensed consolidated financial statements and footnotes
were prepared in accordance with GAAP for interim financial information and with
the instructions to Form 10-Q and Article 10 of Regulation S-X of the
SEC. Accordingly, they do not include all of the information and
footnotes required by GAAP for complete annual financial
statements.
In the
opinion of management, the unaudited interim financial statements reflect all
normal and recurring accruals and adjustments necessary for a fair presentation
of our results of operations, financial position and cash flows for the interim
periods. The results of operations for the three and six months ended
June 30, 2008 are not necessarily indicative of results that may be expected for
the year ending December 31, 2008. The accompanying condensed
consolidated financial statements are unaudited and should be read in
conjunction with the audited 2007 consolidated financial statements and notes
thereto, which are included in our Annual Report on Form 10-K for the year ended
December 31, 2007 as filed with the SEC on February 28, 2008.
Earnings
Per Share
The
following table presents our basic and diluted EPS calculations included on our
Condensed Consolidated Statements of Income:
|
|
Three
Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
|
$/share
|
|
|
|
|
|
$/share
|
|
Earnings
Applicable to Common Stock
|
|
$ |
281 |
|
|
|
|
|
$ |
180 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Basic Shares Outstanding
|
|
|
401.5 |
|
|
$ |
0.70 |
|
|
|
398.7 |
|
|
$ |
0.45 |
|
Average
Dilutive Effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
0.9 |
|
|
|
- |
|
|
|
0.6 |
|
|
|
- |
|
Stock
Options
|
|
|
0.2 |
|
|
|
- |
|
|
|
0.4 |
|
|
|
- |
|
Restricted
Stock Units
|
|
|
0.1 |
|
|
|
- |
|
|
|
0.1 |
|
|
|
- |
|
Restricted
Shares
|
|
|
0.1 |
|
|
|
- |
|
|
|
0.1 |
|
|
|
- |
|
Average
Number of Diluted Shares Outstanding
|
|
|
402.8 |
|
|
$ |
0.70 |
|
|
|
399.9 |
|
|
$ |
0.45 |
|
|
|
Six
Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
|
$/share
|
|
|
|
|
|
$/share
|
|
Earnings
Applicable to Common Stock
|
|
$ |
854 |
|
|
|
|
|
$ |
451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Basic Shares Outstanding
|
|
|
401.2 |
|
|
$ |
2.13 |
|
|
|
398.0 |
|
|
$ |
1.13 |
|
Average
Dilutive Effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
0.8 |
|
|
|
(0.01
|
) |
|
|
0.6 |
|
|
|
- |
|
Stock
Options
|
|
|
0.2 |
|
|
|
- |
|
|
|
0.4 |
|
|
|
- |
|
Restricted
Stock Units
|
|
|
0.1 |
|
|
|
- |
|
|
|
0.1 |
|
|
|
- |
|
Restricted
Shares
|
|
|
0.1 |
|
|
|
- |
|
|
|
0.1 |
|
|
|
- |
|
Average
Number of Diluted Shares Outstanding
|
|
|
402.4 |
|
|
$ |
2.12 |
|
|
|
399.2 |
|
|
$ |
1.13 |
|
The
assumed conversion of our share-based compensation does not affect net earnings
for purposes of calculating diluted earnings per share.
Options
to purchase 146,900 and 83,450 shares of common stock were outstanding at June
30, 2008 and 2007, respectively, but were not included in the computation of
diluted earnings per share because the options’ exercise prices were greater
than the quarter-end market price of the common shares and, therefore, the
effect would be antidilutive.
Supplementary
Information
|
|
Three
Months Ended
June
30,
|
|
|
Six
Months Ended
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Related
Party Transactions
|
|
(in
millions)
|
|
|
(in
millions)
|
|
AEP
Consolidated Revenues – Utility Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
Pool Purchases – Ohio Valley Electric
Corporation
(43.47% owned)
|
|
$ |
(13 |
) |
|
$ |
(4 |
) |
|
$ |
(25 |
) |
|
$ |
(4 |
) |
AEP
Consolidated Revenues – Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
Valley Electric Corporation – Barging and
Other
Transportation Services (43.47% Owned)
|
|
|
5 |
|
|
|
8 |
|
|
|
14 |
|
|
|
17 |
|
AEP
Consolidated Expenses – Purchased Energy for Resale:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
Valley Electric Corporation (43.47% Owned)
|
|
|
61 |
|
|
|
56 |
|
|
|
124 |
|
|
|
105 |
|
Sweeny
Cogeneration Limited Partnership (a)
|
|
|
- |
|
|
|
29 |
|
|
|
- |
|
|
|
59 |
|
(a)
|
In
October 2007, we sold our 50% ownership in the Sweeny Cogeneration Limited
Partnership.
|
Reclassifications
Certain
prior period financial statement items have been reclassified to conform to
current period presentation. See “FSP FIN 39-1 “Amendment of FASB
Interpretation No. 39” (FIN 39-1)” section of Note 2 for discussion of changes
in netting certain balance sheet amounts. These reclassifications had
no impact on our previously reported results of operations or changes in
shareholders’ equity.
2.
|
NEW ACCOUNTING
PRONOUNCEMENTS AND EXTRAORDINARY
ITEM
|
NEW
ACCOUNTING PRONOUNCEMENTS
Upon
issuance of final pronouncements, we thoroughly review the new accounting
literature to determine the relevance, if any, to our business. The
following represents a summary of new pronouncements issued or implemented in
2008 and standards issued but not implemented that we have determined relate to
our operations.
SFAS
141 (revised 2007) “Business Combinations” (SFAS 141R)
In
December 2007, the FASB issued SFAS 141R, improving financial reporting about
business combinations and their effects. It establishes how the
acquiring entity recognizes and measures the identifiable assets acquired,
liabilities assumed, goodwill acquired, any gain on bargain purchases and any
noncontrolling interest in the acquired entity. SFAS 141R no longer
allows acquisition-related costs to be included in the cost of the business
combination, but rather expensed in the periods they are incurred, with the
exception of the costs to issue debt or equity securities which shall be
recognized in accordance with other applicable GAAP. SFAS 141R
requires disclosure of information for a business combination that occurs during
the accounting period or prior to the issuance of the financial statements for
the accounting period.
SFAS 141R
is effective prospectively for business combinations with an acquisition date on
or after the beginning of the first annual reporting period after December 15,
2008. Early adoption is prohibited. We will adopt SFAS
141R effective January 1, 2009 and apply it to any business combinations on or
after that date.
SFAS
157 “Fair Value Measurements” (SFAS 157)
In
September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair
value measurement of assets and liabilities and instruments measured at fair
value that are classified in shareholders’ equity. The statement
defines fair value, establishes a fair value measurement framework and expands
fair value disclosures. It emphasizes that fair value is market-based
with the highest measurement hierarchy level being market prices in active
markets. The standard requires fair value measurements be disclosed
by hierarchy level, an entity includes its own credit standing in the
measurement of its liabilities and modifies the transaction price
presumption. The standard also nullifies the consensus reached in
EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held
for Trading Purposes and Contracts Involved in Energy Trading and Risk
Management Activities” (EITF 02-3) that prohibited the recognition of trading
gains or losses at the inception of a derivative contract, unless the fair value
of such derivative is supported by observable market data.
In
February 2008, the FASB issued FSP SFAS 157-1 “Application of FASB Statement No.
157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address
Fair Value Measurements for Purposes of Lease Classification or Measurement
under Statement 13” (SFAS 157-1) which amends SFAS 157 to exclude SFAS 13
“Accounting for Leases” (SFAS 13) and other accounting pronouncements that
address fair value measurements for purposes of lease classification or
measurement under SFAS 13.
In
February 2008, the FASB issued FSP SFAS 157-2 “Effective Date of FASB Statement
No. 157” (SFAS 157-2) which delays the effective date of SFAS 157 to fiscal
years beginning after November 15, 2008 for all nonfinancial assets and
nonfinancial liabilities, except those that are recognized or disclosed at fair
value in the financial statements on a recurring basis (at least
annually).
We
partially adopted SFAS 157 effective January 1, 2008. We will fully
adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP SFAS
157-2. The provisions of SFAS 157 are applied prospectively, except
for a) changes in fair value measurements of existing derivative financial
instruments measured initially using the transaction price under EITF 02-3, b)
existing hybrid financial instruments measured initially at fair value using the
transaction price and c) blockage discount factors. Although the
statement is applied prospectively upon adoption, in accordance with the
provisions of SFAS 157 related to EITF 02-3, we recorded an immaterial
transition adjustment to beginning retained earnings. The impact of
considering our own credit risk when measuring the fair value of liabilities,
including derivatives, had an immaterial impact on fair value measurements upon
adoption.
In
accordance with SFAS 157, assets and liabilities are classified based on the
inputs utilized in the fair value measurement. SFAS 157 provides
definitions for two types of inputs: observable and
unobservable. Observable inputs are valuation inputs that reflect the
assumptions market participants would use in pricing the asset or liability
developed based on market data obtained from sources independent of the
reporting entity. Unobservable inputs are valuation inputs that
reflect the reporting entity’s own assumptions about the assumptions market
participants would use in pricing the asset or liability developed based on the
best information in the circumstances.
As
defined in SFAS 157, fair value is the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date (exit price). SFAS 157 establishes a fair
value hierarchy that prioritizes the inputs used to measure fair value. The
hierarchy gives the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (level 1 measurement) and the lowest
priority to unobservable inputs (level 3 measurement).
Level 1
inputs are quoted prices (unadjusted) in active markets for identical assets or
liabilities that the reporting entity has the ability to access at the
measurement date. Level 1 inputs primarily consist of exchange traded
contracts, listed equities and U.S. government treasury securities that exhibit
sufficient frequency and volume to provide pricing information on an ongoing
basis.
Level 2
inputs are inputs other than quoted prices included within level 1 that are
observable for the asset or liability, either directly or
indirectly. If the asset or liability has a specified (contractual)
term, a level 2 input must be observable for substantially the full term of the
asset or liability. Level 2 inputs primarily consist of OTC broker
quotes in moderately active or less active markets, exchange traded contracts
where there was not sufficient market activity to warrant inclusion in level 1,
OTC broker quotes that are corroborated by the same or similar transactions that
have occurred in the market and certain non-exchange-traded debt
securities.
Level 3
inputs are unobservable inputs for the asset or
liability. Unobservable inputs shall be used to measure fair value to
the extent that the observable inputs are not available, thereby allowing for
situations in which there is little, if any, market activity for the asset or
liability at the measurement date. Level 3 inputs primarily consist
of unobservable market data or are valued based on models and/or
assumptions.
Risk
Management Contracts include exchange traded, OTC and bilaterally executed
derivative contracts. Exchange traded derivatives, namely futures
contracts, are generally fair valued based on unadjusted quoted prices in active
markets and are classified within level 1. Other actively traded
derivatives are valued using broker or dealer quotations, similar observable
market transactions in either the listed or OTC markets, or through pricing
models where significant valuation inputs are directly or indirectly
observable in active markets. Derivative instruments, primarily
swaps, forwards, and options that meet these characteristics are classified
within level 2. Bilaterally executed agreements are derivative
contracts entered into directly with third parties, and at times these
instruments may be complex structured transactions that are tailored to meet the
specific customer’s energy requirements. Structured transactions
utilize pricing models that are widely accepted in the energy industry to
measure fair value. Generally, we use a consistent modeling approach
to value similar instruments. Valuation models utilize various inputs
that include quoted prices for similar assets or liabilities in active markets,
quoted prices for identical or similar assets or liabilities in markets that are
not active, market corroborated inputs (i.e. inputs derived principally from, or
correlated to, observable market data), and other observable inputs for the
asset or liability. Where observable inputs are available for
substantially the full term of the asset or liability, the instrument is
categorized in level 2. Certain OTC and bilaterally executed
derivative instruments are executed in less active markets with a lower
availability of pricing information. In addition, long-dated and
illiquid complex or structured transactions or FTRs can introduce the need for
internally developed modeling inputs based upon extrapolations and assumptions
of observable market data to estimate fair value. When such inputs
have a significant impact on the measurement of fair value, the instrument is
categorized in level 3. In certain instances, the fair values of the
transactions that use internally developed model inputs, classified as level 3
are offset partially or in full, by transactions included in level 2 where
observable market data exists for the offsetting transaction.
The
following table sets forth by level within the fair value hierarchy our
financial assets and liabilities that were accounted for at fair value on a
recurring basis as of June 30, 2008. As required by SFAS 157,
financial assets and liabilities are classified in their entirety based on the
lowest level of input that is significant to the fair value measurement. Our
assessment of the significance of a particular input to the fair value
measurement requires judgment, and may affect the valuation of fair value assets
and liabilities and their placement within the fair value hierarchy
levels.
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of June 30,
2008
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents (a)
|
|
$ |
167 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
51 |
|
|
$ |
218 |
|
Other
Temporary Investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents (b)
|
|
$ |
188 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
39 |
|
|
$ |
227 |
|
Equity
Securities
|
|
|
16 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
16 |
|
Total Other Temporary
Investments
|
|
$ |
204 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
39 |
|
|
$ |
243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (c)
|
|
$ |
375 |
|
|
$ |
5,660 |
|
|
$ |
143 |
|
|
$ |
(4,892 |
) |
|
$ |
1,286 |
|
Cash
Flow and Fair Value Hedges (c)
|
|
|
- |
|
|
|
65 |
|
|
|
- |
|
|
|
(17
|
) |
|
|
48 |
|
Dedesignated
Risk Management Contracts (d)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
46 |
|
|
|
46 |
|
Total
Risk Management Assets
|
|
$ |
375 |
|
|
$ |
5,725 |
|
|
$ |
143 |
|
|
$ |
(4,863 |
) |
|
$ |
1,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spent
Nuclear Fuel and Decommissioning Trusts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents (e)
|
|
$ |
- |
|
|
$ |
17 |
|
|
$ |
- |
|
|
$ |
12 |
|
|
$ |
29 |
|
Debt
Securities
|
|
|
326 |
|
|
|
508 |
|
|
|
- |
|
|
|
- |
|
|
|
834 |
|
Equity
Securities
|
|
|
499 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
499 |
|
Total Spent Nuclear Fuel and
Decommissioning Trusts
|
|
$ |
825 |
|
|
$ |
525 |
|
|
$ |
- |
|
|
$ |
12 |
|
|
$ |
1,362 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
1,571 |
|
|
$ |
6,250 |
|
|
$ |
143 |
|
|
$ |
(4,761 |
) |
|
$ |
3,203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (c)
|
|
$ |
405 |
|
|
$ |
5,508 |
|
|
$ |
151 |
|
|
$ |
(4,831 |
) |
|
$ |
1,233 |
|
Cash
Flow and Fair Value Hedges (c)
|
|
|
8 |
|
|
|
115 |
|
|
|
- |
|
|
|
(17
|
) |
|
|
106 |
|
Total
Risk Management Liabilities
|
|
$ |
413 |
|
|
$ |
5,623 |
|
|
$ |
151 |
|
|
$ |
(4,848 |
) |
|
$ |
1,339 |
|
(a)
|
Amounts
in “Other” column primarily represent cash deposits in bank accounts with
financial institutions. Level 1 amounts primarily represent
investments in money market funds.
|
(b)
|
Amounts
in “Other” column primarily represent cash deposits with third
parties. Level 1 amounts primarily represent investments in
money market funds.
|
(c)
|
Amounts
in “Other” column primarily represent counterparty netting of risk
management contracts and associated cash collateral under FSP FIN
39-1.
|
(d)
|
“Dedesignated
Risk Management Contracts” are contracts that were originally MTM but were
subsequently elected as normal under SFAS 133. At the time of
the normal election the MTM value was frozen and no longer fair
valued. This will be amortized into Utility Operations Revenues
over the remaining life of the contract.
|
(e)
|
Amounts
in “Other” column primarily represent accrued interest receivables to/from
financial institutions. Level 2 amounts primarily represent
investments in money market funds.
|
The
following tables set forth a reconciliation of changes in the fair value of net
trading derivatives and other investments classified as level 3 in the fair
value hierarchy:
Three
Months Ended June 30, 2008
|
|
Net
Risk Management Assets (Liabilities)
|
|
|
Other
Temporary Investments
|
|
|
Investments
in Debt Securities
|
|
|
|
(in
millions)
|
|
Balance
as of April 1, 2008
|
|
$ |
49 |
|
|
$ |
22 |
|
|
$ |
17 |
|
Realized
(Gain) Loss Included in Earnings (or Changes in Net Assets)
(a)
|
|
|
(2
|
) |
|
|
- |
|
|
|
- |
|
Unrealized
Gain (Loss) Included in Earnings (or Changes in Net
Assets)
Relating to Assets Still Held at the Reporting Date (a)
|
|
|
(1
|
) |
|
|
- |
|
|
|
- |
|
Realized
and Unrealized Gains (Losses) Included in Other
Comprehensive
Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Purchases,
Issuances and Settlements
|
|
|
- |
|
|
|
(22
|
) |
|
|
(17 |
) |
Transfers
in and/or out of Level 3 (b)
|
|
|
(8
|
) |
|
|
- |
|
|
|
- |
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(46
|
) |
|
|
- |
|
|
|
- |
|
Balance
as of June 30, 2008
|
|
$ |
(8 |
) |
|
$ |
- |
|
|
$ |
- |
|
Six
Months Ended June 30, 2008
|
|
Net
Risk Management Assets (Liabilities)
|
|
|
Other
Temporary Investments
|
|
|
Investments
in Debt Securities
|
|
|
|
(in
millions)
|
|
Balance
as of January 1, 2008
|
|
$ |
49 |
|
|
$ |
- |
|
|
$ |
- |
|
Realized
(Gain) Loss Included in Earnings (or Changes in Net Assets)
(a)
|
|
|
(2
|
) |
|
|
- |
|
|
|
- |
|
Unrealized
Gain (Loss) Included in Earnings (or Changes in Net
Assets)
Relating to Assets Still Held at the Reporting Date (a)
|
|
|
(3
|
) |
|
|
- |
|
|
|
- |
|
Realized
and Unrealized Gains (Losses) Included in Other
Comprehensive
Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Purchases,
Issuances and Settlements
|
|
|
- |
|
|
|
(118
|
) |
|
|
(17 |
) |
Transfers
in and/or out of Level 3 (b)
|
|
|
(1
|
) |
|
|
118 |
|
|
|
17 |
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(51
|
) |
|
|
- |
|
|
|
- |
|
Balance
as of June 30, 2008
|
|
$ |
(8 |
) |
|
$ |
- |
|
|
$ |
- |
|
(a)
|
Included
in revenues on our Condensed Consolidated Statement of
Income.
|
(b)
|
“Transfers
in and/or out of Level 3” represent existing assets or liabilities that
were either previously categorized as a higher level for which the inputs
to the model became unobservable or assets and liabilities that were
previously classified as level 3 for which the lowest significant input
became observable during the period.
|
(c)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected on the Condensed
Consolidated Statements of Income. These net gains (losses) are
recorded as regulatory assets/liabilities for those subsidiaries that
operate in regulated jurisdictions.
|
SFAS
159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS
159)
In
February 2007, the FASB issued SFAS 159, permitting entities to choose to
measure many financial instruments and certain other items at fair
value. The standard also establishes presentation and disclosure
requirements designed to facilitate comparison between entities that choose
different measurement attributes for similar types of assets and
liabilities. If the fair value option is elected, the effect of the
first remeasurement to fair value is reported as a cumulative effect adjustment
to the opening balance of retained earnings. The statement is applied
prospectively upon adoption.
We
adopted SFAS 159 effective January 1, 2008. At adoption, we did not
elect the fair value option for any assets or liabilities.
SFAS
160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS
160)
In
December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling
interest (minority interest) in consolidated financial statements. It
requires noncontrolling interest be reported in equity and establishes a new
framework for recognizing net income or loss and comprehensive income by the
controlling interest. Upon deconsolidation due to loss of control
over a subsidiary, the standard requires a fair value remeasurement of any
remaining noncontrolling equity investment to be used to properly recognize the
gain or loss. SFAS 160 requires specific disclosures regarding
changes in equity interest of both the controlling and noncontrolling parties
and presentation of the noncontrolling equity balance and income or loss for all
periods presented.
SFAS 160
is effective for interim and annual periods in fiscal years beginning after
December 15, 2008. The statement is applied prospectively upon
adoption. Early adoption is prohibited. Upon adoption,
prior period financial statements will be restated for the presentation of the
noncontrolling interest for comparability. Although we have not
completed our analysis, we expect that the adoption of this standard will have
an immaterial impact on our financial statements. We will adopt SFAS
160 effective January 1, 2009.
SFAS
161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS
161)
In March
2008, the FASB issued SFAS 161, enhancing disclosure requirements for derivative
instruments and hedging activities. Affected entities are required to
provide enhanced disclosures about (a) how and why an entity uses derivative
instruments, (b) how derivative instruments and related hedged items are
accounted for under SFAS 133 and its related interpretations, and (c) how
derivative instruments and related hedged items affect an entity’s financial
position, financial performance and cash flows. SFAS 161 requires
that objectives for using derivative instruments be disclosed in terms of
underlying risk and accounting designation. This standard is intended
to improve upon the existing disclosure framework in SFAS 133.
SFAS 161
is effective for fiscal years and interim periods beginning after November 15,
2008. We expect this standard to increase our disclosure requirements
related to derivative instruments and hedging activities. It
encourages retrospective application to comparative disclosure for earlier
periods presented. We will adopt SFAS 161 effective January 1,
2009.
SFAS
162 “The Hierarchy of Generally Accepted Accounting Principles” (SFAS
162)
In May
2008, the FASB issued SFAS 162, clarifying the sources of generally accepted
accounting principles in descending order of authority. The statement
specifies that the reporting entity, not its auditors, is responsible for its
compliance with GAAP.
SFAS 162
is effective 60 days after the SEC approves the Public Company Accounting
Oversight Board’s amendments to AU Section 411, “The Meaning of Present Fairly
in Conformity with Generally Accepted Accounting Principles.” We
expect the adoption of this standard will have no impact on our financial
statements. We will adopt SFAS 162 when it becomes
effective.
EITF
Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life
Insurance Arrangements” (EITF
06-10)
In March
2007, the FASB ratified EITF 06-10, a consensus on collateral
assignment split-dollar life insurance arrangements in which an employee owns
and controls the insurance policy. Under EITF 06-10, an employer
should recognize a liability for the postretirement benefit related to a
collateral assignment split-dollar life insurance arrangement in accordance with
SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension”
or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the
employer has agreed to maintain a life insurance policy during the employee's
retirement or to provide the employee with a death benefit based on a
substantive arrangement with the employee. In addition, an employer
should recognize and measure an asset based on the nature and substance of the
collateral assignment split-dollar life insurance arrangement. EITF
06-10 requires recognition of the effects of its application as either (a) a
change in accounting principle through a cumulative effect adjustment to
retained earnings or other components of equity or net assets in the statement
of financial position at the beginning of the year of adoption or (b) a change
in accounting principle through retrospective application to all prior
periods. We adopted EITF 06-10 effective January 1, 2008 with a
cumulative effect reduction of $16 million ($10 million, net of tax) to
beginning retained earnings.
EITF
Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based
Payment Awards” (EITF
06-11)
In June
2007, the FASB ratified the EITF consensus on the treatment of income tax
benefits of dividends on employee share-based compensation. The issue
is how a company should recognize the income tax benefit received on dividends
that are paid to employees holding equity-classified nonvested shares,
equity-classified nonvested share units or equity-classified outstanding share
options and charged to retained earnings under SFAS 123R, “Share-Based
Payments.” Under EITF 06-11, a realized income tax benefit from
dividends or dividend equivalents that are charged to retained earnings and are
paid to employees for equity-classified nonvested equity shares, nonvested
equity share units and outstanding equity share options should be recognized as
an increase to additional paid-in capital. EITF 06-11 is applied
prospectively to the income tax benefits of dividends on equity-classified
employee share-based payment awards that are declared in fiscal years after
December 15, 2007.
We
adopted EITF 06-11 effective January 1, 2008. The adoption of this
standard had an immaterial impact on our financial statements.
FSP
EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment
Transactions Are Participating Securities” (EITF 03-6-1)
In June
2008, the FASB issued EITF 03-6-1 addressing whether instruments granted in
share-based payment transactions are participating securities prior to vesting
and need to be included in earnings allocation in computing EPS under the
two-class method described in SFAS 128 “Earnings per Share.”
EITF
03-6-1 is effective for interim and annual periods in fiscal years beginning
after December 15, 2008. The statement is applied retrospectively
upon adoption. Early adoption is prohibited. Upon
adoption, prior period financial statements will be restated for
comparability. Although we have not completed our analysis, we expect
that the adoption of this standard will have an immaterial impact on our
financial statements. We will adopt EITF 03-6-1 effective January 1,
2009.
FSP
SFAS 142-3 “Determination of the Useful Life of Intangible Assets” (SFAS
142-3)
In April
2008, the FASB issued SFAS 142-3 amending factors that should be considered in
developing renewal or extension assumptions used to determine the useful life of
a recognized intangible asset under SFAS 142, “Goodwill and Other Intangible
Assets.” The standard is expected to improve consistency between the
useful life of a recognized intangible asset and the period of expected cash
flows used to measure its fair value.
SFAS
142-3 is effective for interim and annual periods in fiscal years beginning
after December 15, 2008. Early adoption is
prohibited. Upon adoption, the guidance within SFAS 142-3 will be
prospectively applied to intangible assets acquired after the effective
date. We expect that the adoption of this standard will have an
immaterial impact on our financial statements. We will adopt SFAS
142-3 effective January 1, 2009.
FSP
FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)
In April
2007, the FASB issued FIN 39-1. It amends FASB Interpretation No. 39
“Offsetting of Amounts Related to Certain Contracts” by replacing the
interpretation’s definition of contracts with the definition of derivative
instruments per SFAS 133. It also requires entities that offset fair
values of derivatives with the same party under a netting agreement to net the
fair values (or approximate fair values) of related cash
collateral. The entities must disclose whether or not they offset
fair values of derivatives and related cash collateral and amounts recognized
for cash collateral payables and receivables at the end of each reporting
period.
We
adopted FIN 39-1 effective January 1, 2008. This standard changed our
method of netting certain balance sheet amounts and reduced assets and
liabilities. It requires retrospective application as a change in
accounting principle. Consequently, we reclassified the following
amounts on the December 31, 2007 Condensed Consolidated Balance Sheet as
shown:
Balance
Sheet
Line
Description
|
|
As
Reported for
the
December 2007 10-K
|
|
|
FIN
39-1
Reclassification
|
|
|
As
Reported for
the
June
2008
10-Q
|
|
Current
Assets:
|
|
(in
millions)
|
|
Risk
Management Assets
|
|
$ |
286 |
|
|
$ |
(15 |
) |
|
$ |
271 |
|
Margin
Deposits
|
|
|
58 |
|
|
|
(11
|
) |
|
|
47 |
|
Long-term
Risk Management Assets
|
|
|
340 |
|
|
|
(21
|
) |
|
|
319 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities
|
|
|
250 |
|
|
|
(10
|
) |
|
|
240 |
|
Customer
Deposits
|
|
|
337 |
|
|
|
(36
|
) |
|
|
301 |
|
Long-term
Risk Management Liabilities
|
|
|
189 |
|
|
|
(1
|
) |
|
|
188 |
|
For
certain risk management contracts, we are required to post or receive cash
collateral based on third party contractual agreements and risk
profiles. For the June 30, 2008 balance sheet, we netted $182 million
of cash collateral received from third parties against short-term and long-term
risk management assets and $121 million of cash collateral paid to third parties
against short-term and long-term risk management liabilities.
Future
Accounting Changes
The
FASB’s standard-setting process is ongoing and until new standards have been
finalized and issued by the FASB, we cannot determine the impact on the
reporting of our operations and financial position that may result from any such
future changes. The FASB is currently working on several projects
including revenue recognition, contingencies, liabilities and equity, emission
allowances, earnings per share calculations, leases, hedge accounting, trading
inventory and related tax impacts. We also expect to see more FASB
projects as a result of its desire to converge International Accounting
Standards with GAAP. The ultimate pronouncements resulting from these
and future projects could have an impact on our future results of operations and
financial position.
EXTRAORDINARY
ITEM
In April
2007, Virginia passed legislation to reestablish regulation for retail
generation and supply of electricity. As a result, we recorded an
extraordinary loss of $118 million ($79 million, net of tax) during the second
quarter of 2007 for the reestablishment of regulatory assets and liabilities
related to our Virginia retail generation and supply operations. In
2000, we discontinued SFAS 71 regulatory accounting in our Virginia jurisdiction
for retail generation and supply operations due to the passage of legislation
for customer choice and deregulation.
As
discussed in the 2007 Annual Report, our subsidiaries are involved in rate and
regulatory proceedings at the FERC and their state commissions. The
Rate Matters note within our 2007 Annual Report should be read in conjunction
with this report to gain a complete understanding of material rate matters still
pending that could impact results of operations, cash flows and possibly
financial condition. The following discusses ratemaking developments
in 2008 and updates the 2007 Annual Report.
Ohio Rate
Matters
Ohio
Electric Security Plan Filings
In April
2008, the Ohio legislature passed Senate Bill 221, which amends the
restructuring law effective July 31, 2008 and requires electric utilities to
adjust their rates by filing an Electric Security Plan
(ESP). Electric utilities may file an ESP with a fuel cost recovery
mechanism. Electric utilities also have an option to file a Market
Rate Offer (MRO) for generation pricing. A MRO, from the date of its
commencement, could transition CSPCo and OPCo to full market rates no sooner
than six years and no later than ten years. The PUCO has the
authority to approve or modify the utilities’ ESP request. The PUCO
is required to approve an ESP if, in the aggregate, the ESP is more favorable to
ratepayers than the MRO. Both alternatives involve a “substantially
excessive earnings” test based on what public companies, including other
utilities with similar risk profiles, earn on equity. Management has
preliminarily concluded, pending the issuance of final rules by the PUCO and the
outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply
operations are not subject to cost-based rate regulation
accounting. However, if a fuel cost recovery mechanism is implemented
within the ESP, CSPCo’s and OPCo’s fuel operations would be subject to
cost-based rate regulation accounting. Management is unable to
predict the financial statement impact of the restructuring legislation until
the PUCO acts on specific proposals made by CSPCo and OPCo in their
ESPs.
In July
2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to
establish rates for 2009 through 2011. CSPCo and OPCo did not file
MROs. CSPCo and
OPCo each requested an annual rate increase for 2009 through 2011 that would not
exceed approximately 15% per year. A significant portion of the
requested increases results from the implementation of a fuel cost recovery
mechanism that primarily includes fuel costs, purchased power costs including
mandated renewable energy, consumables such as urea, other variable production
costs and gains and losses on sales of emission allowances. The
increases in customer bills related to the fuel cost recovery mechanism would be
phased-in over the three year period from 2009 through
2011. Effective January 1, 2009, CSPCo and OPCo will defer the fuel
cost under-recoveries and related carrying costs for future recovery over seven
years from 2012 through 2018. In addition to the fuel cost recovery
mechanisms, the requested increases would also recover incremental carrying
costs associated with environmental costs, Provider of Last Resort (POLR)
charges to compensate for the risk of customers changing electric suppliers,
automatic increases for unexpected costs and reliability costs. The filings also
include programs for smart metering initiatives and economic development
and mandated energy efficiency and peak demand reduction
programs. Management expects a PUCO decision on the ESP filings in
the fourth quarter of 2008.
Within
the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $45
million and $36 million, respectively, for customer choice implementation and
line extension carrying costs. In addition, CSPCo and OPCo would
recover related unrecorded equity carrying costs of $28 million and $19 million,
respectively. Such costs would be recovered over an 8 year
period beginning January 2011. Failure of the PUCO to ultimately
approve the recovery of the regulatory assets would have an adverse effect on
future results of operations and cash flows.
2008
Generation Rider and Transmission Rider Rate Settlement
On
January 30, 2008, the PUCO approved a settlement agreement, among CSPCo, OPCo
and other parties, under the additional average 4% generation rate increase and
transmission cost recovery rider (“TCRR”) provisions of the RSP. The
increase was to recover additional governmentally-mandated costs including
incremental environmental costs. Under the settlement, the PUCO also
approved recovery through the TCRR of increased PJM costs associated with
transmission line losses of $39 million each for CSPCo and OPCo. As a
result, CSPCo and OPCo established regulatory assets in the first quarter of
2008 of $12 million and $14 million, respectively, related to the future
recovery of increased PJM billings from June 2007 to December
2007. The PUCO also approved a credit applied to the TCRR of $10
million for OPCo and $8 million for CSPCo for a reduction in PJM net congestion
costs. To the extent that collections for the TCRR items are
over/under actual net costs, CSPCo and OPCo will defer the difference and adjust
future customer billings to reflect actual costs including carrying costs on the
unrecovered deferral. Under the terms of the settlement, although the
increased PJM costs associated with transmission line losses will be recovered
through the TCRR, these recoveries will still be applied to reduce the annual
average 4% generation rate increase limitation. In addition, the PUCO
approved recoveries through generation rates of environmental costs and related
carrying costs of $29 million for CSPCo and $5 million for
OPCo. These RSP rate adjustments were implemented in February
2008.
In
February 2008, Ormet, a major industrial customer, filed a motion to intervene
and an application for rehearing of the PUCO’s January 2008 RSP order claiming
the settlement inappropriately shifted $4 million in cost recovery to
Ormet. In March 2008, the PUCO granted Ormet’s motion to
intervene. Ormet’s rehearing application also was granted for the
purpose of providing the PUCO with additional time to consider the issues raised
by Ormet. Management cannot predict the outcome of this rehearing
process.
Ohio
IGCC Plant
In March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of
cost recovery associated with the IGCC plant: Phase 1, recovery of
$24 million in pre-construction costs; Phase 2, concurrent recovery of
construction-financing costs; and Phase 3, recovery or refund in distribution
rates of any difference between the generation rates which may be a market-based
standard service offer price for generation and the expected higher cost of
operating and maintaining the plant, including a return on and return of the
projected cost to construct the plant.
In June
2006, the PUCO issued an order approving a tariff to allow CSPCo and OPCo to
recover Phase 1 pre-construction costs over a period of no more than twelve
months effective July 1, 2006. During that period CSPCo and OPCo each
collected $12 million in pre-construction costs.
The order
also provided that if CSPCo and OPCo have not commenced a continuous course of
construction of the proposed IGCC plant within five years of the June 2006 PUCO
order, all Phase 1 costs associated with items that may be utilized in projects
at other sites, must be refunded to Ohio ratepayers with
interest. The PUCO deferred ruling on cost recovery for Phases 2 and
3 pending further hearings.
In August
2006, intervenors filed four separate appeals of the PUCO’s order in the IGCC
proceeding. In March 2008, the Ohio Supreme Court issued its opinion
affirming in part, and reversing in part the PUCO’s order and remanded the
matter back to the PUCO. The Ohio Supreme Court held that while there
could be an opportunity under existing law to recover a portion of the IGCC
costs in distribution rates, traditional rate making procedures would apply to
the recoverable portion. The Ohio Supreme Court did not address the
matter of refunding the Phase 1 cost recovery and declined to create an
exception to its precedent of denying claims for refund of past recoveries from
approved orders of the PUCO.
Recent
estimates of the cost to build the proposed IGCC plant are approximately $2.7
billion. Management continues to pursue the ultimate construction of
the IGCC plant. However, in light of the Ohio Supreme Court’s
decision, CSPCo and OPCo will not start construction of the IGCC plant until
sufficient assurance of cost recovery exists. If CSPCo and OPCo were
required to refund the $24 million collected and those costs were not
recoverable in another jurisdiction in connection with the construction of an
IGCC plant, it would have an adverse effect on future results of operations and
cash flows.
Ormet
Effective
January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial
customer with a 520 MW load, in accordance with a settlement agreement approved
by the PUCO. The settlement agreement allows for the recovery in 2007
and 2008 of the difference between the $43 per MWH Ormet pays for power and a
PUCO-approved market price, if higher. The PUCO approved a $47.69 per
MWH market price for 2007 and the difference was recovered through the
amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo)
excess deferred tax regulatory liability resulting from an Ohio franchise tax
phase-out recorded in 2005.
CSPCo and
OPCo each amortized $5 million of this regulatory liability to income for the
six months ended June 30, 2008 based on the previously approved 2007 price of
$47.69 per MWH. In December 2007, CSPCo and OPCo submitted for
approval a market price of $53.03 per MWH for 2008. The PUCO has not
yet approved the increase. If the PUCO approves a market price for
2008 below $47.69, it could have an adverse effect on future results of
operations and cash flows. A price above $47.69 should result in a
favorable effect. If CSPCo and OPCo serve the Ormet load after 2008
without any special provisions, they could experience incremental costs to
acquire additional capacity to meet their reserve requirements and/or forgo more
profitable market priced off-system sales.
Texas Rate
Matters
TEXAS
RESTRUCTURING
TCC
Texas Restructuring Appeals
Pursuant
to PUCT orders, TCC securitized its net recoverable stranded generation costs of
$2.5 billion and is recovering such costs over a period ending in
2020. TCC has refunded its net other true-up items of $375 million
during the period October 2006 through June 2008 via a CTC credit rate
rider. Cash paid for CTC refunds for the six months ended June 30,
2008 and 2007 was $68 million and $170 million, respectively. TCC appealed
the PUCT stranded costs true-up and related orders seeking relief in both state
and federal court on the grounds that certain aspects of the orders are contrary
to the Texas Restructuring Legislation, PUCT rulemakings and federal law and
fail to fully compensate TCC for its net stranded cost and other true-up
items. The significant items appealed by TCC are:
·
|
The
PUCT ruling that TCC did not comply with the Texas Restructuring
Legislation and PUCT rules regarding the required auction of 15% of its
Texas jurisdictional installed capacity, which led to a significant
disallowance of capacity auction true-up revenues.
|
·
|
The
PUCT ruling that TCC acted in a manner that was commercially unreasonable,
because TCC failed to determine a minimum price at which it would reject
bids for the sale of its nuclear generating plant and TCC bundled
out-of-the-money gas units with the sale of its coal unit, which led to
the disallowance of a significant portion of TCC’s net stranded generation
plant costs.
|
·
|
Two
federal matters regarding the allocation of off-system sales related to
fuel recoveries and a potential tax normalization
violation.
|
Municipal
customers and other intervenors also appealed the PUCT true-up and related
orders seeking to further reduce TCC’s true-up recoveries.
In March
2007, the Texas District Court judge hearing the appeal of the true-up order
affirmed the PUCT’s April 2006 final true-up order for TCC with two significant
exceptions. The judge determined that the PUCT erred by applying an
invalid rule to determine the carrying cost rate for the true-up of stranded
costs and remanded this matter to the PUCT for further
consideration. The District Court judge also determined that the PUCT
improperly reduced TCC’s net stranded plant costs for commercial
unreasonableness.
TCC, the
PUCT and intervenors appealed the District Court decision to the Texas Court of
Appeals. In May 2008, the Texas Court of Appeals affirmed the
District Court decision in all but one major respect. It reversed the
District Court’s decision finding that the PUCT erred by applying an invalid
rule to determine the carrying cost rate. The Texas Court of Appeals
denied intervenors’ motion for rehearing. Management expects
intervenors to appeal the decision to the Texas Supreme Court. If
upheld on appeal, this ruling could have a favorable effect on TCC’s results of
operations and cash flows.
Management
cannot predict the outcome of these court proceedings and PUCT remand
decisions. If TCC ultimately succeeds in its appeals, it could have a
favorable effect on future results of operations, cash flows and financial
condition. If municipal customers and other intervenors succeed in
their appeals it could have a substantial adverse effect on future results of
operations, cash flows and financial condition.
TCC
Deferred Investment Tax Credits and Excess Deferred Federal Income
Taxes
Appeals
remain outstanding related to the stranded costs true-up and related orders
regarding whether the PUCT may require TCC to refund certain tax benefits to
customers. The PUCT agreed to allow TCC to defer a $103 million refund to
customers ($61 million in present value of the tax benefits associated with
TCC’s generation assets plus $42 million of related carrying costs) pending
resolution of whether the PUCT’s proposed refund is an IRS normalization
violation. In May 2008, as requested by the PUCT, the Texas Court of
Appeals ordered a remand of the tax normalization issue for the consideration of
additional evidence.
The IRS
issued final regulations on March 20, 2008 addressing Accumulated Deferred
Investment Tax Credit (ADITC) and Excess Deferred Federal Income Tax (EDFIT)
normalization requirements. Consistent with the Private Letter Ruling TCC
received in 2006, the regulations clearly state that TCC will sustain a
normalization violation if the PUCT orders TCC to flow the tax benefits to
customers. TCC notified the PUCT that the final regulations were
issued. TCC expects that the PUCT will allow TCC to retain and not
refund these amounts, which will have a favorable effect on future results of
operations and cash flows as TCC will record the ADITC and EDFIT tax benefits in
income due to the sale of the generating plants that generated the tax
benefits.
However,
if the PUCT orders TCC to flow the tax benefits to customers, thereby causing
TCC to have a normalization violation, it could result in TCC’s repayment to the
IRS of ADITC on all property, including transmission and distribution property,
which approximates $103 million as of June 30, 2008, and a loss of TCC’s right
to claim accelerated tax depreciation in future tax returns. Tax
counsel advised management that a normalization violation should not occur until
all remedies under law have been exhausted and the tax benefits are actually
returned to ratepayers under a nonappealable
order. Management intends to continue its efforts to work
with the PUCT to resolve the issue and avoid a normalization
violation.
TCC
and TNC Deferred Fuel
TCC, TNC
and the PUCT have been involved in litigation in the federal courts concerning
whether the PUCT has the right to order a reallocation of off-system sales
margins thereby reducing recoverable fuel costs. In 2005, TCC and TNC
recorded provisions for refunds after the PUCT ordered such
reallocation. After receipt of favorable federal court decisions and
the refusal of the U.S. Supreme Court to hear a PUCT appeal of the TNC decision,
TCC and TNC reversed their provisions of $16 million and $9 million,
respectively, in the third quarter of 2007.
The PUCT
or another interested party could file a complaint at the FERC to challenge the
allocation of off-system sales margins under FERC-approved allocation
agreements. In December 2007, some cities served by TNC requested the
PUCT to initiate, or order TNC to initiate a proceeding at the FERC to determine
if AEP misapplied the allocation methodology under the FERC-approved
agreements. In January 2008, TNC filed a response with the PUCT
recommending the cities’ request be denied. Although management
cannot predict if a complaint will be filed at the FERC, management believes its
allocations were in accordance with the then-existing FERC-approved allocation
agreements and additional off-system sales margins should not be retroactively
reallocated to the AEP West companies including TCC and TNC.
TCC
Excess Earnings
In 2005,
a Texas appellate court issued a decision finding that a PUCT order requiring
TCC to refund to the REPs excess earnings prior to and outside of the true-up
process was unlawful under the Texas Restructuring Legislation. From
2002 to 2005, TCC refunded $55 million of excess earnings, including interest,
under the overturned PUCT order. On remand, the PUCT must determine
how to implement the Court of Appeals decision given that the unauthorized
refunds were made in lieu of reducing stranded cost recoveries in the True-up
Proceeding. As a result, TCC’s stranded cost recovery, which is
currently on appeal, may be affected by a PUCT remedy.
In
December 2007, the Texas Court of Appeals issued a decision in CenterPoint’s, a
nonaffiliated Texas utility, true-up proceeding determining that even though
excess earnings had been previously refunded to the affiliated REP, CenterPoint
still must reduce stranded cost recoveries in its true-up
proceeding. In 2005, TCC reflected the obligation to refund excess
earnings to customers through the true-up process and recorded a regulatory
asset of $55 million representing a receivable from the REPs for prior refunds
to them by TCC. However, certain parties have taken positions that, if adopted,
could result in TCC being required to refund additional amounts of excess
earnings or interest through the true-up process without receiving a refund back
from the REPs. If this were to occur it would have an adverse effect on future
results of operations and cash flows. AEP sold its affiliate REPs in
December 2002. While AEP owned the affiliate REPs, TCC refunded $11
million of excess earnings to the affiliate REPs. Management cannot
predict the outcome of these matters and whether they will adversely affect
future results of operations, cash flows and financial condition.
OTHER
TEXAS RATE MATTERS
Stall
Unit
See
“Stall Unit” section within the Louisiana Rate Matters for
disclosure.
Turk
Plant
See “Turk
Plant” section within the Arkansas Rate Matters for disclosure.
Virginia Rate
Matters
Virginia
Base Rate Filing
In May
2008, APCo filed an application with the Virginia SCC to increase its base rates
by $208 million on an annual basis. The requested increase is based
upon a calendar 2007 test year adjusted for changes in revenues, expenses, rate
base and capital structure through June 2008 which is consistent with the
ratemaking treatment adopted by the Virginia SCC in APCo’s 2006 base rate
case. The proposed revenue requirement reflects a return on equity of
11.75%. The Virginia SCC ordered hearings to begin in October
2008. As permitted under Virginia law, APCo plans to implement these
new base rates, subject to refund, effective October 28, 2008 if the Virginia
SCC fails to make a decision by that date.
Virginia
E&R Costs Recovery Filing
As of
June 30, 2008, APCo has $97 million of deferred Virginia incremental E&R
costs. Currently APCo is recovering $16 million of the deferral for
incremental costs incurred through September 30, 2006. In May 2008,
APCo filed for recovery of deferred incremental E&R costs incurred from
October 1, 2006 through December 31, 2007 which totals $50
million. The remaining deferral will be requested in a 2009
filing. As of June 30, 2008, APCo has $22 million of unrecorded
E&R equity carrying costs of which $7 million should increase 2008 annual
earnings as collected. In connection with the 2009 filing, the
Virginia SCC will determine the level of incremental E&R costs being
collected in base revenues since October 2006 that APCo has estimated to be $48
million annually. If the Virginia SCC were to determine that these
recovered base revenues are in excess of $48 million a year, it would require
that the E&R deferrals be reduced by the excess amount, thus adversely
affecting future earnings and cash flows.
In July
2008, the Old Dominion Committee for Fair Utility Rates (ODC) filed a motion to
dismiss the E&R filing based on ODC’s belief that the opportunity to collect
E&R surcharges expires December 31, 2008. A dismissal would not
eliminate APCo’s ability to request for future recovery of its deferred E&R
costs. APCo filed a response requesting the Virginia SCC to deny
ODC’s motion. If the Virginia SCC were to disallow any additional
portion of APCo’s deferral, it would also have an adverse effect on future
results of operations and cash flows. If the outstanding request for
E&R recovery is approved it will have a favorable effect on future cash
flows.
Virginia
Fuel Clause Filings
In July
2007, APCo filed an application with the Virginia SCC to seek an annualized
increase, effective September 1, 2007, of $33 million for fuel costs and sharing
of off-system sales.
In
February 2008, the Virginia SCC issued an order that approved a reduced fuel
factor effective with the February 2008 billing cycle. The order
terminated the off-system sales margin rider and approved a 75%-25% sharing of
off-system sales margins between customers and APCo effective September 1, 2007
as required by the re-regulation legislation in Virginia. The order
also allows APCo to include in its monthly under/over recovery deferrals the
Virginia jurisdictional share of PJM transmission line loss costs from June 2007
to June 2008 which totaled $28 million. The adjusted factor increases
annual revenues by $4 million. The order authorized the Virginia SCC
staff and other parties to make specific recommendations to the Virginia SCC in
APCo’s next fuel factor proceeding to ensure accurate assignment of the
prudently incurred PJM transmission line loss costs to APCo’s Virginia
jurisdictional operations. Management believes the incurred PJM
transmission line loss costs are prudently incurred and are being properly
assigned to APCo’s Virginia jurisdictional operations.
In
February 2008, the Old Dominion Committee for Fair Utility Rates (ODC) filed a
notice of appeal to the Supreme Court of Virginia appealing the Virginia SCC’s
decisions regarding off-system sales margins and PJM transmission line loss
costs. In May 2008, the ODC withdrew its appeal.
In July
2008, APCo filed its next fuel factor proceeding with the Virginia SCC and
requested an annualized increase of $132 million effective September 1,
2008. The increase primarily relates to increases in coal
costs.
If costs
included in APCo’s Virginia fuel under/over recovery deferrals are disallowed,
it could result in an adverse effect on future results of operations and cash
flows.
APCo’s
Virginia SCC Filing for an IGCC Plant
In July
2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to
recover initial costs associated with a proposed 629 MW IGCC plant to be
constructed in Mason County, West Virginia adjacent to APCo’s existing
Mountaineer Generating Station for an estimated cost of $2.2
billion. The filing requested recovery of an estimated $45 million
over twelve months beginning January 1, 2009 including a return on projected
CWIP and development, design and planning pre-construction costs incurred from
July 1, 2007 through December 31, 2009. APCo also requested
authorization to defer a return on deferred pre-construction costs incurred
beginning July 1, 2007 until such costs are recovered. Through June
30, 2008, APCo has deferred for future recovery pre-construction IGCC costs of
$9 million allocated to Virginia jurisdictional operations. The rate
adjustment clause provisions of the 2007 re-regulation legislation provides for
full recovery of all costs of this type of new clean coal technology including
recovery of an enhanced return on equity.
The
Virginia SCC issued an order in April 2008 denying APCo’s requests stating the
belief that the estimated cost may be significantly understated. The
Virginia SCC also expressed concern that the $2.2 billion estimated cost did not
include a retrofitting of carbon capture and sequestration
facilities. In April 2008, APCo filed a petition for reconsideration
in Virginia. In May 2008, the Virginia SCC denied APCo’s request to
reconsider its previous ruling. In July 2008, the IRS awarded $134
million in future tax credits for the IGCC plant. Management
continues to pursue the ultimate construction of the IGCC plant; however, APCo
will not start construction of the IGCC plant until sufficient assurance of cost
recovery exists. If the plant is canceled, APCo plans to seek
recovery of its prudently incurred deferred pre-construction
costs. If the plant is canceled and the deferred costs are not
recoverable, it would have an adverse effect on future results of operations and
cash flows.
West Virginia Rate
Matters
APCo’s
and WPCo’s 2008 Expanded Net Energy Cost (ENEC) Filing
In
February 2008, APCo and WPCo filed for an increase of approximately $156 million
including a $135 million increase in the ENEC, a $17 million increase in
construction cost surcharges and $4 million of reliability expenditures, to
become effective July 2008. In June 2008, the WVPSC issued an order
approving a joint stipulation and settlement agreement granting an increase,
effective July 2008, of approximately $106 million, including an $88 million
increase in the ENEC, a $14 million increase in construction cost surcharges and
$4 million of reliability expenditures. The ENEC is an expanded form
of fuel clause mechanism, which includes all energy-related costs including
fuel, purchased power expenses, off-system sales credits, PJM costs associated
with transmission line losses due to the implementation of marginal loss pricing
and other energy/transmission items.
The ENEC
is subject to a true up to actual costs and should have no earnings effect due
to the deferral of any over/under-recovery of actual ENEC costs. The
construction cost and reliability surcharges are not subject to a true up to
actual costs and could result in an adverse under recovery.
APCo’s
West Virginia IGCC Plant Filing
In
January 2006, APCo filed a petition with the WVPSC requesting its approval of a
Certificate of Public Convenience and Necessity (CCN) to construct a 629 MW IGCC
plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
County, West Virginia.
In June
2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and
for pre-approval of a surcharge rate mechanism to provide for the timely
recovery of both pre-construction costs and the ongoing finance costs of the
project during the construction period as well as the capital costs, operating
costs and a return on equity once the facility is placed into commercial
operation. In March 2008, the WVPSC granted APCo the CCN to build the
plant and the request for cost recovery. Various intervenors filed
petitions with the WVPSC to reconsider the order. At the time of the
filing, the cost of the plant was estimated at $2.2 billion. In July
2008, based on the order received in Virginia, the WVPSC issued a notice seeking
comments from parties on how the WVPSC should proceed (See the “APCo’s Virginia
SCC Filing for an IGCC Plant” section above). Through June 30, 2008,
APCo deferred for future recovery pre-construction IGCC costs of $8 million
applicable to the West Virginia jurisdiction and $2 million applicable to the
FERC jurisdiction. In July 2008, the
IRS awarded $134 million in future tax credits for the IGCC
plant. Management continues to pursue the ultimate construction of
the IGCC plant; however, APCo will not start construction of the IGCC plant
until sufficient assurance of cost recovery exists. If the plant is
canceled, APCo plans to seek recovery of its prudently incurred deferred
pre-construction costs. If the plant is canceled and the deferred
costs are not recoverable, it would have an adverse effect on future results of
operations and cash flows.
Indiana Rate
Matters
Indiana
Rate Filing
In a
January 2008 filing with the IURC, updated in the second quarter of 2008,
I&M requested an increase in its Indiana base rates of $80 million including
a return on equity of 11.5%. The base rate increase includes the
$69 million annual reduction in depreciation expense previously approved by the
IURC and implemented for accounting purposes effective June 2007. The
depreciation reduction will no longer favorably impact earnings if and when
tariff rates are revised to reflect the reduction. The filing
requests trackers for certain variable components of the cost of service
including recently increased PJM costs associated with transmission line losses
due to the implementation of marginal loss pricing and other RTO costs,
reliability enhancement costs, demand side management/energy efficiency costs,
off-system sales margins and environmental compliance
costs. The trackers would initially increase annual revenues by an
additional $45 million. I&M proposes to share with ratepayers,
through a tracker, 50% of off-system sales margins initially estimated to be $96
million annually with a guaranteed credit to customers of $20
million. A decision is expected from the IURC by June
2009.
Kentucky Rate
Matters
Validity
of Nonstatutory Surcharges
In August
2007, the Franklin County Circuit Court concluded the KPSC did not have the
authority to order a surcharge for a gas company subsidiary of Duke Energy
absent a full cost of service rate proceeding due to the lack of statutory
authority. The Kentucky Attorney General (AG) notified the KPSC that
the Franklin County Circuit Court judge’s order in the Duke Energy case can be
interpreted to include other existing surcharges, rates or fees established
outside of the context of a general rate case proceeding and not specifically
authorized by statute, including fuel clauses. The KPSC and Duke
Energy appealed the Franklin County Circuit Court decision.
Although
this order is not directly applicable, KPCo has existing surcharges which are
not specifically authorized by statute. These include KPCo’s fuel
clause surcharge, annual Rockport Plant capacity surcharge, the merger surcredit
and the off-system sales credit rider. On an annual basis these
surcharges recently ranged from revenues of approximately $10 million to a
reduction of revenues of $2 million due to the volatility of these
surcharges. The KPSC asked interested parties to brief the issue in
KPCo’s fuel cost proceeding. The AG responded that the KPCo fuel
clause should be invalidated because the KPSC lacked the authority to implement
a fuel clause for KPCo without a full rate case review. The KPSC
issued an order stating that it has the authority to provide for surcharges and
surcredits until the Court of Appeals rules. The appeals process
could take up to two years to complete. The AG agreed to stay its
challenge during that time. KPCo’s exposure is indeterminable at this
time since it is not known whether a final adverse appeal could result in a
refund of prior amounts collected, which would have an adverse effect on future
results of operations and cash flows.
2008
Fuel Cost Reconciliation
In
January 2008, KPCo filed its semi-annual fuel cost reconciliation covering the
period May 2007 through October 2007. As part of this filing, KPCo
sought recovery of incremental costs associated with transmission line losses
billed by PJM since June 2007 due to PJM’s implementation of marginal loss
pricing. KPCo expensed these incremental PJM costs associated with
transmission line losses pending a determination that they are recoverable
through the Kentucky fuel clause. In June 2008, the KPSC issued an
order approving KPCo’s semi-annual fuel cost reconciliation filing and recovery
of incremental costs associated with transmission line losses billed by PJM
beginning May 2008. Therefore, in the second quarter of 2008, KPCo
recorded $13 million of income and the related Regulatory Asset for
Under-Recovered Fuel Costs for transmission line losses incurred from June 2007
through June 2008 of which $7 million related to 2007.
Oklahoma Rate
Matters
PSO
Fuel and Purchased Power and its Possible Impact on AEP East companies and AEP
West companies
In 2004,
intervenors and the OCC staff argued that AEP had inappropriately under
allocated off-system sales credits to PSO by $37 million for the period June
2000 to December 2004 under a FERC-approved allocation agreement. An
ALJ assigned to hear intervenor claims found that the OCC lacked authority to
examine whether AEP deviated from the FERC-approved allocation methodology for
off-system sales margins and held that any such complaints should be addressed
at the FERC. In October 2007, the OCC adopted the ALJ’s
recommendation and orally directed the OCC staff to explore filing a complaint
at FERC alleging the allocation of off-system sales margins to PSO is not in
compliance with the FERC-approved methodology which could result in an adverse
effect on future results of operations and cash flows for AEP Consolidated and
the AEP East companies. In June 2008, the ALJ issued a final
recommendation and incorporated the prior finding that the OCC lacked authority
to review AEP’s application of a FERC-approved methodology. The OCC
is scheduled to consider the final recommendation in August 2008. To
date, no claim has been asserted at the FERC and management continues to believe
that the allocation is consistent with the FERC-approved agreement.
In
February 2006, the OCC enacted a rule, requiring the OCC staff to conduct
prudence reviews on PSO’s generation and fuel procurement processes, practices
and costs on a periodic basis. PSO filed testimony in June 2007
covering a prudence review for the year 2005. The OCC staff and intervenors
filed testimony in September 2007, and hearings were held in November
2007. The only major issue in the proceeding was the alleged
under allocation of off-system sales credits under the FERC-approved allocation
methodology, which was determined not to be jurisdictional to the
OCC. Consistent with her prior recommendation, the ALJ found that the
OCC lacked authority to alter the FERC-approved methodology and that PSO’s fuel
costs were prudent. The OCC is scheduled to consider the ALJ’s findings and rule
in August 2008.
In
November 2007, PSO filed testimony in another proceeding to address its fuel
costs for 2006. In April 2008, intervenor testimony was filed again
challenging the allocation of off-system sales credits during the portion of the
year when the allocation was in effect. Hearings were held in July
2008 and the OCC changed the scope of the proceeding from a prudence review to
only a review of the mechanics of the fuel cost calculation. No party
contested PSO’s fuel cost calculation and an order is expected in August
2008.
Management
cannot predict the outcome of the pending fuel and purchased power cost recovery
filings and prudence reviews or whether a complaint will be filed at FERC
regarding the off-system sales allocation issue. However, PSO
believes its fuel and purchased power procurement practices and costs were
prudent and properly incurred and that it allocated off-system sales credits
consistent with governing FERC-approved agreements. If a complaint is
filed at FERC resulting in an unfavorable decision, it could have an adverse
effect on results of operations and cash flows.
Red
Rock Generating Facility
In July
2006, PSO announced an agreement with Oklahoma Gas and Electric Company
(OG&E) to build a 950 MW pulverized coal ultra-supercritical generating
unit. PSO would own 50% of the new unit. Under the
agreement, OG&E would manage construction of the plant. OG&E
and PSO requested preapproval to construct the Red Rock Generating Facility and
to implement a recovery rider.
In
October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of
additional capacity by the year 2012, but rejected the ALJ’s recommendation and
denied PSO’s and OG&E’s applications for construction
preapproval. The OCC stated that PSO failed to fully study other
alternatives to a coal-fired plant. Since PSO and OG&E could not
obtain preapproval to build the coal-fired Red Rock Generating Facility, PSO and
OG&E canceled the third party construction contract and their joint venture
development contract. PSO has issued a request-for-proposal to meet
its capacity and energy needs.
In
December 2007, PSO filed an application at the OCC requesting recovery of the
$21 million in pre-construction costs and contract cancellation fees associated
with Red Rock. In March 2008, PSO and all other parties in this
docket signed a settlement agreement that provides for recovery of $11 million
of Red Rock costs, and provides carrying costs at PSO’s AFUDC rate beginning in
March 2008 and continuing until the $11 million is included in PSO’s next base
rate case. PSO will recover the costs over the expected life of the
peaking facilities at the Southwestern Station, and include the costs in rate
base beginning in its next base rate filing. The settlement was filed
with the OCC in March 2008. The OCC approved the settlement in May
2008. As a result of the settlement, PSO wrote off $10 million of its
deferred pre-construction costs/cancellation fees in the first quarter of
2008.
Oklahoma
2007 Ice Storms
In
October 2007, PSO filed with the OCC requesting recovery of $13 million of
operation and maintenance expense related to service restoration efforts after a
January 2007 ice storm. PSO proposed in its application to establish
a regulatory asset of $13 million to defer the previously expensed January 2007
ice storm restoration costs and to amortize the regulatory asset coincident with
gains from the sale of excess SO2 emission
allowances. In December 2007, PSO expensed approximately $70 million
of additional storm restoration costs related to another ice storm in December
2007.
In
February 2008, PSO entered into a settlement agreement for recovery of costs
from both ice storms. In March 2008, the OCC approved the settlement
subject to an audit of the final December ice storm costs filed in July
2008. As a result, PSO recorded an $81 million regulatory asset for ice storm
maintenance expenses and related carrying costs less $9 million of amortization
expense to offset recognition of deferred gains from sales of SO2 emission
allowances. Under the settlement agreement, PSO would apply proceeds
from sales of excess SO2 emission
allowances of an estimated $26 million to recover part of the ice storm
regulatory asset. PSO will amortize and recover the remaining amount
of the regulatory asset through a rider over a period of five years beginning in
the fourth quarter of 2008. The regulatory asset will earn a return
of 10.92% on the unrecovered balance.
In June
2008, PSO adjusted its regulatory asset to true-up the estimated costs to
reflect actual costs as of June 30, 2008. After the true-up,
application of proceeds from to-date sales of excess SO2 emission
allowances and carrying costs, the ice storm regulatory asset as of June 30,
2008 was $64 million. In July 2008, PSO filed with the OCC
to establish the recovery rider and the final recoverable December 2007 ice
storm costs. The estimate of future gains from the sale of SO2 emission
allowances has significantly declined with the decrease in value of such
allowances. As a result, estimated collections from customers through
the special storm damage recovery rider will be higher than the estimate in the
settlement agreement. Nonetheless, management believes that the
settlement provides for full recovery of the remaining deferral.
2008
Oklahoma Annual Fuel Factor Filing
In May
2008, pursuant to its tariff, PSO filed its annual update with the OCC for
increases in the various service level fuel factors based on estimated increases
in fuel, primarily natural gas and purchased power expenses, of approximately
$300 million. The request included recovery of $26 million in
under-recovered deferred fuel. In June 2008, PSO implemented the fuel
factor increase. Because of the substantial increase, the OCC held an
administrative proceeding to determine whether the proposed charges were based
upon the appropriate coal, purchased gas and purchased power prices and were
properly computed. In June 2008, the OCC ordered that PSO properly
estimated the increase in natural gas prices, properly determined its fuel costs
and, thus, should implement the increase.
2008
Oklahoma Base Rate Filing
In July
2008, PSO filed an application with the OCC to increase its base rates by $133
million on an annual basis. PSO recovers costs related to new peaking
units recently placed into service through the Generation Cost Recovery Rider
(GCRR). Upon implementation of the new base rates, PSO will recover
these costs through the new base rates and the GCRR will
terminate. Therefore, PSO’s net annual requested increase in total
revenues is $117 million. The requested increase is based upon a test
year ended February 29, 2008, adjusted for known and measurable changes through
August 2008, which is consistent with the ratemaking treatment adopted by the
OCC in PSO’s 2006 base rate case. The proposed revenue requirement
reflects a return on equity of 11.25%. PSO expects hearings to begin
in December 2008 and new rates effective in the first quarter of
2009.
Louisiana Rate
Matters
Louisiana
Compliance Filing
In
connection with SWEPCo’s merger related compliance filings, the LPSC approved a
settlement agreement in April 2008 that prospectively resolves all issues
regarding claims that SWEPCo had over-earned its allowed
return. SWEPCo agreed to a formula rate plan (FRP) with a three-year
term. Beginning August 2008, rates shall be established to allow
SWEPCo to earn an adjusted return on common equity of 10.565%. The
adjustments are standard Louisiana rate filing adjustments.
If in the
second and third year of the FRP, the adjusted earned return is within the range
of 10.015% to 11.115%, no adjustment to rates is necessary. However,
if the adjusted earned return is outside of the above-specified range, an FRP
rider will be established to increase or decrease rates
prospectively. If the adjusted earned return is less than 10.015%,
SWEPCo will prospectively increase rates to collect 60% of the difference
between 10.565% and the adjusted earned return. Alternatively, if the
adjusted earned return is more than 11.115%, SWEPCo will prospectively decrease
rates by 60% of the difference between the adjusted earned return and
10.565%. SWEPCo will not record over/under recovery deferrals for
refund or future recovery under this FRP.
The
settlement provides for a separate credit rider decreasing Louisiana retail base
rates by $5 million prospectively over the entire three year term of the FRP,
which shall not affect the adjusted earned return in the FRP
calculation. This separate credit rider will cease effective August
2011.
In
addition, the settlement provides for a reduction in generation depreciation
rates effective October 2007. SWEPCo will defer as a regulatory
liability, the effects of the expected depreciation reduction through July
2008. SWEPCo will amortize this regulatory liability over the three
year term of the FRP as a reduction to the cost of service used to determine the
adjusted earned return.
In April
2008, SWEPCo filed the first FRP which would increase its annual Louisiana
retail rates by $11 million in August 2008 to earn an adjusted return on common
equity of 10.565%. In June 2008, SWEPCo recorded a $3 million
regulatory liability related to the reduction in generation depreciation
rates.
Stall
Unit
In May
2006, SWEPCo announced plans to build a new intermediate load 500 MW natural
gas-fired combustion turbine combined cycle generating unit (the Stall Unit) at
its existing Arsenal Hill Plant location in Shreveport,
Louisiana. SWEPCo submitted the appropriate filings to the PUCT, the
APSC, the LPSC and the Louisiana Department of Environmental Quality to seek
approvals to construct the unit. The Stall Unit is estimated to cost
$378 million, excluding AFUDC, and is expected to be in-service in
mid-2010.
In March
2007, the PUCT approved SWEPCo’s request for a certificate for the facility
based on a prior cost estimate. In February 2008, the LPSC staff
submitted testimony in support of the Stall Unit and one intervenor submitted
testimony opposing the Stall Unit due to the increase in cost. The
LPSC held hearings in April 2008. In July 2008, an ALJ in the LPSC
proceeding recommended approval of the Stall Unit. The APSC has not
established a procedural schedule at this time. The Louisiana
Department of Environmental Quality issued an air permit for the unit in March
2008. If SWEPCo does not receive appropriate authorizations and
permits to build the Stall Unit, SWEPCo would seek recovery of the capitalized
pre-construction costs including any cancellation fees. As of June
30, 2008, SWEPCo has capitalized pre-construction costs of $106 million and has
contractual construction commitments of an additional $191
million. As of June 30, 2008, if the plant had been canceled,
cancellation fees of $60 million would have been required in order to terminate
these construction commitments. If SWEPCo canceled the plant and
cannot recover its capitalized costs, including any cancellation fees, it would
have an adverse effect on future results of operations and cash
flows.
Turk
Plant
See “Turk
Plant” section within Arkansas Rate Matters for disclosure.
Arkansas Rate
Matters
Turk
Plant
In August
2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW
pulverized coal ultra-supercritical generating unit in
Arkansas. Ultra-supercritical technology uses higher temperatures and
higher pressures to produce electricity more efficiently – thereby using less
fuel and providing substantial emissions reductions. SWEPCo submitted
filings with the APSC, the PUCT and the LPSC seeking certification of the
plant. SWEPCo will own 73% of the Turk Plant and will operate the
facility. During 2007, SWEPCo signed joint ownership agreements with
the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative
Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the
remaining 27% of the Turk Plant. The Turk Plant is estimated to cost
$1.5 billion with SWEPCo’s portion estimated to cost $1.1 billion, excluding
AFUDC. If approved on a timely basis, the plant is expected to be
in-service in 2012.
In
November 2007, the APSC granted approval to build the plant. Certain
landowners filed a notice of appeal to the Arkansas State Court of
Appeals. In March 2008, the LPSC approved the application to
construct the Turk Plant. In July 2008, the PUCT approved a
certificate of convenience and necessity for construction of the
plant. We expect a written order in August 2008 which will also
provide for the conditions of the PUCT’s approval.
SWEPCo is
working with the Arkansas Department of Environmental Quality and the U.S. Army
Corps of Engineers for approval later this year. A request to stop
pre-construction activities at the site was filed in Federal court by the same
Arkansas landowners who appealed the APSC decision to the Arkansas State Court
of Appeals. In July 2008, the Federal court denied the request and
the Arkansas landowners appealed the denial to the U.S. Court of
Appeals.
If SWEPCo
does not receive appropriate authorizations and permits to build the Turk Plant,
SWEPCo could incur significant cancellation fees to terminate its commitments
and would be responsible to reimburse OMPA, AECC and ETEC for their share of
paid costs. If that occurred, SWEPCo would seek recovery of its
capitalized costs including any cancellation fees and joint owner
reimbursements. As of June 30, 2008, including the joint owners’
share, SWEPCo has capitalized approximately $407 million of expenditures and has
significant contractual construction commitments for an additional $815
million. As of June 30, 2008, if the plant had been canceled,
cancellation fees of $60 million would have been required in order to terminate
these construction commitments. If SWEPCo cannot recover its costs,
it would have an adverse effect on future results of operations, cash flows and
possibly financial condition.
Stall
Unit
See
“Stall Unit” section within Louisiana Rate Matters for disclosure.
FERC Rate
Matters
Regional
Transmission Rate Proceedings at the FERC
SECA Revenue Subject to
Refund
Effective
December 1, 2004, AEP eliminated transaction-based through-and-out transmission
service (T&O) charges in accordance with FERC orders and collected at FERC’s
direction load-based charges, referred to as RTO SECA, to partially mitigate the
loss of T&O revenues on a temporary basis through March 31,
2006. Intervenors objected to the temporary SECA rates, raising
various issues. As a result, the FERC set SECA rate issues for
hearing and ordered that the SECA rate revenues be collected, subject to
refund. The AEP East companies paid SECA rates to other utilities at
considerably lesser amounts than they collected. If a refund is
ordered, the AEP East companies would also receive refunds related to the SECA
rates they paid to third parties. The AEP East companies recognized
gross SECA revenues of $220 million from December 2004 through March 2006 when
the SECA rates terminated leaving the AEP East companies and ultimately their
internal load retail customers to make up the short fall in
revenues.
In August
2006, a FERC ALJ issued an initial decision, finding that the rate design for
the recovery of SECA charges was flawed and that a large portion of the “lost
revenues” reflected in the SECA rates should not have been
recoverable. The ALJ found that the SECA rates charged were unfair,
unjust and discriminatory and that new compliance filings and refunds should be
made. The ALJ also found that the unpaid SECA rates must be paid in
the recommended reduced amount.
In
September 2006, AEP filed briefs jointly with other affected companies noting
exceptions to the ALJ’s initial decision and asking the FERC to reverse the
decision in large part. Management believes that the FERC should
reject the ALJ’s initial decision because it contradicts prior related FERC
decisions, which are presently subject to rehearing. Furthermore,
management believes the ALJ’s findings on key issues are largely without
merit. AEP and SECA ratepayers have engaged in settlement
discussions in an effort to settle the SECA issue. However, if the
ALJ’s initial decision is upheld in its entirety, it could result in a
disallowance of a large portion on any unsettled SECA revenues.
During
2006, the AEP East companies provided reserves of $37 million for net refunds
for current and future SECA settlements. After reviewing existing
settlements, the AEP East companies increased their reserves by an additional $5
million in December 2007.
Completed
and in-process settlements cover $107 million of the $220 million of SECA
revenues and will consume about $7 million of the reserve for refund, leaving
approximately $113 million of contested SECA revenues and $35 million of refund
reserves.
If the
FERC adopts the ALJ’s decision and/or AEP cannot settle the remaining unsettled
claims within the amount reserved for refunds, it will have an adverse effect on
future results of operations and cash flows. Based on advice of
external FERC counsel, recent settlement experience and the expectation that
most of the unsettled SECA revenues will be settled, management believes that
the remaining reserve of $35 million is adequate to cover all remaining
settlements. However, management cannot predict the ultimate outcome
of ongoing settlement discussions or future FERC proceedings or court appeals,
if such are necessary.
The FERC PJM Regional
Transmission Rate Proceeding
With the
elimination of T&O rates and the expiration of SECA rates and after
considerable administrative litigation at the FERC in which AEP sought to
mitigate the effect of T&O rate elimination, the FERC failed to implement a
regional rate in PJM. As a result, the AEP East companies’ retail
customers incur the bulk of the cost of the existing AEP east transmission zone
facilities. However, the FERC ruled that the cost of any new 500 kV
and higher voltage transmission facilities built in PJM would be shared by all
customers in the region. It is expected that most of the new 500 kV
and higher voltage transmission facilities will be built in other zones of PJM,
not AEP’s zone. The AEP East companies will need to obtain regulatory
approvals for recovery of any costs of new facilities that are assigned to
them. AEP had requested rehearing of this order, which the FERC
denied. In February 2008, AEP filed a Petition for Review of the FERC
orders in this case in the United States Court of Appeals. Management
cannot estimate at this time what effect, if any, this order will have on the
AEP East companies’ future construction of new transmission facilities, results
of operations and cash flows.
The AEP
East companies filed for and in 2006 obtained increases in its wholesale
transmission rates to recover lost revenues previously applied to reduce those
rates. AEP has also sought and received retail rate increases in
Ohio, Virginia, West Virginia and Kentucky. As a result, AEP is now
recovering approximately 85% of the lost T&O transmission
revenues. AEP received net SECA transmission revenues of $128 million
in 2005. I&M requested recovery of these lost revenues in its
Indiana rate filing in January 2008 but does not expect to commence recovering
the new rates until early 2009. Future results of operations and cash
flows will continue to be adversely affected in Indiana and Michigan until the
remaining 15% of the lost T&O transmission revenues are recovered in retail
rates.
The FERC PJM and MISO
Regional Transmission Rate Proceeding
In the
SECA proceedings, the FERC ordered the RTOs and transmission owners in the
PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to
establish a permanent transmission rate design for the Super Region to be
effective February 1, 2008. All of the transmission owners in PJM and
MISO, with the exception of AEP and one MISO transmission owner, elected to
support continuation of zonal rates in both RTOs. In September 2007,
AEP filed a formal complaint proposing a highway/byway rate design be
implemented for the Super Region where users pay based on their use of the
transmission system. AEP argues the use of other PJM and MISO
facilities by AEP is not as large as the use of AEP transmission by others in
PJM and MISO. Therefore, a regional rate design change is required to
recognize that the provision and use of transmission service in the Super Region
is not sufficiently uniform between transmission owners and users to justify
zonal rates. In January 2008, the FERC denied AEP’s
complaint. AEP filed a rehearing request with the FERC in March
2008. Should this effort be successful, earnings could benefit for a
certain period due to regulatory lag; however, AEP East companies would reduce
future retail revenues in their next fuel or base rate
proceedings. Management is unable to predict the outcome of this
case.
PJM
Transmission Formula Rate Filing
In July
2008, AEP filed an application with the FERC to increase its rates for
wholesale transmission service within PJM. The filing seeks to
implement a formula rate allowing annual adjustments reflecting future changes
in AEP's cost of service. The requested increase would result in
additional annual revenues of approximately $9 million from nonaffiliated
customers within PJM. AEP requested an effective date of
October 1, 2008. Retail rates are not immediately affected by the
filing at the FERC, but retail rates in Ohio would reflect the revised
FERC transmission rate through the Transmission Cost Recovery Rider (TCRR)
effective January 2009 resulting in additional annual revenues of approximately
$22 million. Management is unable to predict the outcome of this
filing.
FERC
Market Power Mitigation
FERC
allows utilities to sell wholesale power at market-based rates if they can
demonstrate that they lack market power in the markets in which they
participate. Sellers with market rate authority must, at least every
three years, update their studies demonstrating lack of market
power. In December 2007, AEP filed its most recent triennial
update. In March and May 2008, the PUCO filed comments suggesting
that FERC should further investigate whether AEP continues to pass FERC’s
indicative screens for the lack of market power in PJM. Certain
industrial retail customers also urged FERC to further investigate this
matter. AEP responded that its market power studies were performed in
accordance with FERC’s guidelines, and continue to demonstrate lack of market
power. Management is unable to predict the outcome of this proceeding; however,
if a further investigation by the FERC limits AEP’s ability to sell power at
market based rates in PJM, it would result in an adverse effect on future
off-system sales margins, results of operations and cash flows.
4.
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COMMITMENTS,
GUARANTEES AND CONTINGENCIES
|
We are
subject to certain claims and legal actions arising in our ordinary course of
business. In addition, our business activities are subject to
extensive governmental regulation related to public health and the
environment. The ultimate outcome of such pending or potential
litigation against us cannot be predicted. For current proceedings
not specifically discussed below, management does not anticipate that the
liabilities, if any, arising from such proceedings would have a material adverse
effect on our financial statements. The Commitments, Guarantees and
Contingencies note within our 2007 Annual Report should be read in conjunction
with this report.
GUARANTEES
There are
certain immaterial liabilities recorded for guarantees in accordance with FASB
Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others.” There is no collateral held in relation to any guarantees in
excess of our ownership percentages. In the event any guarantee is
drawn, there is no recourse to third parties unless specified
below.
Letters
Of Credit
We enter
into standby letters of credit (LOCs) with third parties. These LOCs
cover items such as gas and electricity risk management contracts, construction
contracts, insurance programs, security deposits and debt service
reserves. As the Parent, we issued all of these LOCs in our ordinary
course of business on behalf of our subsidiaries. At June 30, 2008,
the maximum future payments for LOCs issued under the two $1.5 billion credit
facilities are approximately $58 million with maturities ranging from August
2008 to October 2009.
In April
2008, we entered into a $650 million 3-year credit agreement and a $350 million
364-day credit agreement. As of June 30, 2008, $371 million of
letters of credit were issued by subsidiaries under the 3-year credit agreement
to support variable rate demand notes.
Guarantees
Of Third-Party Obligations
SWEPCo
As part
of the process to receive a renewal of a Texas Railroad Commission permit for
lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of
approximately $65 million. Since SWEPCo uses self-bonding, the
guarantee provides for SWEPCo to commit to use its resources to complete the
reclamation in the event the work is not completed by Sabine Mining Company
(Sabine), an entity consolidated under FIN 46R. This guarantee ends
upon depletion of reserves and completion of final reclamation. Based
on the latest study, we estimate the reserves will be depleted in 2029 with
final reclamation completed by 2036, at an estimated cost of approximately $39
million. As of June 30, 2008, SWEPCo has collected approximately $36
million through a rider for final mine closure costs, of which approximately $7
million is recorded in Other Current Liabilities, $8 million is recorded in
Asset Retirement Obligations and $21 million is recorded in Deferred Credits and
Other on our Condensed Consolidated Balance Sheets.
Sabine
charges SWEPCo, its only customer, all its costs. SWEPCo passes these
costs through its fuel clause.
Indemnifications
And Other Guarantees
Contracts
We enter
into several types of contracts which require
indemnifications. Typically these contracts include, but are not
limited to, sale agreements, lease agreements, purchase agreements and financing
agreements. Generally, these agreements may include, but are not
limited to, indemnifications around certain tax, contractual and environmental
matters. With respect to sale agreements, our exposure generally does
not exceed the sale price. The status of certain sales agreements is
discussed in the 2007 Annual Report, “Dispositions” section of Note
8. These sale agreements include indemnifications with a maximum
exposure related to the collective purchase price, which is approximately $1.3
billion (approximately $1 billion relates to the Bank of America (BOA)
litigation, see “Enron Bankruptcy” section of this note). There are
no material liabilities recorded for any indemnifications other than amounts
recorded related to the BOA litigation.
Master Operating
Lease
We lease
certain equipment under a master operating lease. Under the lease
agreement, the lessor is guaranteed receipt of up to 87% of the unamortized
balance of the equipment at the end of the lease term. If the fair
market value of the leased equipment is below the unamortized balance at the end
of the lease term, we are committed to pay the difference between the fair
market value and the unamortized balance, with the total guarantee not to exceed
87% of the unamortized balance. Historically, at the end of the lease
term the fair market value has been in excess of the unamortized
balance. At June 30, 2008, the maximum potential loss for these lease
agreements was approximately $66 million ($43 million, net of tax) assuming the
fair market value of the equipment is zero at the end of the lease
term.
Railcar
Lease
In June
2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered
into an agreement with BTM Capital Corporation, as lessor, to lease 875
coal-transporting aluminum railcars. The lease is accounted for as an
operating lease. We intend to maintain the lease for twenty years,
via renewal options. Under the lease agreement, the lessor is
guaranteed that the sale proceeds under a return-and-sale option will equal at
least a lessee obligation amount specified in the lease, which declines over the
current lease term from approximately 84% to 77% of the projected fair market
value of the equipment.
In
January 2008, AEP Transportation assigned the remaining 848 railcars under the
original lease agreement to I&M (390 railcars) and SWEPCo (458
railcars). The assignment is accounted for as new operating leases
for I&M and SWEPCo. The future minimum lease obligation is $21
million for I&M and $24 million for SWEPCo as of June 30,
2008. I&M and SWEPCo intend to renew these leases for the full
remaining terms and have assumed the guarantee under the return-and-sale
option. I&M’s maximum potential loss related to the guarantee
discussed above is approximately $12 million ($8 million, net of tax) and
SWEPCo’s is approximately $14 million ($9 million, net of tax).
We have
other railcar lease arrangements that do not utilize this type of financing
structure.
CONTINGENCIES
Federal
EPA Complaint and Notice of Violation
The
Federal EPA, certain special interest groups and a number of states alleged that
APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired
generating plants in violation of the NSR requirements of the
CAA. The alleged modifications occurred over a 20-year
period. Cases with similar allegations against CSPCo, Dayton Power
and Light Company (DP&L) and Duke Energy Ohio, Inc. were also filed related
to their jointly-owned units.
The AEP
System settled their cases in 2007. A case is still pending that
could affect CSPCo’s share of jointly-owned units at the Stuart
Station. The Stuart units, operated by DP&L, are equipped with
SCR and flue gas desulfurization equipment (FGD or scrubbers)
controls. A trial on liability issues was scheduled for August
2008. The Court issued a stay to allow the parties to pursue
settlement discussions. Those discussions are
ongoing. Another case involving a jointly-owned Beckjord unit had a
liability trial in May 2008. Following the trial, the jury found no
liability for claims made against the jointly-owned Beckjord unit.
We are
unable to estimate the loss or range of loss related to any contingent
liability, if any, we might have for civil penalties under the pending CAA
proceedings for our jointly-owned units. If we do not prevail, we
believe we can recover any capital and operating costs of additional pollution
control equipment that may be required through market prices of
electricity. If we are unable to recover such costs or if material
penalties are imposed, it would adversely affect our future results of
operations, cash flows and possibly financial condition.
SWEPCo
Notice of Enforcement and Notice of Citizen Suit
In March
2005, two special interest groups, Sierra Club and Public Citizen, filed a
complaint in Federal District Court for the Eastern District of Texas alleging
violations of the CAA at SWEPCo’s Welsh Plant. In April 2008, the
parties filed a proposed consent decree to resolve all claims in this case and
in the pending appeal of the altered permit for the Welsh Plant. The
consent decree requires SWEPCo to install continuous particulate emission
monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010,
fund $2 million in emission reduction, energy efficiency or environmental
mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and
costs. The consent decree was entered as a final order in June
2008.
In 2004,
the Texas Commission on Environmental Quality (TCEQ) issued a Notice of
Enforcement to SWEPCo relating to the Welsh Plant. In April 2005,
TCEQ issued an Executive Director’s Report (Report) recommending the entry of an
enforcement order to undertake certain corrective actions and assessing an
administrative penalty of approximately $228 thousand against
SWEPCo. In 2008, the matter was remanded to TCEQ to pursue settlement
discussions. The original Report contained a recommendation to limit
the heat input on each Welsh unit to the referenced heat input contained within
the state permit within 10 days of the issuance of a final TCEQ order and until
the permit is changed. SWEPCo had previously requested a permit
alteration to remove the reference to a specific heat input value for each Welsh
unit and to clarify the sulfur content requirement for fuels consumed at the
plant. A permit alteration was issued in March 2007. In
June 2007, TCEQ denied a motion to overturn the permit
alteration. The permit alteration was appealed to the Travis County
District Court, but was resolved by entry of the consent decree in the federal
citizen suit action, and dismissed with prejudice in July
2008. Notice of an administrative settlement of the TCEQ enforcement
action was published in June 2008. The settlement requires SWEPCo to
pay an administrative penalty of $49 thousand and to fund a supplemental
environmental project in the amount of $49 thousand, and resolves all violations
alleged by TCEQ. The settlement will become final upon approval by
the TCEQ.
In
February 2008, the Federal EPA issued a Notice of Violation (NOV) based on
alleged violations of a percent sulfur in fuel limitation and the heat input
values listed in the previous state permit. The NOV also alleges that
the permit alteration issued by TCEQ was improper. SWEPCo met with
the Federal EPA to discuss the alleged violations in March 2008. The
Federal EPA did not object to the settlement of similar alleged violations in
the federal citizen suit.
We are
unable to predict the timing of any future action by the Federal EPA or the
effect of such action on our results of operations, cash flows or financial
condition.
Carbon
Dioxide (CO2) Public
Nuisance Claims
In 2004,
eight states and the City of New York filed an action in federal district court
for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel
Energy, Southern Company and Tennessee Valley Authority. The Natural
Resources Defense Council, on behalf of three special interest groups, filed a
similar complaint against the same defendants. The actions allege
that CO2 emissions
from the defendants’ power plants constitute a public nuisance under federal
common law due to impacts of global warming, and sought injunctive relief in the
form of specific emission reduction commitments from the
defendants. The dismissal of this lawsuit was appealed to the Second
Circuit Court of Appeals. Briefing and oral argument have
concluded. In April 2007, the U.S. Supreme Court issued a
decision holding that the Federal EPA has authority to regulate emissions of
CO2
and other greenhouse gases under the CAA, which may impact the Second Circuit’s
analysis of these issues. The Second Circuit requested supplemental
briefs addressing the impact of the U.S. Supreme Court’s decision on this
case. We believe the actions are without merit and intend to defend
against the claims.
Alaskan
Villages’ Claims
In
February 2008, the Native Village of Kivalina and the City of Kivalina,
Alaska filed a lawsuit in federal court in the Northern District of
California against AEP, AEPSC and 22 other unrelated defendants including oil
& gas companies, a coal company, and other electric generating
companies. The complaint alleges that the defendants' emissions of
CO2
contribute to global warming and constitute a public and private nuisance and
that the defendants are acting together. The complaint further
alleges that some of the defendants, including AEP, conspired to create a false
scientific debate about global warming in order to deceive the public and
perpetuate the alleged nuisance. The plaintiffs also allege that the
effects of global warming will require the relocation of the village at an
alleged cost of $95 million to $400 million. We believe the action is
without merit and intend to defend against the claims.
Clean
Air Act Interstate Rule
In 2005,
the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that
required further reductions in SO2 and
NOx
emissions and assists states developing new state implementation plans to meet
1997 national ambient air quality standards (NAAQS). CAIR reduces
regional emissions of SO2 and
NOx
(which can be transformed into PM and ozone) from power plants in the Eastern
U.S. (29 states and the District of Columbia). Reduction of both
SO2
and NOx would be
achieved through a cap-and-trade program. In July 2008, the D.C.
Circuit Court of Appeals vacated the CAIR and remanded the rule to the Federal
EPA. We are unable to predict how the Federal EPA will respond to the
remand which could be stayed or appealed to the U.S. Supreme Court.
In
anticipation of compliance with CAIR in 2009, I&M purchased $8 million of
annual CAIR NOx allowances
which are included in inventory as of June 30, 2008. The market value
of annual CAIR NOx allowances
decreased in the weeks following this court decision. Management
intends to seek recovery of the cost of purchased allowances. If the
recovery is denied, it would have an adverse effect on future results of
operations and cash flows. None of AEP’s other subsidiaries purchased
any significant number of CAIR allowances. SO2 and
seasonal NOx allowances
allocated to our facilities under the Acid Rain Program and the NOx SIP Call
will still be required to comply with existing CAA programs that were not
affected by the court’s decision.
It is too
early to determine the full implication of these decisions on environmental
compliance strategy. However, independent obligations under the CAA,
including obligations under future state implementation plan submittals, and
actions taken pursuant to the recent settlement of the NSR enforcement action,
are consistent with the actions included in a least-cost CAIR compliance
plan. Consequently, management does not anticipate making any
immediate changes in near-term compliance plans as a result of these court
decisions.
The
Comprehensive Environmental Response Compensation and Liability Act (Superfund)
and State Remediation
By-products
from the generation of electricity include materials such as ash, slag, sludge,
low-level radioactive waste and SNF. Coal combustion by-products,
which constitute the overwhelming percentage of these materials, are typically
treated and deposited in captive disposal facilities or are beneficially
utilized. In addition, our generating plants and transmission and
distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and
other hazardous and nonhazardous materials. We currently incur costs
to safely dispose of these substances.
Superfund
addresses clean-up of hazardous substances that have been released to the
environment. The Federal EPA administers the clean-up
programs. Several states have enacted similar laws. In
March 2008, I&M received a letter from the Michigan Department of
Environmental Quality (MDEQ) concerning conditions at a site under state law and
requesting I&M take voluntary action necessary to prevent and/or mitigate
public harm. I&M requested remediation proposals from
environmental consulting firms. In May 2008, I&M issued a
contract to one of the consulting firms and recorded approximately $1 million of
expense. As the remediation work is completed, I&M’s cost may
increase. I&M cannot predict the amount of additional cost, if
any. At present, our estimates do not anticipate material cleanup
costs for this site.
TEM
Litigation
We agreed
to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc.
(TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years
under a Power Purchase and Sale Agreement (PPA). Beginning May 1,
2003, we tendered replacement capacity, energy and ancillary services to TEM
pursuant to the PPA that TEM rejected as nonconforming.
In 2003,
TEM and AEP separately filed declaratory judgment actions in the United States
District Court for the Southern District of New York. We alleged that
TEM breached the PPA and sought a determination of our rights under the
PPA. TEM alleged that the PPA never became enforceable, or
alternatively, that the PPA was terminated as the result of our
breaches.
In
January 2008, we reached a settlement with TEM to resolve all litigation
regarding the PPA. TEM paid us $255 million. We recorded
the $255 million as a pretax gain in January 2008 under Asset Impairments and
Other Related Items on our Condensed Consolidated Statements of
Income. This settlement and the PPA related to the Plaquemine
Cogeneration Facility which was impaired and sold in 2006.
Enron
Bankruptcy
In 2001,
we purchased HPL from Enron. Various HPL-related contingencies and
indemnities from Enron remained unsettled at the date of Enron’s
bankruptcy. In connection with our acquisition of HPL, we entered
into an agreement with BAM Lease Company, which granted HPL the exclusive right
to use approximately 55 billion cubic feet (BCF) of cushion gas required for the
normal operation of the Bammel gas storage facility. At the time of
our acquisition of HPL, BOA and certain other banks (the BOA Syndicate) and
Enron entered into an agreement granting HPL the exclusive use of the cushion
gas. Also at the time of our acquisition, Enron and the BOA Syndicate
released HPL from all prior and future liabilities and obligations in connection
with the financing arrangement. After the Enron bankruptcy, the BOA
Syndicate informed HPL of a purported default by Enron under the terms of the
financing arrangement. This dispute is being litigated in the Enron
bankruptcy proceedings and in Federal courts in Texas and New York.
In
February 2004, Enron filed Notices of Rejection regarding the cushion gas
exclusive right to use agreement and other incidental agreements. We
objected to Enron’s attempted rejection of these agreements and filed an
adversary proceeding contesting Enron’s right to reject these
agreements.
In 2003,
AEP filed a lawsuit against BOA in the United States District Court for the
Southern District of Texas. BOA led the lending syndicate involving
the monetization of the cushion gas to Enron and its
subsidiaries. The lawsuit asserts that BOA made misrepresentations
and engaged in fraud to induce and promote the stock sale of HPL, that BOA
directly benefited from the sale of HPL and that AEP undertook the stock
purchase and entered into the cushion gas arrangement with Enron and BOA based
on misrepresentations that BOA made about Enron’s financial condition that BOA
knew or should have known were false. In April 2005, the Judge
entered an order severing and transferring the declaratory judgment claims
involving the right to use and cushion gas consent agreements to the Southern
District of New York and retaining the four counts alleging breach of contract,
fraud and negligent misrepresentation in the Southern District of
Texas. HPL and BOA filed motions for summary judgment in the case
pending in the Southern District of New York. Trial in federal court
in Texas was continued pending a decision on the motions for summary judgment in
the New York case.
In August
2007, the judge in the New York action issued a decision granting BOA summary
judgment and dismissing our claims. In December 2007, the judge held
that BOA is entitled to recover damages of approximately $347 million ($437
million and $427 million including interest at June 30, 2008 and December 31,
2007, respectively) less a to be determined amount BOA would have incurred to
remove 55 BCF of natural gas from the Bammel storage facility. The
judge denied our Motion for Reconsideration. We plan to appeal the
court’s decision once the court enters a final judgment. If the Court
enters a final judgment adverse to us and we appeal from the judgment, we will
be required under court rules to post security in the form of a bond or stand-by
letter of credit covering the amount of the judgment entered against
us.
In 2005,
we sold our interest in HPL. We indemnified the buyer of HPL against
any damages resulting from the BOA litigation up to the purchase
price. The amounts discussed above are included in Deferred Credits
and Other on our Condensed Consolidated Balance Sheets.
Shareholder
Lawsuits
In 2002
and 2003, three putative class action lawsuits were filed against AEP, certain
executives and AEP’s Employee Retirement Income Security Act (ERISA) Plan
Administrator alleging violations of ERISA in the selection of AEP stock as an
investment alternative and in the allocation of assets to AEP
stock. The ERISA actions were pending in Federal District Court,
Columbus, Ohio. In these actions, the plaintiffs sought recovery of
an unstated amount of compensatory damages, attorney fees and
costs. Two of the three actions were dropped voluntarily by the
plaintiffs in those cases. In July 2006, the Court entered judgment
in the remaining case, denying plaintiff’s motion for class certification and
dismissing all claims without prejudice. In August 2007, the appeals
court reversed the trial court’s decision and held that the plaintiff did have
standing to pursue his claim. The appeals court remanded the case to the trial
court to consider the issue of whether the plaintiff is an adequate
representative for the class of plan participants. We intend to
continue to defend against these claims.
Natural
Gas Markets Lawsuits
In 2002,
the Lieutenant Governor of California filed a lawsuit in Los Angeles County
California Superior Court against numerous energy companies, including AEP,
alleging violations of California law through alleged fraudulent reporting of
false natural gas price and volume information with an intent to affect the
market price of natural gas and electricity. AEP was dismissed from
the case. A number of similar cases were also filed in California and
in state and federal courts in several states making essentially the same
allegations under federal or state laws against the same
companies. AEP (or a subsidiary) is among the companies named as
defendants in some of these cases. These cases are at various
pre-trial stages. In June 2008, we settled all of the cases pending
against us in California state court along with all of the cases brought against
us in federal court by plaintiffs in California. The settlements did
not impact 2008 earnings due to provisions made in prior periods. We
will continue to defend each remaining case where an AEP company is a
defendant. We believe the remaining provision balance is
adequate.
FERC
Long-term Contracts
In 2002,
the FERC held a hearing related to a complaint filed by Nevada Power Company and
Sierra Pacific Power Company (the Nevada utilities). The complaint
sought to break long-term contracts entered during the 2000 and 2001 California
energy price spike which the customers alleged were
“high-priced.” The complaint alleged that we sold power at unjust and
unreasonable prices because the market for power was allegedly dysfunctional at
the time such contracts were executed. In 2003, the FERC rejected the
complaint. In 2006, the U.S. Court of Appeals for the Ninth Circuit
reversed the FERC order and remanded the case to the FERC for further
proceedings. That decision was appealed to the U.S. Supreme
Court. In June 2008, the U.S. Supreme Court affirmed the validity of
contractually-agreed rates except in cases of serious harm to the
public. The U.S. Supreme Court affirmed the Ninth Circuit’s remand on
two issues, market manipulation and excessive burden on
consumers. Management is unable to predict the outcome of these
proceedings or their impact on future results of operations and cash
flows. We have asserted claims against certain companies that sold
power to us, which we resold to the Nevada utilities, seeking to recover a
portion of any amounts we may owe to the Nevada utilities.
5.
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ACQUISITIONS,
DISPOSITIONS AND DISCONTINUED
OPERATIONS
|
ACQUISITIONS
2008
Erlbacher
companies (MEMCO Operations segment)
In June
2008, MEMCO purchased certain barging assets from Missouri Barge Line Company,
Missouri Dry Dock and Repair Company and Cape Girardeau Fleeting, Inc.
(collectively known as Erlbacher companies) for $35 million. These
assets were incorporated into MEMCO’s operations which will diversify its
customer base.
2007
Darby
Electric Generating Station (Utility Operations segment)
In
November 2006, CSPCo agreed to purchase Darby Electric Generating Station
(Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light
Company, for $102 million and the assumption of liabilities of $2
million. CSPCo completed the purchase in April 2007. The
Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple
cycle power plant with a generating capacity of 480 MW.
Lawrenceburg
Generating Station (Utility Operations segment)
In
January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station
(Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for
$325 million and the assumption of liabilities of $3 million. AEGCo
completed the purchase in May 2007. The Lawrenceburg plant is located
in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a
natural gas, combined cycle power plant with a generating capacity of 1,096
MW. AEGCo sells the power to CSPCo through a FERC-approved unit power
agreement.
DISPOSITIONS
2008
None
2007
Texas
Plants – Oklaunion Power Station (Utility Operations segment)
In
February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public
Utilities Board of the City of Brownsville for $43 million plus working capital
adjustments. The sale did not have an impact on our results of
operations nor do we expect any remaining litigation to have a significant
effect on our results of operations.
Intercontinental
Exchange, Inc. (ICE) (All Other)
In March
2007, we sold 130,000 shares of ICE and recognized a $16 million pretax gain
($10 million, net of tax). We recorded the gain in Interest and
Investment Income on our 2007 Condensed Consolidated Statement of
Income. Our remaining investment of approximately 138,000 shares at
June 30, 2008 and December 31, 2007 is recorded in Other Temporary Investments
on our Condensed Consolidated Balance Sheets.
Texas
REPs (Utility Operations segment)
As part
of the purchase-and-sale agreement related to the sale of our Texas REPs in
2002, we retained the right to share in earnings with Centrica from the two REPs
above a threshold amount through 2006 if the Texas retail market developed
increased earnings opportunities. In 2007, we received the final
earnings sharing payment of $20 million. This payment is reflected in
Gain on Disposition of Assets, Net on our Condensed Consolidated Statement of
Income.
DISCONTINUED
OPERATIONS
We
determined that certain of our operations were discontinued operations and
classified them as such for all periods presented. We recorded the
following in 2008 and 2007 related to discontinued operations:
|
|
U.K.
Generation (a)
|
|
Three
Months Ended June 30,
|
|
(in
millions)
|
|
2008
Revenue
|
|
$
|
-
|
|
2008
Pretax Income
|
|
|
2
|
|
2008
Earnings, Net of Tax
|
|
|
1
|
|
|
|
|
|
|
2007
Revenue
|
|
$
|
-
|
|
2007
Pretax Income
|
|
|
3
|
|
2007
Earnings, Net of Tax
|
|
|
2
|
|
|
|
U.K.
Generation (a)
|
|
Six
Months Ended June 30,
|
|
(in
millions)
|
|
2008
Revenue
|
|
$
|
-
|
|
2008
Pretax Income
|
|
|
2
|
|
2008
Earnings, Net of Tax
|
|
|
1
|
|
|
|
|
|
|
2007
Revenue
|
|
$
|
-
|
|
2007
Pretax Income
|
|
|
3
|
|
2007
Earnings, Net of Tax
|
|
|
2
|
|
(a)
|
The
2008 amounts relate to final proceeds received for the sale of land
related to the sale of U.K. Generation. The 2007 amounts relate
to tax adjustments from the sale of U.K.
Generation.
|
There
were no cash flows used for or provided by operating, investing or financing
activities related to our discontinued operations for the six months ended June
30, 2008 and 2007.
6. BENEFIT
PLANS
Components
of Net Periodic Benefit Cost
The
following tables provide the components of our net periodic benefit cost for the
plans for the three and six months ended June 30, 2008 and 2007:
|
|
|
Other
Postretirement
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
Three
Months Ended June 30,
|
|
Three
Months Ended June 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Service
Cost
|
$ |
25 |
|
$ |
23 |
|
$ |
11 |
|
$ |
11 |
|
Interest
Cost
|
|
62 |
|
|
57 |
|
|
28 |
|
|
26 |
|
Expected
Return on Plan Assets
|
|
(84
|
) |
|
(82
|
) |
|
(28
|
) |
|
(26
|
) |
Amortization
of Transition Obligation
|
|
- |
|
|
- |
|
|
7 |
|
|
7 |
|
Amortization
of Net Actuarial Loss
|
|
10 |
|
|
14 |
|
|
2 |
|
|
3 |
|
Net
Periodic Benefit Cost
|
$ |
13 |
|
$ |
12 |
|
$ |
20 |
|
$ |
21 |
|
|
|
|
Other
Postretirement
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
Six
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Service
Cost
|
$ |
50 |
|
$ |
47 |
|
$ |
21 |
|
$ |
21 |
|
Interest
Cost
|
|
125 |
|
|
116 |
|
|
56 |
|
|
52 |
|
Expected
Return on Plan Assets
|
|
(168
|
) |
|
(167
|
) |
|
(56
|
) |
|
(52
|
) |
Amortization
of Transition Obligation
|
|
- |
|
|
- |
|
|
14 |
|
|
14 |
|
Amortization
of Net Actuarial Loss
|
|
19 |
|
|
29 |
|
|
5 |
|
|
6 |
|
Net
Periodic Benefit Cost
|
$ |
26 |
|
$ |
25 |
|
$ |
40 |
|
$ |
41 |
|
As
outlined in our 2007 Annual Report, our primary business strategy and the core
of our business are to focus on our electric utility
operations. Within our Utility Operations segment, we centrally
dispatch generation assets and manage our overall utility operations on an
integrated basis because of the substantial impact of cost-based rates and
regulatory oversight. Generation/supply in Ohio continues to have
commission-determined rates transitioning from cost-based to market-based
rates. The legislature in Ohio is currently considering
possibly returning to some form of cost-based rate-regulation or a hybrid form
of rate-regulation for generation. While our Utility Operations
segment remains our primary business segment, other segments include our MEMCO
Operations segment with significant barging activities and our Generation and
Marketing segment, which includes our nonregulated generating, marketing and
risk management activities in the ERCOT market area. Intersegment
sales and transfers are generally based on underlying contractual arrangements
and agreements.
Our
reportable segments and their related business activities are as
follows:
Utility
Operations
·
|
Generation
of electricity for sale to U.S. retail and wholesale
customers.
|
·
|
Electricity
transmission and distribution in the
U.S.
|
MEMCO
Operations
·
|
Barging
operations that annually transport approximately 35 million tons of coal
and dry bulk commodities primarily on the Ohio, Illinois and lower
Mississippi Rivers. Approximately 39% of the barging is for
transportation of agricultural products, 30% for coal, 14% for steel and
17% for other commodities. Effective July 30, 2008, AEP MEMCO LLC's
name was changed to AEP River Operations,
LLC.
|
Generation
and Marketing
·
|
Wind
farms and marketing and risk management activities primarily in
ERCOT.
|
The
remainder of our activities is presented as All Other. While not
considered a business segment, All Other includes:
·
|
Parent’s
guarantee revenue received from affiliates, investment income, interest
income and interest expense and other nonallocated
costs.
|
·
|
Forward
natural gas contracts that were not sold with our natural gas pipeline and
storage operations in 2004 and 2005. These contracts are
financial derivatives which will gradually liquidate and completely expire
in 2011.
|
·
|
The
first quarter 2008 cash settlement of a purchase power and sale agreement
with TEM related to the Plaquemine Cogeneration Facility which was sold in
the fourth quarter of 2006.
|
·
|
Revenue
sharing related to the Plaquemine Cogeneration
Facility.
|
The
tables below present our reportable segment information for the three and six
months ended June 30, 2008 and 2007 and balance sheet information as of June 30,
2008 and December 31, 2007. These amounts include certain estimates
and allocations where necessary. We reclassified prior year amounts to conform
to the current year’s segment presentation. See “FSP FIN 39-1
“Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2 for
discussion of changes in netting certain balance sheet amounts.
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
Three
Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
3,200
|
(d)
|
$
|
144
|
|
$
|
137
|
|
$
|
65
|
|
$
|
-
|
|
$
|
3,546
|
|
|
Other
Operating Segments
|
|
|
113
|
(d)
|
|
7
|
|
|
(26
|
)
|
|
(57
|
)
|
|
(37
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
3,313
|
|
$
|
151
|
|
$
|
111
|
|
$
|
8
|
|
$
|
(37
|
)
|
$
|
3,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued Operations and Extraordinary
Loss
|
|
$
|
263
|
|
$
|
3
|
|
$
|
26
|
|
$
|
(12
|
)
|
$
|
-
|
|
$
|
280
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
-
|
|
|
1
|
|
Net
Income (Loss)
|
|
$
|
263
|
|
$
|
3
|
|
$
|
26
|
|
$
|
(11
|
)
|
$
|
-
|
|
$
|
281
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
Three
Months Ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
2,818
|
(d)
|
$
|
116
|
|
$
|
218
|
|
$
|
(6
|
)
|
$
|
-
|
|
$
|
3,146
|
|
|
Other
Operating Segments
|
|
|
136
|
(d)
|
|
3
|
|
|
(113
|
)
|
|
12
|
|
|
(38
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
2,954
|
|
$
|
119
|
|
$
|
105
|
|
$
|
6
|
|
$
|
(38
|
)
|
$
|
3,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued Operations and Extraordinary
Loss
|
|
$
|
238
|
|
$
|
7
|
|
$
|
15
|
|
$
|
(3
|
)
|
$
|
-
|
|
$
|
257
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
-
|
|
|
2
|
|
Extraordinary
Loss, Net of Tax
|
|
|
(79
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(79
|
)
|
Net
Income (Loss)
|
|
$
|
159
|
|
$
|
7
|
|
$
|
15
|
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
180
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
Six
Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
6,210
|
(d)
|
$
|
282
|
|
$
|
408
|
|
$
|
113
|
|
$
|
-
|
|
$
|
7,013
|
|
|
Other
Operating Segments
|
|
|
397
|
(d)
|
|
11
|
|
|
(238
|
)
|
|
(100
|
)
|
|
(70
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
6,607
|
|
$
|
293
|
|
$
|
170
|
|
$
|
13
|
|
$
|
(70
|
)
|
$
|
7,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations
and
Extraordinary Loss
|
|
$
|
673
|
|
$
|
10
|
|
$
|
27
|
|
$
|
143
|
|
$
|
-
|
|
$
|
853
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
-
|
|
|
1
|
|
Net
Income
|
|
$
|
673
|
|
$
|
10
|
|
$
|
27
|
|
$
|
144
|
|
$
|
-
|
|
$
|
854
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
5,704
|
(d)
|
$
|
233
|
|
$
|
333
|
|
$
|
45
|
|
$
|
-
|
|
$
|
6,315
|
|
|
Other
Operating Segments
|
|
|
283
|
(d)
|
|
6
|
|
|
(186
|
)
|
|
(33
|
)
|
|
(70
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
5,987
|
|
$
|
239
|
|
$
|
147
|
|
$
|
12
|
|
$
|
(70
|
)
|
$
|
6,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations
and
Extraordinary Loss
|
|
$
|
491
|
|
$
|
22
|
|
$
|
14
|
|
$
|
1
|
|
$
|
-
|
|
$
|
528
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
-
|
|
|
2
|
|
Extraordinary
Loss, Net of Tax
|
|
|
(79
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(79
|
)
|
Net
Income
|
|
$
|
412
|
|
$
|
22
|
|
$
|
14
|
|
$
|
3
|
|
$
|
-
|
|
$
|
451
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
(c)
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
June
30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Property, Plant and Equipment
|
|
$
|
46,776
|
|
$
|
302
|
|
$
|
576
|
|
$
|
42
|
|
$
|
(245
|
)
|
$
|
47,451
|
|
Accumulated
Depreciation and
Amortization
|
|
|
16,266
|
|
|
66
|
|
|
126
|
|
|
7
|
|
|
(18
|
)
|
|
16,447
|
|
Total
Property, Plant and Equipment – Net
|
|
$
|
30,510
|
|
$
|
236
|
|
$
|
450
|
|
$
|
35
|
|
$
|
(227
|
)
|
$
|
31,004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
41,519
|
|
$
|
374
|
|
$
|
953
|
|
$
|
13,182
|
|
$
|
(13,332
|
)(b)
|
$
|
42,696
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
(c)
|
|
Consolidated
|
|
December
31, 2007
|
|
(in
millions)
|
|
Total
Property, Plant and Equipment
|
|
$
|
45,514
|
|
$
|
263
|
|
$
|
567
|
|
$
|
38
|
|
$
|
(237
|
)
|
$
|
46,145
|
|
Accumulated
Depreciation and
Amortization
|
|
|
16,107
|
|
|
61
|
|
|
112
|
|
|
7
|
|
|
(12
|
)
|
|
16,275
|
|
Total
Property, Plant and Equipment – Net
|
|
$
|
29,407
|
|
$
|
202
|
|
$
|
455
|
|
$
|
31
|
|
$
|
(225
|
)
|
$
|
29,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
39,298
|
|
$
|
340
|
|
$
|
697
|
|
$
|
12,117
|
|
$
|
(12,133
|
)(b)
|
$
|
40,319
|
|
(a)
|
All
Other includes:
|
|
·
|
Parent’s
guarantee revenue received from affiliates, investment income, interest
income and interest expense and other nonallocated
costs.
|
|
·
|
Forward
natural gas contracts that were not sold with our natural gas pipeline and
storage operations in 2004 and 2005. These contracts are
financial derivatives which will gradually liquidate and completely expire
in 2011.
|
|
·
|
The
first quarter 2008 cash settlement of a purchase power and sale agreement
with TEM related to the Plaquemine Cogeneration Facility which was sold in
the fourth quarter of 2006. The cash settlement of $255 million
($163 million, net of tax) is included in Net Income.
|
|
·
|
Revenue
sharing related to the Plaquemine Cogeneration
Facility.
|
(b)
|
Reconciling
Adjustments for Total Assets primarily include the elimination of
intercompany advances to affiliates and intercompany accounts receivable
along with the elimination of AEP’s investments in subsidiary
companies.
|
(c)
|
Includes
eliminations due to an intercompany capital lease.
|
(d)
|
PSO
and SWEPCo transferred certain existing ERCOT energy marketing contracts
to AEP Energy Partners, Inc. (AEPEP) (Generation and Marketing segment)
and entered into intercompany financial and physical purchase and sales
agreements with AEPEP. As a result, we reported third-party net
purchases for these energy marketing contracts as a reduction of Revenues
from External Customers for the Utility Operations
segment. This is offset by the Utility Operations segment’s
related sales to AEPEP in Revenues from Other Operating Segments of $26
million and $113 million for the three months ended June 30, 2008 and
2007, respectively, and $238 million and $186 million for the six months
ended June 30, 2008 and 2007, respectively. The Generation and
Marketing segment reports purchases related to these contracts as a
reduction to Revenues from Other Operating
segments.
|
We
adopted FIN 48 as of January 1, 2007. As a result, we recognized an
increase in liabilities for unrecognized tax benefits, as well as related
interest and penalties, which was accounted for as a reduction to the January 1,
2007 balance of retained earnings.
We, along
with our subsidiaries, file a consolidated federal income tax
return. The allocation of the AEP System’s current consolidated
federal income tax to the AEP System companies allocates the benefit of current
tax losses to the AEP System companies giving rise to such losses in determining
their current expense. The tax benefit of the Parent is allocated to
our subsidiaries with taxable income. With the exception of the loss
of the Parent, the method of allocation reflects a separate return result for
each company in the consolidated group.
We are no
longer subject to U.S. federal examination for years before
2000. However, we have filed refund claims with the IRS for years
1997 through 2000 for the CSW pre-merger tax period, which are currently being
reviewed. We have completed the exam for the years 2001 through 2003
and have issues that will be pursued at the appeals level. The
returns for the years 2004 through 2006 are presently under audit by the
IRS. Although the outcome of tax audits is uncertain, in management’s
opinion adequate provisions for income taxes have been made for potential
liabilities resulting from such matters. In addition, we accrue
interest on these uncertain tax positions. We are not aware of any
issues for open tax years that upon final resolution are expected to have a
material adverse effect on results of operations.
We, along
with our subsidiaries, file income tax returns in various state, local and
foreign jurisdictions. These taxing authorities routinely examine our
tax returns and we are currently under examination in several state and local
jurisdictions. We believe that we have filed tax returns with
positions that may be challenged by these tax authorities. However,
management does not believe that the ultimate resolution of these audits
will materially impact results of operations. With few exceptions, we
are no longer subject to state, local or non-U.S. income tax examinations by tax
authorities for years before 2000.
Federal
Tax Legislation
In 2005,
the Energy Tax Incentives Act of 2005 was signed into law. This act
created a limited amount of tax credits for the building of IGCC
plants. The credit is 20% of the eligible property in the
construction of a new plant or 20% of the total cost of repowering of an
existing plant using IGCC technology. In the case of a newly
constructed IGCC plant, eligible property is defined as the components necessary
for the gasification of coal, including any coal handling and gas separation
equipment. We announced plans to construct two new IGCC plants that
may be eligible for the allocation of these credits. We filed
applications for the West Virginia and Ohio IGCC projects with the DOE and
the IRS. Both projects were certified by the DOE and qualified by the
IRS. However, neither project was awarded credits during the first
round of credit awards. After one of the original credit recipients
surrendered their credits in the Fall of 2007, the IRS announced a supplemental
credit round for the Spring of 2008. We filed a new application in 2008
for the West Virginia IGCC project and in July 2008 the IRS awarded the project
$134 million in credits subject to entering into a memorandum of understanding
with the IRS.
State
Tax Legislation
In March
2008, the Governor of West Virginia signed legislation providing for, among
other things, a reduction in the West Virginia corporate income tax rate from
8.75% to 8.5% beginning in 2009. The corporate income tax rate could
also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state
government achieving certain minimum levels of shortfall reserve
funds. We have evaluated the impact of the law change and the
application of the law change will not materially impact our results of
operations, cash flows or financial condition.
Long-term
Debt
|
|
June
30,
|
|
|
December
31,
|
|
Type
of Debt
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Senior
Unsecured Notes
|
|
$ |
10,940 |
|
|
$ |
9,905 |
|
Pollution
Control Bonds
|
|
|
1,747 |
|
|
|
2,190 |
|
First
Mortgage Bonds
|
|
|
- |
|
|
|
19 |
|
Notes
Payable
|
|
|
258 |
|
|
|
311 |
|
Securitization
Bonds
|
|
|
2,183 |
|
|
|
2,257 |
|
Junior
Subordinated Debentures
|
|
|
315 |
|
|
|
- |
|
Notes
Payable To Trust
|
|
|
113 |
|
|
|
113 |
|
Spent
Nuclear Fuel Obligation (a)
|
|
|
262 |
|
|
|
259 |
|
Other
Long-term Debt
|
|
|
3 |
|
|
|
2 |
|
Unamortized
Discount (net)
|
|
|
(68
|
) |
|
|
(62
|
) |
Total
Long-term Debt Outstanding
|
|
|
15,753 |
|
|
|
14,994 |
|
Less
Portion Due Within One Year
|
|
|
569 |
|
|
|
792 |
|
Long-term
Portion
|
|
$ |
15,184 |
|
|
$ |
14,202 |
|
(a)
|
Pursuant
to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has
an obligation to the United States Department of Energy for spent nuclear
fuel disposal. The obligation includes a one-time fee for
nuclear fuel consumed prior to April 7, 1983. Trust fund assets
related to this obligation of $294 million and $285 million at June 30,
2008 and December 31, 2007, respectively, are included in Spent Nuclear
Fuel and Decommissioning Trusts on our Condensed Consolidated Balance
Sheets.
|
Long-term
debt and other securities issued, retired and principal payments made during the
first six months of 2008 are shown in the tables below.
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
|
(in
millions)
|
|
(%)
|
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
AEP
|
|
Junior
Subordinated Debentures
|
|
$
|
315
|
|
8.75
|
|
2063
|
|
APCo
|
|
Pollution
Control Bonds
|
|
|
75
|
|
Variable
|
|
2036
|
|
APCo
|
|
Pollution
Control Bonds
|
|
|
50
|
|
Variable
|
|
2036
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
500
|
|
7.00
|
|
2038
|
|
CSPCo
|
|
Senior
Unsecured Notes
|
|
|
350
|
|
6.05
|
|
2018
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
25
|
|
Variable
|
|
2019
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
52
|
|
Variable
|
|
2021
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
40
|
|
5.25
|
|
2025
|
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
50
|
|
Variable
|
|
2014
|
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
50
|
|
Variable
|
|
2014
|
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
65
|
|
Variable
|
|
2036
|
|
SWEPCo
|
|
Senior
Unsecured Notes
|
|
|
400
|
|
6.45
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Registrant:
|
|
|
|
|
|
|
|
|
|
|
TCC
|
|
Pollution
Control Bonds
|
|
|
41
|
|
5.625
|
|
2017
|
|
TCC
|
|
Pollution
Control Bonds
|
|
|
120
|
|
5.125
|
|
2030
|
|
TNC
|
|
Senior
Unsecured Notes
|
|
|
30
|
|
5.89
|
|
2018
|
|
TNC
|
|
Senior
Unsecured Notes
|
|
|
70
|
|
6.76
|
|
2038
|
|
Total
Issuances
|
|
|
|
$
|
2,233
|
(a)
|
|
|
|
|
Other
than the possible dividend restrictions of the AEP Junior Subordinated
Debentures, the above borrowing arrangements do not contain guarantees,
collateral or dividend restrictions.
(a)
|
Amount
indicated on statement of cash flows of $2,204 million is net of issuance
costs and premium or discount.
|
The net
proceeds from the sale of Junior Subordinated Debentures will be used for
general corporate purposes including the payment of short-term
indebtedness.
Company
|
|
Type
of Debt
|
|
Principal
Amount Paid
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
|
(in
millions)
|
|
(%)
|
|
|
|
Retirements
and
Principal Payments:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
$
|
200
|
|
3.60
|
|
2008
|
|
APCo
|
|
Pollution
Control Bonds
|
|
|
40
|
|
Variable
|
|
2019
|
|
APCo
|
|
Pollution
Control Bonds
|
|
|
30
|
|
Variable
|
|
2019
|
|
APCo
|
|
Pollution
Control Bonds
|
|
|
18
|
|
Variable
|
|
2021
|
|
APCo
|
|
Pollution
Control Bonds
|
|
|
50
|
|
Variable
|
|
2036
|
|
APCo
|
|
Pollution
Control Bonds
|
|
|
75
|
|
Variable
|
|
2037
|
|
CSPCo
|
|
Senior
Unsecured Notes
|
|
|
60
|
|
6.55
|
|
2008
|
|
CSPCo
|
|
Senior
Unsecured Notes
|
|
|
52
|
|
6.51
|
|
2008
|
|
CSPCo
|
|
Pollution
Control Bonds
|
|
|
48
|
|
Variable
|
|
2038
|
|
CSPCo
|
|
Pollution
Control Bonds
|
|
|
44
|
|
Variable
|
|
2038
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
45
|
|
Variable
|
|
2009
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
25
|
|
Variable
|
|
2019
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
52
|
|
Variable
|
|
2021
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
50
|
|
Variable
|
|
2025
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
50
|
|
Variable
|
|
2025
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
40
|
|
Variable
|
|
2025
|
|
OPCo
|
|
Notes
Payable
|
|
|
1
|
|
6.81
|
|
2008
|
|
OPCo
|
|
Notes
Payable
|
|
|
6
|
|
6.27
|
|
2009
|
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
50
|
|
Variable
|
|
2014
|
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
50
|
|
Variable
|
|
2016
|
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
50
|
|
Variable
|
|
2022
|
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
35
|
|
Variable
|
|
2022
|
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
65
|
|
Variable
|
|
2036
|
|
PSO
|
|
Pollution
Control Bonds
|
|
|
34
|
|
Variable
|
|
2014
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
2
|
|
Variable
|
|
2008
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
2
|
|
4.47
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Registrant:
|
|
|
|
|
|
|
|
|
|
|
AEP
Subsidiaries
|
|
Notes
Payable
|
|
|
4
|
|
5.88
|
|
2011
|
|
AEP
Subsidiaries
|
|
Notes
Payable
|
|
|
2
|
|
Variable
|
|
2017
|
|
AEGCo
|
|
Senior
Unsecured Notes
|
|
|
4
|
|
6.33
|
|
2037
|
|
AEPSC
|
|
Mortgage
Notes
|
|
|
34
|
|
9.60
|
|
2008
|
|
TCC
|
|
First
Mortgage Bonds
|
|
|
19
|
|
7.125
|
|
2008
|
|
TCC
|
|
Securitization
Bonds
|
|
|
29
|
|
5.01
|
|
2008
|
|
TCC
|
|
Securitization
Bonds
|
|
|
45
|
|
4.98
|
|
2010
|
|
TCC
|
|
Pollution
Control Bonds
|
|
|
41
|
|
Variable
|
|
2015
|
|
TCC
|
|
Pollution
Control Bonds
|
|
|
60
|
|
Variable
|
|
2028
|
|
TCC
|
|
Pollution
Control Bonds
|
|
|
60
|
|
Variable
|
|
2028
|
|
Total
Retirements and
Principal Payments
|
|
|
$
|
1,472
|
|
|
|
|
|
As of
June 30, 2008, we had $313 million outstanding of tax-exempt long-term debt sold
at auction rates that reset every 35 days. This debt is insured by
bond insurers previously AAA-rated, namely Ambac Assurance Corporation and
Financial Guaranty Insurance Co. Due to the exposure that these bond
insurers have in connection with developments in the subprime credit market, the
credit ratings of these insurers have been downgraded or placed on negative
outlook. These market factors have contributed to higher interest
rates in successful auctions and increasing occurrences of failed auctions,
including many of the auctions of our tax-exempt long-term debt. The
instruments under which the bonds are issued allow us to convert to other
short-term variable-rate structures, term-put structures and fixed-rate
structures. Through June 30, 2008, we reduced our outstanding auction
rate securities by $1.2 billion. We plan to continue the conversion
and refunding process for the remaining $313 million to other permitted modes,
including term-put structures, variable-rate and fixed-rate structures, during
the second half of 2008 to lower our interest rates as such opportunities
arise.
As of
June 30, 2008, $367 million of the prior auction rate debt was issued in a
weekly variable rate mode supported by letters of credit at variable rates
ranging from 1.45% to 1.68% and $384 million was issued at fixed rates ranging
from 4.85% to 5.625%. As of June 30, 2008, trustees held, on our
behalf, approximately $400 million of our reacquired auction rate tax-exempt
long-term debt which we plan to reissue to the public as market conditions
permit.
Dividend
Restrictions
We have
the option to defer interest payments on the AEP Junior Subordinated Debentures
issued in March 2008 for one or more periods of up to 10 consecutive years per
period. During any period in which we defer interest payments, we may
not declare or pay any dividends or distributions on, or redeem, repurchase or
acquire, our common stock. We believe that these restrictions will
not have a material effect on our results of operations, cash flows, financial
condition or limit any dividend payments in the foreseeable future.
Short-term
Debt
Our
outstanding short-term debt is as follows:
|
|
June
30, 2008
|
|
|
December
31, 2007
|
|
|
|
Outstanding
Amount
|
|
Interest
Rate
(a)
|
|
|
Outstanding
Amount
|
|
Interest
Rate
(a)
|
|
Type
of Debt
|
|
(in
thousands)
|
|
|
|
|
|
(in
thousands)
|
|
|
|
|
Commercial
Paper – AEP
|
|
$
|
697,974
|
|
|
3.22
|
%
|
|
$
|
659,135
|
|
|
5.54
|
%
|
Commercial
Paper – JMG (b)
|
|
|
-
|
|
|
-
|
|
|
|
701
|
|
|
5.35
|
%
|
Line
of Credit – Sabine Mining Company (c)
|
|
|
7,039
|
|
|
3.25
|
%
|
|
|
285
|
|
|
5.25
|
%
|
Total
|
|
$
|
705,013
|
|
|
|
|
|
$
|
660,121
|
|
|
|
|
(a)
|
Weighted
average rate.
|
(b)
|
This
commercial paper is specifically associated with the Gavin Scrubber and is
backed by a separate credit facility. This commercial paper
does not reduce available liquidity under AEP’s credit
facilities.
|
(c)
|
Sabine
Mining Company is consolidated under FIN 46R. This line of
credit does not reduce available liquidity under AEP’s credit
facilities.
|
Credit
Facilities
As of
June 30, 2008, we had two $1.5 billion credit facilities to support our
commercial paper program. In March 2008, the credit facilities were
amended so that $750 million may be issued under each credit facility as letters
of credit.
In April
2008, we entered into a $650 million 3-year credit agreement and a $350 million
364-day credit agreement. Under the facilities, we may issue letters
of credit. As of June 30, 2008, $371 million of letters of credit
were issued by subsidiaries under the 3-year credit agreement to support
variable rate demand notes.
In July
2008, TCC suffered damages in its southern Texas service territory related to
Hurricane Dolly. Management is currently developing an estimate of
the storm recovery costs related to Hurricane Dolly, but does not believe
that these costs will have a material effect on future results of operations due
to expected recovery in rates.
APPALACHIAN
POWER COMPANY
AND
SUBSIDIARIES
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
Second Quarter of 2008
Compared to Second Quarter of 2007
Reconciliation
of Second Quarter of 2007 to Second Quarter of 2008
Income
Before Extraordinary Loss
(in
millions)
Second
Quarter of 2007
|
|
|
|
|
$ |
3 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
48 |
|
|
|
|
|
Off-system
Sales
|
|
|
8 |
|
|
|
|
|
Other
|
|
|
(1
|
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
55 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
6 |
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(31
|
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1
|
) |
|
|
|
|
Carrying
Costs Income
|
|
|
6 |
|
|
|
|
|
Other
Income
|
|
|
4 |
|
|
|
|
|
Interest
Expense
|
|
|
(2
|
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(18
|
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(14
|
) |
|
|
|
|
|
|
|
|
|
Second Quarter of 2008
|
|
|
|
|
|
$ |
26 |
|
Income
Before Extraordinary Loss increased $23 million to $26 million in
2008. The key drivers of the increase were a $55 million increase in
Gross Margin partially offset by an increase in Operating Expenses and Other of
$18 million and an increase in Income Tax Expense of $14 million.
The major
components of the change in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $48 million primarily due to the impact of the Virginia
base rate order issued in May 2007 which included a second quarter 2007
provision for revenue refund in addition to an increase in the recovery of
E&R costs in Virginia and construction financing costs in West
Virginia. These increases were partially offset by an increase
in sharing of off-system sales margins with customers and higher capacity
settlement expenses under the Interconnection
Agreement.
|
·
|
Margins
from Off-system Sales increased $8 million primarily due to higher
physical sales margins partially offset by lower trading margins.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses decreased $6 million primarily due to a
$3 million decrease in expenses associated with the Transmission
Equalization Agreement and a $3 million decrease in uncollectible accounts
receivable expense.
|
·
|
Depreciation
and Amortization expenses increased $31 million primarily due to favorable
adjustments made in the second quarter of 2007 for the Virginia Rate Base
order of $22 million and an increase in the amortization of carrying
charges and depreciation expense of $6 million that are being collected
through the Virginia E&R surcharges.
|
·
|
Carrying
Costs Income increased $6 million due to an increase in Virginia E&R
deferrals.
|
·
|
Interest
Expense increased $2 million primarily due to an $11 million increase in
interest expense from long-term debt issuances. This increase
was partially offset by a $4 million favorable increase in allowance for
borrowed funds used during construction and a $3 million decrease in
interest related to the Virginia provision for refund recorded in the
second quarter of 2007.
|
·
|
Income
Tax Expense increased $14 million primarily due to an increase in pretax
book income.
|
Six Months Ended June 30,
2008 Compared to Six Months Ended June 30, 2007
Reconciliation
of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Income
Before Extraordinary Loss
(in
millions)
Six
Months Ended June 30, 2007
|
|
|
|
|
$ |
74 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
29 |
|
|
|
|
|
Off-system
Sales
|
|
|
24 |
|
|
|
|
|
Transmission
Revenues
|
|
|
1 |
|
|
|
|
|
Other
|
|
|
(2
|
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
52 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(14
|
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(34
|
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(4
|
) |
|
|
|
|
Carrying
Costs Income
|
|
|
13 |
|
|
|
|
|
Other
Income
|
|
|
4 |
|
|
|
|
|
Interest
Expense
|
|
|
(14
|
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(49
|
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008
|
|
|
|
|
|
$ |
82 |
|
Income
Before Extraordinary Loss increased $8 million to $82 million in
2008. The key drivers of the increase were a $52 million increase in
Gross Margin partially offset by a $49 million increase in Operating Expenses
and Other.
The major
components of the change in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $29 million primarily due to the impact of the Virginia
base rate order issued in May 2007 which included a second quarter 2007
provision for revenue refund in addition to an increase in the recovery of
E&R costs in Virginia and construction financing costs in West
Virginia. These increases were partially offset by an increase
in sharing of off-system sales margins with customers and higher capacity
settlement expenses under the Interconnection
Agreement.
|
·
|
Margins
from Off-system Sales increased $24 million primarily due to higher
physical sales margins partially offset by lower trading margins.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $14 million primarily due to
a $6 million increase in distribution maintenance expenses resulting from
repairs from storm damage. In addition, steam maintenance
expenses increased $5 million due to a planned outage at the Mountaineer
Plant in March 2008.
|
·
|
Depreciation
and Amortization expenses increased $34 million primarily due to favorable
adjustments made in the second quarter 2007 for the Virginia base rate
order of $22 million and the amortization of carrying charges and
depreciation expense of $9 million that are being collected through the
Virginia E&R surcharges.
|
·
|
Taxes
Other Than Income Taxes increased $4 million primarily due to favorable
franchise tax return adjustments recorded in 2007.
|
·
|
Carrying
Costs Income increased $13 million due to an increase in Virginia E&R
deferrals.
|
·
|
Interest
Expense increased $14 million primarily due to a $19 million increase in
interest expense from long-term debt issuances partially offset by a $4
million decrease in interest on the Virginia provision for refund recorded
in the second quarter of 2007.
|
·
|
Income
Tax Expense decreased $5 million primarily due to a decrease in state
income taxes partially offset by changes in certain book/tax differences
accounted for on a flow-through
basis.
|
Financial
Condition
Credit
Ratings
S&P
currently has APCo on stable outlook, while Fitch placed APCo on negative
outlook in the second quarter of 2008 and Moody’s placed APCo on negative
outlook in the first quarter of 2008. Current ratings are as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
Baa2
|
|
BBB
|
|
BBB+
|
If APCo
receives an upgrade from any of the rating agencies listed above, its borrowing
costs could decrease. If APCo receives a downgrade from any of the
rating agencies listed above, it borrowing costs could increase and access to
borrowed funds could be negatively affected.
Cash
Flow
Cash
flows for the six months ended June 30, 2008 and 2007 were as
follows:
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$ |
2,195 |
|
|
$ |
2,318 |
|
Cash
Flows from (Used for):
|
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
140,378 |
|
|
|
265,414 |
|
Investing
Activities
|
|
|
(296,095
|
) |
|
|
(378,985
|
) |
Financing
Activities
|
|
|
155,398 |
|
|
|
112,605 |
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(319
|
) |
|
|
(966
|
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,876 |
|
|
$ |
1,352 |
|
Operating
Activities
Net Cash
Flows from Operating Activities were $140 million in 2008. APCo
produced income of $82 million during the period and had noncash expense items
of $124 million for Depreciation and Amortization, $72 million for Deferred
Income Taxes and $27 million for Carrying Costs Income. The other
changes in assets and liabilities represent items that had a current period cash
flow impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The current period activity in working capital
relates to a number of items in 2008. The $41 million cash inflow
from Accounts Payable was primarily due to an increase in fuel
costs. The $77 million cash outflow from Fuel Over/Under-Recovery,
Net resulted in a net under recovery of fuel cost in both Virginia and West
Virginia due to higher fuel costs.
Net Cash
Flows from Operating Activities were $265 million in 2007. APCo
incurred a Net Loss of $5 million during the period and had noncash expense
items of $90 million for Depreciation and Amortization and $79 million for
Extraordinary Loss for the Reapplication of Regulatory Accounting for Generation
and $105 million for Regulatory Provision related to the Virginia base rate
case. The other changes in assets and liabilities represent items
that had a prior period cash flow impact, such as changes in working capital, as
well as items that represent future rights or obligations to receive or pay
cash, such as regulatory assets and liabilities. The activity in
working capital had no significant items in 2007.
Investing
Activities
Net Cash
Flows Used for Investing Activities during 2008 and 2007 were $296 million and
$379 million, respectively. Construction Expenditures were $312
million and $383 million in 2008 and 2007, respectively, primarily related to
transmission and distribution service reliability projects, as well as
environmental upgrades for both periods. Environmental upgrades
includes the installation of the flue gas desulfurization equipment at the Amos
and Mountaineer Plants. In February 2007, environmental upgrades were
completed for the Mountaineer Plant. For the remainder of 2008, APCo
expects construction expenditures to be approximately $458 million.
Financing
Activities
Net Cash
Flows from Financing Activities were $155 million in 2008. APCo
received a capital contribution from Parent of $125 million. APCo
issued $500 million of Senior Unsecured Notes in March 2008 and $125 million of
Pollution Control Bonds in June 2008. These increases were partially
offset by the retirement of $213 million of Pollution Control Bonds and the
retirement of $200 million of Senior Unsecured Notes in the second quarter of
2008. In addition, APCo had a net decrease of $171 million in
borrowings from the Utility Money Pool.
Net Cash
Flows from Financing Activities in 2007 were $113 million primarily due to an
increase of $213 million in borrowings from the Utility Money Pool and the
issuance of $75 million of Pollution Control Bonds. These increases
were partially offset by the retirement of $125 million of Senior Notes and
payment of $25 million in dividends on common stock.
Financing
Activity
Long-term
debt issuances, retirements and principal payments made during the first six
months of 2008 were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$
|
75,000
|
|
Variable
|
|
2036
|
Pollution
Control Bonds
|
|
|
50,275
|
|
Variable
|
|
2036
|
Senior
Unsecured Notes
|
|
|
500,000
|
|
7.00
|
|
2038
|
Retirements and Principal
Payments
|
|
Principal
Amount
Paid
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$
|
40,000
|
|
Variable
|
|
2019
|
Pollution
Control Bonds
|
|
|
17,500
|
|
Variable
|
|
2021
|
Pollution
Control Bonds
|
|
|
30,000
|
|
Variable
|
|
2019
|
Pollution
Control Bonds
|
|
|
50,275
|
|
Variable
|
|
2036
|
Pollution
Control Bonds
|
|
|
75,000
|
|
Variable
|
|
2037
|
Senior
Unsecured Notes
|
|
|
200,000
|
|
3.60
|
|
2008
|
Other
|
|
|
7
|
|
13.718
|
|
2026
|
Liquidity
APCo has
solid investment grade ratings, which provide ready access to capital markets in
order to issue new debt or refinance long-term debt maturities. In
addition, APCo participates in the Utility Money Pool, which provides access to
AEP’s liquidity.
Summary Obligation
Information
A summary
of contractual obligations is included in the 2007 Annual Report and has not
changed significantly from year-end other than the debt issuances and
retirements discussed in “Cash Flow” and “Financing Activity” above and letters
of credit. In April 2008, the Registrant Subsidiaries and certain
other companies in the AEP System entered into a $650 million 3-year credit
agreement and a $350 million 364-day credit agreement. As of June 30,
2008, $127 million of letters of credit were issued by APCo under the 3-year
credit agreement to support variable rate demand notes.
Significant
Factors
Litigation
and Regulatory Activity
In the
ordinary course of business, APCo is involved in employment, commercial,
environmental and regulatory litigation. Since it is difficult to
predict the outcome of these proceedings, management cannot state what the
eventual outcome of these proceedings will be, or what the timing of the amount
of any loss, fine or penalty may be. Management does, however, assess
the probability of loss for such contingencies and accrues a liability for cases
which have a probable likelihood of loss and the loss amount can be
estimated. For details on regulatory proceedings and pending
litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 2007 Annual Report. Also, see Note 3 – Rate
Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed
Notes to Condensed Financial Statements of Registrant Subsidiaries”
section. Adverse results in these proceedings have the potential to
materially affect results of operations, financial condition and cash
flows.
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of relevant factors.
Critical Accounting
Estimates
See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption of New Accounting
Pronouncements
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market
Risks
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion within AEP’s “Quantitative and
Qualitative Disclosures About Risk Management Activities”
section. The following tables provide information about AEP’s risk
management activities’ effect on APCo.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in APCo’s Condensed Consolidated Balance Sheet as of June 30, 2008 and
the reasons for changes in total MTM value as compared to December 31,
2007.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of June 30, 2008
(in
thousands)
|
|
|
|
|
Cash
Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
MTM
Risk
|
|
|
&
|
|
|
DETM
|
|
|
|
|
|
|
|
|
|
Management
|
|
|
Fair
Value
|
|
|
Assignment
|
|
|
Collateral
|
|
|
|
|
|
|
Contracts
|
|
|
Hedges
|
|
|
(a)
|
|
|
Deposits
|
|
|
Total
|
|
Current
Assets
|
|
$ |
219,254 |
|
|
$ |
3,871 |
|
|
$ |
- |
|
|
$ |
(15,261 |
) |
|
$ |
207,864 |
|
Noncurrent
Assets
|
|
|
114,005 |
|
|
|
363 |
|
|
|
- |
|
|
|
(8,538
|
) |
|
|
105,830 |
|
Total
MTM Derivative Contract Assets
|
|
|
333,259 |
|
|
|
4,234 |
|
|
|
- |
|
|
|
(23,799
|
) |
|
|
313,694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(223,908
|
) |
|
|
(28,732
|
) |
|
|
(3,396
|
) |
|
|
17,200 |
|
|
|
(238,836
|
) |
Noncurrent
Liabilities
|
|
|
(80,869
|
) |
|
|
(1,287
|
) |
|
|
(3,720
|
) |
|
|
2,519 |
|
|
|
(83,357
|
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(304,777
|
) |
|
|
(30,019
|
) |
|
|
(7,116
|
) |
|
|
19,719 |
|
|
|
(322,193
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$ |
28,482 |
|
|
$ |
(25,785 |
) |
|
$ |
(7,116 |
) |
|
$ |
(4,080 |
) |
|
$ |
(8,499 |
) |
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Six
Months Ended June 30, 2008
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2007
|
|
$
|
45,870
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered in a
Prior Period
|
|
|
(8,933
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
-
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
-
|
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward Contracts
(b)
|
|
|
1,151
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(c)
|
|
|
(408
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
(9,198
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
28,482
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
(25,785
|
)
|
DETM
Assignment (e)
|
|
|
(7,116
|
)
|
Collateral
Deposits
|
|
|
(4,080
|
)
|
Ending
Net Risk Management Assets at June 30, 2008
|
|
$
|
(8,499
|
)
|
(a)
|
Reflects
fair value on long-term contracts which are typically with customers that
seek fixed pricing to limit their risk against fluctuating energy
prices. The contract prices are valued against market curves
associated with the delivery location and delivery
term.
|
(b)
|
Represents
the impact of applying AEP’s credit risk when measuring the fair value of
derivative liabilities according to SFAS 157.
|
(c)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(d)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected in the Condensed
Consolidated Statements of Income. These net gains (losses) are
recorded as regulatory assets/liabilities for those subsidiaries that
operate in regulated jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
The
following table presents the maturity, by year, of net assets/liabilities to
give an indication of when these MTM amounts will settle and generate
cash:
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets
Fair
Value of Contracts as of June 30, 2008
(in
thousands)
|
|
Remainder
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2012
|
|
|
Total
|
|
Level
1 (a)
|
|
$ |
(2,770 |
) |
|
$ |
471 |
|
|
$ |
(21 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(2,320 |
) |
Level
2 (b)
|
|
|
2,314 |
|
|
|
12,244 |
|
|
|
12,956 |
|
|
|
5,150 |
|
|
|
1,782 |
|
|
|
- |
|
|
|
34,446 |
|
Level
3 (c)
|
|
|
(9,305
|
) |
|
|
(1,566
|
) |
|
|
(3,892
|
) |
|
|
(2,504
|
) |
|
|
(1,293
|
) |
|
|
- |
|
|
|
(18,560
|
) |
Total
|
|
|
(9,761
|
) |
|
|
11,149 |
|
|
|
9,043 |
|
|
|
2,646 |
|
|
|
489 |
|
|
|
- |
|
|
|
13,566 |
|
Dedesignated
Risk Management Contracts
(d)
|
|
|
2,380 |
|
|
|
4,602 |
|
|
|
4,565 |
|
|
|
1,778 |
|
|
|
1,591 |
|
|
|
- |
|
|
|
14,916 |
|
Total MTM Risk Management
Contract Net Assets
(Liabilities)
|
|
$ |
(7,381 |
) |
|
$ |
15,751 |
|
|
$ |
13,608 |
|
|
$ |
4,424 |
|
|
$ |
2,080 |
|
|
$ |
- |
|
|
$ |
28,482 |
|
(a)
|
Level
1 inputs are quoted prices (unadjusted) in active markets for identical
assets or liabilities that the reporting entity has the ability to access
at the measurement date. Level 1 inputs primarily consist of
exchange traded contracts that exhibit sufficient frequency and volume to
provide pricing information on an ongoing basis.
|
(b)
|
Level
2 inputs are inputs other than quoted prices included within Level 1 that
are observable for the asset or liability, either directly or
indirectly. If the asset or liability has a specified
(contractual) term, a Level 2 input must be observable for substantially
the full term of the asset or liability. Level 2 inputs
primarily consist of OTC broker quotes in moderately active or less active
markets, exchange traded contracts where there was not sufficient market
activity to warrant inclusion in Level 1, and OTC broker quotes that are
corroborated by the same or similar transactions that have occurred in the
market.
|
(c)
|
Level
3 inputs are unobservable inputs for the asset or
liability. Unobservable inputs shall be used to measure fair
value to the extent that the observable inputs are not available, thereby
allowing for situations in which there is little, if any, market activity
for the asset or liability at the measurement date. Level 3
inputs primarily consist of unobservable market data or are valued based
on models and/or assumptions.
|
(d)
|
Dedesignated
Risk Management Contracts are contracts that were originally MTM but were
subsequently elected as normal under SFAS 133. At the time of
the normal election the MTM value was frozen and no longer fair
valued. This will be amortized into Revenues over the remaining
life of the contract.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on
the Condensed Consolidated Balance Sheet
APCo is
exposed to market fluctuations in energy commodity prices impacting power
operations. Management monitors these risks on future
operations and may use various commodity instruments designated in qualifying
cash flow hedge strategies to mitigate the impact of these fluctuations on the
future cash flows. Management does not hedge all commodity price
risk.
Management
uses interest rate derivative transactions to manage interest rate risk related
to anticipated borrowings of fixed-rate debt. Management does not
hedge all interest rate risk.
Management
uses foreign currency derivatives to lock in prices on certain forecasted
transactions denominated in foreign currencies where deemed necessary, and
designates qualifying instruments as cash flow hedges. Management
does not hedge all foreign currency exposure.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on APCo’s Condensed Consolidated Balance Sheets and the reasons
for the changes from December 31, 2007 to June 30, 2008. Only
contracts designated as cash flow hedges are recorded in
AOCI. Therefore, economic hedge contracts that are not designated as
effective cash flow hedges are marked-to-market and included in the previous
risk management tables. All amounts are presented net of related
income taxes.
Total
Accumulated Other Comprehensive Income (Loss) Activity
Six
Months Ended June 30, 2008
(in
thousands)
|
|
Power
|
|
|
Interest
Rate
|
|
|
Foreign
Currency
|
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2007
|
|
$
|
783
|
|
|
$
|
(6,602
|
)
|
|
$
|
(125
|
)
|
|
$
|
(5,944
|
)
|
Changes
in Fair Value
|
|
|
(15,824
|
)
|
|
|
(3,114
|
)
|
|
|
75
|
|
|
|
(18,863
|
)
|
Reclassifications
from AOCI for Cash Flow Hedges
Settled
|
|
|
(682
|
)
|
|
|
813
|
|
|
|
3
|
|
|
|
134
|
|
Ending
Balance in AOCI June 30, 2008
|
|
$
|
(15,723
|
)
|
|
$
|
(8,903
|
)
|
|
$
|
(47
|
)
|
|
$
|
(24,673
|
)
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $16.8 million loss.
Credit
Risk
Counterparty
credit quality and exposure is generally consistent with that of
AEP.
VaR
Associated with Risk Management Contracts
Management
uses risk measurement model, which calculates Value at Risk (VaR) to measure
commodity price risk in the risk management portfolio. The VaR is based on the
variance-covariance method using historical prices to estimate volatilities and
correlations and assumes a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at June 30, 2008, a near term
typical change in commodity prices is not expected to have a material effect on
APCo’s results of operations, cash flows or financial condition.
The
following table shows the end, high, average and low market risk as measured by
VaR for the periods indicated:
Six
Months Ended
June
30, 2008
|
|
|
Twelve
Months Ended
December
31, 2007
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
|
$603
|
|
|
$1,002
|
|
|
$391
|
|
|
$161
|
|
|
$455
|
|
|
$2,328
|
|
|
$569
|
|
|
$117
|
Management
back-tests its VaR results against performance due to actual price
moves. Based on the assumed 95% confidence interval, the performance
due to actual price moves would be expected to exceed the VaR at least once
every 20 trading days. Management’s backtesting results show that its
actual performance exceeded VaR far fewer than once every 20 trading
days. As a result, management believes APCo’s VaR
calculation is conservative.
As APCo’s
VaR calculation captures recent price moves, management also performs regular
stress testing of the portfolio to understand its exposure to extreme price
moves. Management employs a historically-based method whereby the
current portfolio is subjected to actual, observed price moves from the last
three years in order to ascertain which historical price moves translate into
the largest potential mark-to-market loss. Management then researches
the underlying positions, price moves and market events that created the most
significant exposure.
Interest
Rate Risk
Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure. EaR statistically quantifies the extent to which APCo’s interest
expense could vary over the next twelve months and gives a probabilistic
estimate of different levels of interest expense. The resulting EaR
is interpreted as the dollar amount by which actual interest expense for the
next twelve months could exceed expected interest expense with a one-in-twenty
chance of occurrence. The primary drivers of EaR are from the
existing floating rate debt (including short-term debt) as well as long-term
debt issuances in the next twelve months. The estimated EaR on APCo’s
debt portfolio was $5.2 million.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
For
the Three and Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
566,089 |
|
|
$ |
499,189 |
|
|
$ |
1,207,546 |
|
|
$ |
1,100,735 |
|
Sales
to AEP Affiliates
|
|
|
97,508 |
|
|
|
55,371 |
|
|
|
187,598 |
|
|
|
116,916 |
|
Other
|
|
|
3,800 |
|
|
|
2,850 |
|
|
|
7,280 |
|
|
|
5,487 |
|
TOTAL
|
|
|
667,397 |
|
|
|
557,410 |
|
|
|
1,402,424 |
|
|
|
1,223,138 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
159,237 |
|
|
|
164,018 |
|
|
|
333,067 |
|
|
|
335,204 |
|
Purchased
Electricity for Resale
|
|
|
52,931 |
|
|
|
34,328 |
|
|
|
96,130 |
|
|
|
70,278 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
186,243 |
|
|
|
144,630 |
|
|
|
375,838 |
|
|
|
272,231 |
|
Other
Operation
|
|
|
68,415 |
|
|
|
75,125 |
|
|
|
143,946 |
|
|
|
142,754 |
|
Maintenance
|
|
|
52,235 |
|
|
|
51,414 |
|
|
|
110,079 |
|
|
|
97,167 |
|
Depreciation
and Amortization
|
|
|
61,592 |
|
|
|
31,076 |
|
|
|
124,164 |
|
|
|
90,236 |
|
Taxes
Other Than Income Taxes
|
|
|
24,104 |
|
|
|
22,975 |
|
|
|
48,095 |
|
|
|
44,250 |
|
TOTAL
|
|
|
604,757 |
|
|
|
523,566 |
|
|
|
1,231,319 |
|
|
|
1,052,120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
62,640 |
|
|
|
33,844 |
|
|
|
171,105 |
|
|
|
171,018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
2,827 |
|
|
|
390 |
|
|
|
5,596 |
|
|
|
1,029 |
|
Carrying
Costs Income
|
|
|
17,411 |
|
|
|
10,950 |
|
|
|
26,997 |
|
|
|
14,116 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
2,652 |
|
|
|
1,581 |
|
|
|
4,148 |
|
|
|
4,358 |
|
Interest
Expense
|
|
|
(47,119
|
) |
|
|
(44,955
|
) |
|
|
(91,259
|
) |
|
|
(76,778
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE (CREDIT)
|
|
|
38,411 |
|
|
|
1,810 |
|
|
|
116,587 |
|
|
|
113,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense (Credit)
|
|
|
12,129 |
|
|
|
(1,471
|
) |
|
|
34,992 |
|
|
|
40,235 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE EXTRAORDINARY LOSS
|
|
|
26,282 |
|
|
|
3,281 |
|
|
|
81,595 |
|
|
|
73,508 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extraordinary
Loss – Reapplication of Regulatory Accounting for Generation,
Net of Tax
|
|
|
- |
|
|
|
(78,763
|
) |
|
|
- |
|
|
|
(78,763
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
|
26,282 |
|
|
|
(75,482
|
) |
|
|
81,595 |
|
|
|
(5,255
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements Including
Capital
Stock Expense
|
|
|
238 |
|
|
|
238 |
|
|
|
476 |
|
|
|
476 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
(LOSS) APPLICABLE TO COMMON STOCK
|
|
$ |
26,044 |
|
|
$ |
(75,720 |
) |
|
$ |
81,119 |
|
|
$ |
(5,731 |
) |
The
common stock of APCo is wholly-owned by AEP.
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
|
Paid-in
Capital
|
|
|
Retained
Earnings
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
Total
|
|
DECEMBER
31, 2006
|
|
$ |
260,458 |
|
|
$ |
1,024,994 |
|
|
$ |
805,513 |
|
|
$ |
(54,791 |
) |
|
$ |
2,036,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(2,685
|
) |
|
|
|
|
|
|
(2,685
|
) |
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(25,000
|
) |
|
|
|
|
|
|
(25,000
|
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(400
|
) |
|
|
|
|
|
|
(400
|
) |
Capital
Stock Expense
|
|
|
|
|
|
|
76 |
|
|
|
(76
|
) |
|
|
|
|
|
|
- |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,008,089 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,482
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,610 |
|
|
|
4,610 |
|
SFAS
158 Costs Established as a Regulatory
Asset
Related to the Reapplication of
SFAS
71, Net of Tax of $6,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,245 |
|
|
|
11,245 |
|
NET
LOSS
|
|
|
|
|
|
|
|
|
|
|
(5,255
|
) |
|
|
|
|
|
|
(5,255
|
) |
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
260,458 |
|
|
$ |
1,025,070 |
|
|
$ |
772,097 |
|
|
$ |
(38,936 |
) |
|
$ |
2,018,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2007
|
|
$ |
260,458 |
|
|
$ |
1,025,149 |
|
|
$ |
831,612 |
|
|
$ |
(35,187 |
) |
|
$ |
2,082,032 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EITF
06-10 Adoption, Net of Tax of $1,175
|
|
|
|
|
|
|
|
|
|
|
(2,181
|
) |
|
|
|
|
|
|
(2,181
|
) |
SFAS
157 Adoption, Net of Tax of $154
|
|
|
|
|
|
|
|
|
|
|
(286
|
) |
|
|
|
|
|
|
(286
|
) |
Capital
Contribution from Parent
|
|
|
|
|
|
|
125,000 |
|
|
|
|
|
|
|
|
|
|
|
125,000 |
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(399
|
) |
|
|
|
|
|
|
(399
|
) |
Capital
Stock Expense
|
|
|
|
|
|
|
77 |
|
|
|
(77
|
) |
|
|
|
|
|
|
- |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,204,166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of
$10,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(18,729
|
) |
|
|
(18,729
|
) |
Amortization
of Pension and OPEB Deferred
Costs,
Net of Tax of $897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,666 |
|
|
|
1,666 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
81,595 |
|
|
|
|
|
|
|
81,595 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64,532 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2008
|
|
$ |
260,458 |
|
|
$ |
1,150,226 |
|
|
$ |
910,264 |
|
|
$ |
(52,250 |
) |
|
$ |
2,268,698 |
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,876 |
|
|
$ |
2,195 |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
198,958 |
|
|
|
176,834 |
|
Affiliated Companies
|
|
|
79,810 |
|
|
|
113,582 |
|
Accrued Unbilled Revenues
|
|
|
34,213 |
|
|
|
38,397 |
|
Miscellaneous
|
|
|
592 |
|
|
|
2,823 |
|
Allowance for Uncollectible Accounts
|
|
|
(5,835
|
) |
|
|
(13,948 |
) |
Total
Accounts Receivable
|
|
|
307,738 |
|
|
|
317,688 |
|
Fuel
|
|
|
84,139 |
|
|
|
82,203 |
|
Materials
and Supplies
|
|
|
80,244 |
|
|
|
76,685 |
|
Risk
Management Assets
|
|
|
207,864 |
|
|
|
62,955 |
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
53,399 |
|
|
|
- |
|
Prepayments
and Other
|
|
|
51,831 |
|
|
|
16,369 |
|
TOTAL
|
|
|
787,091 |
|
|
|
558,095 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
3,633,832 |
|
|
|
3,625,788 |
|
Transmission
|
|
|
1,712,793 |
|
|
|
1,675,081 |
|
Distribution
|
|
|
2,429,600 |
|
|
|
2,372,687 |
|
Other
|
|
|
356,089 |
|
|
|
351,827 |
|
Construction
Work in Progress
|
|
|
856,270 |
|
|
|
713,063 |
|
Total
|
|
|
8,988,584 |
|
|
|
8,738,446 |
|
Accumulated
Depreciation and Amortization
|
|
|
2,639,155 |
|
|
|
2,591,833 |
|
TOTAL
- NET
|
|
|
6,349,429 |
|
|
|
6,146,613 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
683,609 |
|
|
|
652,739 |
|
Long-term
Risk Management Assets
|
|
|
105,830 |
|
|
|
72,366 |
|
Deferred
Charges and Other
|
|
|
197,938 |
|
|
|
191,871 |
|
TOTAL
|
|
|
987,377 |
|
|
|
916,976 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
8,123,897 |
|
|
$ |
7,621,684 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
June
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
103,802 |
|
|
$ |
275,257 |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
281,893 |
|
|
|
241,871 |
|
Affiliated Companies
|
|
|
99,692 |
|
|
|
106,852 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
150,016 |
|
|
|
239,732 |
|
Risk
Management Liabilities
|
|
|
238,836 |
|
|
|
51,708 |
|
Customer
Deposits
|
|
|
50,978 |
|
|
|
45,920 |
|
Accrued
Taxes
|
|
|
48,527 |
|
|
|
58,519 |
|
Accrued
Interest
|
|
|
46,693 |
|
|
|
41,699 |
|
Other
|
|
|
99,752 |
|
|
|
139,476 |
|
TOTAL
|
|
|
1,120,189 |
|
|
|
1,201,034 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
2,803,466 |
|
|
|
2,507,567 |
|
Long-term
Debt – Affiliated
|
|
|
100,000 |
|
|
|
100,000 |
|
Long-term
Risk Management Liabilities
|
|
|
83,357 |
|
|
|
47,357 |
|
Deferred
Income Taxes
|
|
|
1,013,394 |
|
|
|
948,891 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
490,350 |
|
|
|
505,556 |
|
Deferred
Credits and Other
|
|
|
226,691 |
|
|
|
211,495 |
|
TOTAL
|
|
|
4,717,258 |
|
|
|
4,320,866 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
5,837,447 |
|
|
|
5,521,900 |
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
17,752 |
|
|
|
17,752 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
|
Common
Stock – No Par Value:
|
|
|
|
|
|
|
|
|
Authorized – 30,000,000 Shares
|
|
|
|
|
|
|
|
|
Outstanding – 13,499,500 Shares
|
|
|
260,458 |
|
|
|
260,458 |
|
Paid-in
Capital
|
|
|
1,150,226 |
|
|
|
1,025,149 |
|
Retained
Earnings
|
|
|
910,264 |
|
|
|
831,612 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(52,250
|
) |
|
|
(35,187
|
) |
TOTAL
|
|
|
2,268,698 |
|
|
|
2,082,032 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
8,123,897 |
|
|
$ |
7,621,684 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$ |
81,595 |
|
|
$ |
(5,255 |
) |
Adjustments
to Reconcile Net Income (Loss) to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
124,164 |
|
|
|
90,236 |
|
Deferred
Income Taxes
|
|
|
71,728 |
|
|
|
(17,439 |
) |
Extraordinary
Loss, Net of Tax
|
|
|
- |
|
|
|
78,763 |
|
Regulatory
Provision
|
|
|
- |
|
|
|
105,110 |
|
Carrying
Costs Income
|
|
|
(26,997
|
) |
|
|
(14,116 |
) |
Allowance
for Equity Funds Used During Construction
|
|
|
(4,148
|
) |
|
|
(4,358 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
17,298 |
|
|
|
5,457 |
|
Change
in Other Noncurrent Assets
|
|
|
(14,006
|
) |
|
|
(7,896 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
(20,038
|
) |
|
|
(1,239 |
) |
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts Receivable, Net
|
|
|
2,583 |
|
|
|
31,483 |
|
Fuel, Materials and Supplies
|
|
|
(5,495
|
) |
|
|
(20,654 |
) |
Accounts Payable
|
|
|
40,905 |
|
|
|
(26,786 |
) |
Accrued Taxes, Net
|
|
|
(31,213
|
) |
|
|
39,168 |
|
Fuel Over/Under-Recovery, Net
|
|
|
(77,036
|
) |
|
|
15,221 |
|
Other Current Assets
|
|
|
(14,225
|
) |
|
|
3,140 |
|
Other Current Liabilities
|
|
|
(4,737
|
) |
|
|
(5,421 |
) |
Net
Cash Flows from Operating Activities
|
|
|
140,378 |
|
|
|
265,414 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(311,550
|
) |
|
|
(382,501 |
) |
Change
in Other Cash Deposits, Net
|
|
|
(15
|
) |
|
|
(2,678 |
) |
Proceeds
from Sales of Assets
|
|
|
15,470 |
|
|
|
6,194 |
|
Net
Cash Flows Used for Investing Activities
|
|
|
(296,095
|
) |
|
|
(378,985 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
125,000 |
|
|
|
- |
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
617,111 |
|
|
|
73,438 |
|
Change
in Advances from Affiliates, Net
|
|
|
(171,455
|
) |
|
|
212,641 |
|
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(412,782
|
) |
|
|
(125,006 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(2,077
|
) |
|
|
(2,200 |
) |
Amortization
of Funds From Amended Coal Contract
|
|
|
- |
|
|
|
(20,868 |
) |
Dividends
Paid on Common Stock
|
|
|
- |
|
|
|
(25,000 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(399
|
) |
|
|
(400 |
) |
Net
Cash Flows from Financing Activities
|
|
|
155,398 |
|
|
|
112,605 |
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(319
|
) |
|
|
(966 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
2,195 |
|
|
|
2,318 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,876 |
|
|
$ |
1,352 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
86,873 |
|
|
$ |
69,823 |
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(10,708
|
) |
|
|
6,197 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,014 |
|
|
|
1,693 |
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
98,958 |
|
|
|
97,044 |
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to APCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to
APCo.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
COLUMBUS
SOUTHERN POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S NARRATIVE
FINANCIAL DISCUSSION AND ANALYSIS
Second Quarter of 2008
Compared to Second Quarter of 2007
Reconciliation
of Second Quarter of 2007 to Second Quarter of 2008
Net
Income
(in
millions)
Second
Quarter of 2007
|
|
|
|
|
$ |
80 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(13
|
) |
|
|
|
|
Off-system
Sales
|
|
|
10 |
|
|
|
|
|
Transmission
Revenues
|
|
|
1 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(2
|
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(30
|
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
2 |
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(5
|
) |
|
|
|
|
Interest
Expense
|
|
|
(1
|
) |
|
|
|
|
Other
|
|
|
1 |
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(33
|
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
Second
Quarter of 2008
|
|
|
|
|
|
$ |
56 |
|
Net
Income decreased $24 million to $56 million in 2008. The key drivers
of the decrease were a $33 million increase in Operating Expenses and Other
partially offset by an $11 million decrease in Income Tax Expense.
The major
components of the decrease in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins decreased $13 million primarily due to:
|
|
·
|
A
$32 million decrease related to increased fuel and PJM
expenses.
|
|
·
|
A
$12 million decrease in residential and commercial revenue primarily due
to a 55% decrease in heating degree days and a 24% decrease in cooling
degree days.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$26 million increase related to a net increase in rates
implemented.
|
|
·
|
A
$7 million decrease in capacity purchases related to CSPCo’s unit power
agreement for AEGCo’s Lawrenceburg Plant which began in May 2007 and the
April 2007 acquisition of the Darby Plant.
|
|
·
|
A
$4 million increase in industrial revenue due to increased usage by Ormet,
a major industrial customer.
|
·
|
Margins
from Off-system Sales increased $10 million primarily due to higher
physical sales margins and higher trading
margins.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $30 million due
to:
|
|
·
|
A
$9 million increase in recoverable PJM costs.
|
|
·
|
An
$8 million increase in steam plant maintenance expenses primarily related
to work performed at the Conesville Plant.
|
|
·
|
A
$4 million increase in boiler plant removal expenses primarily related to
work performed at the Conesville Plant.
|
|
·
|
A
$4 million increase in expenses related to CSPCo’s unit power agreement
for AEGCo’s Lawrenceburg Plant which began in May 2007.
|
|
·
|
A
$3 million increase in recoverable customer account expenses related to
the Universal Service Fund for customers who qualify for payment
assistance.
|
·
|
Depreciation
and Amortization decreased $2 million primarily due to the amortization of
IGCC pre-construction costs, which ended in the second quarter of
2007. The amortization of IGCC pre-construction costs was
offset by a corresponding increase in Retail Margins in
2007.
|
·
|
Taxes
Other Than Income Taxes increased $5 million due to property tax
adjustments.
|
·
|
Income
Tax Expense decreased $11 million primarily due to a decrease in pretax
book income.
|
Six Months Ended June 30,
2008 Compared to Six Months Ended June 30, 2007
Reconciliation
of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Net
Income
(in
millions)
Six
Months Ended June 30, 2007
|
|
|
|
|
$ |
127 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
40 |
|
|
|
|
|
Off-system
Sales
|
|
|
20 |
|
|
|
|
|
Transmission
Revenues
|
|
|
1 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
61 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(43
|
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
4 |
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(9
|
) |
|
|
|
|
Other
Income
|
|
|
5 |
|
|
|
|
|
Interest
Expense
|
|
|
(5
|
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(48
|
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(7
|
) |
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2008
|
|
|
|
|
|
$ |
133 |
|
Net
Income increased $6 million to $133 million in 2008. The key drivers
of the increase were a $61 million increase in Gross Margin primarily offset by
a $48 million increase in Operating Expenses and Other and a $7 million increase
in Income Tax Expense.
The major
components of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $40 million primarily due to:
|
|
·
|
A
$58 million increase related to a net increase in rates
implemented.
|
|
·
|
A
$39 million decrease in capacity settlement charges related to CSPCo’s
unit power agreement for AEGCo’s Lawrenceburg Plant which began in May
2007 and the April 2007 acquisition of the Darby Plant.
|
|
·
|
A
$15 million increase in industrial revenue due to increased usage by
Ormet, a major industrial customer.
|
|
These
increases were partially offset by:
|
|
·
|
A
$60 million decrease related to increased fuel and PJM
expenses.
|
|
·
|
A
$9 million decrease in residential and commercial revenue primarily due to
a 25% decrease in cooling degree days.
|
·
|
Margins
from Off-system Sales increased $20 million primarily due to higher
physical sales margins and higher trading
margins.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $43 million primarily due
to:
|
|
·
|
A
$13 million increase in expenses related to CSPCo’s unit power agreement
for AEGCo’s Lawrenceburg Plant which began in May 2007.
|
|
·
|
A
$12 million increase in steam plant maintenance expenses primarily related
to work performed at the Conesville Plant.
|
|
·
|
An
$8 million increase in recoverable PJM expenses.
|
|
·
|
A
$5 million increase in recoverable customer account expenses related to
the Universal Service Fund for customers who qualify for payment
assistance.
|
|
·
|
A
$3 million increase in boiler plant removal expenses primarily related to
work performed at the Conesville Plant.
|
·
|
Depreciation
and Amortization decreased $4 million primarily due to a $6 million
decrease in amortization of IGCC pre-construction costs offset by a $3
million increase related to the acquisition of the Darby Plant in
2007.
|
·
|
Taxes
Other Than Income Taxes increased $9 million due to property tax
adjustments.
|
·
|
Interest
Expense increased $5 million due to increased long-term borrowings and an
increase in short-term borrowings from the Utility Money
Pool.
|
·
|
Income
Tax Expense increased $7 million primarily due to an increase in pretax
book income and state income taxes.
|
Critical Accounting
Estimates
See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption of New Accounting
Pronouncements
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market
Risks
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion and analysis within AEP’s
“Quantitative and Qualitative Disclosures About Risk Management Activities”
section for disclosures about risk management activities.
Interest
Rate Risk
Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure. EaR statistically quantifies the extent to which CSPCo’s interest
expense could vary over the next twelve months and gives a probabilistic
estimate of different levels of interest expense. The resulting EaR
is interpreted as the dollar amount by which actual interest expense for the
next twelve months could exceed expected interest expense with a one-in-twenty
chance of occurrence. The primary drivers of EaR are from the
existing floating rate debt (including short-term debt) as well as long-term
debt issuances in the next twelve months. The estimated EaR on
CSPCo’s debt portfolio was $2.1 million.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
500,056 |
|
|
$ |
469,648 |
|
|
$ |
1,005,380 |
|
|
$ |
893,114 |
|
Sales
to AEP Affiliates
|
|
|
47,413 |
|
|
|
35,356 |
|
|
|
82,521 |
|
|
|
58,369 |
|
Other
|
|
|
1,478 |
|
|
|
1,018 |
|
|
|
2,695 |
|
|
|
2,451 |
|
TOTAL
|
|
|
548,947 |
|
|
|
506,022 |
|
|
|
1,090,596 |
|
|
|
953,934 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
86,253 |
|
|
|
76,342 |
|
|
|
171,380 |
|
|
|
152,204 |
|
Purchased
Electricity for Resale
|
|
|
45,010 |
|
|
|
32,835 |
|
|
|
87,196 |
|
|
|
64,146 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
110,578 |
|
|
|
87,788 |
|
|
|
204,682 |
|
|
|
171,329 |
|
Other
Operation
|
|
|
84,955 |
|
|
|
62,516 |
|
|
|
158,021 |
|
|
|
123,675 |
|
Maintenance
|
|
|
34,435 |
|
|
|
26,723 |
|
|
|
57,666 |
|
|
|
49,287 |
|
Depreciation
and Amortization
|
|
|
47,693 |
|
|
|
49,446 |
|
|
|
96,295 |
|
|
|
99,743 |
|
Taxes
Other Than Income Taxes
|
|
|
40,989 |
|
|
|
35,796 |
|
|
|
85,545 |
|
|
|
76,378 |
|
TOTAL
|
|
|
449,913 |
|
|
|
371,446 |
|
|
|
860,785 |
|
|
|
736,762 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
99,034 |
|
|
|
134,576 |
|
|
|
229,811 |
|
|
|
217,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
1,603 |
|
|
|
194 |
|
|
|
3,942 |
|
|
|
616 |
|
Carrying
Costs Income
|
|
|
1,538 |
|
|
|
1,139 |
|
|
|
3,304 |
|
|
|
2,231 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
565 |
|
|
|
620 |
|
|
|
1,420 |
|
|
|
1,392 |
|
Interest
Expense
|
|
|
(17,246
|
) |
|
|
(16,382
|
) |
|
|
(36,485
|
) |
|
|
(31,663
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE
|
|
|
85,494 |
|
|
|
120,147 |
|
|
|
201,992 |
|
|
|
189,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
29,101 |
|
|
|
40,125 |
|
|
|
69,446 |
|
|
|
62,745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME |
|
|
56,393 |
|
|
|
80,022 |
|
|
|
132,546 |
|
|
|
127,003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
Stock Expense
|
|
|
40 |
|
|
|
40 |
|
|
|
79 |
|
|
|
79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK |
|
$ |
56,353 |
|
|
$ |
79,982 |
|
|
$ |
132,467 |
|
|
$ |
126,924 |
|
The
common stock of CSPCo is wholly-owned by AEP.
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
|
Paid-in
Capital
|
|
|
Retained
Earnings
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
Total
|
|
DECEMBER
31, 2006
|
|
$ |
41,026 |
|
|
$ |
580,192 |
|
|
$ |
456,787 |
|
|
$ |
(21,988 |
) |
|
$ |
1,056,017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(3,022
|
) |
|
|
|
|
|
|
(3,022
|
) |
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(40,000
|
) |
|
|
|
|
|
|
(40,000
|
) |
Capital
Stock Expense
|
|
|
|
|
|
|
79 |
|
|
|
(79
|
) |
|
|
|
|
|
|
- |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,012,995 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
669 |
|
|
|
669 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
127,003 |
|
|
|
|
|
|
|
127,003 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
127,672 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
41,026 |
|
|
$ |
580,271 |
|
|
$ |
540,689 |
|
|
$ |
(21,319 |
) |
|
$ |
1,140,667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2007
|
|
$ |
41,026 |
|
|
$ |
580,349 |
|
|
$ |
561,696 |
|
|
$ |
(18,794 |
) |
|
$ |
1,164,277 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EITF
06-10 Adoption, Net of Tax of $589
|
|
|
|
|
|
|
|
|
|
|
(1,095
|
) |
|
|
|
|
|
|
(1,095
|
) |
SFAS
157 Adoption, Net of Tax of $170
|
|
|
|
|
|
|
|
|
|
|
(316
|
) |
|
|
|
|
|
|
(316
|
) |
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(62,500
|
) |
|
|
|
|
|
|
(62,500
|
) |
Capital
Stock Expense
|
|
|
|
|
|
|
79 |
|
|
|
(79
|
) |
|
|
|
|
|
|
- |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,100,366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $5,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,451
|
) |
|
|
(9,451
|
) |
Amortization
of Pension and OPEB Deferred
Costs,
Net of Tax of $304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
564 |
|
|
|
564 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
132,546 |
|
|
|
|
|
|
|
132,546 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
123,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2008
|
|
$ |
41,026 |
|
|
$ |
580,428 |
|
|
$ |
630,252 |
|
|
$ |
(27,681 |
) |
|
$ |
1,224,025 |
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,591 |
|
|
$ |
1,389 |
|
Other
Cash Deposits
|
|
|
36,975 |
|
|
|
53,760 |
|
Advances
to Affiliates
|
|
|
25,199 |
|
|
|
- |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
78,715 |
|
|
|
57,268 |
|
Affiliated Companies
|
|
|
20,346 |
|
|
|
32,852 |
|
Accrued Unbilled Revenues
|
|
|
18,759 |
|
|
|
14,815 |
|
Miscellaneous
|
|
|
15,238 |
|
|
|
9,905 |
|
Allowance for Uncollectible Accounts
|
|
|
(2,647
|
) |
|
|
(2,563 |
) |
Total
Accounts Receivable
|
|
|
130,411 |
|
|
|
112,277 |
|
Fuel
|
|
|
37,196 |
|
|
|
35,849 |
|
Materials
and Supplies
|
|
|
37,191 |
|
|
|
36,626 |
|
Emission
Allowances
|
|
|
11,766 |
|
|
|
16,811 |
|
Risk
Management Assets
|
|
|
111,622 |
|
|
|
33,558 |
|
Prepayments
and Other
|
|
|
17,153 |
|
|
|
9,960 |
|
TOTAL
|
|
|
409,104 |
|
|
|
300,230 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
2,135,486 |
|
|
|
2,072,564 |
|
Transmission
|
|
|
563,847 |
|
|
|
510,107 |
|
Distribution
|
|
|
1,577,693 |
|
|
|
1,552,999 |
|
Other
|
|
|
205,097 |
|
|
|
198,476 |
|
Construction
Work in Progress
|
|
|
464,286 |
|
|
|
415,327 |
|
Total
|
|
|
4,946,409 |
|
|
|
4,749,473 |
|
Accumulated
Depreciation and Amortization
|
|
|
1,749,038 |
|
|
|
1,697,793 |
|
TOTAL
- NET
|
|
|
3,197,371 |
|
|
|
3,051,680 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
218,323 |
|
|
|
235,883 |
|
Long-term
Risk Management Assets
|
|
|
61,708 |
|
|
|
41,852 |
|
Deferred
Charges and Other
|
|
|
146,808 |
|
|
|
181,563 |
|
TOTAL
|
|
|
426,839 |
|
|
|
459,298 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
4,033,314 |
|
|
$ |
3,811,208 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDER’S EQUITY
June
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
- |
|
|
$ |
95,199 |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
150,298 |
|
|
|
113,290 |
|
Affiliated
Companies
|
|
|
57,025 |
|
|
|
65,292 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
- |
|
|
|
112,000 |
|
Risk
Management Liabilities
|
|
|
131,260 |
|
|
|
28,237 |
|
Customer
Deposits
|
|
|
45,190 |
|
|
|
43,095 |
|
Accrued
Taxes
|
|
|
154,288 |
|
|
|
179,831 |
|
Other
|
|
|
85,794 |
|
|
|
96,892 |
|
TOTAL
|
|
|
623,855 |
|
|
|
733,836 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
1,343,388 |
|
|
|
1,086,224 |
|
Long-term
Debt – Affiliated
|
|
|
100,000 |
|
|
|
100,000 |
|
Long-term
Risk Management Liabilities
|
|
|
49,103 |
|
|
|
27,419 |
|
Deferred
Income Taxes
|
|
|
440,884 |
|
|
|
437,306 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
159,635 |
|
|
|
165,635 |
|
Deferred
Credits and Other
|
|
|
92,424 |
|
|
|
96,511 |
|
TOTAL
|
|
|
2,185,434 |
|
|
|
1,913,095 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,809,289 |
|
|
|
2,646,931 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
|
Common
Stock – No Par Value:
|
|
|
|
|
|
|
|
|
Authorized
– 24,000,000 Shares
|
|
|
|
|
|
|
|
|
Outstanding
– 16,410,426 Shares
|
|
|
41,026 |
|
|
|
41,026 |
|
Paid-in
Capital
|
|
|
580,428 |
|
|
|
580,349 |
|
Retained
Earnings
|
|
|
630,252 |
|
|
|
561,696 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(27,681
|
) |
|
|
(18,794
|
) |
TOTAL
|
|
|
1,224,025 |
|
|
|
1,164,277 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$ |
4,033,314 |
|
|
$ |
3,811,208 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
|
Net
Income
|
|
$ |
132,546 |
|
|
$ |
127,003 |
|
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
96,295 |
|
|
|
99,743 |
|
|
Deferred
Income Taxes
|
|
|
9,670 |
|
|
|
(5,077 |
) |
|
Carrying
Costs Income
|
|
|
(3,304
|
) |
|
|
(2,231 |
) |
|
Allowance
for Equity Funds Used During Construction
|
|
|
(1,420
|
) |
|
|
(1,392 |
) |
|
Mark-to-Market
of Risk Management Contracts
|
|
|
10,859 |
|
|
|
6,842 |
|
|
Deferred
Property Taxes
|
|
|
43,745 |
|
|
|
39,063 |
|
|
Change
in Other Noncurrent Assets
|
|
|
(19,046
|
) |
|
|
(24,593 |
) |
|
Change
in Other Noncurrent Liabilities
|
|
|
(2,759
|
) |
|
|
(7,054 |
) |
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
|
Accounts Receivable, Net
|
|
|
(18,134
|
) |
|
|
7,678 |
|
|
Fuel, Materials and Supplies
|
|
|
(1,912
|
) |
|
|
(8,896 |
) |
|
Accounts Payable
|
|
|
8,747 |
|
|
|
(10,735 |
) |
|
Customer Deposits
|
|
|
2,095 |
|
|
|
15,616 |
|
|
Accrued Taxes, Net
|
|
|
(25,530
|
) |
|
|
5,493 |
|
|
Other Current Assets
|
|
|
(2,160
|
) |
|
|
8,601 |
|
|
Other Current Liabilities
|
|
|
(13,657
|
) |
|
|
(1,952 |
) |
|
Net
Cash Flows from Operating Activities
|
|
|
216,035 |
|
|
|
248,109 |
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(191,668
|
) |
|
|
(169,014 |
) |
|
Change
in Other Cash Deposits, Net
|
|
|
16,785 |
|
|
|
(20 |
) |
|
Change
in Advances to Affiliates, Net
|
|
|
(25,199
|
) |
|
|
- |
|
|
Acquisition
of Darby Plant
|
|
|
- |
|
|
|
(102,032 |
) |
|
Proceeds
from Sales of Assets
|
|
|
700 |
|
|
|
842 |
|
|
Net
Cash Flows Used for Investing Activities
|
|
|
(199,382
|
) |
|
|
(270,224 |
) |
|
|
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
346,934 |
|
|
|
- |
|
|
Change
in Advances from Affiliates, Net
|
|
|
(95,199
|
) |
|
|
63,307 |
|
|
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(204,245
|
) |
|
|
- |
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(1,441
|
) |
|
|
(1,446 |
) |
|
Dividends
Paid on Common Stock
|
|
|
(62,500
|
) |
|
|
(40,000 |
) |
|
Net
Cash Flows from (Used for) Financing Activities
|
|
|
(16,451
|
) |
|
|
21,861 |
|
|
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
202 |
|
|
|
(254 |
) |
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,389 |
|
|
|
1,319 |
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,591 |
|
|
$ |
1,065 |
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
38,531 |
|
|
$ |
31,557 |
|
|
Net
Cash Paid for Income Taxes
|
|
|
22,307 |
|
|
|
1,704 |
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,228 |
|
|
|
1,347 |
|
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
62,157 |
|
|
|
30,659 |
|
|
Noncash
Assumption of Liabilities Related to Acquisition of Darby
Plant
|
|
|
- |
|
|
|
2,339 |
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to CSPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to
CSPCo.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Acquisition
|
Note
5
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
INDIANA
MICHIGAN POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S NARRATIVE
FINANCIAL DISCUSSION AND ANALYSIS
Results of
Operations
Second Quarter of 2008
Compared to Second Quarter of 2007
Reconciliation
of Second Quarter of 2007 to Second Quarter of 2008
Net
Income
(in
millions)
Second
Quarter of 2007
|
|
|
|
|
$ |
30 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(3
|
) |
|
|
|
|
FERC
Municipals and Cooperatives
|
|
|
3 |
|
|
|
|
|
Off-system
Sales
|
|
|
5 |
|
|
|
|
|
Other
|
|
|
10 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(14
|
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
22 |
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1
|
) |
|
|
|
|
Interest
Expense
|
|
|
3 |
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(5
|
) |
|
|
|
|
|
|
|
|
|
Second
Quarter of 2008
|
|
|
|
|
|
$ |
50 |
|
Net
Income increased $20 million to $50 million in 2008. The key drivers
of the increase were a $15 million increase in Gross Margin and a $10 million
decrease in Operating Expenses and Other partially offset by a $5 million
increase in Income Tax Expense.
The major
components of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins decreased $3 million primarily due to lower retail sales
reflecting weather conditions as cooling degree days decreased
significantly in both the Indiana and Michigan
jurisdictions.
|
·
|
FERC
Municipals and Cooperatives margins increased $3 million due to higher
revenues under formula rate plans in 2008.
|
·
|
Margins
from Off-system Sales increased $5 million primarily due to higher
physical sales margins partially offset by lower trading
margins.
|
·
|
Other
revenues increased $10 million primarily due to increased River
Transportation Division (RTD) revenues for barging
services. RTD’s related expenses which offset the RTD revenue
increase are included in Other Operation on the Condensed Consolidated
Statements of Income resulting in earning only a return approved under a
regulatory order.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $14 million primarily due to
higher operation and maintenance expenses for RTD of $12 million caused by
increased barging activity and increased cost of fuel. Nuclear
operation and maintenance expense increases were offset by lower
coal-fired plant maintenance expenses. Scheduled outages
occurred at Cook Plant in 2008 and Rockport Plant in
2007.
|
·
|
Depreciation
and Amortization expense decreased $22 million primarily due to reduced
depreciation rates reflecting longer estimated lives for Cook and Tanners
Creek Plants. Depreciation rates were reduced for the Indiana
jurisdiction in June 2007 and the FERC and Michigan jurisdictions in
October 2007. See “Indiana Depreciation Study Filing” and
“Michigan Depreciation Study Filing” sections of Note 4 in the 2007 Annual
Report.
|
·
|
Income
Tax Expense increased $5 million primarily due to an increase in pretax
book income and a decrease in amortization of investment tax credits
partially offset by changes in certain book/tax differences accounted for
on a flow-through basis and a decrease in state income
tax.
|
Six Months Ended June 30,
2008 Compared to Six Months Ended June 30, 2007
Reconciliation
of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Net
Income
(in
millions)
Six
Months Ended June 30, 2007
|
|
|
|
|
$ |
59 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(2
|
) |
|
|
|
|
FERC
Municipals and Cooperatives
|
|
|
7 |
|
|
|
|
|
Off-system
Sales
|
|
|
14 |
|
|
|
|
|
Transmission
Revenues
|
|
|
(1
|
) |
|
|
|
|
Other
|
|
|
18 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(23
|
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
47 |
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(3
|
) |
|
|
|
|
Other
Income
|
|
|
2 |
|
|
|
|
|
Interest
Expense
|
|
|
3 |
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(16
|
) |
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2008
|
|
|
|
|
|
$ |
105 |
|
Net
Income increased $46 million to $105 million in 2008. The key drivers
of the increase were a $36 million increase in Gross Margin and a $26 million
decrease in Operating Expenses and Other partially offset by a $16 million
increase in Income Tax Expense.
The major
components of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power, were as follows:
·
|
FERC
Municipals and Cooperatives margins increased $7 million due to higher
revenues under formula rate plans in 2008.
|
·
|
Margins
from Off-system Sales increased $14 million primarily due to higher
physical sales margins partially offset by lower trading
margins.
|
·
|
Other
revenues increased $18 million primarily due to increased RTD revenues for
barging services. RTD’s related expenses which offset the RTD
revenue increase are included in Other Operation on the Condensed
Consolidated Statements of Income resulting in earning only a return
approved under regulatory
order.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other Operation
and Maintenance expenses increased $23 million primarily due to higher
operation and maintenance expenses for RTD of $19 million caused by
increased barging activity and increased cost of fuel. Nuclear
operation and maintenance expense increases were offset by lower
coal-fired plant maintenance and accretion expenses. Scheduled
outages occurred at Cook Plant in 2008 and Rockport Plant in
2007.
|
·
|
Depreciation
and Amortization expense decreased $47 million primarily due to the
reduced depreciation rates in all jurisdictions.
|
·
|
Income
Tax Expense increased $16 million primarily due to an increase in pretax
book income and a decrease in amortization of investment tax credits
partially offset by changes in certain book/tax differences accounted for
on a flow-through basis.
|
Critical Accounting
Estimates
See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption of New Accounting
Pronouncements
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market
Risks
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion and analysis within AEP’s
“Quantitative and Qualitative Disclosures About Risk Management Activities”
section for disclosures about risk management activities.
Interest
Rate Risk
Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure. EaR statistically quantifies the extent to which I&M’s interest
expense could vary over the next twelve months and gives a probabilistic
estimate of different levels of interest expense. The resulting EaR
is interpreted as the dollar amount by which actual interest expense for the
next twelve months could exceed expected interest expense with a one-in-twenty
chance of occurrence. The primary drivers of EaR are from the
existing floating rate debt (including short-term debt) as well as long-term
debt issuances in the next twelve months. The estimated EaR on
I&M’s debt portfolio was $4.8 million.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
425,018 |
|
|
$ |
402,152 |
|
|
$ |
856,610 |
|
|
$ |
807,316 |
|
Sales
to AEP Affiliates
|
|
|
83,927 |
|
|
|
62,962 |
|
|
|
160,439 |
|
|
|
130,391 |
|
Other
– Affiliated
|
|
|
29,257 |
|
|
|
14,571 |
|
|
|
52,476 |
|
|
|
27,238 |
|
Other
– Nonaffiliated
|
|
|
4,445 |
|
|
|
6,352 |
|
|
|
10,271 |
|
|
|
13,961 |
|
TOTAL
|
|
|
542,647 |
|
|
|
486,037 |
|
|
|
1,079,796 |
|
|
|
978,906 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
108,496 |
|
|
|
90,650 |
|
|
|
209,737 |
|
|
|
186,767 |
|
Purchased
Electricity for Resale
|
|
|
26,441 |
|
|
|
19,310 |
|
|
|
47,924 |
|
|
|
37,250 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
91,858 |
|
|
|
75,791 |
|
|
|
184,499 |
|
|
|
153,304 |
|
Other
Operation
|
|
|
124,687 |
|
|
|
117,311 |
|
|
|
245,053 |
|
|
|
238,044 |
|
Maintenance
|
|
|
52,608 |
|
|
|
45,725 |
|
|
|
103,829 |
|
|
|
88,155 |
|
Depreciation
and Amortization
|
|
|
31,757 |
|
|
|
53,890 |
|
|
|
63,479 |
|
|
|
110,197 |
|
Taxes
Other Than Income Taxes
|
|
|
20,342 |
|
|
|
19,238 |
|
|
|
40,244 |
|
|
|
37,232 |
|
TOTAL
|
|
|
456,189 |
|
|
|
421,915 |
|
|
|
894,765 |
|
|
|
850,949 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
86,458 |
|
|
|
64,122 |
|
|
|
185,031 |
|
|
|
127,957 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
1,904 |
|
|
|
707 |
|
|
|
2,733 |
|
|
|
1,295 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
128 |
|
|
|
727 |
|
|
|
1,008 |
|
|
|
992 |
|
Interest
Expense
|
|
|
(17,146
|
) |
|
|
(19,611
|
) |
|
|
(36,348
|
) |
|
|
(39,432
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE
|
|
|
71,344 |
|
|
|
45,945 |
|
|
|
152,424 |
|
|
|
90,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
21,200 |
|
|
|
15,910 |
|
|
|
47,022 |
|
|
|
31,314 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
50,144 |
|
|
|
30,035 |
|
|
|
105,402 |
|
|
|
59,498 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
85 |
|
|
|
85 |
|
|
|
170 |
|
|
|
170 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
50,059 |
|
|
$ |
29,950 |
|
|
$ |
105,232 |
|
|
$ |
59,328 |
|
The common stock of I&M is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
|
Paid-in
Capital
|
|
|
Retained
Earnings
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
Total
|
|
DECEMBER
31, 2006
|
|
$ |
56,584 |
|
|
$ |
861,290 |
|
|
$ |
386,616 |
|
|
$ |
(15,051 |
) |
|
$ |
1,289,439 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
327 |
|
|
|
|
|
|
|
327 |
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(20,000
|
) |
|
|
|
|
|
|
(20,000
|
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(170
|
) |
|
|
|
|
|
|
(170
|
) |
Gain
on Reacquired Preferred Stock
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,269,597 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,206 |
|
|
|
1,206 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
59,498 |
|
|
|
|
|
|
|
59,498 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60,704 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
56,584 |
|
|
$ |
861,291 |
|
|
$ |
426,271 |
|
|
$ |
(13,845 |
) |
|
$ |
1,330,301 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2007
|
|
$ |
56,584 |
|
|
$ |
861,291 |
|
|
$ |
483,499 |
|
|
$ |
(15,675 |
) |
|
$ |
1,385,699 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EITF
06-10 Adoption, Net of Tax of $753
|
|
|
|
|
|
|
|
|
|
|
(1,398
|
) |
|
|
|
|
|
|
(1,398
|
) |
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(37,500
|
) |
|
|
|
|
|
|
(37,500
|
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(170
|
) |
|
|
|
|
|
|
(170
|
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,346,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $4,618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,577
|
) |
|
|
(8,577
|
) |
Amortization
of Pension and OPEB Deferred
Costs,
Net of Tax of $118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
220 |
|
|
|
220 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
105,402 |
|
|
|
|
|
|
|
105,402 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
97,045 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2008
|
|
$ |
56,584 |
|
|
$ |
861,291 |
|
|
$ |
549,833 |
|
|
$ |
(24,032 |
) |
|
$ |
1,443,676 |
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
982 |
|
|
$ |
1,139 |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
97,676 |
|
|
|
70,995 |
|
Affiliated Companies
|
|
|
62,238 |
|
|
|
92,018 |
|
Accrued Unbilled Revenues
|
|
|
13,432 |
|
|
|
16,207 |
|
Miscellaneous
|
|
|
1,080 |
|
|
|
1,335 |
|
Allowance for Uncollectible Accounts
|
|
|
(2,776
|
) |
|
|
(2,711 |
) |
Total
Accounts Receivable
|
|
|
171,650 |
|
|
|
177,844 |
|
Fuel
|
|
|
56,541 |
|
|
|
61,342 |
|
Materials
and Supplies
|
|
|
145,091 |
|
|
|
141,384 |
|
Risk
Management Assets
|
|
|
105,164 |
|
|
|
32,365 |
|
Accrued
Tax Benefits
|
|
|
10,619 |
|
|
|
4,438 |
|
Prepayments
and Other
|
|
|
22,870 |
|
|
|
11,091 |
|
TOTAL
|
|
|
512,917 |
|
|
|
429,603 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
3,507,581 |
|
|
|
3,529,524 |
|
Transmission
|
|
|
1,094,164 |
|
|
|
1,078,575 |
|
Distribution
|
|
|
1,242,898 |
|
|
|
1,196,397 |
|
Other
(including nuclear fuel and coal mining)
|
|
|
608,205 |
|
|
|
626,390 |
|
Construction
Work in Progress
|
|
|
135,723 |
|
|
|
122,296 |
|
Total
|
|
|
6,588,571 |
|
|
|
6,553,182 |
|
Accumulated
Depreciation, Depletion and Amortization
|
|
|
2,988,253 |
|
|
|
2,998,416 |
|
TOTAL
- NET
|
|
|
3,600,318 |
|
|
|
3,554,766 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
263,951 |
|
|
|
246,435 |
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,361,927 |
|
|
|
1,346,798 |
|
Long-term
Risk Management Assets
|
|
|
58,516 |
|
|
|
40,227 |
|
Deferred
Charges and Other
|
|
|
134,693 |
|
|
|
128,623 |
|
TOTAL
|
|
|
1,819,087 |
|
|
|
1,762,083 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
5,932,322 |
|
|
$ |
5,746,452 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
June
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
272,707 |
|
|
$ |
45,064 |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
107,120 |
|
|
|
184,435 |
|
Affiliated
Companies
|
|
|
47,603 |
|
|
|
61,749 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
50,000 |
|
|
|
145,000 |
|
Risk
Management Liabilities
|
|
|
124,092 |
|
|
|
27,271 |
|
Customer
Deposits
|
|
|
27,341 |
|
|
|
26,445 |
|
Accrued
Taxes
|
|
|
73,783 |
|
|
|
60,995 |
|
Obligations
Under Capital Leases
|
|
|
44,388 |
|
|
|
43,382 |
|
Other
|
|
|
108,766 |
|
|
|
130,232 |
|
TOTAL
|
|
|
855,800 |
|
|
|
724,573 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
1,375,757 |
|
|
|
1,422,427 |
|
Long-term
Risk Management Liabilities
|
|
|
46,777 |
|
|
|
26,348 |
|
Deferred
Income Taxes
|
|
|
370,242 |
|
|
|
321,716 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
767,385 |
|
|
|
789,346 |
|
Asset
Retirement Obligations
|
|
|
874,941 |
|
|
|
852,646 |
|
Deferred
Credits and Other
|
|
|
189,664 |
|
|
|
215,617 |
|
TOTAL
|
|
|
3,624,766 |
|
|
|
3,628,100 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,480,566 |
|
|
|
4,352,673 |
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
8,080 |
|
|
|
8,080 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
|
Common
Stock – No Par Value:
|
|
|
|
|
|
|
|
|
Authorized
– 2,500,000 Shares
|
|
|
|
|
|
|
|
|
Outstanding
– 1,400,000 Shares
|
|
|
56,584 |
|
|
|
56,584 |
|
Paid-in
Capital
|
|
|
861,291 |
|
|
|
861,291 |
|
Retained
Earnings
|
|
|
549,833 |
|
|
|
483,499 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(24,032
|
) |
|
|
(15,675
|
) |
TOTAL
|
|
|
1,443,676 |
|
|
|
1,385,699 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
5,932,322 |
|
|
$ |
5,746,452 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
105,402 |
|
|
$ |
59,498 |
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
63,479 |
|
|
|
110,197 |
|
Deferred
Income Taxes
|
|
|
41,362 |
|
|
|
(9,547 |
) |
Amortization
(Deferral) of Incremental Nuclear Refueling Outage Expenses,
Net
|
|
|
(8,576
|
) |
|
|
23,099 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
(1,008
|
) |
|
|
(992 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
10,862 |
|
|
|
6,903 |
|
Amortization
of Nuclear Fuel
|
|
|
45,312 |
|
|
|
33,003 |
|
Change
in Other Noncurrent Assets
|
|
|
(9,103
|
) |
|
|
(11,316 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
19,847 |
|
|
|
19,425 |
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts Receivable, Net
|
|
|
6,194 |
|
|
|
36,805 |
|
Fuel, Materials and Supplies
|
|
|
1,094 |
|
|
|
9,911 |
|
Accounts Payable
|
|
|
449 |
|
|
|
(46,049 |
) |
Accrued Taxes, Net
|
|
|
6,607 |
|
|
|
72,977 |
|
Other Current Assets
|
|
|
(11,777
|
) |
|
|
3,373 |
|
Other Current Liabilities
|
|
|
(23,583
|
) |
|
|
(16,388 |
) |
Net
Cash Flows from Operating Activities
|
|
|
246,561 |
|
|
|
290,899 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(140,537
|
) |
|
|
(124,252 |
) |
Purchases
of Investment Securities
|
|
|
(276,031
|
) |
|
|
(409,163 |
) |
Sales
of Investment Securities
|
|
|
241,079 |
|
|
|
370,986 |
|
Acquisitions
of Nuclear Fuel
|
|
|
(98,732
|
) |
|
|
(30,498 |
) |
Proceeds
from Sales of Assets and Other
|
|
|
2,912 |
|
|
|
292 |
|
Net
Cash Flows Used for Investing Activities
|
|
|
(271,309
|
) |
|
|
(192,635 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
115,553 |
|
|
|
- |
|
Change
in Advances from Affiliates, Net
|
|
|
227,643 |
|
|
|
(76,232 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(262,000
|
) |
|
|
- |
|
Retirement
of Cumulative Preferred Stock
|
|
|
- |
|
|
|
(2 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(18,935
|
) |
|
|
(2,622 |
) |
Dividends
Paid on Common Stock
|
|
|
(37,500
|
) |
|
|
(20,000 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(170
|
) |
|
|
(170 |
) |
Net
Cash Flows from (Used for) Financing Activities
|
|
|
24,591 |
|
|
|
(99,026 |
) |
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(157
|
) |
|
|
(762 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,139 |
|
|
|
1,369 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
982 |
|
|
$ |
607 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
38,706 |
|
|
$ |
32,082 |
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
13,827 |
|
|
|
(20,001 |
) |
Noncash
Acquisitions Under Capital Leases
|
|
|
2,911 |
|
|
|
1,160 |
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
20,650 |
|
|
|
24,145 |
|
Acquisition
of Nuclear Fuel Included in Accounts Payable at June 30,
|
|
|
- |
|
|
|
30,867 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to I&M’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to
I&M.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
OHIO
POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
Results of
Operations
Second Quarter of 2008
Compared to Second Quarter of 2007
Reconciliation
of Second Quarter of 2007 to Second Quarter of 2008
Net
Income
(in
millions)
Second
Quarter of 2007
|
|
|
|
|
$ |
74 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(46
|
) |
|
|
|
|
Off-system
Sales
|
|
|
9 |
|
|
|
|
|
Other
|
|
|
2 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(35
|
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(13
|
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
14 |
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
4 |
|
|
|
|
|
Other
Income
|
|
|
2 |
|
|
|
|
|
Interest
Expense
|
|
|
(8
|
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(1
|
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
Second
Quarter of 2008
|
|
|
|
|
|
$ |
53 |
|
Net
Income decreased $21 million to $53 million in 2008. The key drivers
of the decrease were a $35 million decrease in Gross Margin offset by a $15
million decrease in Income Tax Expense.
The major
components of the decrease in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins decreased $46 million primarily due to the
following:
|
|
·
|
A
$29 million decrease related to a coal contract amendment in the second
quarter of 2008.
|
|
·
|
A
$29 million decrease related to increased fuel, consumable, allowance and
PJM expenses.
|
|
·
|
A
$6 million decrease in residential revenue primarily due to a 27% decrease
in cooling degree days and a 30% decrease in heating degree
days.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$14 million increase related to a net increase in rates
implemented.
|
·
|
Margins
from Off-system Sales increased $9 million due to higher physical sales
margins partially offset by lower trading
margins.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $13 million primarily due
to:
|
|
·
|
A
$10 million increase in recoverable PJM expenses.
|
|
·
|
A
$10 million increase in steam plant maintenance
expenses.
|
|
·
|
A
$3 million increase in recoverable customer account expenses related to
the Universal Service Fund for customers who qualify for payment
assistance.
|
|
These
increases were partially offset by:
|
|
·
|
A
$4 million decrease in overhead line maintenance
expenses.
|
|
·
|
A
$3 million decrease in removal expenses due to work performed at the
Cardinal, Mitchell and Gavin Plants in 2007.
|
·
|
Depreciation
and Amortization decreased $14 million primarily due
to:
|
|
·
|
A
$17 million decrease in amortization as a result of completion of
amortization of regulatory assets in December 2007.
|
|
·
|
A
$3 million decrease due to the amortization of IGCC pre-construction
costs, which ended in the second quarter of 2007. The
amortization of IGCC pre-construction costs was offset by a corresponding
increase in Retail Margins in 2007.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$6 million increase in depreciation related to environmental improvements
placed in service at the Cardinal Plant in 2008 and the Mitchell Plant in
July 2007.
|
·
|
Taxes
Other Than Income Taxes decreased $4 million primarily due to property tax
adjustments.
|
·
|
Interest
Expense increased $8 million primarily due to a decrease in the debt
component of AFUDC as a result of Mitchell Plant and Cardinal Plant
environmental improvements placed in service and higher interest rates on
variable rate debt.
|
·
|
Income
Tax Expense decreased $15 million primarily due to a decrease in pretax
book income.
|
Six Months Ended
June 30,
2008 Compared
to Six Months Ended June 30,
2007
Reconciliation
of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Net
Income
(in
millions)
Six
Months Ended June 30, 2007
|
|
|
|
|
$ |
154 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(6
|
) |
|
|
|
|
Off-system
Sales
|
|
|
23 |
|
|
|
|
|
Other
|
|
|
9 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
10 |
|
|
|
|
|
Depreciation
and Amortization
|
|
|
29 |
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
1 |
|
|
|
|
|
Other
Income
|
|
|
5 |
|
|
|
|
|
Interest
Expense
|
|
|
(16
|
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
29 |
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(18
|
) |
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2008
|
|
|
|
|
|
$ |
191 |
|
Net
Income increased $37 million to $191 million in 2008. The key drivers
of the increase were a $26 million increase in Gross Margin and a $29 million
decrease in Operating Expenses and Other offset by an $18 million increase in
Income Tax Expense.
The major
components of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins decreased $6 million primarily due to the
following:
|
|
·
|
A
$76 million decrease related to increased fuel, consumable and PJM
expenses.
|
|
·
|
A
$5 million decrease in residential and commercial revenues primarily due
to a 28% decrease in cooling degree days.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$29 million increase related to coal contract amendments in
2008.
|
|
·
|
A
$25 million increase related to a net increase in rates
implemented.
|
|
·
|
A
$15 million increase related to increased usage by Ormet, an industrial
customer. See “Ormet” section of Note 3.
|
|
·
|
A
$7 million increase in capacity settlements under the Interconnection
Agreement related to an increase in an affiliate’s
peak.
|
·
|
Margins
from Off-system Sales increased $23 million due to higher physical sales
margins and higher trading margins.
|
·
|
Other
revenues increased $9 million primarily due to increased gains on sales of
emission allowances.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses decreased $10 million primarily due
to:
|
|
·
|
A
$21 million decrease in removal expenses.
|
|
·
|
A
$9 million decrease in overhead line maintenance
expenses.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$7 million increase in recoverable customer account expenses related to
the Universal Service Fund for customers who qualify for payment
assistance.
|
|
·
|
A
$7 million increase in recoverable PJM expenses.
|
·
|
Depreciation
and Amortization decreased $29 million primarily due
to:
|
|
·
|
A
$35 million decrease in amortization as a result of completion of
amortization of regulatory assets in December 2007.
|
|
·
|
A
$6 million decrease due to the amortization of IGCC pre-construction
costs, which ended in the second quarter of 2007. The
amortization of IGCC pre-construction costs was offset by a corresponding
increase in Retail Margins in 2007.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$14 million increase in depreciation related to environmental improvements
placed in service at the Cardinal Plant in 2008 and the Mitchell Plant
during 2007.
|
·
|
Interest
Expense increased $16 million primarily due to a decrease in the debt
component of AFUDC as a result of Mitchell Plant and Cardinal Plant
environmental improvements placed in service, the issuance of additional
long-term debt and higher interest rates on variable rate
debt.
|
·
|
Income
Tax Expense increased $18 million primarily due to an increase in pretax
book income.
|
Financial
Condition
Credit
Ratings
S&P
and Fitch currently have OPCo on stable outlook, while Moody’s placed OPCo on
negative outlook in the first quarter of 2008. Current ratings are as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
A3 |
|
BBB
|
|
BBB+
|
If OPCo
receives an upgrade from any of the rating agencies listed above, its borrowing
costs could decrease. If OPCo receives a downgrade from any of the
rating agencies listed above, it borrowing costs could increase and access to
borrowed funds could be negatively affected.
Cash
Flow
Cash
flows for the six months ended June 30, 2008 and 2007 were as
follows:
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$ |
6,666 |
|
|
$ |
1,625 |
|
Cash
Flows from (Used for):
|
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
289,944 |
|
|
|
279,029 |
|
Investing
Activities
|
|
|
(271,527
|
) |
|
|
(560,262
|
) |
Financing
Activities
|
|
|
(14,985
|
) |
|
|
282,607 |
|
Net
Increase in Cash and Cash Equivalents
|
|
|
3,432 |
|
|
|
1,374 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
10,098 |
|
|
$ |
2,999 |
|
Operating
Activities
Net Cash
Flows from Operating Activities were $290 million in 2008. OPCo
produced Net Income of $191 million during the period and a noncash expense item
of $140 million for Depreciation and Amortization. The other changes
in assets and liabilities represent items that had a current period cash flow
impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. Accounts Payable had a $47 million inflow primarily
due to increases in tonnage and prices per ton related to fuel and consumable
purchases. Fuel, Materials and Supplies had a $41 million outflow due
to price increases. Accounts Receivable, Net had a $38 million
outflow primarily due to a coal contract amendment which reduced future
deliveries in exchange for consideration received.
Net Cash
Flows from Operating Activities were $279 million in 2007. OPCo
produced income of $154 million during the period and a noncash expense item of
$169 million for Depreciation and Amortization. The other changes in
assets and liabilities represent items that had a prior period cash flow impact,
such as changes in working capital, as well as items that represent future
rights or obligations to receive or pay cash, such as regulatory assets and
liabilities. The prior period activity in working capital relates to
a number of items. Accounts Payable had a $47 million cash outflow
partially due to emission allowance payments in January 2007. Accrued
Taxes, Net, had a $47 million cash inflow primarily due to an increase of
federal income tax related accruals offset by temporary timing differences of
payments for property taxes. Fuel, Materials and Supplies had a $42
million cash outflow primarily due to an increase in coal inventory in
preparation for the summer cooling season and an increase in materials related
to projects at the Mitchell, Amos, Gavin and Sporn Plants.
Investing
Activities
Net Cash
Used for Investing Activities were $272 million and $560 million in 2008 and
2007, respectively. Construction Expenditures were $277 million and
$566 million in 2008 and 2007, respectively, primarily related to environmental
upgrades, as well as projects to improve service reliability for transmission
and distribution. Environmental upgrades include the installation of
selective catalytic reduction equipment and the flue gas desulfurization
projects at the Cardinal, Amos and Mitchell Plants. In January 2007,
environmental upgrades were completed for Unit 2 at the Mitchell
Plant. For the remainder of 2008, OPCo expects construction
expenditures to be approximately $410 million.
Financing
Activities
Net Cash
Flows Used for Financing Activities were $15 million in 2008. OPCo
issued $165 million of Pollution Control Bonds and retired $250 million of
Pollution Control Bonds. OPCo had a net increase in borrowings of $72
million from the Utility Money Pool.
Net Cash
Flows from Financing Activities were $283 million in 2007. OPCo
issued Senior Unsecured Notes for $400 million and $65 million of Pollution
Control Bonds. OPCo had a net decrease in borrowings of $165 million
from the Utility Money Pool.
Financing
Activity
Long-term
debt issuances, retirements and principal payments made during the first six
months of 2008 were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$
|
50,000
|
|
Variable
|
|
2014
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2014
|
Pollution
Control Bonds
|
|
|
65,000
|
|
Variable
|
|
2036
|
Retirements and Principal
Payments
|
|
Principal
Amount
Paid
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Notes
Payable – Nonaffiliated
|
|
$
|
1,463
|
|
6.81
|
|
2008
|
Notes
Payable – Nonaffiliated
|
|
|
6,000
|
|
6.27
|
|
2009
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2014
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2016
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2022
|
Pollution
Control Bonds
|
|
|
35,000
|
|
Variable
|
|
2022
|
Pollution
Control Bonds
|
|
|
65,000
|
|
Variable
|
|
2036
|
Liquidity
OPCo has
solid investment grade ratings, which provide ready access to capital markets in
order to issue new debt, refinance short-term debt or refinance long-term debt
maturities. In addition, OPCo participates in the Utility Money Pool,
which provides access to AEP’s liquidity.
Summary Obligation
Information
A summary
of contractual obligations is included in the 2007 Annual Report and has not
changed significantly from year-end other than the debt issuances and
retirements discussed in “Cash Flow” and “Financing Activity” above and letters
of credit. In April 2008, the Registrant Subsidiaries and certain
other companies in the AEP System entered into a $650 million 3-year credit
agreement and a $350 million 364-day credit agreement. As of June 30,
2008, $167 million of letters of credit were issued by OPCo under the 3-year
credit agreement to support variable rate demand notes.
Significant
Factors
Litigation
and Regulatory Activity
In the
ordinary course of business, OPCo is involved in employment, commercial,
environmental and regulatory litigation. Since it is difficult to
predict the outcome of these proceedings, management cannot state what the
eventual outcome of these proceedings will be, or what the timing of the amount
of any loss, fine or penalty may be. Management does, however, assess
the probability of loss for such contingencies and accrues a liability for cases
which have a probable likelihood of loss and the loss amount can be
estimated. For details on regulatory proceedings and pending
litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 2007 Annual Report. Also, see Note 3 – Rate
Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed
Notes to Condensed Financial Statements of Registrant Subsidiaries”
section. Adverse results in these proceedings have the potential to
materially affect results of operations, financial condition and cash
flows.
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of relevant factors.
Critical Accounting
Estimates
See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption of New Accounting
Pronouncements
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market
Risks
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion within AEP’s “Quantitative and
Qualitative Disclosures About Risk Management Activities”
section. The following tables provide information about AEP’s risk
management activities’ effect on OPCo.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in OPCo’s Condensed Consolidated Balance sheet as of June 30, 2008 and
the reasons for changes in total MTM value as compared to December 31,
2007.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of June 30, 2008
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
|
Cash
Flow
&
Fair
Value Hedges
|
|
|
DETM
Assignment (a)
|
|
|
Collateral
Deposits
|
|
|
Total
|
|
Current
Assets
|
|
$ |
183,037 |
|
|
$ |
1,530 |
|
|
$ |
- |
|
|
$ |
(10,714 |
) |
|
$ |
173,853 |
|
Noncurrent
Assets
|
|
|
93,550 |
|
|
|
254 |
|
|
|
- |
|
|
|
(5,974
|
) |
|
|
87,830 |
|
Total
MTM Derivative Contract Assets
|
|
|
276,587 |
|
|
|
1,784 |
|
|
|
- |
|
|
|
(16,688
|
) |
|
|
261,683 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(189,390
|
) |
|
|
(22,777
|
) |
|
|
(2,376
|
) |
|
|
17,082 |
|
|
|
(197,461
|
) |
Noncurrent
Liabilities
|
|
|
(66,264
|
) |
|
|
(901
|
) |
|
|
(2,603
|
) |
|
|
4,305 |
|
|
|
(65,463
|
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(255,654
|
) |
|
|
(23,678
|
) |
|
|
(4,979
|
) |
|
|
21,387 |
|
|
|
(262,924
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$ |
20,933 |
|
|
$ |
(21,894 |
) |
|
$ |
(4,979 |
) |
|
$ |
4,699 |
|
|
$ |
(1,241 |
) |
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Six
Months Ended June 30, 2008
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2007
|
|
$
|
30,248
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered in a
Prior Period
|
|
|
(5,931
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
866
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
(64
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward Contracts
(b)
|
|
|
2,158
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(c)
|
|
|
4,368
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
(10,712
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
20,933
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
(21,894
|
)
|
DETM
Assignment (e)
|
|
|
(4,979
|
)
|
Collateral
Deposits
|
|
|
4,699
|
|
Ending
Net Risk Management Assets at June 30, 2008
|
|
$
|
(1,241
|
)
|
(a)
|
Reflects
fair value on long-term contracts which are typically with customers that
seek fixed pricing to limit their risk against fluctuating energy
prices. The contract prices are valued against market curves
associated with the delivery location and delivery
term.
|
(b)
|
Represents
the impact of applying AEP’s credit risk when measuring the fair value of
derivative liabilities according to SFAS 157.
|
(c)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(d)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected in the Condensed
Consolidated Statements of Income. These net gains (losses) are
recorded as regulatory assets/liabilities for those subsidiaries that
operate in regulated jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
The
following table presents the maturity, by year, of net assets/liabilities to
give an indication of when these MTM amounts will settle and generate
cash:
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets
Fair
Value of Contracts as of June 30, 2008
(in
thousands)
|
|
Remainder
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
After
2012
|
|
|
Total
|
|
Level
1 (a)
|
|
$ |
(1,938 |
) |
|
$ |
330 |
|
|
$ |
(14 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(1,622 |
) |
Level
2 (b)
|
|
|
(1,281
|
) |
|
|
13,609 |
|
|
|
8,184 |
|
|
|
3,604 |
|
|
|
1,247 |
|
|
|
- |
|
|
|
25,363 |
|
Level
3 (c)
|
|
|
(6,774
|
) |
|
|
(1,096
|
) |
|
|
(2,719
|
) |
|
|
(1,752
|
) |
|
|
(904
|
) |
|
|
- |
|
|
|
(13,245
|
) |
Total
|
|
|
(9,993
|
) |
|
|
12,843 |
|
|
|
5,451 |
|
|
|
1,852 |
|
|
|
343 |
|
|
|
- |
|
|
|
10,496 |
|
Dedesignated
Risk Management Contracts (d)
|
|
|
1,666 |
|
|
|
3,220 |
|
|
|
3,194 |
|
|
|
1,244 |
|
|
|
1,113 |
|
|
|
- |
|
|
|
10,437 |
|
Total
MTM Risk Management Contract
Net Assets (Liabilities)
|
|
$ |
(8,327 |
) |
|
$ |
16,063 |
|
|
$ |
8,645 |
|
|
$ |
3,096 |
|
|
$ |
1,456 |
|
|
$ |
- |
|
|
$ |
20,933 |
|
(a)
|
Level
1 inputs are quoted prices (unadjusted) in active markets for identical
assets or liabilities that the reporting entity has the ability to access
at the measurement date. Level 1 inputs primarily consist of
exchange traded contracts that exhibit sufficient frequency and volume to
provide pricing information on an ongoing basis.
|
(b)
|
Level
2 inputs are inputs other than quoted prices included within Level 1 that
are observable for the asset or liability, either directly or
indirectly. If the asset or liability has a specified
(contractual) term, a Level 2 input must be observable for substantially
the full term of the asset or liability. Level 2 inputs
primarily consist of OTC broker quotes in moderately active or less active
markets, exchange traded contracts where there was not sufficient market
activity to warrant inclusion in Level 1, and OTC broker quotes that are
corroborated by the same or similar transactions that have occurred in the
market.
|
(c)
|
Level
3 inputs are unobservable inputs for the asset or
liability. Unobservable inputs shall be used to measure fair
value to the extent that the observable inputs are not available, thereby
allowing for situations in which there is little, if any, market activity
for the asset or liability at the measurement date. Level 3
inputs primarily consist of unobservable market data or are valued based
on models and/or assumptions.
|
(d)
|
Dedesignated
Risk Management Contracts are contracts that were originally MTM but were
subsequently elected as normal under SFAS 133. At the time of
the normal election the MTM value was frozen and no longer fair
valued. This will be amortized into Revenues over the remaining
life of the contract.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on
the Condensed Consolidated Balance Sheet
OPCo is
exposed to market fluctuations in energy commodity prices impacting power
operations. Management monitors these risks on future operations and
may use various commodity instruments designated in qualifying cash flow hedge
strategies to mitigate the impact of these fluctuations on the future cash
flows. Management does not hedge all commodity price
risk.
Management
uses interest rate derivative transactions to manage interest rate risk related
to anticipated borrowings of fixed-rate debt. Management does not
hedge all interest rate risk.
Management
uses foreign currency derivatives to lock in prices on certain forecasted
transactions denominated in foreign currencies where deemed necessary, and
designates qualifying instruments as cash flow hedges. Management
does not hedge all foreign currency exposure.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on OPCo’s Condensed Consolidated Balance Sheets and the reasons
for the changes from December 31, 2007 to June 30, 2008. Only
contracts designated as cash flow hedges are recorded in
AOCI. Therefore, economic hedge contracts that are not designated as
effective cash flow hedges are marked-to-market and included in the previous
risk management tables. All amounts are presented net of related
income taxes.
Total
Accumulated Other Comprehensive Income (Loss) Activity
Six
Months Ended June 30, 2008
(in
thousands)
|
|
Power
|
|
|
Interest
Rate
|
|
|
Foreign
Currency
|
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2007
|
|
$ |
(756 |
) |
|
$ |
2,167 |
|
|
$ |
(254 |
) |
|
$ |
1,157 |
|
Changes
in Fair Value
|
|
|
(11,404
|
) |
|
|
(899
|
) |
|
|
205 |
|
|
|
(12,098
|
) |
Reclassifications
from AOCI for Cash Flow Hedges
Settled
|
|
|
101 |
|
|
|
(382
|
) |
|
|
(123
|
) |
|
|
(404
|
) |
Ending
Balance in AOCI June 30, 2008
|
|
$ |
(12,059 |
) |
|
$ |
886 |
|
|
$ |
(172 |
) |
|
$ |
(11,345 |
) |
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $12.6 million loss.
Credit
Risk
Counterparty
credit quality and exposure is generally consistent with that of
AEP.
VaR
Associated with Risk Management Contracts
Management
uses a risk measurement model, which calculates Value at Risk (VaR) to measure
commodity price risk in the risk management portfolio. The VaR is
based on the variance-covariance method using historical prices to estimate
volatilities and correlations and assumes a 95% confidence level and a one-day
holding period. Based on this VaR analysis, at June 30, 2008, a near
term typical change in commodity prices is not expected to have a material
effect on OPCo’s results of operations, cash flows or financial
condition.
The
following table shows the end, high, average and low market risk as measured by
VaR for the periods indicated:
Six
Months Ended
|
|
|
Twelve
Months Ended
|
June
30, 2008
|
|
|
December
31, 2007
|
(in
thousands)
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$585
|
|
$1,048
|
|
$385
|
|
$132
|
|
|
$325
|
|
$2,054
|
|
$490
|
|
$90
|
Management
back-tests its VaR results against performance due to actual price
moves. Based on the assumed 95% confidence interval, performance due
to actual price moves would be expected to exceed the VaR at least once every 20
trading days. Management’s backtesting results show that its actual
performance exceeded VaR far fewer than once every 20 trading
days. As a result, management believes OPCo’s VaR calculation is
conservative.
As OPCo’s
VaR calculation captures recent price moves, management also performs regular
stress testing of the portfolio to understand its exposure to extreme price
moves. Management employs a historically-based method whereby the
current portfolio is subjected to actual, observed price moves from the last
three years in order to ascertain which historical price moves translate into
the largest potential mark-to-market loss. Management then researches
the underlying positions, price moves and market events that created the most
significant exposure.
Interest
Rate Risk
Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure. EaR statistically quantifies the extent to which OPCo’s interest
expense could vary over the next twelve months and gives a probabilistic
estimate of different levels of interest expense. The resulting EaR
is interpreted as the dollar amount by which actual interest expense for the
next twelve months could exceed expected interest expense with a one-in-twenty
chance of occurrence. The primary drivers of EaR are from the
existing floating rate debt (including short-term debt) as well as long-term
debt issuances in the next twelve months. The estimated EaR on OPCo’s
debt portfolio was $10.7 million.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
515,884 |
|
|
$ |
480,445 |
|
|
$ |
1,071,362 |
|
|
$ |
972,979 |
|
Sales
to AEP Affiliates
|
|
|
256,399 |
|
|
|
180,205 |
|
|
|
493,247 |
|
|
|
359,099 |
|
Other
- Affiliated
|
|
|
6,487 |
|
|
|
6,817 |
|
|
|
11,786 |
|
|
|
10,855 |
|
Other
- Nonaffiliated
|
|
|
3,591 |
|
|
|
3,466 |
|
|
|
8,154 |
|
|
|
7,441 |
|
TOTAL
|
|
|
782,361 |
|
|
|
670,933 |
|
|
|
1,584,549 |
|
|
|
1,350,374 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
330,190 |
|
|
|
201,338 |
|
|
|
569,124 |
|
|
|
399,631 |
|
Purchased
Electricity for Resale
|
|
|
39,155 |
|
|
|
27,868 |
|
|
|
73,732 |
|
|
|
52,722 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
35,157 |
|
|
|
28,745 |
|
|
|
67,673 |
|
|
|
49,711 |
|
Other
Operation
|
|
|
91,959 |
|
|
|
86,972 |
|
|
|
181,841 |
|
|
|
189,959 |
|
Maintenance
|
|
|
59,218 |
|
|
|
50,617 |
|
|
|
107,915 |
|
|
|
109,765 |
|
Depreciation
and Amortization
|
|
|
71,173 |
|
|
|
84,779 |
|
|
|
139,739 |
|
|
|
169,055 |
|
Taxes
Other Than Income Taxes
|
|
|
45,937 |
|
|
|
50,320 |
|
|
|
97,515 |
|
|
|
98,705 |
|
TOTAL
|
|
|
672,789 |
|
|
|
530,639 |
|
|
|
1,237,539 |
|
|
|
1,069,548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
109,572 |
|
|
|
140,294 |
|
|
|
347,010 |
|
|
|
280,826 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
1,750 |
|
|
|
472 |
|
|
|
4,658 |
|
|
|
884 |
|
Carrying
Costs Income
|
|
|
3,994 |
|
|
|
3,594 |
|
|
|
8,223 |
|
|
|
7,135 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
702 |
|
|
|
446 |
|
|
|
1,246 |
|
|
|
1,017 |
|
Interest
Expense
|
|
|
(41,853
|
) |
|
|
(33,734
|
) |
|
|
(76,235
|
) |
|
|
(59,665
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE
|
|
|
74,165 |
|
|
|
111,072 |
|
|
|
284,902 |
|
|
|
230,197 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
21,271 |
|
|
|
36,732 |
|
|
|
94,181 |
|
|
|
76,596 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
52,894 |
|
|
|
74,340 |
|
|
|
190,721 |
|
|
|
153,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
183 |
|
|
|
183 |
|
|
|
366 |
|
|
|
366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
52,711 |
|
|
$ |
74,157 |
|
|
$ |
190,355 |
|
|
$ |
153,235 |
|
The
common stock of OPCo is wholly-owned by AEP.
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
|
Paid-in
Capital
|
|
|
Retained
Earnings
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
Total
|
|
DECEMBER
31, 2006
|
|
$ |
321,201 |
|
|
$ |
536,639 |
|
|
$ |
1,207,265 |
|
|
$ |
(56,763 |
) |
|
$ |
2,008,342 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(5,380
|
) |
|
|
|
|
|
|
(5,380
|
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(366
|
) |
|
|
|
|
|
|
(366
|
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,002,596 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
971 |
|
|
|
971 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
153,601 |
|
|
|
|
|
|
|
153,601 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
154,572 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
321,201 |
|
|
$ |
536,639 |
|
|
$ |
1,355,120 |
|
|
$ |
(55,792 |
) |
|
$ |
2,157,168 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2007
|
|
$ |
321,201 |
|
|
$ |
536,640 |
|
|
$ |
1,469,717 |
|
|
$ |
(36,541 |
) |
|
$ |
2,291,017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EITF
06-10 Adoption, Net of Tax of $1,004
|
|
|
|
|
|
|
|
|
|
|
(1,864
|
) |
|
|
|
|
|
|
(1,864
|
) |
SFAS
157 Adoption, Net of Tax of $152
|
|
|
|
|
|
|
|
|
|
|
(282
|
) |
|
|
|
|
|
|
(282
|
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(366
|
) |
|
|
|
|
|
|
(366
|
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,288,505 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $6,732
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,502
|
) |
|
|
(12,502
|
) |
Amortization
of Pension and OPEB Deferred
Costs,
Net of Tax of $758
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,406 |
|
|
|
1,406 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
190,721 |
|
|
|
|
|
|
|
190,721 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
179,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2008
|
|
$ |
321,201 |
|
|
$ |
536,640 |
|
|
$ |
1,657,926 |
|
|
$ |
(47,637 |
) |
|
$ |
2,468,130 |
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
10,098 |
|
|
$ |
6,666 |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
117,920 |
|
|
|
104,783 |
|
Affiliated Companies
|
|
|
125,613 |
|
|
|
119,560 |
|
Accrued Unbilled Revenues
|
|
|
26,903 |
|
|
|
26,819 |
|
Miscellaneous
|
|
|
20,689 |
|
|
|
1,578 |
|
Allowance for Uncollectible Accounts
|
|
|
(3,502
|
) |
|
|
(3,396 |
) |
Total Accounts Receivable
|
|
|
287,623 |
|
|
|
249,344 |
|
Fuel
|
|
|
125,844 |
|
|
|
92,874 |
|
Materials
and Supplies
|
|
|
116,097 |
|
|
|
108,447 |
|
Risk
Management Assets
|
|
|
173,853 |
|
|
|
44,236 |
|
Prepayments
and Other
|
|
|
33,256 |
|
|
|
18,300 |
|
TOTAL
|
|
|
746,771 |
|
|
|
519,867 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
5,906,996 |
|
|
|
5,641,537 |
|
Transmission
|
|
|
1,092,630 |
|
|
|
1,068,387 |
|
Distribution
|
|
|
1,424,744 |
|
|
|
1,394,988 |
|
Other
|
|
|
371,427 |
|
|
|
318,805 |
|
Construction
Work in Progress
|
|
|
586,892 |
|
|
|
716,640 |
|
Total
|
|
|
9,382,689 |
|
|
|
9,140,357 |
|
Accumulated
Depreciation and Amortization
|
|
|
3,032,379 |
|
|
|
2,967,285 |
|
TOTAL
- NET
|
|
|
6,350,310 |
|
|
|
6,173,072 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
327,764 |
|
|
|
323,105 |
|
Long-term
Risk Management Assets
|
|
|
87,830 |
|
|
|
49,586 |
|
Deferred
Charges and Other
|
|
|
230,925 |
|
|
|
272,799 |
|
TOTAL
|
|
|
646,519 |
|
|
|
645,490 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
7,743,600 |
|
|
$ |
7,338,429 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
June
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
173,833 |
|
|
$ |
101,548 |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
209,084 |
|
|
|
141,196 |
|
Affiliated Companies
|
|
|
104,468 |
|
|
|
137,389 |
|
Short-term
Debt – Nonaffiliated
|
|
|
- |
|
|
|
701 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
125,225 |
|
|
|
55,188 |
|
Risk
Management Liabilities
|
|
|
197,461 |
|
|
|
40,548 |
|
Customer
Deposits
|
|
|
32,031 |
|
|
|
30,613 |
|
Accrued
Taxes
|
|
|
180,760 |
|
|
|
185,011 |
|
Accrued
Interest
|
|
|
39,687 |
|
|
|
41,880 |
|
Other
|
|
|
143,465 |
|
|
|
149,658 |
|
TOTAL
|
|
|
1,206,014 |
|
|
|
883,732 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
2,432,266 |
|
|
|
2,594,410 |
|
Long-term
Debt – Affiliated
|
|
|
200,000 |
|
|
|
200,000 |
|
Long-term
Risk Management Liabilities
|
|
|
65,463 |
|
|
|
32,194 |
|
Deferred
Income Taxes
|
|
|
926,957 |
|
|
|
914,170 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
154,258 |
|
|
|
160,721 |
|
Deferred
Credits and Other
|
|
|
256,438 |
|
|
|
229,635 |
|
TOTAL
|
|
|
4,035,382 |
|
|
|
4,131,130 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
5,241,396 |
|
|
|
5,014,862 |
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
17,447 |
|
|
|
15,923 |
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
16,627 |
|
|
|
16,627 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
|
Common
Stock – No Par Value:
|
|
|
|
|
|
|
|
|
Authorized – 40,000,000 Shares
|
|
|
|
|
|
|
|
|
Outstanding – 27,952,473 Shares
|
|
|
321,201 |
|
|
|
321,201 |
|
Paid-in
Capital
|
|
|
536,640 |
|
|
|
536,640 |
|
Retained
Earnings
|
|
|
1,657,926 |
|
|
|
1,469,717 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(47,637
|
) |
|
|
(36,541 |
) |
TOTAL
|
|
|
2,468,130 |
|
|
|
2,291,017 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
7,743,600 |
|
|
$ |
7,338,429 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
190,721 |
|
|
$ |
153,601 |
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
139,739 |
|
|
|
169,055 |
|
Deferred
Income Taxes
|
|
|
27,984 |
|
|
|
550 |
|
Carrying
Costs Income
|
|
|
(8,223
|
) |
|
|
(7,135 |
) |
Allowance
for Equity Funds Used During Construction
|
|
|
(1,246
|
) |
|
|
(1,017 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
2,018 |
|
|
|
2,876 |
|
Deferred
Property Taxes
|
|
|
42,089 |
|
|
|
34,629 |
|
Change
in Other Noncurrent Assets
|
|
|
(59,294
|
) |
|
|
(17,321 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
13,265 |
|
|
|
272 |
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts Receivable, Net
|
|
|
(38,279
|
) |
|
|
(18,273 |
) |
Fuel, Materials and Supplies
|
|
|
(40,620
|
) |
|
|
(42,452 |
) |
Accounts Payable
|
|
|
47,035 |
|
|
|
(46,758 |
) |
Accrued Taxes, Net
|
|
|
(5,865
|
) |
|
|
46,587 |
|
Other Current Assets
|
|
|
(9,620
|
) |
|
|
162 |
|
Other Current Liabilities
|
|
|
(9,760
|
) |
|
|
4,253 |
|
Net
Cash Flows from Operating Activities
|
|
|
289,944 |
|
|
|
279,029 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(276,911
|
) |
|
|
(565,832 |
) |
Proceeds
from Sales of Assets
|
|
|
5,889 |
|
|
|
5,594 |
|
Other
|
|
|
(505
|
) |
|
|
(24 |
) |
Net
Cash Flows Used for Investing Activities
|
|
|
(271,527
|
) |
|
|
(560,262 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
164,474 |
|
|
|
461,324 |
|
Change
in Short-term Debt, Net – Nonaffiliated
|
|
|
(701
|
) |
|
|
(1,203 |
) |
Change
in Advances from Affiliates, Net
|
|
|
72,285 |
|
|
|
(164,698 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(257,463
|
) |
|
|
(8,927 |
) |
Retirement
of Cumulative Preferred Stock
|
|
|
- |
|
|
|
(2 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(3,214
|
) |
|
|
(3,521 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(366
|
) |
|
|
(366 |
) |
Other
|
|
|
10,000 |
|
|
|
- |
|
Net
Cash Flows from (Used for) Financing Activities
|
|
|
(14,985
|
) |
|
|
282,607 |
|
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
3,432 |
|
|
|
1,374 |
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
6,666 |
|
|
|
1,625 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
10,098 |
|
|
$ |
2,999 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
72,685 |
|
|
$ |
51,991 |
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
32,569 |
|
|
|
(9,193 |
) |
Noncash
Acquisitions Under Capital Leases
|
|
|
1,673 |
|
|
|
1,036 |
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
27,610 |
|
|
|
65,936 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to OPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to
OPCo.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
Results of
Operations
Second Quarter of 2008
Compared to Second Quarter of 2007
Reconciliation
of Second Quarter of 2007 to Second Quarter of 2008
Net
Income
(in
millions)
Second
Quarter of 2007
|
|
|
|
|
$ |
6 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
8 |
|
|
|
|
|
Transmission
Revenues
|
|
|
3 |
|
|
|
|
|
Other
|
|
|
1 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(6
|
) |
|
|
|
|
Deferral
of Ice Storm Costs
|
|
|
(8
|
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(2
|
) |
|
|
|
|
Other
Income
|
|
|
3 |
|
|
|
|
|
Interest
Expense
|
|
|
(2
|
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(15
|
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
Second
Quarter of 2008
|
|
|
|
|
|
$ |
4 |
|
Net
Income decreased $2 million to $4 million in 2008. The key drivers of
the decrease were a $15 million increase in Operating Expenses and Other offset
by a $12 million increase in Gross Margin and a $1 million decrease in Income
Tax Expense.
The major
components of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions allowances
and purchased power were as follows:
·
|
Retail
and Off-system Sales Margins increased $8 million primarily due
to:
|
|
·
|
A
$7 million increase in retail sales margins mainly due to base rate
adjustments and a slight increase in KWH sales.
|
|
·
|
A
$1 million net increase in off-system margins retained primarily due to
higher physical sales margins, partially offset by lower trading
margins.
|
·
|
Transmission
Revenues increased $3 million primarily due to higher rates within
SPP.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $6 million primarily due
to:
|
|
·
|
A
$7 million increase due to a credit in 2007 to adjust the expenses of the
January 2007 ice storm.
|
|
·
|
A
$4 million increase in transmission expense primarily due to an increase
in transmission services from other utilities.
|
|
·
|
A
$3 million increase in administrative and general expenses, primarily
associated with maintenance, outside services and employee-related
expenses.
|
|
·
|
A
$2 million increase in expense for the June 2008
storms.
|
|
·
|
A
$2 million increase due to amortization of the deferred ice storm
costs.
|
|
These
increases were partially offset by:
|
|
·
|
A
$10 million decrease primarily to true-up actual December ice storm costs
to the 2007 estimated accrual and is offset in the Deferral
below. See “Deferral of Ice Storm Costs”
below.
|
·
|
Deferral
of Ice Storm Costs increased $8 million due to 2008 costs and true-up
entries as discussed above. See “Oklahoma 2007 Ice Storms”
section of Note 3.
|
·
|
Depreciation
and Amortization expenses increased $2 million primarily due to a $3
million increase in the amortization of the Lawton Settlement regulatory
asset offset by a $1 million decrease in depreciation primarily resulting
from lower rates.
|
·
|
Other
Income increased $3 million primarily due to an increase in carrying
charges related to the new peaking units and to deferred ice storms
costs. See “Oklahoma 2007 Ice Storms” section of Note
3.
|
·
|
Interest
Expense increased $2 million primarily due to a $4 million increase in
interest expense from long-term borrowings offset by a $1 million decrease
in interest expense from short-term
borrowings.
|
Six Months Ended June 30,
2008 Compared to Six Months Ended June 30, 2007
Reconciliation
of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Net
Income (Loss)
(in
millions)
Six
Months Ended June 30, 2007
|
|
|
|
|
$ |
(14 |
) |
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
22 |
|
|
|
|
|
Transmission
Revenues
|
|
|
4 |
|
|
|
|
|
Other
|
|
|
11 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
37 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(13
|
) |
|
|
|
|
Deferral
of Ice Storm Costs
|
|
|
72 |
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(5
|
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1
|
) |
|
|
|
|
Other
Income
|
|
|
6 |
|
|
|
|
|
Interest
Expense
|
|
|
(5
|
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
54 |
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(35
|
) |
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2008
|
|
|
|
|
|
$ |
42 |
|
Net
Income (Loss) increased $56 million to $42 million in 2008. The key
drivers of the increase were a $54 million decrease in Operating Expenses and
Other and a $37 million increase in Gross Margin offset by a $35 million
increase in Income Tax Expense.
The major
components of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
and Off-system Sales Margins increased $22 million primarily due to an
increase in retail sales margins resulting from base rate adjustments and
a slight increase in KWH sales.
|
·
|
Transmission
Revenues increased $4 million primarily due to higher rates within
SPP.
|
·
|
Other
revenues increased $11 million primarily due to a $10 million increase
related to the recognition of the sale of SO2
allowances. See “Oklahoma 2007 Ice Storms” section of Note
3.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $13 million primarily due
to:
|
|
·
|
A
$10 million increase in production expenses primarily due to a write-off
of pre-construction costs related to the canceled Red Rock Generating
Facility. See “Red Rock Generating Facility” section of Note
3.
|
|
·
|
A
$9 million increase due to amortization of the deferred 2007 ice storm
costs.
|
|
·
|
An
$8 million increase in transmission expense primarily due to an increase
in transmission services from other utilities.
|
|
·
|
A
$4 million increase in administrative and general expenses, primarily
associated with maintenance, outside services and employee-related
expenses.
|
|
·
|
A
$2 million increase in expense for the June 2008
storms.
|
|
·
|
A
$1 million increase in distribution maintenance expense due to increased
vegetation management activities.
|
|
These
increases were partially offset by:
|
|
·
|
A
$14 million decrease for the costs of the January 2007 ice
storm.
|
|
·
|
A
$10 million decrease primarily to true-up actual December ice storm costs
to the 2007 estimated accrual.
|
·
|
Deferral
of Ice Storm Costs in 2008 of $72 million results from an OCC order
approving recovery of ice storm costs related to ice storms in January and
December 2007. See “Oklahoma 2007 Ice Storms” section of Note
3.
|
·
|
Depreciation
and Amortization expenses increased $5 million primarily due to a $7
million increase related to the amortization of the Lawton Settlement
regulatory asset offset by a $2 million decrease in depreciation primarily
resulting from lower rates.
|
·
|
Other
Income increased $6 million primarily due to a $3 million increase in
carrying charges related to the new peaking units and to deferred ice
storms costs (see “Oklahoma 2007 Ice Storms” section of Note 3) and a $1
million increase in the equity component of AFUDC.
|
·
|
Interest
Expense increased $5 million primarily due to an $8 million increase in
interest expense from long-term borrowings offset by a $2 million decrease
in interest expense from short-term borrowings.
|
·
|
Income
Tax Expense increased $35 million primarily due to an increase in pretax
book income.
|
Financial
Condition
Credit
Ratings
The
rating agencies currently have PSO on stable outlook. In the first
quarter of 2008, Fitch downgraded PSO from A- to BBB+ for senior unsecured
debt. Current credit ratings are as follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
Baa1
|
|
BBB
|
|
BBB+
|
If PSO
receives an upgrade from any of the rating agencies listed above, its borrowing
costs could decrease. If PSO receives a downgrade from any
of the rating agencies listed above, its borrowing costs could increase and
access to borrowed funds could be negatively affected.
Cash
Flow
Cash
flows for the six months ended June 30, 2008 and 2007 were as
follows:
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$ |
1,370 |
|
|
$ |
1,651 |
|
Cash
Flows from (Used for):
|
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
(6,309
|
) |
|
|
(30,543
|
) |
Investing
Activities
|
|
|
(99,942
|
) |
|
|
(161,760
|
) |
Financing
Activities
|
|
|
106,405 |
|
|
|
191,560 |
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
154 |
|
|
|
(743
|
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,524 |
|
|
$ |
908 |
|
Operating
Activities
Net Cash
Flows Used for Operating Activities were $6 million in 2008. PSO
produced Net Income of $42 million during the period and had noncash expense
items of $71 million for Deferred Income Taxes and $51 million for Depreciation
and Amortization. PSO established a $72 million regulatory asset for
an OCC order approving recovery of ice storm costs related to storms in January
and December 2007. The other changes in assets and liabilities
represent items that had a current period cash flow impact, such as changes in
working capital, as well as items that represent future rights or obligations to
receive or pay cash, such as regulatory assets and liabilities. The
activity in working capital primarily relates to Fuel Over/Under-Recovery, Net
which had a $74 million outflow as a result of rapidly increasing cost of
natural gas which fuels the majority of PSO’s generators.
Net Cash
Flows Used for Operating Activities were $31 million in 2007. PSO
incurred a Net Loss of $14 million during the period and had a noncash expense
item of $46 million for Depreciation and Amortization. The $26
million outflow from Other Noncurrent Assets was primarily related to the
establishment of a $35 million regulatory asset for the payment of the Lawton
Settlement. The other changes in assets and liabilities represent
items that had a prior period cash flow impact, such as changes in working
capital, as well as items that represent future rights or obligations to receive
or pay cash, such as regulatory assets and liabilities. The activity
in working capital relates to a number of items. The $14 million
outflow from Fuel Over/Under-Recovery, Net was the result
of increasing costs of natural gas which fuels the majority of PSO’s
generators. The $22 million outflow from Other Current Liabilities
was primarily due to $18 million fewer outstanding checks at June 30, 2007 when
compared to December 31, 2006.
Investing
Activities
Net Cash
Flows Used for Investing Activities during 2008 and 2007 were $100 million and
$162 million, respectively. Construction Expenditures of $152 million
in 2008 and 2007 were primarily related to projects for improved generation,
transmission and distribution service reliability. In addition,
during 2008, PSO had a net decrease of $51 million in loans to the Utility Money
Pool. For the remainder of 2008, PSO expects construction
expenditures to be approximately $130 million.
Financing
Activities
Net Cash
Flows from Financing Activities were $106 million during 2008. PSO
had a net increase of $111 million in borrowings from the Utility Money
Pool. PSO repurchased $34 million in Pollution Control Bonds in May
2008. PSO received a capital contribution from Parent of $30
million.
Net Cash
Flows from Financing Activities were $192 million during 2007. PSO
had a net increase of $140 million in borrowings from the Utility Money
Pool. PSO received a capital contribution from Parent of $40
million.
Financing
Activity
Long-term
debt issuances, retirements and principal payments made during the first six
months of 2008 were:
Issuances
None
Retirements and Principal
Payments
Type
of Debt
|
|
Principal
Amount
Paid
|
|
Interest
Rate
|
|
Due
Date
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$ |
33,700 |
|
Variable
|
|
2014
|
Liquidity
PSO has
solid investment grade ratings, which provide ready access to capital markets in
order to issue new debt or refinance long-term debt maturities. In
addition, PSO participates in the Utility Money Pool, which provides access to
AEP’s liquidity.
Summary Obligation
Information
PSO’s
contractual obligations include amounts reported on PSO’s Balance Sheets and
other obligations disclosed in the footnotes. The following table
summarizes PSO’s contractual cash obligations at December 31, 2007:
Payments
Due by Period
(in
millions)
Contractual
Cash Obligations
|
|
Less
Than
1
year
|
|
|
2-3
years
|
|
|
4-5
years
|
|
|
After
5
years
|
|
|
Total
|
|
Interest
on Fixed Rate Portion of Long-term
Debt
(a)
|
|
$ |
51.7 |
|
|
$ |
99.5 |
|
|
$ |
78.5 |
|
|
$ |
695.2 |
|
|
$ |
924.9 |
|
Fixed
Rate Portion of Long-term Debt (b)
|
|
|
- |
|
|
|
200.0 |
|
|
|
75.0 |
|
|
|
612.7 |
|
|
|
887.7 |
|
Variable
Rate Portion of Long-term Debt (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
33.7 |
|
|
|
33.7 |
|
Capital
Lease Obligations (d)
|
|
|
1.7 |
|
|
|
2.2 |
|
|
|
0.5 |
|
|
|
- |
|
|
|
4.4 |
|
Noncancelable
Operating Leases (d)
|
|
|
6.7 |
|
|
|
10.7 |
|
|
|
5.7 |
|
|
|
5.6 |
|
|
|
28.7 |
|
Fuel
Purchase Contracts (e)
|
|
|
295.6 |
|
|
|
130.1 |
|
|
|
85.3 |
|
|
|
- |
|
|
|
511.0 |
|
Energy
and Capacity Purchase Contracts (f)
|
|
|
6.9 |
|
|
|
6.4 |
|
|
|
- |
|
|
|
- |
|
|
|
13.3 |
|
Construction
Contracts for Capital Assets (g)
|
|
|
55.2 |
|
|
|
128.4 |
|
|
|
143.5 |
|
|
|
10.0 |
|
|
|
337.1 |
|
Total
|
|
$ |
417.8 |
|
|
$ |
577.3 |
|
|
$ |
388.5 |
|
|
$ |
1,357.2 |
|
|
$ |
2,740.8 |
|
(a)
|
Interest
payments are estimated based on final maturity dates of debt securities
outstanding at December 31, 2007 and do not reflect anticipated future
refinancing, early redemptions or debt issuances.
|
(b)
|
See
Note 15 of the 2007 Annual Report. Represents principal only
excluding interest.
|
(c)
|
See
Note 15 of the 2007 Annual Report. Represents principal only
excluding interest. Variable rate debt had a 3.75% interest
rate at December 31, 2007.
|
(d)
|
See
Note 14 of the 2007 Annual Report.
|
(e)
|
Represents
contractual obligations to purchase coal, natural gas and other consumable
as fuel for electric generation along with related transportation of the
fuel.
|
(f)
|
Represents
contractual cash flows of energy and capacity purchase
contracts.
|
(g)
|
Represents
only capital assets that are contractual
obligations.
|
PSO’s FIN
48 liabilities of $5 million are not included above because PSO cannot
reasonably estimate the cash flows by period.
As
discussed in Note 9 of the 2007 Annual Report, PSO’s minimum pension funding
requirements are not included above as such amounts are discretionary based upon
the status of the trusts.
As of
December 31, 2007, PSO had no outstanding standby letters of credit or
guarantees of performance.
The
summary of contractual obligations has not changed significantly from year-end
other than the debt retirement discussed in “Cash Flow” and “Financing Activity”
above.
Significant
Factors
Litigation
and Regulatory Activity
In the
ordinary course of business, PSO is involved in employment, commercial,
environmental and regulatory litigation. Since it is difficult to
predict the outcome of these proceedings, management cannot state what the
eventual outcome of these proceedings will be, or what the timing of the amount
of any loss, fine or penalty may be. Management does, however, assess
the probability of loss for such contingencies and accrues a liability for cases
which have a probable likelihood of loss and the loss amount can be
estimated. For details on regulatory proceedings and pending
litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 2007 Annual Report. Also, see Note 3 – Rate
Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed
Notes to Condensed Financial Statements of Registrant Subsidiaries”
section. Adverse results in these proceedings have the potential to
materially affect results of operations, financial condition and cash
flows.
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of relevant factors.
Critical Accounting
Estimates
See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption of New Accounting
Pronouncements
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market
Risks
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion within AEP’s “Quantitative and
Qualitative Disclosures About Risk Management Activities”
section. The following tables provide information about AEP’s risk
management activities’ effect on PSO.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in PSO’s Condensed Consolidated Balance Sheet as of June 30, 2008 and
the reasons for changes in total MTM value as compared to December 31,
2007.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of June 30, 2008
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MTM
Risk
|
|
|
DETM
|
|
|
|
|
|
|
|
|
|
Management
|
|
|
Assignment
|
|
|
Collateral
|
|
|
|
|
|
|
Contracts
|
|
|
(a)
|
|
|
Deposits
|
|
|
Total
|
|
Current
Assets
|
|
$ |
88,788 |
|
|
$ |
- |
|
|
$ |
(1,705 |
) |
|
$ |
87,083 |
|
Noncurrent
Assets
|
|
|
12,321 |
|
|
|
- |
|
|
|
(39
|
) |
|
|
12,282 |
|
Total
MTM Derivative Contract Assets
|
|
|
101,109 |
|
|
|
- |
|
|
|
(1,744
|
) |
|
|
99,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(86,621
|
) |
|
|
(93
|
) |
|
|
2,249 |
|
|
|
(84,465
|
) |
Noncurrent
Liabilities
|
|
|
(11,098
|
) |
|
|
(102
|
) |
|
|
852 |
|
|
|
(10,348
|
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(97,719
|
) |
|
|
(195
|
) |
|
|
3,101 |
|
|
|
(94,813
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$ |
3,390 |
|
|
$ |
(195 |
) |
|
$ |
1,357 |
|
|
$ |
4,552 |
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Six
Months Ended June 30, 2008
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2007
|
|
$
|
6,981
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered in a
Prior Period
|
|
|
(4,066
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
-
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
-
|
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward Contracts
(b)
|
|
|
32
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(c)
|
|
|
(146
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
589
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
3,390
|
|
DETM
Assignment (e)
|
|
|
(195
|
)
|
Collateral
Deposits
|
|
|
1,357
|
|
Ending
Net Risk Management Assets at June 30, 2008
|
|
$
|
4,552
|
|
(a)
|
Reflects
fair value on long-term contracts which are typically with customers that
seek fixed pricing to limit their risk against fluctuating energy
prices. The contract prices are valued against market curves
associated with the delivery location and delivery
term.
|
(b)
|
Represents
the impact of applying AEP’s credit risk when measuring the fair value of
derivative liabilities according to SFAS 157.
|
(c)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(d)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected in the Condensed
Consolidated Statements of Income. These net gains (losses) are
recorded as regulatory assets/liabilities for those subsidiaries that
operate in regulated jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
The
following table presents the maturity, by year, of net assets/liabilities to
give an indication of when these MTM amounts will settle and generate
cash:
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets
Fair
Value of Contracts as of June 30, 2008
(in
thousands)
|
|
Remainder
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
After
2012
|
|
|
Total
|
|
Level
1 (a)
|
|
$ |
1,167 |
|
|
$ |
(235 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
932 |
|
Level
2 (b)
|
|
|
434 |
|
|
|
2,189 |
|
|
|
(128
|
) |
|
|
(14
|
) |
|
|
- |
|
|
|
- |
|
|
|
2,481 |
|
Level
3 (c)
|
|
|
(24
|
) |
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(23
|
) |
Total
|
|
$ |
1,577 |
|
|
$ |
1,954 |
|
|
$ |
(127 |
) |
|
$ |
(14 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
3,390 |
|
(a)
|
Level
1 inputs are quoted prices (unadjusted) in active markets for identical
assets or liabilities that the reporting entity has the ability to access
at the measurement date. Level 1 inputs primarily consist of
exchange traded contracts that exhibit sufficient frequency and volume to
provide pricing information on an ongoing basis.
|
(b)
|
Level
2 inputs are inputs other than quoted prices included within Level 1 that
are observable for the asset or liability, either directly or
indirectly. If the asset or liability has a specified
(contractual) term, a Level 2 input must be observable for substantially
the full term of the asset or liability. Level 2 inputs
primarily consist of OTC broker quotes in moderately active or less active
markets, exchange traded contracts where there was not sufficient market
activity to warrant inclusion in Level 1, and OTC broker quotes that are
corroborated by the same or similar transactions that have occurred in the
market.
|
(c)
|
Level
3 inputs are unobservable inputs for the asset or
liability. Unobservable inputs shall be used to measure fair
value to the extent that the observable inputs are not available, thereby
allowing for situations in which there is little, if any, market activity
for the asset or liability at the measurement date. Level 3
inputs primarily consist of unobservable market data or are valued based
on models and/or assumptions.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on
the Condensed Consolidated Balance Sheet
Management
uses interest rate derivative transactions to manage interest rate risk related
to anticipated borrowings of fixed-rate debt. Management does not
hedge all interest rate risk.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on PSO’s Condensed Consolidated Balance Sheets and the reasons
for the changes from December 31, 2007 to June 30, 2008. Only
contracts designated as cash flow hedges are recorded in
AOCI. Therefore, economic hedge contracts that are not designated as
effective cash flow hedges are marked-to-market and included in the previous
risk management tables. All amounts are presented net of related
income taxes.
Total
Accumulated Other Comprehensive Income (Loss) Activity
Six
Months Ended June 30, 2008
(in
thousands)
|
|
Interest
Rate
|
|
Beginning
Balance in AOCI December 31, 2007
|
|
$
|
(887
|
)
|
Changes
in Fair Value
|
|
|
-
|
|
Reclassifications
from AOCI for Cash Flow Hedges
Settled
|
|
|
91
|
|
Ending
Balance in AOCI June 30, 2008
|
|
$
|
(796
|
)
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is an $183 thousand loss.
Credit
Risk
Counterparty
credit quality and exposure is generally consistent with that of
AEP.
VaR
Associated with Risk Management Contracts
Management
uses a risk measurement model, which calculates Value at Risk (VaR) to measure
commodity price risk in the risk management portfolio. The VaR is based on the
variance-covariance method using historical prices to estimate volatilities and
correlations and assumes a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at June 30, 2008, a near term
typical change in commodity prices is not expected to have a material effect on
PSO’s results of operations, cash flows or financial condition.
The
following table shows the end, high, average and low market risk as measured by
VaR for the periods indicated:
Six
Months Ended June 30, 2008
|
|
|
Twelve
Months Ended December 31, 2007
|
(in
thousands)
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$39
|
|
$109
|
|
$37
|
|
$8
|
|
|
$13
|
|
$189
|
|
$53
|
|
$5
|
Management
back-tests its VaR results against performance due to actual price
moves. Based on the assumed 95% confidence interval, the performance
due to actual price moves would be expected to exceed the VaR at least once
every 20 trading days. Management’s backtesting results show that its
actual performance exceeded VaR far fewer than once every 20 trading
days. As a result, management believes PSO’s VaR calculation is
conservative.
As PSO’s
VaR calculation captures recent price moves, management also performs regular
stress testing of the portfolio to understand PSO’s exposure to extreme price
moves. Management employs a historically-based method whereby the
current portfolio is subjected to actual, observed price moves from the last
three years in order to ascertain which historical price moves translate into
the largest potential mark-to-market loss. Management then researches
the underlying positions, price moves and market events that created the most
significant exposure.
Interest
Rate Risk
Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure. EaR statistically quantifies the extent to which PSO’s interest
expense could vary over the next twelve months and gives a probabilistic
estimate of different levels of interest expense. The resulting EaR
is interpreted as the dollar amount by which actual interest expense for the
next twelve months could exceed expected interest expense with a one-in-twenty
chance of occurrence. The primary drivers of EaR are from the
existing floating rate debt (including short-term debt) as well as long-term
debt issuances in the next twelve months. The estimated EaR on PSO’s
debt portfolio was $800 thousand.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
STATEMENTS OF OPERATIONS
For
the Three and Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
357,675 |
|
|
$ |
304,820 |
|
|
$ |
676,555 |
|
|
$ |
594,900 |
|
Sales
to AEP Affiliates
|
|
|
41,767 |
|
|
|
16,275 |
|
|
|
57,702 |
|
|
|
40,868 |
|
Other
|
|
|
892 |
|
|
|
544 |
|
|
|
2,077 |
|
|
|
1,184 |
|
TOTAL
|
|
|
400,334 |
|
|
|
321,639 |
|
|
|
736,334 |
|
|
|
636,952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
143,537 |
|
|
|
113,633 |
|
|
|
296,742 |
|
|
|
256,148 |
|
Purchased
Electricity for Resale
|
|
|
104,016 |
|
|
|
70,145 |
|
|
|
152,598 |
|
|
|
137,554 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
21,506 |
|
|
|
18,979 |
|
|
|
38,775 |
|
|
|
32,463 |
|
Other
Operation
|
|
|
45,186 |
|
|
|
42,345 |
|
|
|
101,185 |
|
|
|
83,352 |
|
Maintenance
|
|
|
25,655 |
|
|
|
22,177 |
|
|
|
60,242 |
|
|
|
65,262 |
|
Deferral
of Ice Storm Costs
|
|
|
8,223 |
|
|
|
- |
|
|
|
(71,679
|
) |
|
|
- |
|
Depreciation
and Amortization
|
|
|
24,720 |
|
|
|
22,992 |
|
|
|
50,887 |
|
|
|
45,698 |
|
Taxes
Other Than Income Taxes
|
|
|
10,474 |
|
|
|
9,890 |
|
|
|
21,426 |
|
|
|
20,184 |
|
TOTAL
|
|
|
383,317 |
|
|
|
300,161 |
|
|
|
650,176 |
|
|
|
640,661 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME (LOSS)
|
|
|
17,017 |
|
|
|
21,478 |
|
|
|
86,158 |
|
|
|
(3,709
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
967 |
|
|
|
518 |
|
|
|
2,095 |
|
|
|
518 |
|
Carrying
Costs Income
|
|
|
2,128 |
|
|
|
- |
|
|
|
3,762 |
|
|
|
- |
|
Allowance
for Equity Funds Used During Construction
|
|
|
516 |
|
|
|
44 |
|
|
|
1,875 |
|
|
|
690 |
|
Interest
Expense
|
|
|
(14,525
|
) |
|
|
(12,785
|
) |
|
|
(29,466
|
) |
|
|
(24,168
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
(LOSS) BEFORE INCOME TAX EXPENSE
(CREDIT)
|
|
|
6,103 |
|
|
|
9,255 |
|
|
|
64,424 |
|
|
|
(26,669
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense (Credit)
|
|
|
1,976 |
|
|
|
2,960 |
|
|
|
22,898 |
|
|
|
(12,538
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
|
4,127 |
|
|
|
6,295 |
|
|
|
41,526 |
|
|
|
(14,131
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
53 |
|
|
|
53 |
|
|
|
106 |
|
|
|
106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
(LOSS) APPLICABLE TO COMMON STOCK
|
|
$ |
4,074 |
|
|
$ |
6,242 |
|
|
$ |
41,420 |
|
|
$ |
(14,237 |
) |
The
common stock of PSO is wholly-owned by AEP.
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
|
Paid-in
Capital
|
|
|
Retained
Earnings
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
Total
|
|
DECEMBER
31, 2006
|
|
$ |
157,230 |
|
|
$ |
230,016 |
|
|
$ |
199,262 |
|
|
$ |
(1,070 |
) |
|
$ |
585,438 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(386
|
) |
|
|
|
|
|
|
(386
|
) |
Capital
Contribution from Parent
|
|
|
|
|
|
|
40,000 |
|
|
|
|
|
|
|
|
|
|
|
40,000 |
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(106
|
) |
|
|
|
|
|
|
(106
|
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
624,946 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91 |
|
|
|
91 |
|
NET
LOSS
|
|
|
|
|
|
|
|
|
|
|
(14,131
|
) |
|
|
|
|
|
|
(14,131
|
) |
TOTAL
COMPREHENSIVE LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,040
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
157,230 |
|
|
$ |
270,016 |
|
|
$ |
184,639 |
|
|
$ |
(979 |
) |
|
$ |
610,906 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2007
|
|
$ |
157,230 |
|
|
$ |
310,016 |
|
|
$ |
174,539 |
|
|
$ |
(887 |
) |
|
$ |
640,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EITF
06-10 Adoption, Net of Tax of $596
|
|
|
|
|
|
|
|
|
|
|
(1,107
|
) |
|
|
|
|
|
|
(1,107
|
) |
Capital
Contribution from Parent
|
|
|
|
|
|
|
30,000 |
|
|
|
|
|
|
|
|
|
|
|
30,000 |
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(106
|
) |
|
|
|
|
|
|
(106
|
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
669,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive
Income, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91 |
|
|
|
91 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
41,526 |
|
|
|
|
|
|
|
41,526 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2008
|
|
$ |
157,230 |
|
|
$ |
340,016 |
|
|
$ |
214,852 |
|
|
$ |
(796 |
) |
|
$ |
711,302 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
BALANCE SHEETS
ASSETS
June
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,524 |
|
|
$ |
1,370 |
|
Advances
to Affiliates
|
|
|
- |
|
|
|
51,202 |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
54,815 |
|
|
|
74,330 |
|
Affiliated Companies
|
|
|
79,370 |
|
|
|
59,835 |
|
Miscellaneous
|
|
|
10,748 |
|
|
|
10,315 |
|
Allowance for Uncollectible Accounts
|
|
|
(18
|
) |
|
|
- |
|
Total
Accounts Receivable
|
|
|
144,915 |
|
|
|
144,480 |
|
Fuel
|
|
|
27,124 |
|
|
|
19,394 |
|
Materials
and Supplies
|
|
|
47,925 |
|
|
|
47,691 |
|
Risk
Management Assets
|
|
|
87,083 |
|
|
|
33,308 |
|
Accrued
Tax Benefits
|
|
|
52,082 |
|
|
|
31,756 |
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
61,876 |
|
|
|
- |
|
Margin
Deposits
|
|
|
992 |
|
|
|
8,980 |
|
Prepayments
and Other
|
|
|
14,559 |
|
|
|
18,137 |
|
TOTAL
|
|
|
438,080 |
|
|
|
356,318 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
1,234,217 |
|
|
|
1,110,657 |
|
Transmission
|
|
|
598,361 |
|
|
|
569,746 |
|
Distribution
|
|
|
1,402,521 |
|
|
|
1,337,038 |
|
Other
|
|
|
249,073 |
|
|
|
241,722 |
|
Construction
Work in Progress
|
|
|
94,615 |
|
|
|
200,018 |
|
Total
|
|
|
3,578,787 |
|
|
|
3,459,181 |
|
Accumulated
Depreciation and Amortization
|
|
|
1,191,109 |
|
|
|
1,182,171 |
|
TOTAL
- NET
|
|
|
2,387,678 |
|
|
|
2,277,010 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
186,807 |
|
|
|
158,731 |
|
Long-term
Risk Management Assets
|
|
|
12,282 |
|
|
|
3,358 |
|
Deferred
Charges and Other
|
|
|
67,944 |
|
|
|
48,454 |
|
TOTAL
|
|
|
267,033 |
|
|
|
210,543 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
3,092,791 |
|
|
$ |
2,843,871 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED
BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
June
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
110,981 |
|
|
$ |
- |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
164,652 |
|
|
|
189,032 |
|
Affiliated
Companies
|
|
|
107,254 |
|
|
|
80,316 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
50,000 |
|
|
|
- |
|
Risk
Management Liabilities
|
|
|
84,465 |
|
|
|
27,118 |
|
Customer
Deposits
|
|
|
40,409 |
|
|
|
41,477 |
|
Accrued
Taxes
|
|
|
36,383 |
|
|
|
18,374 |
|
Regulatory
Liability for Over-Recovered Fuel Costs
|
|
|
- |
|
|
|
11,697 |
|
Other
|
|
|
42,588 |
|
|
|
57,708 |
|
TOTAL
|
|
|
636,732 |
|
|
|
425,722 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
834,737 |
|
|
|
918,316 |
|
Long-term
Risk Management Liabilities
|
|
|
10,348 |
|
|
|
2,808 |
|
Deferred
Income Taxes
|
|
|
526,319 |
|
|
|
456,497 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
316,575 |
|
|
|
338,788 |
|
Deferred
Credits and Other
|
|
|
51,516 |
|
|
|
55,580 |
|
TOTAL
|
|
|
1,739,495 |
|
|
|
1,771,989 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,376,227 |
|
|
|
2,197,711 |
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
5,262 |
|
|
|
5,262 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
|
Common
Stock – $15 Par Value Per Share:
|
|
|
|
|
|
|
|
|
Authorized – 11,000,000 Shares
|
|
|
|
|
|
|
|
|
Issued – 10,482,000 Shares
|
|
|
|
|
|
|
|
|
Outstanding – 9,013,000 Shares
|
|
|
157,230 |
|
|
|
157,230 |
|
Paid-in
Capital
|
|
|
340,016 |
|
|
|
310,016 |
|
Retained
Earnings
|
|
|
214,852 |
|
|
|
174,539 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(796
|
) |
|
|
(887 |
) |
TOTAL
|
|
|
711,302 |
|
|
|
640,898 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
3,092,791 |
|
|
$ |
2,843,871 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
STATEMENTS OF CASH FLOWS
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$ |
41,526 |
|
|
$ |
(14,131 |
) |
Adjustments
to Reconcile Net Income (Loss) to Net Cash Flows Used for
Operating Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
50,887 |
|
|
|
45,698 |
|
Deferred
Income Taxes
|
|
|
70,618 |
|
|
|
11,059 |
|
Deferral
of Ice Storm Costs
|
|
|
(71,679
|
) |
|
|
- |
|
Allowance
for Equity Funds Used During Construction
|
|
|
(1,875
|
) |
|
|
(690 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
2,216 |
|
|
|
4,832 |
|
Deferred
Property Taxes
|
|
|
(17,796
|
) |
|
|
(16,539 |
) |
Change
in Other Noncurrent Assets
|
|
|
25,981 |
|
|
|
(25,601 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
(33,384
|
) |
|
|
(22,811 |
) |
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts Receivable, Net
|
|
|
1,270 |
|
|
|
19,413 |
|
Fuel, Materials and Supplies
|
|
|
(7,964
|
) |
|
|
(8,414 |
) |
Margin Deposits
|
|
|
7,988 |
|
|
|
10,216 |
|
Accounts Payable
|
|
|
18,238 |
|
|
|
11,810 |
|
Customer Deposits
|
|
|
(1,068
|
) |
|
|
(3,354 |
) |
Accrued Taxes, Net
|
|
|
(2,317
|
) |
|
|
(6,888 |
) |
Fuel Over/Under-Recovery, Net
|
|
|
(73,573
|
) |
|
|
(13,512 |
) |
Other Current Assets
|
|
|
820 |
|
|
|
597 |
|
Other Current Liabilities
|
|
|
(16,197
|
) |
|
|
(22,228 |
) |
Net
Cash Flows Used for Operating Activities
|
|
|
(6,309
|
) |
|
|
(30,543 |
) |
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(151,711
|
) |
|
|
(151,973 |
) |
Change
in Other Cash Deposits, Net
|
|
|
- |
|
|
|
(12,896 |
) |
Change
in Advances to Affiliates, Net
|
|
|
51,202 |
|
|
|
- |
|
Proceeds
from Sales of Assets
|
|
|
567 |
|
|
|
3,109 |
|
Net
Cash Flows Used for Investing Activities
|
|
|
(99,942
|
) |
|
|
(161,760 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
30,000 |
|
|
|
40,000 |
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
- |
|
|
|
12,495 |
|
Change
in Advances from Affiliates, Net
|
|
|
110,981 |
|
|
|
139,916 |
|
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(33,700
|
) |
|
|
- |
|
Principal
Payments for Capital Lease Obligations
|
|
|
(770
|
) |
|
|
(745 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(106
|
) |
|
|
(106 |
) |
Net
Cash Flows from Financing Activities
|
|
|
106,405 |
|
|
|
191,560 |
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
154 |
|
|
|
(743 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,370 |
|
|
|
1,651 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,524 |
|
|
$ |
908 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
27,774 |
|
|
$ |
21,339 |
|
Net
Cash Received for Income Taxes
|
|
|
19,529 |
|
|
|
2,353 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
253 |
|
|
|
434 |
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
11,731 |
|
|
|
21,261 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to PSO’s condensed financial statements are combined with the
condensed notes to condensed financial statements for other registrant
subsidiaries. Listed below are the notes that apply to
PSO.
|
Footnote Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
Results of
Operations
Second Quarter of 2008
Compared to Second Quarter of 2007
Reconciliation
of Second Quarter of 2007 to Second Quarter of 2008
Net
Income
(in
millions)
Second
Quarter of 2007
|
|
|
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
23 |
|
|
|
|
|
Transmission
Revenues
|
|
|
2 |
|
|
|
|
|
Other
|
|
|
(2
|
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(7
|
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(2
|
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
2 |
|
|
|
|
|
Other
Income
|
|
|
1 |
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(6
|
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(5
|
) |
|
|
|
|
|
|
|
|
|
Second
Quarter of 2008
|
|
|
|
|
|
$ |
14 |
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income increased $12 million to $14 million in 2008. The key drivers
of the increase were a $23 million increase in Gross Margin partially offset by
a $6 million increase in Operating Expenses and Other and a $5 million increase
in Income Tax Expense.
The major
component of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions allowances
and purchased power were as follows:
·
|
Retail
and Off-system Sales Margins increased $23 million primarily due to a $25
million refund provision booked in 2007 pursuant to an unfavorable ALJ
ruling in the Texas Fuel Reconciliation proceeding.
|
·
|
Transmission
Revenues increased $2 million due to higher rates in the SPP
region.
|
·
|
Other
revenues decreased $2 million primarily due to a $6 million decrease in
gains on sales of emission allowances offset by a $4 million increase in
revenues from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills
Lignite Company, LLC, to Cleco Corporation, a nonaffiliated
entity. The increase in coal deliveries was the result of
planned and forced outages during 2007 at the Dolet Hills Generating
Station, which is jointly-owned by SWEPCo and Cleco
Corporation. The increased revenue from coal deliveries was
offset by a corresponding increase in Other Operation and Maintenance
expenses from mining operations as discussed
below.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $7 million primarily due to a
$5 million increase in expenses for coal deliveries from SWEPCo’s mining
subsidiary, Dolet Hills Lignite Company, LLC. The increased
expenses for coal deliveries were partially offset by a corresponding
increase in revenues from mining operations as discussed
above.
|
·
|
Depreciation
and Amortization increased $2 million primarily due to higher depreciable
asset balances.
|
·
|
Taxes
Other Than Income Taxes decreased $2 million primarily due to a decrease
in franchise taxes.
|
·
|
Income
Tax Expense increased $5 million primarily due to an increase in pretax
book income.
|
Six Months Ended June 30,
2008 Compared to Six Months Ended June 30, 2007
Reconciliation
of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Net
Income
(in
millions)
Six
Months Ended June 30, 2007
|
|
|
|
|
$ |
11 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
28 |
|
|
|
|
|
Transmission
Revenues
|
|
|
3 |
|
|
|
|
|
Other
|
|
|
(3
|
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
28 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(17
|
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(4
|
) |
|
|
|
|
Other
Income
|
|
|
3 |
|
|
|
|
|
Interest
Expense
|
|
|
(2
|
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(20
|
) |
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2008
|
|
|
|
|
|
$ |
19 |
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income increased $8 million to $19 million in 2008. The key drivers
of the increase were a $28 million increase in Gross Margin partially offset by
a $20 million increase in Operating Expenses and Other.
The major
components of the increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
and Off-system Sales Margins increased $28 million primarily due to a $25
million refund provision booked in 2007 pursuant to an unfavorable ALJ
ruling in the Texas Fuel Reconciliation proceeding.
|
·
|
Transmission
Revenues increased $3 million due to higher rates in the SPP
region.
|
·
|
Other
revenues decreased $3 million primarily due to a $12 million decrease in
gains on sales of emission allowances offset by a $9 million increase in
revenue from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills
Lignite Company, LLC, to Cleco Corporation, a nonaffiliated
entity. The increase in coal deliveries was the result of
planned and forced outages during 2007 at the Dolet Hills Generating
Station, which is jointly-owned by SWEPCo and Cleco
Corporation. The increased revenue from coal deliveries was
offset by a corresponding increase in Other Operation and Maintenance
expenses from mining operations as discussed
below.
|
Operating
Expenses and Other and Income Tax Expense changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $17 million primarily due to
the following:
|
|
·
|
An
$11 million increase in expenses for coal deliveries from SWEPCo’s mining
subsidiary, Dolet Hills Lignite Company, LLC. The increased
expenses for coal deliveries were partially offset by a corresponding
increase in revenues from mining operations as discussed
above.
|
|
·
|
A
$3 million increase in transmission expenses related to increased usage
and rates in the SPP region.
|
|
·
|
A
$3 million increase in administrative and general expenses, primarily
associated with outside services and employee-related
expenses.
|
·
|
Depreciation
and Amortization increased $4 million primarily due to higher depreciable
asset balances.
|
·
|
Other
Income increased $3 million primarily due to an increase in the equity
component of AFUDC as a result of new generation
projects.
|
·
|
Interest
Expense increased $2 million primarily due to higher interest of $8
million related to higher long-term debt partially offset by a $4 million
increase in the debt component of AFUDC due to new generation projects and
a $3 million decrease in other interest expense partially related to
decreased interest expense on fuel
recovery.
|
Financial
Condition
Credit
Ratings
S&P
and Fitch currently have SWEPCo on stable outlook, while Moody’s placed SWEPCo
on negative outlook in the first quarter of 2008. In addition, in the
first quarter of 2008, Fitch downgraded SWEPCo from A- to BBB+ for senior
unsecured debt. Current credit ratings are as follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
Baa1
|
|
BBB
|
|
BBB+
|
If SWEPCo
receives an upgrade from any of the rating agencies listed above, its borrowing
costs could decrease. If SWEPCo receives a downgrade from any of the
rating agencies listed above, it borrowing costs could increase and access to
borrowed funds could be negatively affected.
Cash
Flow
Cash
flows for the six months ended June 30, 2008 and 2007 were as
follows:
|
|
2008
|
|
|
2007
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$ |
1,742 |
|
|
$ |
2,618 |
|
Cash
Flows from (Used for):
|
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
74,622 |
|
|
|
120,597 |
|
Investing
Activities
|
|
|
(569,109
|
) |
|
|
(253,267
|
) |
Financing
Activities
|
|
|
494,987 |
|
|
|
131,610 |
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
500 |
|
|
|
(1,060
|
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
2,242 |
|
|
$ |
1,558 |
|
Operating
Activities
Net Cash
Flows from Operating Activities were $75 million in 2008. SWEPCo
produced Net Income of $19 million during the period and had a noncash expense
item of $73 million for Depreciation and Amortization. The other
changes in assets and liabilities represent items that had a current period cash
flow impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The activity in working capital relates to a number
of items. The $84 million outflow from Fuel Over/Under-Recovery, Net
was the result of higher fuel costs. The $61 million inflow from
Accounts Payable was primarily due to higher fuel related costs. The
$32 million inflow from Accounts Receivable, Net was primarily due to the
assignment of certain ERCOT contracts to an affiliate company. The
$13 million outflow from Accrued Taxes, Net was the result of increased payments
related to property and income taxes.
Net Cash
Flows from Operating Activities were $121 million in 2007. SWEPCo
produced Net Income of $11 million during the period and had noncash expense
items of $69 million for Depreciation and Amortization and $25 million related
to the Provision for Fuel Disallowance recorded as the result of an ALJ ruling
in SWEPCo’s Texas fuel reconciliation proceeding. The other changes
in assets and liabilities represent items that had a prior period cash flow
impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The activity in working capital relates to a number
of items. The $36 million inflow from Accrued Taxes, Net was the
result of increased accruals related to property and income
taxes. The $27 million inflow from Accounts Receivable, Net was
primarily due to the assignment of certain ERCOT contracts to an affiliate
company.
Investing
Activities
Cash
Flows Used for Investing Activities during 2008 and 2007 were $569 million and
$253 million, respectively. Construction Expenditures of $266 million
and $250 million in 2008 and 2007, respectively, were primarily related to new
generation projects at the Turk Plant, Mattison Plant and Stall
Unit. In addition, during 2008, SWEPCo had a net increase of $301
million in loans to the Utility Money Pool. For the remainder of
2008, SWEPCo expects construction expenditures to be approximately $350
million.
Financing
Activities
Cash
Flows from Financing Activities were $495 million during 2008. SWEPCo
issued $400 million of Senior Unsecured Notes. SWEPCo received a
capital contribution from Parent of $100 million.
Cash
Flows from Financing Activities were $132 million during 2007. SWEPCo
issued $250 million of Senior Unsecured Notes and had a net decrease of $135
million in borrowings from the Utility Money Pool. SWEPCo received a
capital contribution from Parent of $25 million.
Financing
Activity
Long-term
debt issuances, retirements and principal payments made during the first six
months of 2008 were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Senior
Unsecured Notes
|
|
$
|
400,000
|
|
6.45
|
|
2019
|
Retirements and Principal
Payments
|
|
Principal
Amount
Paid
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Notes
Payable – Nonaffiliated
|
|
$
|
2,203
|
|
4.47
|
|
2011
|
Notes
Payable – Nonaffiliated
|
|
|
1,500
|
|
Variable
|
|
2008
|
Liquidity
SWEPCo
has solid investment grade ratings, which provide ready access to capital
markets in order to issue new debt or refinance long-term debt
maturities. In addition, SWEPCo participates in the Utility Money
Pool, which provides access to AEP’s liquidity.
Summary Obligation
Information
A summary
of contractual obligations is included in the 2007 Annual Report and has not
changed significantly from year-end other than the debt issuance discussed in
“Cash Flow” and “Financing Activity” above.
Significant
Factors
Litigation
and Regulatory Activity
In the
ordinary course of business, SWEPCo is involved in employment, commercial,
environmental and regulatory litigation. Since it is difficult to
predict the outcome of these proceedings, management cannot state what the
eventual outcome of these proceedings will be, or what the timing of the amount
of any loss, fine or penalty may be. Management does, however, assess
the probability of loss for such contingencies and accrues a liability for cases
which have a probable likelihood of loss and the loss amount can be
estimated. For details on regulatory proceedings and pending
litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 2007 Annual Report. Also, see Note 3 – Rate
Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed
Notes to Condensed Financial Statements of Registrant Subsidiaries”
section. Adverse results in these proceedings have the potential to
materially affect results of operations, financial condition and cash
flows.
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of relevant factors.
Critical Accounting
Estimates
See the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption of New Accounting
Pronouncements
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market
Risks
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion within AEP’s “Quantitative and
Qualitative Disclosures About Risk Management Activities”
section. The following tables provide information about AEP’s risk
management activities’ effect on SWEPCo.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in SWEPCo’s Condensed Consolidated Balance Sheet as of June 30, 2008
and the reasons for changes in total MTM value as compared to December 31,
2007.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of June 30, 2008
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
|
Cash
Flow
&
Fair
Value Hedges
|
|
|
DETM
Assignment (a)
|
|
|
Collateral
Deposits
|
|
|
Total
|
|
Current
Assets
|
|
$ |
108,564 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(2,014 |
) |
|
$ |
106,550 |
|
Noncurrent
Assets
|
|
|
15,872 |
|
|
|
71 |
|
|
|
- |
|
|
|
(46
|
) |
|
|
15,897 |
|
Total
MTM Derivative Contract Assets
|
|
|
124,436 |
|
|
|
71 |
|
|
|
- |
|
|
|
(2,060
|
) |
|
|
122,447 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(106,167
|
) |
|
|
(4
|
) |
|
|
(110
|
) |
|
|
3,144 |
|
|
|
(103,137
|
) |
Noncurrent
Liabilities
|
|
|
(14,030
|
) |
|
|
- |
|
|
|
(120
|
) |
|
|
1,252 |
|
|
|
(12,898
|
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(120,197
|
) |
|
|
(4
|
) |
|
|
(230
|
) |
|
|
4,396 |
|
|
|
(116,035
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$ |
4,239 |
|
|
$ |
67 |
|
|
$ |
(230 |
) |
|
$ |
2,336 |
|
|
$ |
6,412 |
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Six
Months Ended June 30, 2008
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2007
|
|
$
|
8,131
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered in a
Prior Period
|
|
|
(4,779
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
-
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
-
|
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward Contracts
(b)
|
|
|
418
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(c)
|
|
|
(258
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
727
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
4,239
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
67
|
|
DETM
Assignment (e)
|
|
|
(230
|
)
|
Collateral
Deposits
|
|
|
2,336
|
|
Ending
Net Risk Management Assets at June 30, 2008
|
|
$
|
6,412
|
|
(a)
|
Reflects
fair value on long-term contracts which are typically with customers that
seek fixed pricing to limit their risk against fluctuating energy
prices. The contract prices are valued against market curves
associated with the delivery location and delivery
term.
|
(b)
|
Represents
the impact of applying AEP’s credit risk when measuring the fair value of
derivative liabilities according to SFAS 157.
|
(c)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(d)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected in the Condensed
Consolidated Statements of Income. These net gains (losses) are
recorded as regulatory assets/liabilities for those subsidiaries that
operate in regulated jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
The
following table presents the maturity, by year, of net assets/liabilities to
give an indication of when these MTM amounts will settle and generate
cash:
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets
Fair
Value of Contracts as of June 30, 2008
(in
thousands)
|
|
Remainder
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
After
2012
|
|
|
Total
|
|
Level
1 (a)
|
|
$ |
1,376 |
|
|
$ |
(277 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,099 |
|
Level
2 (b)
|
|
|
366 |
|
|
|
3,072 |
|
|
|
(237
|
) |
|
|
(16
|
) |
|
|
- |
|
|
|
- |
|
|
|
3,185 |
|
Level
3 (c)
|
|
|
(47
|
) |
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(45
|
) |
Total
|
|
$ |
1,695 |
|
|
$ |
2,795 |
|
|
$ |
(235 |
) |
|
$ |
(16 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
4,239 |
|
(a)
|
Level
1 inputs are quoted prices (unadjusted) in active markets for identical
assets or liabilities that the reporting entity has the ability to access
at the measurement date. Level 1 inputs primarily consist of
exchange traded contracts that exhibit sufficient frequency and volume to
provide pricing information on an ongoing basis.
|
(b)
|
Level
2 inputs are inputs other than quoted prices included within Level 1 that
are observable for the asset or liability, either directly or
indirectly. If the asset or liability has a specified
(contractual) term, a Level 2 input must be observable for substantially
the full term of the asset or liability. Level 2 inputs
primarily consist of OTC broker quotes in moderately active or less active
markets, exchange traded contracts where there was not sufficient market
activity to warrant inclusion in Level 1, and OTC broker quotes that are
corroborated by the same or similar transactions that have occurred in the
market.
|
(c)
|
Level
3 inputs are unobservable inputs for the asset or
liability. Unobservable inputs shall be used to measure fair
value to the extent that the observable inputs are not available, thereby
allowing for situations in which there is little, if any, market activity
for the asset or liability at the measurement date. Level 3
inputs primarily consist of unobservable market data or are valued based
on models and/or assumptions.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on
the Condensed Consolidated Balance Sheet
Management
uses interest rate derivative transactions to manage interest rate risk related
to anticipated borrowings of fixed-rate debt. Management does not
hedge all interest rate risk.
Management
uses foreign currency derivatives to lock in prices on certain forecasted
transactions denominated in foreign currencies where deemed necessary, and
designates qualifying instruments as cash flow hedges. Management
does not hedge all foreign currency exposure.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on SWEPCo’s Condensed Consolidated Balance Sheets and the
reasons for the changes from December 31, 2007 to June 30, 2008. Only
contracts designated as cash flow hedges are recorded in
AOCI. Therefore, economic hedge contracts that are not designated as
effective cash flow hedges are marked-to-market and included in the previous
risk management tables. All amounts are presented net of related
income taxes.
Total
Accumulated Other Comprehensive Income (Loss) Activity
Six
Months Ended June 30, 2008
(in
thousands)
|
|
Interest
Rate
|
|
|
Foreign
Currency
|
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2007
|
|
$ |
(6,650 |
) |
|
$ |
629 |
|
|
$ |
(6,021 |
) |
Changes
in Fair Value
|
|
|
- |
|
|
|
120 |
|
|
|
120 |
|
Reclassifications
from AOCI for Cash
Flow Hedges Settled
|
|
|
413 |
|
|
|
(705
|
) |
|
|
(292
|
) |
Ending
Balance in AOCI June 30, 2008
|
|
$ |
(6,237 |
) |
|
$ |
44 |
|
|
$ |
(6,193 |
) |
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is an $829 thousand loss.
Credit
Risk
Counterparty
credit quality and exposure is generally consistent with that of
AEP.
VaR
Associated with Risk Management Contracts
Management
uses a risk measurement model, which calculates Value at Risk (VaR) to measure
commodity price risk in the risk management portfolio. The VaR is based on the
variance-covariance method using historical prices to estimate volatilities and
correlations and assumes a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at June 30, 2008, a near term
typical change in commodity prices is not expected to have a material effect on
SWEPCo’s results of operations, cash flows or financial condition.
The
following table shows the end, high, average and low market risk as measured by
VaR for the periods indicated:
Six
Months Ended
June
30, 2008
|
|
|
Twelve
Months Ended
December
31, 2007
|
(in
thousands)
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$62
|
|
$163
|
|
$54
|
|
$11
|
|
|
$17
|
|
$245
|
|
$75
|
|
$7
|
Management
back-tests its VaR results against performance due to actual price
moves. Based on the assumed 95% confidence interval, the performance
due to actual price moves would be expected to exceed the VaR at least once
every 20 trading days. Management’s backtesting results show that its
actual performance exceeded VaR far fewer than once every 20 trading
days. As a result, management believes SWEPCo’s VaR calculation is
conservative.
As
SWEPCo’s VaR calculation captures recent price moves, management also performs
regular stress testing of the portfolio to understand SWEPCo’s exposure to
extreme price moves. Management employs a historically-based method
whereby the current portfolio is subjected to actual, observed price moves from
the last three years in order to ascertain which historical price moves
translate into the largest potential mark-to-market loss. Management
then researches the underlying positions, price moves and market events that
created the most significant exposure.
Interest
Rate Risk
Management
utilizes an Earnings at Risk (EaR) model to measure interest rate market risk
exposure. EaR statistically quantifies the extent to which SWEPCo’s interest
expense could vary over the next twelve months and gives a probabilistic
estimate of different levels of interest expense. The resulting EaR
is interpreted as the dollar amount by which actual interest expense for the
next twelve months could exceed expected interest expense with a one-in-twenty
chance of occurrence. The primary drivers of EaR are from the
existing floating rate debt (including short-term debt) as well as long-term
debt issuances in the next twelve months. The estimated EaR on
SWEPCo’s debt portfolio was $2 million.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
405,632 |
|
|
$ |
329,250 |
|
|
$ |
731,533 |
|
|
$ |
656,534 |
|
Sales
to AEP Affiliates
|
|
|
17,592 |
|
|
|
16,237 |
|
|
|
31,184 |
|
|
|
32,652 |
|
Other
|
|
|
393 |
|
|
|
535 |
|
|
|
693 |
|
|
|
935 |
|
TOTAL
|
|
|
423,617 |
|
|
|
346,022 |
|
|
|
763,410 |
|
|
|
690,121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
147,147 |
|
|
|
125,994 |
|
|
|
264,808 |
|
|
|
237,981 |
|
Purchased
Electricity for Resale
|
|
|
54,378 |
|
|
|
56,870 |
|
|
|
94,648 |
|
|
|
109,368 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
51,932 |
|
|
|
16,085 |
|
|
|
72,372 |
|
|
|
39,002 |
|
Other
Operation
|
|
|
58,757 |
|
|
|
50,204 |
|
|
|
122,336 |
|
|
|
103,987 |
|
Maintenance
|
|
|
27,692 |
|
|
|
29,721 |
|
|
|
55,160 |
|
|
|
56,060 |
|
Depreciation
and Amortization
|
|
|
36,897 |
|
|
|
34,668 |
|
|
|
73,033 |
|
|
|
68,790 |
|
Taxes
Other Than Income Taxes
|
|
|
15,705 |
|
|
|
17,540 |
|
|
|
33,124 |
|
|
|
33,531 |
|
TOTAL
|
|
|
392,508 |
|
|
|
331,082 |
|
|
|
715,481 |
|
|
|
648,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
31,109 |
|
|
|
14,940 |
|
|
|
47,929 |
|
|
|
41,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
1,540 |
|
|
|
776 |
|
|
|
2,417 |
|
|
|
1,481 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
2,952 |
|
|
|
2,562 |
|
|
|
6,015 |
|
|
|
3,953 |
|
Interest
Expense
|
|
|
(17,270
|
) |
|
|
(17,235
|
) |
|
|
(34,412
|
) |
|
|
(32,725
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE (CREDIT)
AND MINORITY INTEREST EXPENSE
|
|
|
18,331 |
|
|
|
1,043 |
|
|
|
21,949 |
|
|
|
14,111 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense (Credit)
|
|
|
3,351 |
|
|
|
(1,553
|
) |
|
|
1,364 |
|
|
|
1,068 |
|
Minority
Interest Expense
|
|
|
899 |
|
|
|
972 |
|
|
|
1,894 |
|
|
|
1,814 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
14,081 |
|
|
|
1,624 |
|
|
|
18,691 |
|
|
|
11,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
57 |
|
|
|
57 |
|
|
|
114 |
|
|
|
114 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
14,024 |
|
|
$ |
1,567 |
|
|
$ |
18,577 |
|
|
$ |
11,115 |
|
The
common stock of SWEPCo is wholly-owned by AEP.
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
|
Paid-in
Capital
|
|
|
Retained
Earnings
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
Total
|
|
DECEMBER
31, 2006
|
|
$ |
135,660 |
|
|
$ |
245,003 |
|
|
$ |
459,338 |
|
|
$ |
(18,799 |
) |
|
$ |
821,202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(1,642
|
) |
|
|
|
|
|
|
(1,642
|
) |
Capital
Contribution from Parent
|
|
|
|
|
|
|
25,000 |
|
|
|
|
|
|
|
|
|
|
|
25,000 |
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(114
|
) |
|
|
|
|
|
|
(114
|
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
844,446 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(79
|
) |
|
|
(79
|
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
11,229 |
|
|
|
|
|
|
|
11,229 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
135,660 |
|
|
$ |
270,003 |
|
|
$ |
468,811 |
|
|
$ |
(18,878 |
) |
|
$ |
855,596 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2007
|
|
$ |
135,660 |
|
|
$ |
330,003 |
|
|
$ |
523,731 |
|
|
$ |
(16,439 |
) |
|
$ |
972,955 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EITF
06-10 Adoption, Net of Tax of $622
|
|
|
|
|
|
|
|
|
|
|
(1,156
|
) |
|
|
|
|
|
|
(1,156
|
) |
SFAS
157 Adoption, Net of Tax of $6
|
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
10 |
|
Capital
Contribution from Parent
|
|
|
|
|
|
|
100,000 |
|
|
|
|
|
|
|
|
|
|
|
100,000 |
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(114
|
) |
|
|
|
|
|
|
(114
|
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,071,695 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income
(Loss), Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(172
|
) |
|
|
(172
|
) |
Amortization
of Pension and OPEB Deferred
Costs,
Net of Tax of $253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
471 |
|
|
|
471 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
18,691 |
|
|
|
|
|
|
|
18,691 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,990 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2008
|
|
$ |
135,660 |
|
|
$ |
430,003 |
|
|
$ |
541,162 |
|
|
$ |
(16,140 |
) |
|
$ |
1,090,685 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
2,242 |
|
|
$ |
1,742 |
|
Advances
to Affiliates
|
|
|
300,525 |
|
|
|
- |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
64,754 |
|
|
|
91,379 |
|
Affiliated Companies
|
|
|
25,663 |
|
|
|
33,196 |
|
Miscellaneous
|
|
|
12,723 |
|
|
|
10,544 |
|
Allowance for Uncollectible Accounts
|
|
|
(139
|
) |
|
|
(143 |
) |
Total Accounts Receivable
|
|
|
103,001 |
|
|
|
134,976 |
|
Fuel
|
|
|
87,705 |
|
|
|
75,662 |
|
Materials
and Supplies
|
|
|
51,581 |
|
|
|
48,673 |
|
Risk
Management Assets
|
|
|
106,550 |
|
|
|
39,850 |
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
67,186 |
|
|
|
5,859 |
|
Margin
Deposits
|
|
|
1,319 |
|
|
|
10,650 |
|
Prepayments
and Other
|
|
|
70,233 |
|
|
|
28,147 |
|
TOTAL
|
|
|
790,342 |
|
|
|
345,559 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
1,751,081 |
|
|
|
1,743,198 |
|
Transmission
|
|
|
770,560 |
|
|
|
737,975 |
|
Distribution
|
|
|
1,351,982 |
|
|
|
1,312,746 |
|
Other
|
|
|
642,255 |
|
|
|
631,765 |
|
Construction
Work in Progress
|
|
|
632,514 |
|
|
|
451,228 |
|
Total
|
|
|
5,148,392 |
|
|
|
4,876,912 |
|
Accumulated
Depreciation and Amortization
|
|
|
1,964,954 |
|
|
|
1,939,044 |
|
TOTAL
- NET
|
|
|
3,183,438 |
|
|
|
2,937,868 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
118,139 |
|
|
|
133,617 |
|
Long-term
Risk Management Assets
|
|
|
15,897 |
|
|
|
4,073 |
|
Deferred
Charges and Other
|
|
|
107,440 |
|
|
|
67,269 |
|
TOTAL
|
|
|
241,476 |
|
|
|
204,959 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
4,215,256 |
|
|
$ |
3,488,386 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
June
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
- |
|
|
$ |
1,565 |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
183,533 |
|
|
|
152,305 |
|
Affiliated
Companies
|
|
|
89,863 |
|
|
|
51,767 |
|
Short-term
Debt – Nonaffiliated
|
|
|
7,039 |
|
|
|
285 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
4,406 |
|
|
|
5,906 |
|
Risk
Management Liabilities
|
|
|
103,137 |
|
|
|
32,629 |
|
Customer
Deposits
|
|
|
36,729 |
|
|
|
37,473 |
|
Accrued
Taxes
|
|
|
49,529 |
|
|
|
26,494 |
|
Regulatory
Liability for Over-Recovered Fuel Costs
|
|
|
- |
|
|
|
22,879 |
|
Other
|
|
|
91,895 |
|
|
|
76,554 |
|
TOTAL
|
|
|
566,131 |
|
|
|
407,857 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
1,538,795 |
|
|
|
1,141,311 |
|
Long-term
Debt – Affiliated
|
|
|
50,000 |
|
|
|
50,000 |
|
Long-term
Risk Management Liabilities
|
|
|
12,898 |
|
|
|
3,334 |
|
Deferred
Income Taxes
|
|
|
397,158 |
|
|
|
361,806 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
340,563 |
|
|
|
334,014 |
|
Deferred
Credits and Other
|
|
|
212,656 |
|
|
|
210,725 |
|
TOTAL
|
|
|
2,552,070 |
|
|
|
2,101,190 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
3,118,201 |
|
|
|
2,509,047 |
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
1,673 |
|
|
|
1,687 |
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
4,697 |
|
|
|
4,697 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
|
Common
Stock – Par Value – $18 Per Share:
|
|
|
|
|
|
|
|
|
Authorized
– 7,600,000 Shares
|
|
|
|
|
|
|
|
|
Outstanding
– 7,536,640 Shares
|
|
|
135,660 |
|
|
|
135,660 |
|
Paid-in
Capital
|
|
|
430,003 |
|
|
|
330,003 |
|
Retained
Earnings
|
|
|
541,162 |
|
|
|
523,731 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(16,140
|
) |
|
|
(16,439
|
) |
TOTAL
|
|
|
1,090,685 |
|
|
|
972,955 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
4,215,256 |
|
|
$ |
3,488,386 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Six Months Ended June 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
18,691 |
|
|
$ |
11,229 |
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
73,033 |
|
|
|
68,790 |
|
Deferred
Income Taxes
|
|
|
28,256 |
|
|
|
(21,658 |
) |
Provision
for Fuel Disallowance
|
|
|
- |
|
|
|
24,500 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
(6,015
|
) |
|
|
(3,953 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
1,541 |
|
|
|
5,190 |
|
Deferred
Property Taxes
|
|
|
(19,866
|
) |
|
|
(19,210 |
) |
Change
in Other Noncurrent Assets
|
|
|
3,434 |
|
|
|
3,846 |
|
Change
in Other Noncurrent Liabilities
|
|
|
(17,106
|
) |
|
|
(7,932 |
) |
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts Receivable, Net
|
|
|
31,975 |
|
|
|
26,897 |
|
Fuel, Materials and Supplies
|
|
|
(14,978
|
) |
|
|
(11,126 |
) |
Accounts Payable
|
|
|
60,552 |
|
|
|
8,388 |
|
Accrued Taxes, Net
|
|
|
(12,503
|
) |
|
|
36,445 |
|
Fuel Over/Under-Recovery, Net
|
|
|
(84,206
|
) |
|
|
1,293 |
|
Other Current Assets
|
|
|
7,296 |
|
|
|
12,928 |
|
Other Current Liabilities
|
|
|
4,518 |
|
|
|
(15,030 |
) |
Net
Cash Flows from Operating Activities
|
|
|
74,622 |
|
|
|
120,597 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(266,145
|
) |
|
|
(250,409 |
) |
Change
in Advances to Affiliates, Net
|
|
|
(300,525
|
) |
|
|
- |
|
Other
|
|
|
(2,439
|
) |
|
|
(2,858 |
) |
Net
Cash Flows Used for Investing Activities
|
|
|
(569,109
|
) |
|
|
(253,267 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
100,000 |
|
|
|
25,000 |
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
396,446 |
|
|
|
247,496 |
|
Change
in Short-term Debt, Net – Nonaffiliated
|
|
|
6,754 |
|
|
|
5,230 |
|
Change
in Advances from Affiliates, Net
|
|
|
(1,565
|
) |
|
|
(135,010 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(3,703
|
) |
|
|
(8,609 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(2,831
|
) |
|
|
(2,383 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(114
|
) |
|
|
(114 |
) |
Net
Cash Flows from Financing Activities
|
|
|
494,987 |
|
|
|
131,610 |
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
500 |
|
|
|
(1,060 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,742 |
|
|
|
2,618 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
2,242 |
|
|
$ |
1,558 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
19,848 |
|
|
$ |
25,876 |
|
Net
Cash Paid for Income Taxes
|
|
|
10,276 |
|
|
|
10,617 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
17,236 |
|
|
|
6,511 |
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
68,670 |
|
|
|
38,630 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to SWEPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to
SWEPCo.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
CONDENSED NOTES TO CONDENSED
FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to condensed financial statements that follow are a
combined presentation for the Registrant Subsidiaries. The
following list indicates the registrants to which the footnotes
apply:
|
|
|
|
1.
|
Significant
Accounting Matters
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
2.
|
New
Accounting Pronouncements and Extraordinary Item
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
3.
|
Rate
Matters
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
4.
|
Commitments,
Guarantees and Contingencies
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
5.
|
Acquisition
|
CSPCo
|
6.
|
Benefit
Plans
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
7.
|
Business
Segments
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
8.
|
Income
Taxes
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
9.
|
Financing
Activities
|
APCo,
CSPCo, I&M, OPCo, PSO,
SWEPCo
|
1.
|
SIGNIFICANT ACCOUNTING
MATTERS
|
General
The
accompanying unaudited condensed financial statements and footnotes were
prepared in accordance with GAAP for interim financial information and with the
instructions to Form 10-Q and Article 10 of Regulation S-X of the
SEC. Accordingly, they do not include all the information and
footnotes required by GAAP for complete annual financial
statements.
In the
opinion of management, the unaudited interim financial statements reflect all
normal and recurring accruals and adjustments necessary for a fair presentation
of the results of operations, financial position and cash flows for the interim
periods for each Registrant Subsidiary. The results of operations for
the three and six months ended June 30, 2008 are not necessarily indicative of
results that may be expected for the year ending December 31,
2008. The accompanying condensed financial statements are unaudited
and should be read in conjunction with the audited 2007 financial statements and
notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports
on Form 10-K for the year ended December 31, 2007 as filed with the SEC on
February 28, 2008.
Reclassifications
Certain
prior period financial statement items have been reclassified to conform to
current period presentation. See “FSP FIN 39-1 Amendment of FASB
Interpretation No. 39” section of Note 2 for discussion of changes in netting
certain balance sheet amounts. These revisions had no impact on the
Registrant Subsidiaries’ previously reported results of operations or changes in
shareholders’ equity.
2.
|
NEW ACCOUNTING
PRONOUNCEMENTS AND EXTRAORDINARY
ITEM
|
NEW
ACCOUNTING PRONOUNCEMENTS
Upon
issuance of final pronouncements, management thoroughly reviews the new
accounting literature to determine the relevance, if any, to the Registrant
Subsidiaries’ business. The following represents a summary of new
pronouncements issued or implemented in 2008 and standards issued but not
implemented that management has determined relate to the Registrant
Subsidiaries’ operations.
SFAS
141 (revised 2007) “Business Combinations” (SFAS 141R)
In
December 2007, the FASB issued SFAS 141R, improving financial reporting about
business combinations and their effects. It establishes how the
acquiring entity recognizes and measures the identifiable assets acquired,
liabilities assumed, goodwill acquired, any gain on bargain purchases and any
noncontrolling interest in the acquired entity. SFAS 141R no longer
allows acquisition-related costs to be included in the cost of the business
combination, but rather expensed in the periods they are incurred, with the
exception of the costs to issue debt or equity securities which shall be
recognized in accordance with other applicable GAAP. SFAS 141R
requires disclosure of information for a business combination that occurs during
the accounting period or prior to the issuance of the financial statements for
the accounting period.
SFAS 141R
is effective prospectively for business combinations with an acquisition date on
or after the beginning of the first annual reporting period after December 15,
2008. Early adoption is prohibited. The Registrant
Subsidiaries will adopt SFAS 141R effective January 1, 2009 and apply it to any
business combinations on or after that date.
SFAS
157 “Fair Value Measurements” (SFAS 157)
In
September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair
value measurement of assets and liabilities and instruments measured at fair
value that are classified in shareholders’ equity. The statement
defines fair value, establishes a fair value measurement framework and expands
fair value disclosures. It emphasizes that fair value is market-based
with the highest measurement hierarchy level being market prices in active
markets. The standard requires fair value measurements be disclosed
by hierarchy level, an entity includes its own credit standing in the
measurement of its liabilities and modifies the transaction price
presumption. The standard also nullifies the consensus reached in
EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held
for Trading Purposes and Contracts Involved in Energy Trading and Risk
Management Activities” (EITF 02-3) that prohibited the recognition of trading
gains or losses at the inception of a derivative contract, unless the fair value
of such derivative is supported by observable market data.
In
February 2008, the FASB issued FSP SFAS 157-1 “Application of FASB Statement No.
157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address
Fair Value Measurements for Purposes of Lease Classification or Measurement
under Statement 13” (SFAS 157-1) which amends SFAS 157 to exclude SFAS 13
“Accounting for Leases” (SFAS 13) and other accounting pronouncements that
address fair value measurements for purposes of lease classification or
measurement under SFAS 13.
In
February 2008, the FASB issued FSP SFAS 157-2 “Effective Date of FASB Statement
No. 157” (SFAS 157-2) which delays the effective date of SFAS 157 to fiscal
years beginning after November 15, 2008 for all nonfinancial assets and
nonfinancial liabilities, except those that are recognized or disclosed at fair
value in the financial statements on a recurring basis (at least
annually).
The
Registrant Subsidiaries partially adopted SFAS 157 effective January 1,
2008. The Registrant Subsidiaries will fully adopt SFAS 157 effective
January 1, 2009 for items within the scope of FSP SFAS 157-2. The
provisions of SFAS 157 are applied prospectively, except for a) changes in fair
value measurements of existing derivative financial instruments measured
initially using the transaction price under EITF 02-3, b) existing hybrid
financial instruments measured initially at fair value using the transaction
price and c) blockage discount factors. Although the statement is
applied prospectively upon adoption, in accordance with the provisions of SFAS
157 related to EITF 02-3, APCo, CSPCo and OPCo reduced beginning retained
earnings by $440 thousand ($286 thousand, net of tax), $486 thousand ($316
thousand, net of tax) and $434 thousand ($282 thousand, net of tax),
respectively, for the transition adjustment. SWEPCo’s transition
adjustment was a favorable $16 thousand ($10 thousand, net of tax) adjustment to
beginning retained earnings. The impact of considering AEP’s credit
risk when measuring the fair value of liabilities, including derivatives, had an
immaterial impact on fair value measurements upon adoption.
In
accordance with SFAS 157, assets and liabilities are classified based on the
inputs utilized in the fair value measurement. SFAS 157 provides
definitions for two types of inputs: observable and
unobservable. Observable inputs are valuation inputs that reflect the
assumptions market participants would use in pricing the asset or liability
developed based on market data obtained from sources independent of the
reporting entity. Unobservable inputs are valuation inputs that
reflect the reporting entity’s own assumptions about the assumptions market
participants would use in pricing the asset or liability developed based on the
best information in the circumstances.
As
defined in SFAS 157, fair value is the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date (exit price). SFAS 157
establishes a fair value hierarchy that prioritizes the inputs used to measure
fair value. The hierarchy gives the highest priority to unadjusted quoted prices
in active markets for identical assets or liabilities (level 1 measurement) and
the lowest priority to unobservable inputs (level 3 measurement).
Level 1
inputs are quoted prices (unadjusted) in active markets for identical assets or
liabilities that the reporting entity has the ability to access at the
measurement date. Level 1 inputs primarily consist of exchange traded
contracts, listed equities and U.S. government treasury securities that exhibit
sufficient frequency and volume to provide pricing information on an ongoing
basis.
Level 2
inputs are inputs other than quoted prices included within level 1 that are
observable for the asset or liability, either directly or
indirectly. If the asset or liability has a specified (contractual)
term, a level 2 input must be observable for substantially the full term of the
asset or liability. Level 2 inputs primarily consist of OTC broker
quotes in moderately active or less active markets, exchange traded contracts
where there was not sufficient market activity to warrant inclusion in level 1,
OTC broker quotes that are corroborated by the same or similar transactions that
have occurred in the market and certain non-exchange-traded debt
securities.
Level 3
inputs are unobservable inputs for the asset or
liability. Unobservable inputs shall be used to measure fair value to
the extent that the observable inputs are not available, thereby allowing for
situations in which there is little, if any, market activity for the asset or
liability at the measurement date. Level 3 inputs primarily consist
of unobservable market data or are valued based on models and/or
assumptions.
Risk
Management Contracts include exchange traded, OTC and bilaterally executed
derivative contracts. Exchange traded derivatives, namely futures
contracts, are generally fair valued based on unadjusted quoted prices in active
markets and are classified within level 1. Other actively traded
derivatives are valued using broker or dealer quotations, similar observable
market transactions in either the listed or OTC markets, or through pricing
models where significant valuation inputs are directly or indirectly
observable in active markets. Derivative instruments, primarily
swaps, forwards, and options that meet these characteristics are classified
within level 2. Bilaterally executed agreements are derivative
contracts entered into directly with third parties, and at times these
instruments may be complex structured transactions that are tailored to meet the
specific customer’s energy requirements. Structured transactions
utilize pricing models that are widely accepted in the energy industry to
measure fair value. Generally, management uses a consistent modeling
approach to value similar instruments. Valuation models utilize
various inputs that include quoted prices for similar assets or liabilities in
active markets, quoted prices for identical or similar assets or liabilities in
markets that are not active, market corroborated inputs (i.e. inputs derived
principally from, or correlated to, observable market data), and other
observable inputs for the asset or liability. Where observable inputs
are available for substantially the full term of the asset or liability, the
instrument is categorized in level 2. Certain OTC and bilaterally
executed derivative instruments are executed in less active markets with a lower
availability of pricing information. In addition, long-dated and
illiquid complex or structured transactions can introduce the need for
internally developed modeling inputs based upon extrapolations and assumptions
of observable market data to estimate fair value. When such inputs
have a significant impact on the measurement of fair value, the instrument is
categorized in level 3. In certain instances, the fair values of the
transactions that use internally developed model inputs, classified as level 3
are offset partially or in full, by transactions included in level 2 where
observable market data exists for the offsetting transaction.
The
following table sets forth, by level within the fair value hierarchy, the
Registrant Subsidiaries’ financial assets and liabilities that were accounted
for at fair value on a recurring basis as of June 30, 2008. As
required by SFAS 157, financial assets and liabilities are classified in their
entirety based on the lowest level of input that is significant to the fair
value measurement. Management’s assessment of the significance of a
particular input to the fair value measurement requires judgment, and may affect
the valuation of fair value assets and liabilities and their placement within
the fair value hierarchy levels.
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of June 30,
2008
APCo
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
35,609 |
|
|
$ |
1,261,131 |
|
|
$ |
10,761 |
|
|
$ |
(1,012,957 |
) |
|
$ |
294,544 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
9,201 |
|
|
|
- |
|
|
|
(4,967
|
) |
|
|
4,234 |
|
Dedesignated
Risk Management Contracts (b)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
14,916 |
|
|
|
14,916 |
|
Total
Risk Management Assets
|
|
$ |
35,609 |
|
|
$ |
1,270,332 |
|
|
$ |
10,761 |
|
|
$ |
(1,003,008 |
) |
|
$ |
313,694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
37,928 |
|
|
$ |
1,226,686 |
|
|
$ |
29,321 |
|
|
$ |
(1,008,877 |
) |
|
$ |
285,058 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
34,986 |
|
|
|
- |
|
|
|
(4,967
|
) |
|
|
30,019 |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,116 |
|
|
|
7,116 |
|
Total
Risk Management Liabilities
|
|
$ |
37,928 |
|
|
$ |
1,261,672 |
|
|
$ |
29,321 |
|
|
$ |
(1,006,728 |
) |
|
$ |
322,193 |
|
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of June 30,
2008
CSPCo
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Cash Deposits (e)
|
|
$ |
35,806 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,169 |
|
|
$ |
36,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
21,385 |
|
|
$ |
692,082 |
|
|
$ |
6,467 |
|
|
$ |
(557,082 |
) |
|
$ |
162,852 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
4,503 |
|
|
|
- |
|
|
|
(2,983
|
) |
|
|
1,520 |
|
Dedesignated
Risk Management Contracts (b)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8,958 |
|
|
|
8,958 |
|
Total
Risk Management Assets
|
|
$ |
21,385 |
|
|
$ |
696,585 |
|
|
$ |
6,467 |
|
|
$ |
(551,107 |
) |
|
$ |
173,330 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
57,191 |
|
|
$ |
696,585 |
|
|
$ |
6,467 |
|
|
$ |
(549,938 |
) |
|
$ |
210,305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
22,778 |
|
|
$ |
671,311 |
|
|
$ |
17,589 |
|
|
$ |
(553,617 |
) |
|
$ |
158,061 |
|
Cash
Flow and Fair Value Hedges (b)
|
|
|
- |
|
|
|
21,011 |
|
|
|
- |
|
|
|
(2,983
|
) |
|
|
18,028 |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,274 |
|
|
|
4,274 |
|
Total
Risk Management Liabilities
|
|
$ |
22,778 |
|
|
$ |
692,322 |
|
|
$ |
17,589 |
|
|
$ |
(552,326 |
) |
|
$ |
180,363 |
|
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of June 30,
2008
I&M
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
20,545 |
|
|
$ |
643,285 |
|
|
$ |
6,215 |
|
|
$ |
(516,431 |
) |
|
$ |
153,614 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
4,326 |
|
|
|
- |
|
|
|
(2,866
|
) |
|
|
1,460 |
|
Dedesignated
Risk Management Contracts (b)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8,606 |
|
|
|
8,606 |
|
Total
Risk Management Assets
|
|
$ |
20,545 |
|
|
$ |
647,611 |
|
|
$ |
6,215 |
|
|
$ |
(510,691 |
) |
|
$ |
163,680 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spent
Nuclear Fuel and Decommissioning Trusts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents (d)
|
|
$ |
- |
|
|
$ |
16,728 |
|
|
$ |
- |
|
|
$ |
12,246 |
|
|
$ |
28,974 |
|
Debt
Securities
|
|
|
326,416 |
|
|
|
507,611 |
|
|
|
- |
|
|
|
- |
|
|
|
834,027 |
|
Equity
Securities
|
|
|
498,926 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
498,926 |
|
Total Spent Nuclear Fuel and
Decommissioning Trusts
|
|
$ |
825,342 |
|
|
$ |
524,339 |
|
|
$ |
- |
|
|
$ |
12,246 |
|
|
$ |
1,361,927 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
845,887 |
|
|
$ |
1,171,950 |
|
|
$ |
6,215 |
|
|
$ |
(498,445 |
) |
|
$ |
1,525,607 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
21,883 |
|
|
$ |
623,352 |
|
|
$ |
16,890 |
|
|
$ |
(512,683 |
) |
|
$ |
149,442 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
20,186 |
|
|
|
- |
|
|
|
(2,866
|
) |
|
|
17,320 |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,107 |
|
|
|
4,107 |
|
Total
Risk Management Liabilities
|
|
$ |
21,883 |
|
|
$ |
643,538 |
|
|
$ |
16,890 |
|
|
$ |
(511,442 |
) |
|
$ |
170,869 |
|
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of June 30,
2008
OPCo
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Cash Deposits (e)
|
|
$ |
3,216 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
2,182 |
|
|
$ |
5,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
24,915 |
|
|
$ |
1,255,573 |
|
|
$ |
7,493 |
|
|
$ |
(1,038,518 |
) |
|
$ |
249,463 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
5,259 |
|
|
|
- |
|
|
|
(3,475
|
) |
|
|
1,784 |
|
Dedesignated
Risk Management Contracts (b)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10,436 |
|
|
|
10,436 |
|
Total
Risk Management Assets
|
|
$ |
24,915 |
|
|
$ |
1,260,832 |
|
|
$ |
7,493 |
|
|
$ |
(1,031,557 |
) |
|
$ |
261,683 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
28,131 |
|
|
$ |
1,260,832 |
|
|
$ |
7,493 |
|
|
$ |
(1,029,375 |
) |
|
$ |
267,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
26,538 |
|
|
$ |
1,230,208 |
|
|
$ |
20,738 |
|
|
$ |
(1,043,217 |
) |
|
$ |
234,267 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
27,153 |
|
|
|
- |
|
|
|
(3,475
|
) |
|
|
23,678 |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,979 |
|
|
|
4,979 |
|
Total
Risk Management Liabilities
|
|
$ |
26,538 |
|
|
$ |
1,257,361 |
|
|
$ |
20,738 |
|
|
$ |
(1,041,713 |
) |
|
$ |
262,924 |
|
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of June 30,
2008
PSO
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
52,111 |
|
|
$ |
562,955 |
|
|
$ |
7 |
|
|
$ |
(515,708 |
) |
|
$ |
99,365 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
Risk Management Assets
|
|
$ |
52,111 |
|
|
$ |
562,955 |
|
|
$ |
7 |
|
|
$ |
(515,708 |
) |
|
$ |
99,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
51,180 |
|
|
$ |
560,473 |
|
|
$ |
30 |
|
|
$ |
(517,065 |
) |
|
$ |
94,618 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
195 |
|
|
|
195 |
|
Total
Risk Management Liabilities
|
|
$ |
51,180 |
|
|
$ |
560,473 |
|
|
$ |
30 |
|
|
$ |
(516,870 |
) |
|
$ |
94,813 |
|
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of June 30,
2008
SWEPCo
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
61,460 |
|
|
$ |
701,896 |
|
|
$ |
5 |
|
|
$ |
(640,985 |
) |
|
$ |
122,376 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
80 |
|
|
|
- |
|
|
|
(9
|
) |
|
|
71 |
|
Total
Risk Management Assets
|
|
$ |
61,460 |
|
|
$ |
701,976 |
|
|
$ |
5 |
|
|
$ |
(640,994 |
) |
|
$ |
122,447 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
60,361 |
|
|
$ |
698,711 |
|
|
$ |
50 |
|
|
$ |
(643,321 |
) |
|
$ |
115,801 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
13 |
|
|
|
- |
|
|
|
(9
|
) |
|
|
4 |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
230 |
|
|
|
230 |
|
Total
Risk Management Liabilities
|
|
$ |
60,361 |
|
|
$ |
698,724 |
|
|
$ |
50 |
|
|
$ |
(643,100 |
) |
|
$ |
116,035 |
|
(a)
|
Amounts
in “Other” column primarily represent counterparty netting of risk
management contracts and associated cash collateral under FSP FIN
39-1.
|
(b)
|
“Dedesignated
Risk Management Contracts” are contracts that were originally MTM but were
subsequently elected as normal under SFAS 133. At the time of
the normal election the MTM value was frozen and no longer fair
valued. This will be amortized into Utility Operations Revenues
over the remaining life of the contract.
|
(c)
|
See
“Natural Gas Contracts with DETM” section of Note 16 in the 2007 Annual
Report.
|
(d)
|
Amounts
in “Other” column primarily represent accrued interest receivables to/from
financial institutions. Level 2 amounts primarily represent
investments in money market funds.
|
(e)
|
Amounts
in “Other” column primarily represent cash deposits with third
parties. Level 1 amounts primarily represent investments in
money market funds.
|
The
following tables set forth a reconciliation of changes in the fair value of net
trading derivatives and other investments classified as level 3 in the fair
value hierarchy:
Three
Months Ended June 30, 2008
|
|
APCo
|
|
|
CSPCo
|
|
|
I&M
|
|
|
OPCo
|
|
|
PSO
|
|
|
SWEPCo
|
|
|
|
(in
thousands)
|
|
Balance
as of April 1, 2008
|
|
$ |
(942 |
) |
|
$ |
(552 |
) |
|
$ |
(519 |
) |
|
$ |
(837 |
) |
|
$ |
(21 |
) |
|
$ |
(35 |
) |
Realized
(Gain) Loss Included in Earnings (or Changes in Net Assets)
(a)
|
|
|
(532
|
) |
|
|
(324
|
) |
|
|
(315
|
) |
|
|
(327
|
) |
|
|
1 |
|
|
|
4 |
|
Unrealized
Gain (Loss) Included in Earnings (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date
(a)
|
|
|
- |
|
|
|
261 |
|
|
|
- |
|
|
|
161 |
|
|
|
- |
|
|
|
(5
|
) |
Realized
and Unrealized Gains (Losses) Included in Other Comprehensive
Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Purchases,
Issuances and Settlements
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Transfers
in and/or out of Level 3 (b)
|
|
|
(2,186
|
) |
|
|
(1,313
|
) |
|
|
(1,261
|
) |
|
|
(1,530
|
) |
|
|
- |
|
|
|
- |
|
Changes
in Fair Value Allocated to Regulated Jurisdictions
(c)
|
|
|
(14,900
|
) |
|
|
(9,194
|
) |
|
|
(8,580
|
) |
|
|
(10,712
|
) |
|
|
(3
|
) |
|
|
(9
|
) |
Balance
as of June 30, 2008
|
|
$ |
(18,560 |
) |
|
$ |
(11,122 |
) |
|
$ |
(10,675 |
) |
|
$ |
(13,245 |
) |
|
$ |
(23 |
) |
|
$ |
(45 |
) |
Six
Months Ended June 30, 2008
|
|
APCo
|
|
|
CSPCo
|
|
|
I&M
|
|
|
OPCo
|
|
|
PSO
|
|
|
SWEPCo
|
|
|
|
(in
thousands)
|
|
Balance
as of January 1, 2008
|
|
$ |
(697 |
) |
|
$ |
(263 |
) |
|
$ |
(280 |
) |
|
$ |
(1,607 |
) |
|
$ |
(243 |
) |
|
$ |
(408 |
) |
Realized
(Gain) Loss Included in Earnings (or Changes in Net Assets)
(a)
|
|
|
(467
|
) |
|
|
(339
|
) |
|
|
(312
|
) |
|
|
232 |
|
|
|
98 |
|
|
|
174 |
|
Unrealized
Gain (Loss) Included in Earnings (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date
(a)
|
|
|
- |
|
|
|
(1,138
|
) |
|
|
- |
|
|
|
(2,019
|
) |
|
|
- |
|
|
|
(64
|
) |
Realized
and Unrealized Gains (Losses) Included in Other Comprehensive
Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Purchases,
Issuances and Settlements
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Transfers
in and/or out of Level 3 (b)
|
|
|
(122
|
) |
|
|
(188
|
) |
|
|
(158
|
) |
|
|
861 |
|
|
|
232 |
|
|
|
375 |
|
Changes
in Fair Value Allocated to Regulated Jurisdictions
(c)
|
|
|
(17,274
|
) |
|
|
(9,194
|
) |
|
|
(9,925
|
) |
|
|
(10,712
|
) |
|
|
(110
|
) |
|
|
(122
|
) |
Balance
as of June 30, 2008
|
|
$ |
(18,560 |
) |
|
$ |
(11,122 |
) |
|
$ |
(10,675 |
) |
|
$ |
(13,245 |
) |
|
$ |
(23 |
) |
|
$ |
(45 |
) |
(a)
|
Included
in revenues on the Condensed Statement of Income.
|
(b)
|
“Transfers
in and/or out of Level 3” represent existing assets or liabilities that
were either previously categorized as a higher level for which the inputs
to the model became unobservable or assets and liabilities that were
previously classified as level 3 for which the lowest significant input
became observable during the period.
|
(c)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected on the Condensed
Statements of Income. These net gains (losses) are recorded as
regulatory assets/liabilities for those subsidiaries that operate in
regulated jurisdictions.
|
SFAS
159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS
159)
In
February 2007, the FASB issued SFAS 159, permitting entities to choose to
measure many financial instruments and certain other items at fair
value. The standard also establishes presentation and disclosure
requirements designed to facilitate comparison between entities that choose
different measurement attributes for similar types of assets and
liabilities. If the fair value option is elected, the effect of the
first remeasurement to fair value is reported as a cumulative effect adjustment
to the opening balance of retained earnings. The statement is applied
prospectively upon adoption.
The
Registrant Subsidiaries adopted SFAS 159 effective January 1,
2008. At adoption, the Registrant Subsidiaries did not elect the fair
value option for any assets or liabilities.
SFAS
160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS
160)
In
December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling
interest (minority interest) in consolidated financial statements. It
requires noncontrolling interest be reported in equity and establishes a new
framework for recognizing net income or loss and comprehensive income by the
controlling interest. Upon deconsolidation due to loss of control
over a subsidiary, the standard requires a fair value remeasurement of any
remaining noncontrolling equity investment to be used to properly recognize the
gain or loss. SFAS 160 requires specific disclosures regarding
changes in equity interest of both the controlling and noncontrolling parties
and presentation of the noncontrolling equity balance and income or loss for all
periods presented.
SFAS 160
is effective for interim and annual periods in fiscal years beginning after
December 15, 2008. The statement is applied prospectively upon
adoption. Early adoption is prohibited. Upon adoption,
prior period financial statements will be restated for the presentation of the
noncontrolling interest for comparability. Although management has
not completed its analysis, management expects that the adoption of this
standard will have an immaterial impact on the financial
statements. The Registrant Subsidiaries will adopt SFAS 160 effective
January 1, 2009.
SFAS
161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS
161)
In March
2008, the FASB issued SFAS 161, enhancing disclosure requirements for derivative
instruments and hedging activities. Affected entities are required to
provide enhanced disclosures about (a) how and why an entity uses derivative
instruments, (b) how derivative instruments and related hedged items are
accounted for under SFAS 133 and its related interpretations, and (c) how
derivative instruments and related hedged items affect an entity’s financial
position, financial performance and cash flows. SFAS 161 requires
that objectives for using derivative instruments be disclosed in terms of
underlying risk and accounting designation. This standard is intended
to improve upon the existing disclosure framework in SFAS 133.
SFAS 161
is effective for fiscal years and interim periods beginning after November 15,
2008. Management expects this standard to increase the disclosure
requirements related to derivative instruments and hedging
activities. It encourages retrospective application to comparative
disclosure for earlier periods presented. The Registrant Subsidiaries
will adopt SFAS 161 effective January 1, 2009.
SFAS
162 “The Hierarchy of Generally Accepted Accounting Principles” (SFAS
162)
In May
2008, the FASB issued SFAS 162, clarifying the sources of generally accepted
accounting principles in descending order of authority. The statement
specifies that the reporting entity, not its auditors, is responsible for its
compliance with GAAP.
SFAS 162
is effective 60 days after the SEC approves the Public Company Accounting
Oversight Board’s amendments to AU Section 411, “The Meaning of Present Fairly
in Conformity with Generally Accepted Accounting Principles.” The
Registrant Subsidiaries expect the adoption of this standard will have no impact
on their financial statements. The Registrant Subsidiaries will adopt
SFAS 162 when it becomes effective.
EITF
Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life
Insurance Arrangements” (EITF
06-10)
In March
2007, the FASB ratified EITF 06-10, a consensus on collateral assignment
split-dollar life insurance arrangements in which an employee owns and controls
the insurance policy. Under EITF 06-10, an employer should recognize
a liability for the postretirement benefit related to a collateral assignment
split-dollar life insurance arrangement in accordance with SFAS 106 “Employers'
Accounting for Postretirement Benefits Other Than Pension” or Accounting
Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has
agreed to maintain a life insurance policy during the employee's retirement or
to provide the employee with a death benefit based on a substantive arrangement
with the employee. In addition, an employer should recognize and
measure an asset based on the nature and substance of the collateral assignment
split-dollar life insurance arrangement. EITF 06-10 requires
recognition of the effects of its application as either (a) a change in
accounting principle through a cumulative effect adjustment to retained earnings
or other components of equity or net assets in the statement of financial
position at the beginning of the year of adoption or (b) a change in accounting
principle through retrospective application to all prior periods. The
Registrant Subsidiaries adopted EITF 06-10 effective January 1,
2008. The impact of this standard was an unfavorable cumulative
effect adjustment, net of tax, to beginning retained earnings as
follows:
|
|
Retained
|
|
|
|
|
|
Earnings
|
|
Tax
|
|
Company
|
|
Reduction
|
|
Amount
|
|
|
|
(in
thousands)
|
|
APCo
|
|
$ |
2,181 |
|
$ |
1,175 |
|
CSPCo
|
|
|
1,095 |
|
|
589 |
|
I&M
|
|
|
1,398 |
|
|
753 |
|
OPCo
|
|
|
1,864 |
|
|
1,004 |
|
PSO
|
|
|
1,107 |
|
|
596 |
|
SWEPCo
|
|
|
1,156 |
|
|
622 |
|
EITF
Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based
Payment Awards” (EITF
06-11)
In June
2007, the FASB ratified the EITF consensus on the treatment of income tax
benefits of dividends on employee share-based compensation. The issue
is how a company should recognize the income tax benefit received on dividends
that are paid to employees holding equity-classified nonvested shares,
equity-classified nonvested share units or equity-classified outstanding share
options and charged to retained earnings under SFAS 123R, “Share-Based
Payments.” Under EITF 06-11, a realized income tax benefit from
dividends or dividend equivalents that are charged to retained earnings and are
paid to employees for equity-classified nonvested equity shares, nonvested
equity share units and outstanding equity share options should be recognized as
an increase to additional paid-in capital. EITF 06-11 is applied
prospectively to the income tax benefits of dividends on equity-classified
employee share-based payment awards that are declared in fiscal years after
December 15, 2007.
The
Registrant Subsidiaries adopted EITF 06-11 effective January 1,
2008. The adoption of this standard had an immaterial impact on the
financial statements.
FSP
SFAS 142-3 “Determination of the Useful Life of Intangible Assets” (SFAS
142-3)
In April
2008, the FASB issued SFAS 142-3 amending factors that should be considered in
developing renewal or extension assumptions used to determine the useful life of
a recognized intangible asset under SFAS 142, “Goodwill and Other Intangible
Assets.” The standard is expected to improve consistency between the
useful life of a recognized intangible asset and the period of expected cash
flows used to measure its fair value.
SFAS
142-3 is effective for interim and annual periods in fiscal years beginning
after December 15, 2008. Early adoption is
prohibited. Upon adoption, the guidance within SFAS 142-3 will be
prospectively applied to intangible assets acquired after the effective
date. Management expects that the adoption of this standard will have
an immaterial impact on the Registrant Subsidiaries’ financial
statements. The Registrant Subsidiaries will adopt SFAS 142-3
effective January 1, 2009.
FASB
Staff Position FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN
39-1)
In April
2007, the FASB issued FIN 39-1. It amends FASB Interpretation No. 39
“Offsetting of Amounts Related to Certain Contracts” by replacing the
interpretation’s definition of contracts with the definition of derivative
instruments per SFAS 133. It also requires entities that offset fair
values of derivatives with the same party under a netting agreement to also net
the fair values (or approximate fair values) of related cash
collateral. The entities must disclose whether or not they offset
fair values of derivatives and related cash collateral and amounts recognized
for cash collateral payables and receivables at the end of each reporting
period.
The
Registrant Subsidiaries adopted FIN 39-1 effective January 1,
2008. This standard changed the method of netting certain balance
sheet amounts and reduced assets and liabilities. It requires
retrospective application as a change in accounting
principle. Consequently, the Registrant Subsidiaries reclassified the
following amounts on their December 31, 2007 balance sheets as
shown:
APCo
|
|
|
|
|
|
|
|
|
|
|
|
As
Reported for
|
|
|
|
|
|
As Reported
for |
|
Balance
Sheet
|
|
the
December 2007
|
|
|
FIN
39-1
|
|
|
the June
2008 |
|
Line
Description
|
|
10-K |
|
|
Reclassification
|
|
|
10-Q
|
Current
Assets:
|
|
(in
thousands)
|
Risk
Management Assets
|
|
$ |
64,707 |
|
|
$ |
(1,752 |
) |
|
$ |
62,955
|
|
Prepayments
and Other
|
|
|
19,675 |
|
|
|
(3,306
|
) |
|
|
16,369
|
|
Long-term
Risk Management Assets
|
|
|
74,954 |
|
|
|
(2,588
|
) |
|
|
72,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities
|
|
|
54,955 |
|
|
|
(3,247
|
) |
|
|
51,708
|
|
Customer
Deposits
|
|
|
50,260 |
|
|
|
(4,340
|
) |
|
|
45,920
|
|
Long-term
Risk Management Liabilities
|
|
|
47,416 |
|
|
|
(59
|
) |
|
|
47,357
|
|
CSPCo
|
|
|
|
|
|
|
|
|
|
|
|
|
As
Reported for
|
|
|
|
|
|
As
Reported for
|
|
Balance
Sheet
|
|
the
December 2007
|
|
|
FIN
39-1
|
|
|
the
June 2008 |
|
Line
Description
|
|
10-K |
|
|
Reclassification |
|
|
10-Q
|
|
Current
Assets:
|
|
(in
thousands)
|
Risk
Management Assets
|
|
$ |
34,564 |
|
|
$ |
(1,006 |
) |
|
$ |
33,558 |
|
Prepayments
and Other
|
|
|
11,877 |
|
|
|
(1,917
|
) |
|
|
9,960 |
|
Long-term
Risk Management Assets
|
|
|
43,352 |
|
|
|
(1,500
|
) |
|
|
41,852 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities
|
|
|
30,118 |
|
|
|
(1,881
|
) |
|
|
28,237 |
|
Customer
Deposits
|
|
|
45,602 |
|
|
|
(2,507
|
) |
|
|
43,095 |
|
Long-term
Risk Management Liabilities
|
|
|
27,454 |
|
|
|
(35
|
) |
|
|
27,419 |
|
I&M
|
|
|
|
|
|
|
|
|
|
|
|
As
Reported for
|
|
|
|
|
|
As
Reported for
|
|
Balance
Sheet
|
|
the
December 2007
|
|
|
FIN
39-1
|
|
|
the
June 2008
|
|
Line
Description
|
|
10-K |
|
|
Reclassification
|
|
|
10-Q
|
|
Current
Assets:
|
|
(in
thousands)
|
Risk
Management Assets
|
|
$ |
33,334 |
|
|
$ |
(969 |
) |
|
$ |
32,365 |
|
Prepayments
and Other
|
|
|
12,932 |
|
|
|
(1,841
|
) |
|
|
11,091 |
|
Long-term
Risk Management Assets
|
|
|
41,668 |
|
|
|
(1,441
|
) |
|
|
40,227 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities
|
|
|
29,078 |
|
|
|
(1,807
|
) |
|
|
27,271 |
|
Customer
Deposits
|
|
|
28,855 |
|
|
|
(2,410
|
) |
|
|
26,445 |
|
Long-term
Risk Management Liabilities
|
|
|
26,382 |
|
|
|
(34
|
) |
|
|
26,348 |
|
OPCo
|
|
|
|
|
|
|
|
|
|
|
|
As
Reported for
|
|
|
|
|
|
As
Reported for
|
|
Balance
Sheet
|
|
the
December 2007
|
|
|
FIN
39-1
|
|
|
the
June 2008
|
|
Line
Description
|
|
10-K
|
|
|
Reclassification
|
|
|
10-Q
|
|
Current
Assets:
|
|
(in
thousands)
|
Risk
Management Assets
|
|
$ |
45,490 |
|
|
$ |
(1,254 |
) |
|
$ |
44,236 |
|
Prepayments
and Other
|
|
|
20,532 |
|
|
|
(2,232
|
) |
|
|
18,300 |
|
Long-term
Risk Management Assets
|
|
|
51,334 |
|
|
|
(1,748
|
) |
|
|
49,586 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities
|
|
|
42,740 |
|
|
|
(2,192
|
) |
|
|
40,548 |
|
Customer
Deposits
|
|
|
33,615 |
|
|
|
(3,002
|
) |
|
|
30,613 |
|
Long-term
Risk Management Liabilities
|
|
|
32,234 |
|
|
|
(40
|
) |
|
|
32,194 |
|
PSO
|
|
|
|
|
|
|
|
|
|
|
|
As
Reported for
|
|
|
|
|
|
As
Reported for
|
|
Balance
Sheet
|
|
the
December 2007
|
|
|
FIN
39-1
|
|
|
the
June 2008
|
|
Line
Description
|
|
10-K
|
|
|
Reclassification
|
|
|
10-Q
|
|
Current
Assets:
|
|
(in
thousands)
|
Risk
Management Assets
|
|
$ |
33,338 |
|
|
$ |
(30 |
) |
|
$ |
33,308 |
|
Margin
Deposits
|
|
|
9,119 |
|
|
|
(139 |
) |
|
|
8,980 |
|
Long-term
Risk Management Assets
|
|
|
3,376 |
|
|
|
(18 |
) |
|
|
3,358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities
|
|
|
27,151 |
|
|
|
(33 |
) |
|
|
27,118 |
|
Customer
Deposits
|
|
|
41,525 |
|
|
|
(48 |
) |
|
|
41,477 |
|
Long-term
Risk Management Liabilities
|
|
|
2,914 |
|
|
|
(106
|
) |
|
|
2,808 |
|
SWEPCo
|
|
|
|
|
|
|
|
|
|
|
|
As
Reported for
|
|
|
|
|
|
As
Reported for
|
|
Balance
Sheet
|
|
the
December 2007
|
|
|
FIN
39-1
|
|
|
the
June 2008
|
|
Line
Description
|
|
10-K
|
|
|
Reclassification
|
|
|
10-Q
|
|
Current
Assets:
|
|
(in
thousands)
|
Risk
Management Assets
|
|
$ |
39,893 |
|
|
$ |
(43 |
) |
|
$ |
39,850 |
|
Margin
Deposits
|
|
|
10,814 |
|
|
|
(164 |
) |
|
|
10,650 |
|
Long-term
Risk Management Assets
|
|
|
4,095 |
|
|
|
(22 |
) |
|
|
4,073 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities
|
|
|
32,668 |
|
|
|
(39 |
) |
|
|
32,629 |
|
Customer
Deposits
|
|
|
37,537 |
|
|
|
(64 |
) |
|
|
37,473 |
|
Long-term
Risk Management Liabilities
|
|
|
3,460 |
|
|
|
(126 |
) |
|
|
3,334 |
|
For
certain risk management contracts, the Registrant Subsidiaries are required to
post or receive cash collateral based on third party contractual agreements and
risk profiles. For the June 30, 2008 balance sheets, the Registrant
Subsidiaries netted collateral received from third parties against short-term
and long-term risk management assets and cash collateral paid to third parties
against short-term and long-term risk management liabilities as
follows:
|
June
30, 2008
|
|
|
Cash
Collateral
|
|
Cash
Collateral
|
|
|
Received
|
|
Paid
|
|
|
Netted
Against
|
|
Netted
Against
|
|
|
Risk
Management
|
|
Risk
Management
|
|
|
Assets
|
|
Liabilities
|
|
|
(in
thousands)
|
|
APCo
|
$ |
23,799 |
|
$ |
19,719 |
|
CSPCo
|
|
14,288 |
|
|
10,823 |
|
I&M
|
|
13,724 |
|
|
9,976 |
|
OPCo
|
|
16,688 |
|
|
21,387 |
|
PSO
|
|
1,744 |
|
|
3,101 |
|
SWEPCo
|
|
2,060 |
|
|
4,396 |
|
Future
Accounting Changes
The
FASB’s standard-setting process is ongoing and until new standards have been
finalized and issued by FASB, management cannot determine the impact on the
reporting of the Registrant Subsidiaries’ operations and financial position that
may result from any such future changes. The FASB is currently
working on several projects including revenue recognition, contingencies,
liabilities and equity, emission allowances, leases, hedge accounting, trading
inventory and related tax impacts. Management also expects to see
more FASB projects as a result of its desire to converge International
Accounting Standards with GAAP. The ultimate pronouncements resulting
from these and future projects could have an impact on future results of
operations and financial position.
EXTRAORDINARY
ITEM
APCo
recorded an extraordinary loss of $118 million ($79 million, net of tax) during
the second quarter of 2007 for the establishment of regulatory assets and
liabilities related to the Virginia generation operations. In 2000,
APCo discontinued SFAS 71 regulatory accounting for the Virginia jurisdiction
due to the passage of legislation for customer choice and
deregulation. In April 2007, Virginia passed legislation to establish
electric regulation again.
The
Registrant Subsidiaries are involved in rate and regulatory proceedings at the
FERC and their state commissions. The Rate Matters note within the
2007 Annual Report should be read in conjunction with this report to gain a
complete understanding of material rate matters still pending that could impact
results of operations, cash flows and possibly financial
condition. The following discusses ratemaking developments in 2008
and updates the 2007 Annual Report.
Ohio Rate
Matters
Ohio
Electric Security Plan Filings – Affecting CSPCo and OPCo
In April
2008, the Ohio legislature passed Senate Bill 221, which amends the
restructuring law effective July 31, 2008 and requires electric utilities to
adjust their rates by filing an Electric Security Plan
(ESP). Electric utilities may file an ESP with a fuel cost recovery
mechanism. Electric utilities also have an option to file a Market
Rate Offer (MRO) for generation pricing. A MRO, from the date of its
commencement, could transition CSPCo and OPCo to full market rates no sooner
than six years and no later than ten years. The PUCO has the
authority to approve or modify the utilities’ ESP request. The PUCO
is required to approve an ESP if, in the aggregate, the ESP is more favorable to
ratepayers than the MRO. Both alternatives involve a “substantially
excessive earnings” test based on what public companies, including other
utilities with similar risk profiles, earn on equity. Management has
preliminarily concluded, pending the issuance of final rules by the PUCO and the
outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply
operations are not subject to cost-based rate regulation
accounting. However, if a fuel cost recovery mechanism is implemented
within the ESP, CSPCo’s and OPCo’s fuel operations would be subject to
cost-based rate regulation accounting. Management is unable to
predict the financial statement impact of the restructuring legislation until
the PUCO acts on specific proposals made by CSPCo and OPCo in their
ESPs.
In July
2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to
establish rates for 2009 through 2011. CSPCo and OPCo did not file
MROs. CSPCo and OPCo each requested an annual rate increase for 2009
through 2011 that would not exceed approximately 15% per year. A
significant portion of the requested increases results from the implementation
of a fuel cost recovery mechanism that primarily includes fuel costs, purchased
power costs including mandated renewable energy, consumables such as urea, other
variable production costs and gains and losses on sales of emission
allowances. The increases in customer bills related to the fuel cost
recovery mechanism would be phased-in over the three year period from 2009
through 2011. Effective January 1, 2009, CSPCo and OPCo will defer
the fuel cost under-recoveries and related carrying costs for future recovery
over seven years from 2012 through 2018. In addition to the fuel cost
recovery mechanisms, the requested increases would also recover incremental
carrying costs associated with environmental costs, Provider of Last Resort
(POLR) charges to compensate for the risk of customers changing electric
suppliers, automatic increases for unexpected costs and reliability costs. The
filings also include programs for smart metering initiatives
and economic development and mandated energy efficiency and peak
demand reduction programs. Management expects a PUCO decision on the
ESP filings in the fourth quarter of 2008.
Within
the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $45
million and $36 million, respectively, for customer choice implementation and
line extension carrying costs. In addition, CSPCo and OPCo would
recover related unrecorded equity carrying costs of $28 million and $19 million,
respectively. Such costs would be recovered over an 8 year
period beginning January 2011. Failure of the PUCO to ultimately
approve the recovery of the regulatory assets would have an adverse effect on
future results of operations and cash flows.
2008
Generation Rider and Transmission Rider Rate Settlement – Affecting CSPCo and
OPCo
On
January 30, 2008, the PUCO approved a settlement agreement, among CSPCo, OPCo
and other parties, under the additional average 4% generation rate increase and
transmission cost recovery rider (“TCRR”) provisions of the RSP. The
increase was to recover additional governmentally-mandated costs including
incremental environmental costs. Under the settlement, the PUCO also
approved recovery through the TCRR of increased PJM costs associated with
transmission line losses of $39 million each for CSPCo and OPCo. As a
result, CSPCo and OPCo established regulatory assets in the first quarter of
2008 of $12 million and $14 million, respectively, related to the future
recovery of increased PJM billings from June 2007 to December
2007. The PUCO also approved a credit applied to the TCRR of $10
million for OPCo and $8 million for CSPCo for a reduction in PJM net congestion
costs. To the extent that collections for the TCRR items are
over/under actual net costs, CSPCo and OPCo will defer the difference and adjust
future customer billings to reflect actual costs including carrying costs on the
unrecovered deferral. Under the terms of the settlement, although the
increased PJM costs associated with transmission line losses will be recovered
through the TCRR, these recoveries will still be applied to reduce the annual
average 4% generation rate increase limitation. In addition, the PUCO
approved recoveries through generation rates of environmental costs and related
carrying costs of $29 million for CSPCo and $5 million for
OPCo. These RSP rate adjustments were implemented in February
2008.
In
February 2008, Ormet, a major industrial customer, filed a motion to intervene
and an application for rehearing of the PUCO’s January 2008 RSP order claiming
the settlement inappropriately shifted $4 million in cost recovery to
Ormet. In March 2008, the PUCO granted Ormet’s motion to
intervene. Ormet’s rehearing application also was granted for the
purpose of providing the PUCO with additional time to consider the issues raised
by Ormet. Management cannot predict the outcome of this rehearing
process.
Ohio
IGCC Plant – Affecting CSPCo and OPCo
In March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of
cost recovery associated with the IGCC plant: Phase 1, recovery of
$24 million in pre-construction costs; Phase 2, concurrent recovery of
construction-financing costs; and Phase 3, recovery or refund in distribution
rates of any difference between the generation rates which may be a market-based
standard service offer price for generation and the expected higher cost of
operating and maintaining the plant, including a return on and return of the
projected cost to construct the plant.
In June
2006, the PUCO issued an order approving a tariff to allow CSPCo and OPCo to
recover Phase 1 pre-construction costs over a period of no more than twelve
months effective July 1, 2006. During that period CSPCo and OPCo each
collected $12 million in pre-construction costs.
The order
also provided that if CSPCo and OPCo have not commenced a continuous course of
construction of the proposed IGCC plant within five years of the June 2006 PUCO
order, all Phase 1 costs associated with items that may be utilized in projects
at other sites, must be refunded to Ohio ratepayers with
interest. The PUCO deferred ruling on cost recovery for Phases 2 and
3 pending further hearings.
In August
2006, intervenors filed four separate appeals of the PUCO’s order in the IGCC
proceeding. In March 2008, the Ohio Supreme Court issued its opinion
affirming in part, and reversing in part the PUCO’s order and remanded the
matter back to the PUCO. The Ohio Supreme Court held that while there
could be an opportunity under existing law to recover a portion of the IGCC
costs in distribution rates, traditional rate making procedures would apply to
the recoverable portion. The Ohio Supreme Court did not address the
matter of refunding the Phase 1 cost recovery and declined to create an
exception to its precedent of denying claims for refund of past recoveries from
approved orders of the PUCO.
Recent
estimates of the cost to build the proposed IGCC plant are approximately $2.7
billion. Management continues to pursue the ultimate construction of
the IGCC plant. However, in light of the Ohio Supreme Court’s
decision, CSPCo and OPCo will not start construction of the IGCC plant until
sufficient assurance of cost recovery exists. If CSPCo and OPCo were
required to refund the $24 million collected and those costs were not
recoverable in another jurisdiction in connection with the construction of an
IGCC plant, it would have an adverse effect on future results of operations and
cash flows.
Ormet
– Affecting CSPCo and OPCo
Effective
January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial
customer with a 520 MW load, in accordance with a settlement agreement approved
by the PUCO. The settlement agreement allows for the recovery in 2007
and 2008 of the difference between the $43 per MWH Ormet pays for power and a
PUCO-approved market price, if higher. The PUCO approved a $47.69 per
MWH market price for 2007 and the difference was recovered through the
amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo)
excess deferred tax regulatory liability resulting from an Ohio franchise tax
phase-out recorded in 2005.
CSPCo and
OPCo each amortized $5 million of this regulatory liability to income for the
six months ended June 30, 2008 based on the previously approved 2007 price of
$47.69 per MWH. In December 2007, CSPCo and OPCo submitted for
approval a market price of $53.03 per MWH for 2008. The PUCO has not
yet approved the increase. If the PUCO approves a market price for
2008 below $47.69, it could have an adverse effect on future results of
operations and cash flows. A price above $47.69 should result in a
favorable effect. If CSPCo and OPCo serve the Ormet load after 2008
without any special provisions, they could experience incremental costs to
acquire additional capacity to meet their reserve requirements and/or forgo more
profitable market priced off-system sales.
Virginia Rate
Matters
Virginia
Base Rate Filing – Affecting APCo
In May
2008, APCo filed an application with the Virginia SCC to increase its base rates
by $208 million on an annual basis. The requested increase is based
upon a calendar 2007 test year adjusted for changes in revenues, expenses, rate
base and capital structure through June 2008 which is consistent with the
ratemaking treatment adopted by the Virginia SCC in APCo’s 2006 base rate
case. The proposed revenue requirement reflects a return on equity of
11.75%. The Virginia SCC ordered hearings to begin in October
2008. As permitted under Virginia law, APCo plans to implement these
new base rates, subject to refund, effective October 28, 2008 if the Virginia
SCC fails to make a decision by that date.
Virginia
E&R Costs Recovery Filing – Affecting APCo
As of
June 30, 2008, APCo has $97 million of deferred Virginia incremental E&R
costs. Currently APCo is recovering $16 million of the deferral for
incremental costs incurred through September 30, 2006. In May 2008,
APCo filed for recovery of deferred incremental E&R costs incurred from
October 1, 2006 through December 31, 2007 which totals $50
million. The remaining deferral will be requested in a 2009
filing. As of June 30, 2008, APCo has $22 million of unrecorded
E&R equity carrying costs of which $7 million should increase 2008 annual
earnings as collected. In connection with the 2009 filing, the
Virginia SCC will determine the level of incremental E&R costs being
collected in base revenues since October 2006 that APCo has estimated to be $48
million annually. If the Virginia SCC were to determine that these
recovered base revenues are in excess of $48 million a year, it would require
that the E&R deferrals be reduced by the excess amount, thus adversely
affecting future earnings and cash flows.
In July
2008, the Old Dominion Committee for Fair Utility Rates (ODC) filed a motion to
dismiss the E&R filing based on ODC’s belief that the opportunity to collect
E&R surcharges expires December 31, 2008. A dismissal would not
eliminate APCo’s ability to request for future recovery of its deferred E&R
costs. APCo filed a response requesting the Virginia SCC to deny
ODC’s motion. If the Virginia SCC were to disallow any additional
portion of APCo’s deferral, it would also have an adverse effect on future
results of operations and cash flows. If the outstanding request for
E&R recovery is approved it will have a favorable effect on future cash
flows.
Virginia
Fuel Clause Filings – Affecting APCo
In July
2007, APCo filed an application with the Virginia SCC to seek an annualized
increase, effective September 1, 2007, of $33 million for fuel costs and sharing
of off-system sales.
In
February 2008, the Virginia SCC issued an order that approved a reduced fuel
factor effective with the February 2008 billing cycle. The order
terminated the off-system sales margin rider and approved a 75%-25% sharing of
off-system sales margins between customers and APCo effective September 1, 2007
as required by the re-regulation legislation in Virginia. The order
also allows APCo to include in its monthly under/over recovery deferrals the
Virginia jurisdictional share of PJM transmission line loss costs from June 2007
to June 2008 which totaled $28 million. The adjusted factor increases
annual revenues by $4 million. The order authorized the Virginia SCC
staff and other parties to make specific recommendations to the Virginia SCC in
APCo’s next fuel factor proceeding to ensure accurate assignment of the
prudently incurred PJM transmission line loss costs to APCo’s Virginia
jurisdictional operations. Management believes the incurred PJM
transmission line loss costs are prudently incurred and are being properly
assigned to APCo’s Virginia jurisdictional operations.
In
February 2008, the Old Dominion Committee for Fair Utility Rates (ODC) filed a
notice of appeal to the Supreme Court of Virginia appealing the Virginia SCC’s
decisions regarding off-system sales margins and PJM transmission line loss
costs. In May 2008, the ODC withdrew its appeal.
In July
2008, APCo filed its next fuel factor proceeding with the Virginia SCC and
requested an annualized increase of $132 million effective September 1,
2008. The increase primarily relates to increases in coal
costs.
If costs
included in APCo’s Virginia fuel under/over recovery deferrals are disallowed,
it could result in an adverse effect on future results of operations and cash
flows.
APCo’s
Virginia SCC Filing for an IGCC Plant – Affecting APCo
In July
2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to
recover initial costs associated with a proposed 629 MW IGCC plant to be
constructed in Mason County, West Virginia adjacent to APCo’s existing
Mountaineer Generating Station for an estimated cost of $2.2
billion. The filing requested recovery of an estimated $45 million
over twelve months beginning January 1, 2009 including a return on projected
CWIP and development, design and planning pre-construction costs incurred from
July 1, 2007 through December 31, 2009. APCo also requested
authorization to defer a return on deferred pre-construction costs incurred
beginning July 1, 2007 until such costs are recovered. Through June
30, 2008, APCo has deferred for future recovery pre-construction IGCC costs of
$9 million allocated to Virginia jurisdictional operations. The rate
adjustment clause provisions of the 2007 re-regulation legislation provides for
full recovery of all costs of this type of new clean coal technology including
recovery of an enhanced return on equity.
The
Virginia SCC issued an order in April 2008 denying APCo’s requests stating the
belief that the estimated cost may be significantly understated. The
Virginia SCC also expressed concern that the $2.2 billion estimated cost did not
include a retrofitting of carbon capture and sequestration
facilities. In April 2008, APCo filed a petition for reconsideration
in Virginia. In May 2008, the Virginia SCC denied APCo’s request to
reconsider its previous ruling. In July 2008, the IRS awarded $134
million in future tax credits for the IGCC plant. Management
continues to pursue the ultimate construction of the IGCC plant; however, APCo
will not start construction of the IGCC plant until sufficient assurance of cost
recovery exists. If the plant is canceled, APCo plans to seek
recovery of its prudently incurred deferred pre-construction
costs. If the plant is canceled and the deferred costs are not
recoverable, it would have an adverse effect on future results of operations and
cash flows.
West Virginia Rate
Matters
APCo’s
2008 Expanded Net Energy Cost (ENEC) Filing – Affecting APCo
In
February 2008, APCo filed for an increase of approximately $140 million
including a $122 million increase in the ENEC, a $15 million increase in
construction cost surcharges and $3 million of reliability expenditures, to
become effective July 2008. In June 2008, the WVPSC issued an order
approving a joint stipulation and settlement agreement granting an increase,
effective July 2008, of approximately $95 million, including a $79 million
increase in the ENEC, a $13 million increase in construction cost surcharges and
$3 million of reliability expenditures. The ENEC is an expanded form
of fuel clause mechanism, which includes all energy-related costs including
fuel, purchased power expenses, off-system sales credits, PJM costs associated
with transmission line losses due to the implementation of marginal loss pricing
and other energy/transmission items.
The ENEC
is subject to a true up to actual costs and should have no earnings effect due
to the deferral of any over/under-recovery of actual ENEC costs. The
construction cost and reliability surcharges are not subject to a true up to
actual costs and could result in an adverse under recovery.
APCo’s
West Virginia IGCC Plant Filing – Affecting APCo
In
January 2006, APCo filed a petition with the WVPSC requesting its approval of a
Certificate of Public Convenience and Necessity (CCN) to construct a 629 MW IGCC
plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
County, West Virginia.
In June
2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and
for pre-approval of a surcharge rate mechanism to provide for the timely
recovery of both pre-construction costs and the ongoing finance costs of the
project during the construction period as well as the capital costs, operating
costs and a return on equity once the facility is placed into commercial
operation. In March 2008, the WVPSC granted APCo the CCN to build the
plant and the request for cost recovery. Various intervenors filed
petitions with the WVPSC to reconsider the order. At the time of the
filing, the cost of the plant was estimated at $2.2 billion. In July
2008, based on the order received in Virginia, the WVPSC issued a notice seeking
comments from parties on how the WVPSC should proceed (See the “APCo’s Virginia
SCC Filing for an IGCC Plant” section above). Through June 30, 2008,
APCo deferred for future recovery pre-construction IGCC costs of $8 million
applicable to the West Virginia jurisdiction and $2 million applicable to the
FERC jurisdiction. In July 2008, the
IRS awarded $134 million in future tax credits for the IGCC
plant. Management continues to pursue the ultimate construction of
the IGCC plant; however, APCo will not start construction of the IGCC plant
until sufficient assurance of cost recovery exists. If the plant is
canceled, APCo plans to seek recovery of its prudently incurred deferred
pre-construction costs. If the plant is canceled and the deferred
costs are not recoverable, it would have an adverse effect on future results of
operations and cash flows.
Indiana Rate
Matters
Indiana
Rate Filing – Affecting I&M
In a
January 2008 filing with the IURC, updated in the second quarter of 2008,
I&M requested an increase in its Indiana base rates of $80 million including
a return on equity of 11.5%. The base rate increase includes the
$69 million annual reduction in depreciation expense previously approved by the
IURC and implemented for accounting purposes effective June 2007. The
depreciation reduction will no longer favorably impact earnings if and when
tariff rates are revised to reflect the reduction. The filing
requests trackers for certain variable components of the cost of service
including recently increased PJM costs associated with transmission line losses
due to the implementation of marginal loss pricing and other RTO costs,
reliability enhancement costs, demand side management/energy efficiency costs,
off-system sales margins and environmental compliance
costs. The trackers would initially increase annual revenues by an
additional $45 million. I&M proposes to share with ratepayers,
through a tracker, 50% of off-system sales margins initially estimated to be $96
million annually with a guaranteed credit to customers of $20
million. A decision is expected from the IURC by June
2009.
Oklahoma Rate
Matters
PSO
Fuel and Purchased Power and its Possible Impact on AEP East companies and AEP
West companies
In 2004,
intervenors and the OCC staff argued that AEP had inappropriately under
allocated off-system sales credits to PSO by $37 million for the period June
2000 to December 2004 under a FERC-approved allocation agreement. An
ALJ assigned to hear intervenor claims found that the OCC lacked authority to
examine whether AEP deviated from the FERC-approved allocation methodology for
off-system sales margins and held that any such complaints should be addressed
at the FERC. In October 2007, the OCC adopted the ALJ’s
recommendation and orally directed the OCC staff to explore filing a complaint
at FERC alleging the allocation of off-system sales margins to PSO is not in
compliance with the FERC-approved methodology which could result in an adverse
effect on future results of operations and cash flows for AEP Consolidated and
the AEP East companies. In June 2008, the ALJ issued a final
recommendation and incorporated the prior finding that the OCC lacked authority
to review AEP’s application of a FERC-approved methodology. The OCC
is scheduled to consider the final recommendation in August 2008. To
date, no claim has been asserted at the FERC and management continues to believe
that the allocation is consistent with the FERC-approved agreement.
In
February 2006, the OCC enacted a rule, requiring the OCC staff to conduct
prudence reviews on PSO’s generation and fuel procurement processes, practices
and costs on a periodic basis. PSO filed testimony in June 2007
covering a prudence review for the year 2005. The OCC staff and intervenors
filed testimony in September 2007, and hearings were held in November
2007. The only major issue in the proceeding was the alleged
under allocation of off-system sales credits under the FERC-approved allocation
methodology, which was determined not to be jurisdictional to the
OCC. Consistent with her prior recommendation, the ALJ found that the
OCC lacked authority to alter the FERC-approved methodology and that PSO’s fuel
costs were prudent. The OCC is scheduled to consider the ALJ’s findings and rule
in August 2008.
In
November 2007, PSO filed testimony in another proceeding to address its fuel
costs for 2006. In April 2008, intervenor testimony was filed again
challenging the allocation of off-system sales credits during the portion of the
year when the allocation was in effect. Hearings were held in July
2008 and the OCC changed the scope of the proceeding from a prudence review to
only a review of the mechanics of the fuel cost calculation. No party
contested PSO’s fuel cost calculation and an order is expected in August
2008.
Management
cannot predict the outcome of the pending fuel and purchased power cost recovery
filings and prudence reviews or whether a complaint will be filed at FERC
regarding the off-system sales allocation issue. However, PSO
believes its fuel and purchased power procurement practices and costs were
prudent and properly incurred and that it allocated off-system sales credits
consistent with governing FERC-approved agreements. If a complaint is
filed at FERC resulting in an unfavorable decision, it could have an adverse
effect on results of operations and cash flows.
Red
Rock Generating Facility – Affecting PSO
In July
2006, PSO announced an agreement with Oklahoma Gas and Electric Company
(OG&E) to build a 950 MW pulverized coal ultra-supercritical generating
unit. PSO would own 50% of the new unit. Under the
agreement, OG&E would manage construction of the plant. OG&E
and PSO requested preapproval to construct the Red Rock Generating Facility and
to implement a recovery rider.
In
October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of
additional capacity by the year 2012, but rejected the ALJ’s recommendation and
denied PSO’s and OG&E’s applications for construction
preapproval. The OCC stated that PSO failed to fully study other
alternatives to a coal-fired plant. Since PSO and OG&E could not
obtain preapproval to build the coal-fired Red Rock Generating Facility, PSO and
OG&E canceled the third party construction contract and their joint venture
development contract. PSO has issued a request-for-proposal to meet
its capacity and energy needs.
In
December 2007, PSO filed an application at the OCC requesting recovery of the
$21 million in pre-construction costs and contract cancellation fees associated
with Red Rock. In March 2008, PSO and all other parties in this
docket signed a settlement agreement that provides for recovery of $11 million
of Red Rock costs, and provides carrying costs at PSO’s AFUDC rate beginning in
March 2008 and continuing until the $11 million is included in PSO’s next base
rate case. PSO will recover the costs over the expected life of the
peaking facilities at the Southwestern Station, and include the costs in rate
base beginning in its next base rate filing. The settlement was filed
with the OCC in March 2008. The OCC approved the settlement in May
2008. As a result of the settlement, PSO wrote off $10 million of its
deferred pre-construction costs/cancellation fees in the first quarter of
2008.
Oklahoma
2007 Ice Storms – Affecting PSO
In
October 2007, PSO filed with the OCC requesting recovery of $13 million of
operation and maintenance expense related to service restoration efforts after a
January 2007 ice storm. PSO proposed in its application to establish
a regulatory asset of $13 million to defer the previously expensed January 2007
ice storm restoration costs and to amortize the regulatory asset coincident with
gains from the sale of excess SO2 emission
allowances. In December 2007, PSO expensed approximately $70 million
of additional storm restoration costs related to another ice storm in December
2007.
In
February 2008, PSO entered into a settlement agreement for recovery of costs
from both ice storms. In March 2008, the OCC approved the settlement
subject to an audit of the final December ice storm costs filed in July
2008. As a result, PSO recorded an $81 million regulatory asset for ice storm
maintenance expenses and related carrying costs less $9 million of amortization
expense to offset recognition of deferred gains from sales of SO2 emission
allowances. Under the settlement agreement, PSO would apply proceeds
from sales of excess SO2 emission
allowances of an estimated $26 million to recover part of the ice storm
regulatory asset. PSO will amortize and recover the remaining amount
of the regulatory asset through a rider over a period of five years beginning in
the fourth quarter of 2008. The regulatory asset will earn a return
of 10.92% on the unrecovered balance.
In June
2008, PSO adjusted its regulatory asset to true-up the estimated costs to
reflect actual costs as of June 30, 2008. After the true-up,
application of proceeds from to-date sales of excess SO2 emission
allowances and carrying costs, the ice storm regulatory asset as of June 30,
2008 was $64 million. In July 2008, PSO filed with the OCC
to establish the recovery rider and the final recoverable December 2007 ice
storm costs. The estimate of future gains from the sale of SO2 emission
allowances has significantly declined with the decrease in value of such
allowances. As a result, estimated collections from customers through
the special storm damage recovery rider will be higher than the estimate in the
settlement agreement. Nonetheless, management believes that the
settlement provides for full recovery of the remaining deferral.
2008
Oklahoma Annual Fuel Factor Filing – Affecting PSO
In May
2008, pursuant to its tariff, PSO filed its annual update with the OCC for
increases in the various service level fuel factors based on estimated increases
in fuel, primarily natural gas and purchased power expenses, of approximately
$300 million. The request included recovery of $26 million in
under-recovered deferred fuel. In June 2008, PSO implemented the fuel
factor increase. Because of the substantial increase, the OCC held an
administrative proceeding to determine whether the proposed charges were based
upon the appropriate coal, purchased gas and purchased power prices and were
properly computed. In June 2008, the OCC ordered that PSO properly
estimated the increase in natural gas prices, properly determined its fuel costs
and, thus, should implement the increase.
2008
Oklahoma Base Rate Filing – Affecting PSO
In July
2008, PSO filed an application with the OCC to increase its base rates by $133
million on an annual basis. PSO recovers costs related to new peaking
units recently placed into service through the Generation Cost Recovery Rider
(GCRR). Upon implementation of the new base rates, PSO will recover
these costs through the new base rates and the GCRR will
terminate. Therefore, PSO’s net annual requested increase in total
revenues is $117 million. The requested increase is based upon a test
year ended February 29, 2008, adjusted for known and measurable changes through
August 2008, which is consistent with the ratemaking treatment adopted by the
OCC in PSO’s 2006 base rate case. The proposed revenue requirement
reflects a return on equity of 11.25%. PSO expects hearings to begin
in December 2008 and new rates effective in the first quarter of
2009.
Louisiana Rate
Matters
Louisiana
Compliance Filing – Affecting SWEPCo
In
connection with SWEPCo’s merger related compliance filings, the LPSC approved a
settlement agreement in April 2008 that prospectively resolves all issues
regarding claims that SWEPCo had over-earned its allowed
return. SWEPCo agreed to a formula rate plan (FRP) with a three-year
term. Beginning August 2008, rates shall be established to allow
SWEPCo to earn an adjusted return on common equity of 10.565%. The
adjustments are standard Louisiana rate filing adjustments.
If in the
second and third year of the FRP, the adjusted earned return is within the range
of 10.015% to 11.115%, no adjustment to rates is necessary. However,
if the adjusted earned return is outside of the above-specified range, an FRP
rider will be established to increase or decrease rates
prospectively. If the adjusted earned return is less than 10.015%,
SWEPCo will prospectively increase rates to collect 60% of the difference
between 10.565% and the adjusted earned return. Alternatively, if the
adjusted earned return is more than 11.115%, SWEPCo will prospectively decrease
rates by 60% of the difference between the adjusted earned return and
10.565%. SWEPCo will not record over/under recovery deferrals for
refund or future recovery under this FRP.
The
settlement provides for a separate credit rider decreasing Louisiana retail base
rates by $5 million prospectively over the entire three year term of the FRP,
which shall not affect the adjusted earned return in the FRP
calculation. This separate credit rider will cease effective August
2011.
In
addition, the settlement provides for a reduction in generation depreciation
rates effective October 2007. SWEPCo will defer as a regulatory
liability, the effects of the expected depreciation reduction through July
2008. SWEPCo will amortize this regulatory liability over the three
year term of the FRP as a reduction to the cost of service used to determine the
adjusted earned return.
In April
2008, SWEPCo filed the first FRP which would increase its annual Louisiana
retail rates by $11 million in August 2008 to earn an adjusted return on common
equity of 10.565%. In June 2008, SWEPCo recorded a $3 million
regulatory liability related to the reduction in generation depreciation
rates.
Stall
Unit – Affecting SWEPCo
In May
2006, SWEPCo announced plans to build a new intermediate load 500 MW natural
gas-fired combustion turbine combined cycle generating unit (the Stall Unit) at
its existing Arsenal Hill Plant location in Shreveport,
Louisiana. SWEPCo submitted the appropriate filings to the PUCT, the
APSC, the LPSC and the Louisiana Department of Environmental Quality to seek
approvals to construct the unit. The Stall Unit is estimated to cost
$378 million, excluding AFUDC, and is expected to be in-service in
mid-2010.
In March
2007, the PUCT approved SWEPCo’s request for a certificate for the facility
based on a prior cost estimate. In February 2008, the LPSC staff
submitted testimony in support of the Stall Unit and one intervenor submitted
testimony opposing the Stall Unit due to the increase in cost. The
LPSC held hearings in April 2008. In July 2008, an ALJ in the LPSC
proceeding recommended approval of the Stall Unit. The APSC has not
established a procedural schedule at this time. The Louisiana
Department of Environmental Quality issued an air permit for the unit in March
2008. If SWEPCo does not receive appropriate authorizations and
permits to build the Stall Unit, SWEPCo would seek recovery of the capitalized
pre-construction costs including any cancellation fees. As of June
30, 2008, SWEPCo has capitalized pre-construction costs of $106 million and has
contractual construction commitments of an additional $191
million. As of June 30, 2008, if the plant had been canceled,
cancellation fees of $60 million would have been required in order to terminate
these construction commitments. If SWEPCo canceled the plant and
cannot recover its capitalized costs, including any cancellation fees, it would
have an adverse effect on future results of operations and cash
flows.
Turk
Plant – Affecting SWEPCo
See “Turk
Plant” section within Arkansas Rate Matters for disclosure.
Arkansas Rate
Matters
Turk
Plant – Affecting SWEPCo
In
August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600
MW pulverized coal ultra-supercritical generating unit in
Arkansas. Ultra-supercritical technology uses higher temperatures and
higher pressures to produce electricity more efficiently – thereby using less
fuel and providing substantial emissions reductions. SWEPCo submitted
filings with the APSC, the PUCT and the LPSC seeking certification of the
plant. SWEPCo will own 73% of the Turk Plant and will operate the
facility. During 2007, SWEPCo signed joint ownership agreements with
the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative
Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the
remaining 27% of the Turk Plant. The Turk Plant is estimated to cost
$1.5 billion with SWEPCo’s portion estimated to cost $1.1 billion, excluding
AFUDC. If approved on a timely basis, the plant is expected to be
in-service in 2012.
In
November 2007, the APSC granted approval to build the plant. Certain
landowners filed a notice of appeal to the Arkansas State Court of
Appeals. In March 2008, the LPSC approved the application to
construct the Turk Plant. In July 2008, the PUCT approved a
certificate of convenience and necessity for construction of the
plant. We expect a written order in August 2008 which will also
provide for the conditions of the PUCT’s approval.
SWEPCo is
working with the Arkansas Department of Environmental Quality and the U.S. Army
Corps of Engineers for approval later this year. A request to stop
pre-construction activities at the site was filed in Federal court by the same
Arkansas landowners who appealed the APSC decision to the Arkansas State Court
of Appeals. In July 2008, the Federal court denied the request and
the Arkansas landowners appealed the denial to the U.S. Court of
Appeals.
If SWEPCo
does not receive appropriate authorizations and permits to build the Turk Plant,
SWEPCo could incur significant cancellation fees to terminate its commitments
and would be responsible to reimburse OMPA, AECC and ETEC for their share of
paid costs. If that occurred, SWEPCo would seek recovery of its
capitalized costs including any cancellation fees and joint owner
reimbursements. As of June 30, 2008, including the joint owners’
share, SWEPCo has capitalized approximately $407 million of expenditures and has
significant contractual construction commitments for an additional $815
million. As of June 30, 2008, if the plant had been canceled,
cancellation fees of $60 million would have been required in order to terminate
these construction commitments. If SWEPCo cannot recover its costs,
it would have an adverse effect on future results of operations, cash flows and
possibly financial condition.
Stall
Unit – Affecting SWEPCo
See
“Stall Unit” section within Louisiana Rate Matters for disclosure.
FERC Rate
Matters
Regional
Transmission Rate Proceedings at the FERC – Affecting APCo, CSPCo, I&M and
OPCo
SECA Revenue Subject to
Refund
Effective
December 1, 2004, AEP eliminated transaction-based through-and-out transmission
service (T&O) charges in accordance with FERC orders and collected at FERC’s
direction load-based charges, referred to as RTO SECA, to partially mitigate the
loss of T&O revenues on a temporary basis through March 31,
2006. Intervenors objected to the temporary SECA rates, raising
various issues. As a result, the FERC set SECA rate issues for
hearing and ordered that the SECA rate revenues be collected, subject to
refund. The AEP East companies paid SECA rates to other utilities at
considerably lesser amounts than they collected. If a refund is
ordered, the AEP East companies would also receive refunds related to the SECA
rates they paid to third parties. The AEP East companies recognized
gross SECA revenues of $220 million from December 2004 through March 2006 when
the SECA rates terminated leaving the AEP East companies and ultimately their
internal load customers to make up the short fall in
revenues. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of
recognized gross SECA revenues are as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
70.2
|
|
CSPCo
|
|
|
38.8
|
|
I&M
|
|
|
41.3
|
|
OPCo
|
|
|
53.3
|
|
In August
2006, a FERC ALJ issued an initial decision, finding that the rate design for
the recovery of SECA charges was flawed and that a large portion of the “lost
revenues” reflected in the SECA rates should not have been
recoverable. The ALJ found that the SECA rates charged were
unfair, unjust and discriminatory and that new compliance filings and refunds
should be made. The ALJ also found that the unpaid SECA rates must be
paid in the recommended reduced amount.
In
September 2006, AEP filed briefs jointly with other affected companies noting
exceptions to the ALJ’s initial decision and asking the FERC to reverse the
decision in large part. Management believes that the FERC should
reject the ALJ’s initial decision because it contradicts prior related FERC
decisions, which are presently subject to rehearing. Furthermore,
management believes the ALJ’s findings on key issues are largely without
merit. As a result, SECA ratepayers have been willing to engage with
AEP in settlement discussions. AEP has been engaged in settlement
discussions in an effort to settle the SECA issue. However, if the
ALJ’s initial decision is upheld in its entirety, it could result in a
disallowance of a large portion on any unsettled SECA revenues.
During
2006, the AEP East companies provided reserves of $37 million for net refunds
for current and future SECA settlements. After reviewing existing
settlements, the AEP East companies increased their reserves by an additional $5
million in December 2007. APCo’s, CSPCo’s, I&M’s and OPCo’s
portions of the provision are as follows:
|
|
2007
|
|
|
2006
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
$ |
1.7 |
|
|
$ |
12.0 |
|
CSPCo
|
|
|
0.9 |
|
|
|
6.7 |
|
I&M
|
|
|
1.0 |
|
|
|
7.0 |
|
OPCo
|
|
|
1.3 |
|
|
|
9.1 |
|
Completed
and in-process settlements cover $107 million of the $220 million of SECA
revenues and will consume about $7 million of the reserve for refund, leaving
approximately $113 million of contested SECA revenues and $35 million of refund
reserves.
If the
FERC adopts the ALJ’s decision and/or AEP cannot settle the remaining unsettled
claims within the amount reserved for refunds, it will have an adverse effect on
future results of operations and cash flows. Based on advice of external FERC
counsel, recent settlement experience and the expectation that most of the
unsettled SECA revenues will be settled, management believes that the remaining
reserve of $35 million is adequate to cover all remaining
settlements. However, management cannot predict the ultimate outcome
of ongoing settlement discussions or future FERC proceedings or court appeals,
if such are necessary.
The FERC PJM Regional
Transmission Rate Proceeding
With the
elimination of T&O rates and the expiration of SECA rates and after
considerable administrative litigation at the FERC in which AEP sought to
mitigate the effect of T&O rate elimination, the FERC failed to implement a
regional rate in PJM. As a result, the AEP East companies’ retail
customers incur the bulk of the cost of the existing AEP east transmission zone
facilities. However, the FERC ruled that the cost of any new 500 kV
and higher voltage transmission facilities built in PJM would be shared by all
customers in the region. It is expected that most of the new 500 kV
and higher voltage transmission facilities will be built in other zones of PJM,
not AEP’s zone. The AEP East companies will need to obtain regulatory
approvals for recovery of any costs of new facilities that are assigned to
them. AEP had requested rehearing of this order, which the FERC
denied. In February 2008, AEP filed a Petition for Review of the FERC
orders in this case in the United States Court of Appeals. Management
cannot estimate at this time what effect, if any, this order will have on the
AEP East companies’ future construction of new transmission facilities, results
of operations and cash flows.
The AEP
East companies filed for and in 2006 obtained increases in its wholesale
transmission rates to recover lost revenues previously applied to reduce those
rates. AEP has also sought and received retail rate increases in
Ohio, Virginia, West Virginia and Kentucky. As a result, AEP is now
recovering approximately 85% of the lost T&O transmission
revenues. AEP received net SECA transmission revenues of $128 million
in 2005. I&M requested recovery of these lost revenues in its
Indiana rate filing in January 2008 but does not expect to commence recovering
the new rates until early 2009. Future results of operations and cash
flows will continue to be adversely affected in Indiana and Michigan until the
remaining 15% of the lost T&O transmission revenues are recovered in retail
rates.
The FERC PJM and MISO
Regional Transmission Rate Proceeding
In the
SECA proceedings, the FERC ordered the RTOs and transmission owners in the
PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to
establish a permanent transmission rate design for the Super Region to be
effective February 1, 2008. All of the transmission owners in PJM and
MISO, with the exception of AEP and one MISO transmission owner, elected to
support continuation of zonal rates in both RTOs. In September 2007,
AEP filed a formal complaint proposing a highway/byway rate design be
implemented for the Super Region where users pay based on their use of the
transmission system. AEP argues the use of other PJM and MISO
facilities by AEP is not as large as the use of AEP transmission by others in
PJM and MISO. Therefore, a regional rate design change is required to
recognize that the provision and use of transmission service in the Super Region
is not sufficiently uniform between transmission owners and users to justify
zonal rates. In January 2008, the FERC denied AEP’s
complaint. AEP filed a rehearing request with the FERC in March
2008. Should this effort be successful, earnings could benefit for a
certain period due to regulatory lag; however, AEP East companies would reduce
future retail revenues in their next fuel or base rate
proceedings. Management is unable to predict the outcome of this
case.
PJM
Transmission Formula Rate Filing – Affecting APCo, CSPCo, I&M and
OPCo
In July
2008, AEP filed an application with the FERC to increase its rates for
wholesale transmission service within PJM. The filing seeks to
implement a formula rate allowing annual adjustments reflecting future changes
in AEP's cost of service. The requested increase would result in
additional annual revenues of approximately $9 million from nonaffiliated
customers within PJM. AEP requested an effective date of
October 1, 2008. Retail rates are not immediately affected by the
filing at the FERC, but retail rates in Ohio would reflect the revised
FERC transmission rate through the Transmission Cost Recovery Rider (TCRR)
effective January 2009 resulting in additional annual revenues of approximately
$22 million. Management is unable to predict the outcome of this
filing.
SPP
Transmission Formula Rate Filing – Affecting PSO and SWEPCo
In June
2007, AEPSC filed revised tariffs to establish an up-to-date revenue requirement
for SPP transmission services over the facilities owned by PSO and SWEPCo and to
implement a transmission cost of service formula rate. PSO and SWEPCo
requested an effective date of September 1, 2007 for the revised
tariff. If approved as filed, the revised tariff will increase annual
network transmission service revenues from nonaffiliated municipal and rural
cooperative utilities in the AEP pricing zone of SPP by approximately $10
million. In August 2007, the FERC issued an order conditionally
accepting PSO’s and SWEPCo’s proposed formula rate, subject to a compliance
filing, suspended the effective date until February 1, 2008 and established a
hearing schedule and settlement judge proceedings. New rates, subject
to refund, were implemented in February 2008. Multiple intervenors
have protested or requested re-hearing of the order and settlement discussions
are underway. Management believes it has recognized the appropriate
amount of revenues, subject to refund, since implemented in February
2008. Management is unable to
predict the outcome of this proceeding.
FERC
Market Power Mitigation – Affecting APCo, CSPCo, I&M and OPCo
The FERC
allows utilities to sell wholesale power at market-based rates if they can
demonstrate that they lack market power in the markets in which they
participate. Sellers with market rate authority must, at least every
three years, update their studies demonstrating lack of market
power. In December 2007, AEP filed its most recent triennial
update. In March and May 2008, the PUCO filed comments suggesting
that the FERC should further investigate whether AEP continues to pass the
FERC’s indicative screens for the lack of market power in
PJM. Certain industrial retail customers also urged the FERC to
further investigate this matter. AEP responded that its market power
studies were performed in accordance with the FERC’s guidelines, and continue to
demonstrate lack of market power. Management is unable to predict the
outcome of this proceeding; however, if a further investigation by the FERC
limited AEP’s ability to sell power at market based rates in PJM, it would
result in an adverse effect on future off-system sales margins, results of
operations and cash flows.
4.
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES
|
The
Registrant Subsidiaries are subject to certain claims and legal actions arising
in their ordinary course of business. In addition, their business
activities are subject to extensive governmental regulation related to public
health and the environment. The ultimate outcome of such pending or
potential litigation cannot be predicted. For current proceedings not
specifically discussed below, management does not anticipate that the
liabilities, if any, arising from such proceedings would have a material adverse
effect on the financial statements. The Commitments, Guarantees and
Contingencies note within the 2007 Annual Report should be read in conjunction
with this report.
GUARANTEES
There is
no collateral held in relation to any guarantees. In the event any
guarantee is drawn, there is no recourse to third parties unless specified
below.
Letters
of Credit
Certain
Registrant Subsidiaries enter into standby letters of credit (LOCs) with third
parties. These LOCs cover items such as insurance programs, security
deposits and debt service reserves. These LOCs were issued in the
Registrant Subsidiaries’ ordinary course of business under the two $1.5 billion
credit facilities.
In April
2008, the Registrant Subsidiaries and certain other companies in the AEP System
entered into a $650 million 3-year credit agreement and a $350 million 364-day
credit agreement. As of June 30, 2008, $371 million of letters of
credit were issued by Registrant Subsidiaries under the 3-year credit agreement
to support variable rate demand notes.
At June
30, 2008, the maximum future payments of the LOCs were as follows:
|
|
|
|
|
|
Borrower
|
Company
|
|
Amount
|
|
Maturity
|
|
Sublimit
|
|
|
(in
thousands)
|
|
|
|
|
|
$1.5
billion LOC:
|
|
|
|
|
|
|
|
|
I&M
|
|
$
|
1,113
|
|
March
2009
|
|
|
N/A
|
SWEPCo
|
|
|
4,000
|
|
December
2008
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
$650
million LOC:
|
|
|
|
|
|
|
|
|
APCo
|
|
$
|
126,717
|
|
June
2009
|
|
$
|
300,000
|
I&M
|
|
|
77,886
|
|
May
2009
|
|
|
230,000
|
OPCo
|
|
|
166,899
|
|
June
2009
|
|
|
400,000
|
Guarantees
of Third-Party Obligations
SWEPCo
As part
of the process to receive a renewal of a Texas Railroad Commission permit for
lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of
approximately $65 million. Since SWEPCo uses self-bonding, the
guarantee provides for SWEPCo to commit to use its resources to complete the
reclamation in the event the work is not completed by Sabine Mining Company
(Sabine), an entity consolidated under FIN 46R. This guarantee ends
upon depletion of reserves and completion of final reclamation. Based
on the latest study, it is estimated the reserves will be depleted in 2029 with
final reclamation completed by 2036, at an estimated cost of approximately $39
million. As of June 30, 2008, SWEPCo collected approximately $36
million through a rider for final mine closure costs, of which approximately $7
million is recorded in Other Current Liabilities and $29 million is recorded in
Deferred Credits and Other on SWEPCo’s Condensed Consolidated Balance
Sheets.
Sabine
charges SWEPCo, its only customer, all of its costs. SWEPCo passes
these costs to customers through its fuel clause.
Indemnifications
and Other Guarantees
Contracts
All of
the Registrant Subsidiaries enter into certain types of contracts which require
indemnifications. Typically these contracts include, but are not
limited to, sale agreements, lease agreements, purchase agreements and financing
agreements. Generally, these agreements may include, but are not
limited to, indemnifications around certain tax, contractual and environmental
matters. With respect to sale agreements, exposure generally does not
exceed the sale price. Prior to June 30, 2008, Registrant
Subsidiaries entered into sale agreements which included indemnifications with a
maximum exposure that was not significant for any individual Registrant
Subsidiary. There are no material liabilities recorded for any
indemnifications.
The AEP
East companies, PSO and SWEPCo are jointly and severally liable for activity
conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related
to power purchase and sale activity conducted pursuant to the SIA.
Master Operating
Lease
Certain
Registrant Subsidiaries lease certain equipment under a master operating
lease. Under the lease agreement, the lessor is guaranteed to receive
up to 87% of the unamortized balance of the equipment at the end of the lease
term. If the fair market value of the leased equipment is below the
unamortized balance at the end of the lease term, the subsidiary has committed
to pay the difference between the fair market value and the unamortized balance,
with the total guarantee not to exceed 87% of the unamortized
balance. Historically, at the end of the lease term the fair market
value has been in excess of the unamortized balance. At June 30,
2008, the maximum potential loss by subsidiary for these lease agreements
assuming the fair market value of the equipment is zero at the end of the lease
term is as follows:
|
|
Maximum
|
|
|
|
Potential
|
|
|
|
Loss
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
$ |
10 |
|
CSPCo
|
|
|
5 |
|
I&M
|
|
|
7 |
|
OPCo
|
|
|
10 |
|
PSO
|
|
|
6 |
|
SWEPCo
|
|
|
6 |
|
Railcar
Lease
In June
2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered
into an agreement with BTM Capital Corporation, as lessor, to lease 875
coal-transporting aluminum railcars. The lease is accounted for as an
operating lease. AEP intends to maintain the lease for twenty years,
via renewal options. Under the lease agreement, the lessor is
guaranteed that the sale proceeds under a return-and-sale option will equal at
least a lessee obligation amount specified in the lease, which declines over the
current lease term from approximately 84% to 77% of the projected fair market
value of the equipment.
In
January 2008, AEP Transportation assigned the remaining 848 railcars under the
original lease agreement to I&M (390 railcars) and SWEPCo (458
railcars). The assignment is accounted for as new operating leases
for I&M and SWEPCo. The future minimum lease obligation is $21
million for I&M and $24 million for SWEPCo as of June 30,
2008. I&M and SWEPCo intend to renew these leases for the full
remaining terms and have assumed the guarantee under the return-and-sale
option. I&M’s maximum potential loss related to the guarantee
discussed above is approximately $12 million ($8 million, net of tax) and
SWEPCo’s is approximately $14 million ($9 million, net of
tax). However, management believes that the fair market value would
produce a sufficient sales price to avoid any loss.
The
Registrant Subsidiaries have other railcar lease arrangements that do not
utilize this type of financing structure.
CONTINGENCIES
Federal
EPA Complaint and Notice of Violation – Affecting CSPCo
The
Federal EPA, certain special interest groups and a number of states alleged that
APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired
generating plants in violation of the NSR requirements of the
CAA. The alleged modifications occurred over a 20-year
period. Cases with similar allegations against CSPCo, Dayton Power
and Light Company (DP&L) and Duke Energy Ohio, Inc. were also filed related
to their jointly-owned units.
The AEP
System settled their cases in 2007. A case is still pending that
could affect CSPCo’s share of jointly-owned units at Stuart
Station. The Stuart units, operated by DP&L, are equipped with
SCR and flue gas desulfurization equipment (FGD or scrubbers)
controls. A trial on liability issues was scheduled for August
2008. The Court issued a stay to allow the parties to pursue
settlement discussions. Those discussions are
ongoing. Another case involving a jointly-owned Beckjord unit had a
liability trial in May 2008. Following the trial, the jury found no
liability for claims made against the jointly-owned Beckjord unit.
Management
is unable to estimate the loss or range of loss related to any contingent
liability, if any, CSPCo might have for civil penalties under the pending CAA
proceedings for its jointly-owned plants. If CSPCo does not prevail,
management believes CSPCo can recover any capital and operating costs of
additional pollution control equipment that may be required through market
prices of electricity. If CSPCo is unable to recover such costs or if
material penalties are imposed, it would adversely affect future results of
operations, cash flows and possibly financial condition.
Notice
of Enforcement and Notice of Citizen Suit – Affecting SWEPCo
In March
2005, two special interest groups, Sierra Club and Public Citizen, filed a
complaint in Federal District Court for the Eastern District of Texas alleging
violations of the CAA at SWEPCo’s Welsh Plant. In April 2008, the
parties filed a proposed consent decree to resolve all claims in this case and
in the pending appeal of the altered permit for the Welsh Plant. The
consent decree requires SWEPCo to install continuous particulate emission
monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010,
fund $2 million in emission reduction, energy efficiency or environmental
mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and
costs. The consent decree was entered as a final order in June
2008.
In 2004,
the Texas Commission on Environmental Quality (TCEQ) issued a Notice of
Enforcement to SWEPCo relating to the Welsh Plant. In April 2005,
TCEQ issued an Executive Director’s Report (Report) recommending the entry of an
enforcement order to undertake certain corrective actions and assessing an
administrative penalty of approximately $228 thousand against
SWEPCo. In 2008, the matter was remanded to TCEQ to pursue settlement
discussions. The original Report contained a recommendation to limit
the heat input on each Welsh unit to the referenced heat input contained within
the state permit within 10 days of the issuance of a final TCEQ order and until
the permit is changed. SWEPCo had previously requested a permit
alteration to remove the reference to a specific heat input value for each Welsh
unit and to clarify the sulfur content requirement for fuels consumed at the
plant. A permit alteration was issued in March 2007. In
June 2007, TCEQ denied a motion to overturn the permit
alteration. The permit alteration was appealed to the Travis County
District Court, but was resolved by entry of the consent decree in the federal
citizen suit action, and dismissed with prejudice in July
2008. Notice of an administrative settlement of the TCEQ enforcement
action was published in June 2008. The settlement requires SWEPCo to
pay an administrative penalty of $49 thousand and to fund a supplemental
environmental project in the amount of $49 thousand, and resolves all violations
alleged by TCEQ. The settlement will become final upon approval by
the TCEQ.
In
February 2008, the Federal EPA issued a Notice of Violation (NOV) based on
alleged violations of a percent sulfur in fuel limitation and the heat input
values listed in the previous state permit. The NOV also alleges that
the permit alteration issued by TCEQ was improper. SWEPCo met with
the Federal EPA to discuss the alleged violations in March 2008. The
Federal EPA did not object to the settlement of similar alleged violations in
the federal citizen suit.
Management
is unable to predict the timing of any future action by the Federal EPA or the
effect of such action on results of operations, cash flows or financial
condition.
Carbon
Dioxide (CO2) Public
Nuisance Claims – Affecting AEP East companies and AEP West
companies
In 2004,
eight states and the City of New York filed an action in federal district court
for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel
Energy, Southern Company and Tennessee Valley Authority. The Natural
Resources Defense Council, on behalf of three special interest groups, filed a
similar complaint against the same defendants. The actions allege
that CO2
emissions from the defendants’ power plants constitute a public nuisance
under federal common law due to impacts of global warming, and sought injunctive
relief in the form of specific emission reduction commitments from the
defendants. The dismissal of this lawsuit was appealed to the Second
Circuit Court of Appeals. Briefing and oral argument have
concluded. In April 2007, the U.S. Supreme Court issued a decision
holding that the Federal EPA has authority to regulate emissions of CO2 and other
greenhouse gases under the CAA, which may impact the Second Circuit’s analysis
of these issues. The Second Circuit requested supplemental briefs
addressing the impact of the Supreme Court’s decision on this
case. Management believes the actions are without merit and intends
to defend against the claims.
Alaskan
Villages’ Claims – Affecting AEP East companies and AEP West
companies
In
February 2008, the Native Village of Kivalina and the City of Kivalina,
Alaska filed a lawsuit in federal court in the Northern District of
California against AEP, AEPSC and 22 other unrelated defendants including oil
& gas companies, a coal company, and other electric generating
companies. The complaint alleges that the defendants' emissions of
CO2
contribute to global warming and constitute a public and private nuisance and
that the defendants are acting together. The complaint further
alleges that some of the defendants, including AEP, conspired to create a false
scientific debate about global warming in order to deceive the public and
perpetuate the alleged nuisance. The plaintiffs also allege that the
effects of global warming will require the relocation of the village at an
alleged cost of $95 million to $400 million. Management believes the
action is without merit and intends to defend against the claims.
Clean
Air Act Interstate Rule – Affecting Registrant Subsidiaries
In 2005,
the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that
required further reductions in SO2 and
NOx
emissions and assists states developing new state implementation plans to meet
1997 national ambient air quality standards (NAAQS). CAIR reduces
regional emissions of SO2 and
NOx
(which can be transformed into PM and ozone) from power plants in the Eastern
U.S. (29 states and the District of Columbia). Reduction of both
SO2
and NOx would be
achieved through a cap-and-trade program. In July 2008, the D.C.
Circuit Court of Appeals vacated the CAIR and remanded the rule to the Federal
EPA. We are unable to predict how the Federal EPA will respond to the
remand which could be stayed or appealed to the U.S. Supreme Court.
In
anticipation of compliance with CAIR in 2009, I&M purchased $8 million of
annual CAIR NOx allowances
which are included in inventory as of June 30, 2008. The market value
of annual CAIR NOx allowances
decreased in the weeks following this court decision. Management
intends to seek recovery of the cost of purchased allowances. If the
recovery is denied, it would have an adverse effect on future results of
operations and cash flows. None of the other Registrant Subsidiaries
purchased any significant number of CAIR allowances. SO2 and
seasonal NOx allowances
allocated to the Registrant Subsidiaries’ facilities under the Acid Rain Program
and the NOX SIP Call
will still be required to comply with existing CAA programs that were not
affected by the court’s decision.
It is too
early to determine the full implication of these decisions on environmental
compliance strategy. However, independent obligations under the CAA,
including obligations under future state implementation plan submittals, and
actions taken pursuant to the recent settlement of the NSR enforcement action,
are consistent with the actions included in a least-cost CAIR compliance
plan. Consequently, management does not anticipate making any
immediate changes in near-term compliance plans as a result of these court
decisions.
The
Comprehensive Environmental Response Compensation and Liability Act (Superfund)
and State Remediation – Affecting I&M
By-products
from the generation of electricity include materials such as ash, slag, sludge,
low-level radioactive waste and SNF. Coal combustion by-products,
which constitute the overwhelming percentage of these materials, are typically
treated and deposited in captive disposal facilities or are beneficially
utilized. In addition, the generating plants and transmission and
distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and
other hazardous and nonhazardous materials. The Registrant
Subsidiaries currently incur costs to safely dispose of these
substances.
Superfund
addresses clean-up of hazardous substances that have been released to the
environment. The Federal EPA administers the clean-up
programs. Several states have enacted similar laws. In
March 2008, I&M received a letter from the Michigan Department of
Environmental Quality (MDEQ) concerning conditions at a site under state law and
requesting I&M take voluntary action necessary to prevent and/or mitigate
public harm. I&M requested remediation proposals from
environmental consulting firms. In May 2008, I&M issued a
contract to one of the consulting firms and recorded approximately $1 million of
expense. As the remediation work is completed, I&M’s cost may
increase. I&M cannot predict the amount of additional cost, if
any. At present, management’s estimates do not anticipate material
cleanup costs for this site.
Coal
Transportation Rate Dispute - Affecting PSO
In 1985,
the Burlington Northern Railroad Co. (now BNSF) entered into a coal
transportation agreement with PSO. The agreement contained a base
rate subject to adjustment, a rate floor, a reopener provision and an
arbitration provision. In 1992, PSO reopened the pricing
provision. The parties failed to reach an agreement and the matter
was arbitrated, with the arbitration panel establishing a lowered rate as of
July 1, 1992 (the 1992 Rate), and modifying the rate adjustment
formula. The decision did not mention the rate floor. From
April 1996 through the contract termination in December 2001, the 1992 Rate
exceeded the adjusted rate, determined according to the decision. PSO
paid the adjusted rate and contended that the panel eliminated the rate
floor. BNSF invoiced at the 1992 Rate and contended that the 1992
Rate was the new rate floor. At the end of 1991, PSO terminated the
contract by paying a termination fee, as required by the
agreement. BNSF contends that the termination fee should have been
calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment
of approximately $9.5 million, including interest.
This
matter was submitted to an arbitration board. In April 2006, the
arbitration board filed its decision, denying BNSF’s underpayments
claim. PSO filed a request for an order confirming the arbitration
award and a request for entry of judgment on the award with the U.S. District
Court for the Northern District of Oklahoma. On July 14, 2006, the
U.S. District Court issued an order confirming the arbitration
award. On July 24, 2006, BNSF filed a Motion to Reconsider the July
14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to
Vacate and Correct the Arbitration Award with the U.S. District
Court. In February 2007, the U.S. District Court granted BNSF’s
Motion to Reconsider. PSO filed a substantive response to BNSF’s
motion and BNSF filed a reply. Management continues to defend its
position that PSO paid BNSF all amounts owed.
FERC
Long-term Contracts – Affecting AEP East companies and AEP West
companies
In 2002,
the FERC held a hearing related to a complaint filed by Nevada Power Company and
Sierra Pacific Power Company (the Nevada utilities). The complaint
sought to break long-term contracts entered during the 2000 and 2001 California
energy price spike which the customers alleged were
“high-priced.” The complaint alleged that AEP subsidiaries sold power
at unjust and unreasonable prices because the market for power was allegedly
dysfunctional at the time such contracts were executed. In 2003, the
FERC rejected the complaint. In 2006, the U.S. Court of Appeals for
the Ninth Circuit reversed the FERC order and remanded the case to the FERC for
further proceedings. That decision was appealed to the U.S. Supreme
Court. In June 2008, the U.S. Supreme Court affirmed the validity of
contractually-agreed rates except in cases of serious harm to the
public. The U.S. Supreme Court affirmed the Ninth Circuit’s remand on
two issues, market manipulation and excessive burden on
consumers. Management is unable to predict the outcome of these
proceedings or their impact on future results of operations and cash
flows. The Registrant Subsidiaries asserted claims against certain
companies that sold power to them, which was resold to the Nevada utilities,
seeking to recover a portion of any amounts the Registrant Subsidiaries may owe
to the Nevada utilities.
2008
None
2007
Darby
Electric Generating Station – Affecting CSPCo
In
November 2006, CSPCo agreed to purchase Darby Electric Generating Station
(Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light
Company, for $102 million and the assumption of liabilities of $2
million. CSPCo completed the purchase in April 2007. The
Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple
cycle power plant with a generating capacity of 480 MW.
APCo,
CSPCo, I&M, OPCo, PSO and SWEPCo participate in AEP sponsored qualified
pension plans and nonqualified pension plans. A substantial majority
of employees are covered by either one qualified plan or both a qualified and a
nonqualified pension plan. In addition, APCo, CSPCo, I&M, OPCo,
PSO and SWEPCo participate in other postretirement benefit plans sponsored by
AEP to provide medical and death benefits for retired employees.
Components
of Net Periodic Benefit Cost
The
following tables provide the components of AEP’s net periodic benefit cost for
the plans for the three and six months ended June 30, 2008 and
2007:
|
|
|
Other
Postretirement
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
Three
Months Ended June 30,
|
|
Three
Months Ended June 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Service
Cost
|
$ |
25 |
|
$ |
23 |
|
$ |
11 |
|
$ |
11 |
|
Interest
Cost
|
|
62 |
|
|
57 |
|
|
28 |
|
|
26 |
|
Expected
Return on Plan Assets
|
|
(84
|
) |
|
(82
|
) |
|
(28
|
) |
|
(26
|
) |
Amortization
of Transition Obligation
|
|
- |
|
|
- |
|
|
7 |
|
|
7 |
|
Amortization
of Net Actuarial Loss
|
|
10 |
|
|
14 |
|
|
2 |
|
|
3 |
|
Net
Periodic Benefit Cost
|
$ |
13 |
|
$ |
12 |
|
$ |
20 |
|
$ |
21 |
|
|
|
|
Other
Postretirement
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
Six
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Service
Cost
|
$ |
50 |
|
$ |
47 |
|
$ |
21 |
|
$ |
21 |
|
Interest
Cost
|
|
125 |
|
|
116 |
|
|
56 |
|
|
52 |
|
Expected
Return on Plan Assets
|
|
(168
|
) |
|
(167
|
) |
|
(56
|
) |
|
(52
|
) |
Amortization
of Transition Obligation
|
|
- |
|
|
- |
|
|
14 |
|
|
14 |
|
Amortization
of Net Actuarial Loss
|
|
19 |
|
|
29 |
|
|
5 |
|
|
6 |
|
Net
Periodic Benefit Cost
|
$ |
26 |
|
$ |
25 |
|
$ |
40 |
|
$ |
41 |
|
The
following tables provide the Registrant Subsidiaries’ net periodic benefit cost
(credit) for the plans for the three and six months ended June 30, 2008 and
2007:
|
|
|
|
Other
Postretirement
|
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
|
Three
Months Ended June 30,
|
|
Three
Months Ended June 30,
|
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Company
|
|
(in
thousands)
|
|
APCo
|
|
$ |
834 |
|
$ |
842 |
|
$ |
3,700 |
|
$ |
3,560 |
|
CSPCo
|
|
|
(349
|
) |
|
(258
|
) |
|
1,499 |
|
|
1,491 |
|
I&M
|
|
|
1,820 |
|
|
1,900 |
|
|
2,423 |
|
|
2,531 |
|
OPCo
|
|
|
320 |
|
|
245 |
|
|
2,817 |
|
|
2,801 |
|
PSO
|
|
|
508 |
|
|
424 |
|
|
1,387 |
|
|
1,430 |
|
SWEPCo
|
|
|
936 |
|
|
747 |
|
|
1,376 |
|
|
1,419 |
|
|
|
|
|
Other
Postretirement
|
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
|
Six
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Company
|
|
(in
thousands)
|
|
APCo
|
|
$ |
1,669 |
|
$ |
1,684 |
|
$ |
7,399 |
|
$ |
7,120 |
|
CSPCo
|
|
|
(698
|
) |
|
(515
|
) |
|
2,997 |
|
|
2,982 |
|
I&M
|
|
|
3,641 |
|
|
3,800 |
|
|
4,846 |
|
|
5,061 |
|
OPCo
|
|
|
639 |
|
|
490 |
|
|
5,633 |
|
|
5,603 |
|
PSO
|
|
|
1,016 |
|
|
848 |
|
|
2,774 |
|
|
2,861 |
|
SWEPCo
|
|
|
1,871 |
|
|
1,493 |
|
|
2,752 |
|
|
2,838 |
|
The
Registrant Subsidiaries have one reportable segment. The one
reportable segment is an electricity generation, transmission and distribution
business. All of the Registrant Subsidiaries’ other activities are
insignificant. The Registrant Subsidiaries’ operations are managed as
one segment because of the substantial impact of cost-based rates and regulatory
oversight on the business process, cost structures and operating
results.
The
Registrant Subsidiaries adopted FIN 48 as of January 1, 2007. As a
result, the Registrant Subsidiaries recognized an increase in the liabilities
for unrecognized tax benefits, as well as related interest expense and
penalties, which was accounted for as a reduction to the January 1, 2007 balance
of retained earnings by each Registrant Subsidiary.
The
Registrant Subsidiaries join in the filing of a consolidated federal income tax
return with their affiliates in the AEP System. The allocation of the
AEP System’s current consolidated federal income tax to the AEP System companies
allocates the benefit of current tax losses to the AEP System companies giving
rise to such losses in determining their current tax expense. The tax
benefit of the Parent is allocated to its subsidiaries with taxable
income. With the exception of the loss of the Parent, the method of
allocation reflects a separate return result for each company in the
consolidated group.
The
Registrant Subsidiaries are no longer subject to U.S. federal examination for
years before 2000. However, AEP has filed refund claims with the IRS
for years 1997 through 2000 for the CSW pre-merger tax period, which are
currently being reviewed. The Registrant Subsidiaries have completed
the exam for the years 2001 through 2003 and have issues that will be pursued at
the appeals level. The returns for the years 2004 through 2006 are
presently under audit by the IRS. Although the outcome of tax audits
is uncertain, in management’s opinion, adequate provisions for income taxes have
been made for potential liabilities resulting from such matters. In
addition, the Registrant Subsidiaries accrue interest on these uncertain tax
positions. Management is not aware of any issues for open tax years
that upon final resolution are expected to have a material adverse effect on
results of operations.
The
Registrant Subsidiaries file income tax returns in various state and local
jurisdictions. These taxing authorities routinely examine their tax returns and
the Registrant Subsidiaries are currently under examination in several state and
local jurisdictions. Management believes that previously filed tax
returns have positions that may be challenged by these tax
authorities. However, management does not believe that the ultimate
resolution of these audits will materially impact results of
operations. With few exceptions, the Registrant Subsidiaries are no
longer subject to state or local income tax examinations by tax authorities for
years before 2000.
Federal
Tax Legislation – Affecting APCo, CSPCo and OPCo
In 2005,
the Energy Tax Incentives Act of 2005 was signed into law. This act
created a limited amount of tax credits for the building of IGCC
plants. The credit is 20% of the eligible property in the
construction of a new plant or 20% of the total cost of repowering of an
existing plant using IGCC technology. In the case of a newly
constructed IGCC plant, eligible property is defined as the components necessary
for the gasification of coal, including any coal handling and gas separation
equipment. AEP announced plans to construct two new IGCC plants that
may be eligible for the allocation of these credits. AEP filed
applications for the West Virginia and Ohio IGCC projects with the DOE and the
IRS. Both projects were certified by the DOE and qualified by the
IRS. However, neither project was awarded credits during the first
round of credit awards. After one of the original credit recipients
surrendered their credits in the Fall of 2007, the IRS announced a supplemental
credit round for the Spring of 2008. AEP filed a new application in 2008
for the West Virginia IGCC project and in July 2008 the IRS awarded the project
$134 million in credits subject to entering into a memorandum of understanding
with the IRS.
State
Tax Legislation – Affecting APCo, CSPCo, I&M and OPCo
In March
2008, the Governor of West Virginia signed legislation providing for, among
other things, a reduction in the West Virginia corporate income tax rate from
8.75% to 8.5% beginning in 2009. The corporate income tax rate could
also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state
government achieving certain minimum levels of shortfall reserve
funds. Management has evaluated the impact of the law change and the
application of the law change will not materially impact results of operations,
cash flows or financial condition.
9. FINANCING
ACTIVITIES
Long-term
Debt
Long-term
debt and other securities issued, retired and principal payments made during the
first six months of 2008 were:
|
|
|
|
Principal
|
|
Interest
|
|
Due
|
Company
|
|
Type
of Debt
|
|
Amount
|
|
Rate
|
|
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
Pollution
Control Bonds
|
|
$
|
75,000
|
|
Variable
|
|
2036
|
APCo
|
|
Pollution
Control Bonds
|
|
|
50,275
|
|
Variable
|
|
2036
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
500,000
|
|
7.00
|
|
2038
|
CSPCo
|
|
Senior
Unsecured Notes
|
|
|
350,000
|
|
6.05
|
|
2018
|
I&M
|
|
Pollution
Control Bonds
|
|
|
25,000
|
|
Variable
|
|
2019
|
I&M
|
|
Pollution
Control Bonds
|
|
|
52,000
|
|
Variable
|
|
2021
|
I&M
|
|
Pollution
Control Bonds
|
|
|
40,000
|
|
5.25
|
|
2025
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2014
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2014
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
65,000
|
|
Variable
|
|
2036
|
SWEPCo
|
|
Senior
Unsecured Notes
|
|
|
400,000
|
|
6.45
|
|
2019
|
|
|
|
|
Principal
|
|
Interest
|
|
Due
|
Company
|
|
Type
of Debt
|
|
Amount
Paid
|
|
Rate
|
|
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Retirements
and Principal Payments:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
$
|
200,000
|
|
3.60
|
|
2008
|
APCo
|
|
Pollution
Control Bonds
|
|
|
40,000
|
|
Variable
|
|
2019
|
APCo
|
|
Pollution
Control Bonds
|
|
|
30,000
|
|
Variable
|
|
2019
|
APCo
|
|
Pollution
Control Bonds
|
|
|
17,500
|
|
Variable
|
|
2021
|
APCo
|
|
Pollution
Control Bonds
|
|
|
50,275
|
|
Variable
|
|
2036
|
APCo
|
|
Pollution
Control Bonds
|
|
|
75,000
|
|
Variable
|
|
2037
|
APCo
|
|
Other
|
|
|
7
|
|
13.718
|
|
2026
|
CSPCo
|
|
Senior
Unsecured Notes
|
|
|
52,000
|
|
6.51
|
|
2008
|
CSPCo
|
|
Senior
Unsecured Notes
|
|
|
60,000
|
|
6.55
|
|
2008
|
CSPCo
|
|
Pollution
Control Bonds
|
|
|
48,550
|
|
Variable
|
|
2038
|
CSPCo
|
|
Pollution
Control Bonds
|
|
|
43,695
|
|
Variable
|
|
2038
|
I&M
|
|
Pollution
Control Bonds
|
|
|
45,000
|
|
Variable
|
|
2009
|
I&M
|
|
Pollution
Control Bonds
|
|
|
25,000
|
|
Variable
|
|
2019
|
I&M
|
|
Pollution
Control Bonds
|
|
|
52,000
|
|
Variable
|
|
2021
|
I&M
|
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2025
|
I&M
|
|
Pollution
Control Bonds
|
|
|
40,000
|
|
Variable
|
|
2025
|
I&M
|
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2025
|
OPCo
|
|
Notes
Payable
|
|
|
1,463
|
|
6.81
|
|
2008
|
OPCo
|
|
Notes
Payable
|
|
|
6,000
|
|
6.27
|
|
2009
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2014
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2016
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2022
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
35,000
|
|
Variable
|
|
2022
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
65,000
|
|
Variable
|
|
2036
|
PSO
|
|
Pollution
Control Bonds
|
|
|
33,700
|
|
Variable
|
|
2014
|
SWEPCo
|
|
Notes
Payable
|
|
|
1,500
|
|
Variable
|
|
2008
|
SWEPCo
|
|
Notes
Payable
|
|
|
2,203
|
|
4.47
|
|
2011
|
As of
June 30, 2008, OPCo and SWEPCo had $218 million and $95 million, respectively,
of tax-exempt long-term debt sold at auction rates that reset every 35
days. This debt is insured by bond insurers previously AAA-rated,
namely Ambac Assurance Corporation and Financial Guaranty Insurance
Co. Due to the exposure that these bond insurers have in connection
with recent developments in the subprime credit market, the credit ratings of
these insurers have been downgraded or placed on negative
outlook. These market factors have contributed to higher interest
rates in successful auctions and increasing occurrences of failed auctions,
including many of the auctions of tax-exempt long-term debt. The
instruments under which the bonds are issued allow for conversion to other
short-term variable-rate structures, term-put structures and fixed-rate
structures. Through June 30, 2008, the Registrant Subsidiaries
reduced their outstanding auction rate securities. Management plans
to continue this conversion and refunding process for the remaining $313 million
to other permitted modes, including term-put structures, variable-rate and
fixed-rate structures, during the second half of 2008 to lower interest rates as
such opportunities arise.
As of
June 30, 2008, $367 million of the prior auction rate debt was issued in a
weekly variable rate mode supported by letters of credit at variable rates
ranging from 1.45% to 1.68% and $222 million was issued at fixed rates ranging
from 4.85% to 5.25%. As of June 30, 2008, trustees held, on behalf of
the Registrant Subsidiaries, approximately $400 million of their reacquired
auction rate tax-exempt long-term debt which management plans to reissue to the
public as market conditions permit. The following table shows the
current status of debt which was issued as auction rate debt at December 31,
2007:
|
|
|
|
Remarketed
at
|
|
|
|
|
Remarketed
at
|
|
|
|
|
Remains
at
|
|
|
|
|
|
|
|
Fixed
Rates
|
|
|
|
|
Variable
Rates
|
|
|
|
|
Auction
Rate
|
|
|
|
|
|
|
|
During
the First
|
|
|
|
|
During
the First
|
|
Variable
Rate
|
|
|
at
|
|
Held
by
|
|
|
|
Retired
in
|
|
Six
Months of
|
|
Fixed
Rate at
|
|
|
Six
Months of
|
|
at
|
|
|
June
30,
|
|
Trustee
at
|
|
|
|
2008
|
|
2008
|
|
June
30, 2008
|
|
|
2008
|
|
June
30, 2008
|
|
|
2008
|
|
June
30, 2008
|
|
Company
|
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
|
APCo
|
|
$ |
- |
|
$ |
- |
|
|
- |
% |
|
$ |
75,000 |
|
|
1.62 |
% |
|
$ |
- |
|
$ |
87,500 |
|
APCo
|
|
|
- |
|
|
- |
|
|
- |
% |
|
|
50,275 |
|
|
1.68 |
% |
|
|
- |
|
|
- |
|
CSPCo
|
|
|
- |
|
|
56,000 |
|
|
5.10 |
% |
|
|
- |
|
|
- |
% |
|
|
- |
|
|
92,245 |
|
CSPCo
|
|
|
- |
|
|
44,500 |
|
|
4.85 |
% |
|
|
- |
|
|
- |
% |
|
|
- |
|
|
- |
|
I&M
|
|
|
45,000 |
|
|
40,000 |
|
|
5.25 |
% |
|
|
52,000 |
|
|
1.57 |
% |
|
|
- |
|
|
100,000 |
|
I&M
|
|
|
- |
|
|
- |
|
|
- |
% |
|
|
25,000 |
|
|
1.50 |
% |
|
|
- |
|
|
- |
|
OPCo
|
|
|
- |
|
|
- |
|
|
- |
% |
|
|
65,000 |
|
|
1.60 |
% |
|
|
218,000 |
|
|
85,000 |
|
OPCo
|
|
|
- |
|
|
- |
|
|
- |
% |
|
|
50,000 |
|
|
1.45 |
% |
|
|
- |
|
|
- |
|
OPCo
|
|
|
- |
|
|
- |
|
|
- |
% |
|
|
50,000 |
|
|
1.47 |
% |
|
|
- |
|
|
- |
|
PSO
|
|
|
- |
|
|
- |
|
|
- |
% |
|
|
- |
|
|
- |
% |
|
|
- |
|
|
33,700 |
|
SWEPCo
|
|
|
- |
|
|
81,700 |
|
|
4.95 |
% |
|
|
- |
|
|
- |
% |
|
|
94,635 |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
45,000 |
|
$ |
222,200 |
|
|
|
|
|
$ |
367,275 |
|
|
|
|
|
$ |
312,635 |
|
$ |
398,445 |
|
Lines
of Credit
The AEP
System uses a corporate borrowing program to meet the short-term borrowing needs
of its subsidiaries. The corporate borrowing program includes a
Utility Money Pool, which funds the utility subsidiaries. The AEP
System corporate borrowing program operates in accordance with the terms and
conditions approved in a regulatory order. The amount of outstanding
loans (borrowings) to/from the Utility Money Pool as of June 30, 2008 and
December 31, 2007 are included in Advances to/from Affiliates on each of the
Registrant Subsidiaries’ balance sheets. The Utility Money Pool
participants’ money pool activity and their corresponding authorized borrowing
limits for the six months ended June 30, 2008 are described in the following
table:
|
|
|
|
|
|
|
|
|
|
Loans
|
|
|
|
|
|
Maximum
|
|
Maximum
|
|
Average
|
|
Average
|
|
(Borrowings)
|
|
Authorized
|
|
|
|
Borrowings
|
|
Loans
to
|
|
Borrowings
|
|
Loans
to
|
|
to/from
Utility
|
|
Short-Term
|
|
|
|
from
Utility
|
|
Utility
|
|
from
Utility
|
|
Utility
Money
|
|
Money
Pool as of
|
|
Borrowing
|
|
|
|
Money
Pool
|
|
Money
Pool
|
|
Money
Pool
|
|
Pool
|
|
June
30, 2008
|
|
Limit
|
|
Company
|
|
(in
thousands)
|
|
APCo
|
|
$ |
307,226 |
|
$ |
269,987 |
|
$ |
226,292 |
|
$ |
187,192 |
|
$ |
(103,802 |
) |
|
$ |
600,000 |
|
CSPCo
|
|
|
238,172 |
|
|
150,358 |
|
|
157,569 |
|
|
65,413 |
|
|
25,199 |
|
|
|
350,000 |
|
I&M
|
|
|
345,064 |
|
|
- |
|
|
174,380 |
|
|
- |
|
|
(272,707
|
) |
|
|
500,000 |
|
OPCo
|
|
|
415,951 |
|
|
- |
|
|
165,436 |
|
|
- |
|
|
(173,833
|
) |
|
|
600,000 |
|
PSO
|
|
|
128,114 |
|
|
59,384 |
|
|
61,023 |
|
|
29,811 |
|
|
(110,981
|
) |
|
|
300,000 |
|
SWEPCo
|
|
|
168,495 |
|
|
300,525 |
|
|
87,426 |
|
|
273,118 |
|
|
300,525 |
|
|
|
350,000 |
|
The
maximum and minimum interest rates for funds either borrowed from or loaned to
the Utility Money Pool were as follows:
|
|
Six
Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
Maximum
Interest Rate
|
|
|
5.37 |
% |
|
|
5.46 |
% |
Minimum
Interest Rate
|
|
|
2.91 |
% |
|
|
5.30 |
% |
The
average interest rates for funds borrowed from and loaned to the Utility Money
Pool for the six months ended June 30, 2008 and 2007 are summarized for all
Registrant Subsidiaries in the following table:
|
|
Average
Interest Rate for Funds
|
|
|
Average
Interest Rate for Funds
|
|
|
|
Borrowed
from
|
|
|
Loaned
to
|
|
|
|
the
Utility Money Pool for the
|
|
|
the
Utility Money Pool for the
|
|
|
|
Six
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Company
|
|
|
|
APCo
|
|
|
3.86 |
% |
|
5.36 |
% |
|
3.25 |
% |
|
- |
% |
CSPCo
|
|
|
3.66 |
% |
|
5.37 |
% |
|
2.93 |
% |
|
5.33 |
% |
I&M
|
|
|
3.30 |
% |
|
5.35 |
% |
|
- |
% |
|
- |
% |
OPCo
|
|
|
3.39 |
% |
|
5.35 |
% |
|
- |
% |
|
5.43 |
% |
PSO
|
|
|
3.03 |
% |
|
5.36 |
% |
|
4.53 |
% |
|
- |
% |
SWEPCo
|
|
|
3.36 |
% |
|
5.36 |
% |
|
2.93 |
% |
|
5.34 |
% |
Short-term
Debt
The
Registrant Subsidiaries’ outstanding short-term debt was as
follows:
|
|
|
|
June
30, 2008
|
|
December
31, 2007
|
|
|
|
|
|
Outstanding
|
|
Interest
|
|
Outstanding
|
|
Interest
|
|
|
|
Type
of Debt
|
|
Amount
|
|
Rate
|
|
Amount
|
|
Rate
|
|
Company
|
|
|
|
(in
thousands)
|
|
|
|
(in
thousands)
|
|
|
|
OPCo
|
|
Commercial
Paper – JMG
|
|
$
|
-
|
|
-
|
%
|
$
|
701
|
|
5.35
|
%
|
SWEPCo
|
|
Line
of Credit – Sabine Mining Company
|
|
|
7,039
|
|
3.25
|
%
|
|
285
|
|
5.25
|
%
|
Credit
Facilities
In April
2008, the Registrant Subsidiaries and certain other companies in the AEP System
entered into a $650 million 3-year credit agreement and a $350 million 364-day
credit agreement. Under the facilities, letters of credit may be
issued. As of June 30, 2008, $371 million of letters of credit were
issued by Registrant Subsidiaries under the 3-year credit agreement to support
variable rate demand notes.
The
following is a combined presentation of certain components of the registrants’
management’s discussion and analysis. The information in this section
completes the information necessary for management’s discussion and analysis of
financial condition and results of operations and is meant to be read with (i)
Management’s Financial Discussion and Analysis, (ii) financial statements and
(iii) footnotes of each individual registrant. The combined
Management’s Discussion and Analysis of Registrant Subsidiaries section of the
2007 Annual Report should also be read in conjunction with this
report.
Sources of
Funding
Short-term
funding for the Registrant Subsidiaries comes from AEP’s commercial paper
program under two $1.5 billion revolving credit facilities which support the
Utility Money Pool. In March 2008, these credit facilities were
amended so that $750 million may be issued under each credit facility as letters
of credit (LOC). Certain companies within the AEP System including
the Registrant Subsidiaries operate the Utility Money Pool to minimize external
short-term funding requirements. The Registrant Subsidiaries also
sell accounts receivable to provide liquidity. The Registrant
Subsidiaries generally use short-term funding sources (the Utility Money Pool or
receivables sales) to provide for interim financing of capital expenditures that
exceed internally generated funds and periodically reduce their outstanding
short-term debt through issuances of long-term debt, sale-leaseback, leasing
arrangements and additional capital contributions from AEP.
In April
2008, the Registrant Subsidiaries and certain other companies in the AEP System
entered into a $650 million 3-year credit agreement and a $350 million 364-day
credit agreement. The Registrant Subsidiaries may issue LOCs under
the credit facilities. Each subsidiary has a borrowing/LOC limit
under the credit facilities. As of June 30, 2008, a total of $371
million of LOCs were issued under the 3-year credit agreement to support
variable rate demand notes. The following table shows each Registrant
Subsidiaries’ borrowing/LOC limit under each credit facility and the outstanding
amount of LOCs for the $650 million facility.
|
|
|
|
|
|
LOC
Amount
|
|
|
|
|
|
|
|
Outstanding
|
|
|
|
$650
million
|
|
$350
million
|
|
Against
|
|
|
|
Credit
Facility
|
|
Credit
Facility
|
|
$650
million
|
|
|
|
Borrowing/LOC
|
|
Borrowing/LOC
|
|
Agreement
at
|
|
|
|
Limit
|
|
Limit
|
|
June
30, 2008
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
|
$ |
300 |
|
|
$ |
150 |
|
|
$ |
127 |
|
CSPCo
|
|
|
|
230 |
|
|
|
120 |
|
|
|
- |
|
I&M
|
|
|
|
230 |
|
|
|
120 |
|
|
|
77 |
|
OPCo
|
|
|
|
400 |
|
|
|
200 |
|
|
|
167 |
|
PSO
|
|
|
|
65 |
|
|
|
35 |
|
|
|
- |
|
SWEPCo
|
|
|
|
230 |
|
|
|
120 |
|
|
|
- |
|
At June
30, 2008, there were no outstanding amounts under the $350 million
facility.
Credit
Markets
Management
believes the Registrant Subsidiaries, through the Utility Money Pool, have
adequate liquidity under credit facilities and the ability to issue long-term
debt in the current credit markets. As of June 30, 2008, OPCo had
$218 million and SWEPCo had $95 million outstanding of tax-exempt long-term debt
sold at auction rates that reset every 35 days. This debt is insured
by bond insurers previously AAA-rated, namely Ambac Assurance Corporation and
Financial Guaranty Insurance Co. Due to the exposure that these bond
insurers have in connection with developments in the subprime credit market, the
credit ratings of these insurers have been downgraded or placed on negative
outlook. These market factors have contributed to higher interest
rates in successful auctions and increasing occurrences of failed auctions,
including many of the auctions of tax-exempt long-term debt. The
instruments under which the bonds are issued allow us to convert to other
short-term variable-rate structures, term-put structures and fixed-rate
structures. Through June 30, 2008, the Registrant Subsidiaries
reduced their outstanding auction rate securities. Management plans
to continue the conversion and refunding process for the remaining $313 million
to other permitted modes, including term-put structures, variable-rate and
fixed-rate structures, during the second half of 2008 to lower interest rates as
such opportunities arise.
As of
June 30, 2008, trustees held, on behalf of the Registrant Subsidiaries,
approximately $400 million of their reacquired auction rate tax-exempt long-term
debt which management plans to reissue to the public as the market
permits. The following table shows the current status of debt that
was issued as auction rate at December 31, 2007 by Registrant
Subsidiary.
|
|
|
|
Remarketed
at
|
|
|
|
|
|
|
|
|
|
Fixed
or
|
|
|
|
|
|
|
|
|
|
Variable
Rates
|
|
Remains
in
|
|
Held
|
|
|
|
Retired
|
|
During
the First
|
|
Auction
Rate at
|
|
by
Trustee at
|
|
|
|
in
2008
|
|
Half
of 2008
|
|
June
30, 2008
|
|
June
30, 2008
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
|
$ |
- |
|
|
$ |
125 |
|
|
$ |
- |
|
|
$ |
88 |
|
CSPCo
|
|
|
|
- |
|
|
|
101 |
|
|
|
- |
|
|
|
92 |
|
I&M
|
|
|
|
45 |
|
|
|
117 |
|
|
|
- |
|
|
|
100 |
|
OPCo
|
|
|
|
- |
|
|
|
165 |
|
|
|
218 |
|
|
|
85 |
|
PSO
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
34 |
|
SWEPCo
|
|
|
|
- |
|
|
|
82 |
|
|
|
95 |
|
|
|
- |
|
APCo,
I&M and OPCo issued $125 million, $77 million and $165 million,
respectively, of weekly variable rate debt. As of June 30, 2008, the
variable rates ranged from 1.45% to 1.68%. CSPCo issued fixed rate
debt of $45 million at 4.85% until 2012 and $56 million at 5.1% until
2013. I&M issued $40 million of fixed rate debt at 5.25% due
2025. SWEPCo remarketed $82 million of fixed rate debt at 4.95% due
2018.
Budgeted Construction
Expenditures
Revised
construction expenditures for the Registrant Subsidiaries for 2009 and 2010
are:
|
|
Estimated
Construction Expenditures
|
|
|
|
2009
|
|
|
2010
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
$ |
583.2 |
|
|
$ |
474.4 |
|
CSPCo
|
|
|
311.7 |
|
|
|
308.3 |
|
I&M
|
|
|
457.7 |
|
|
|
496.8 |
|
OPCo
|
|
|
441.1 |
|
|
|
410.9 |
|
PSO
|
|
|
257.2 |
|
|
|
419.2 |
|
SWEPCo
|
|
|
710.3 |
|
|
|
681.0 |
|
The
budgeted amounts increased for I&M and SWEPCo and decreased for APCo, CSPCo,
OPCo and PSO.
Significant
Factors
Ohio
Electric Security Plan Filings
In April
2008, the Ohio legislature passed Senate Bill 221, which amends the
restructuring law effective July 31, 2008 and requires electric utilities to
adjust their rates by filing an Electric Security Plan
(ESP). Electric utilities may file an ESP with a fuel cost recovery
mechanism. Electric utilities also have an option to file a Market
Rate Offer (MRO) for generation pricing. A MRO, from the date of its
commencement, could transition CSPCo and OPCo to full market rates no sooner
than six years and no later than ten years. The PUCO has the
authority to approve or modify the utilities’ ESP request. The PUCO
is required to approve an ESP if, in the aggregate, the ESP is more favorable to
ratepayers than the MRO. Both alternatives involve a “substantially
excessive earnings” test based on what public companies, including other
utilities with similar risk profiles, earn on equity. Management has
preliminarily concluded, pending the issuance of final rules by the PUCO and the
outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply
operations are not subject to cost-based rate regulation
accounting. However, if a fuel cost recovery mechanism is implemented
within the ESP, CSPCo’s and OPCo’s fuel operations would be subject to
cost-based rate regulation accounting. Management is unable to
predict the financial statement impact of the restructuring legislation until
the PUCO acts on specific proposals made by CSPCo and OPCo in their
ESPs.
In July
2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to
establish rates for 2009 through 2011. CSPCo and OPCo did not file
MROs. CSPCo and OPCo did not file MROs. CSPCo and OPCo each
requested an annual rate increase for 2009 through 2011 that would not exceed
approximately 15% per year. A significant portion of the requested
increases results from the implementation of a fuel cost recovery mechanism that
primarily includes fuel costs, purchased power costs including mandated
renewable energy, consumables such as urea, other variable production costs and
gains and losses on sales of emission allowances. The increases in
customer bills related to the fuel cost recovery mechanism would be phased-in
over the three year period from 2009 through 2011. Effective January
1, 2009, CSPCo and OPCo will defer the fuel cost under-recoveries and related
carrying costs for future recovery over seven years from 2012 through
2018. In addition to the fuel cost recovery mechanisms, the requested
increases would also recover incremental carrying costs associated with
environmental costs, Provider of Last Resort (POLR) charges to compensate for
the risk of customers changing electric suppliers, automatic increases for
unexpected costs and reliability costs. The filings also include programs
for smart metering initiatives and economic development and mandated
energy efficiency and peak demand reduction programs. Management
expects a PUCO decision on the ESP filings in the fourth quarter of
2008.
Within
the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $45
million and $36 million, respectively, for customer choice implementation and
line extension carrying costs. In addition, CSPCo and OPCo would
recover related unrecorded equity carrying costs of $28 million and $19 million,
respectively. Such costs would be recovered over an 8 year
period beginning January 2011. Failure of the PUCO to ultimately
approve the recovery of the regulatory assets would have an adverse effect on
future results of operations and cash flows.
FERC
Market Power Mitigation
The FERC
allows utilities to sell wholesale power at market-based rates if they can
demonstrate that they lack market power in the markets in which they
participate. Sellers with market rate authority must, at least every
three years, update their studies demonstrating lack of market
power. In December 2007, AEP filed its most recent triennial
update. In March and May 2008, the PUCO filed comments suggesting
that the FERC should further investigate whether AEP continues to pass the
FERC’s indicative screens for the lack of market power in
PJM. Certain industrial retail customers also urged the FERC to
further investigate this matter. AEP responded that its market power
studies were performed in accordance with the FERC’s guidelines, and continue to
demonstrate lack of market power. Management is unable to predict the
outcome of this proceeding; however, if a further investigation by the FERC
limited AEP’s ability to sell power at market based rates in PJM, it would
result in an adverse effect on future off-system sales margins, results of
operations and cash flows.
New
Generation
In 2008,
AEP completed or is in various stages of construction of the following
generation facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
Nominal
|
|
Operation
|
Operating
|
|
Project
|
|
|
|
Projected
|
|
|
|
|
|
|
|
|
MW
|
|
Date
|
Company
|
|
Name
|
|
Location
|
|
Cost
(a)
|
|
CWIP
(b)
|
|
Fuel
Type
|
|
Plant
Type
|
|
Capacity
|
|
(Projected)
|
|
|
|
|
|
|
(in
millions)
|
|
(in
millions)
|
|
|
|
|
|
|
|
|
PSO
|
|
Southwestern
|
(c)
|
Oklahoma
|
|
|
$ |
56 |
|
|
|
$ |
- |
|
|
Gas
|
|
Simple-cycle
|
|
|
150
|
|
|
2008
|
PSO
|
|
Riverside
|
(d)
|
Oklahoma
|
|
|
|
58 |
|
|
|
|
- |
|
|
Gas
|
|
Simple-cycle
|
|
|
150 |
|
|
2008
|
AEGCo
|
|
Dresden
|
(e)
|
Ohio
|
|
|
|
309 |
|
(e)
|
|
|
119 |
|
|
Gas
|
|
Combined-cycle
|
|
|
580 |
|
|
2010
|
SWEPCo
|
|
Stall
|
|
Louisiana
|
|
|
|
378 |
|
|
|
|
106 |
|
|
Gas
|
|
Combined-cycle
|
|
|
500 |
|
|
2010
|
SWEPCo
|
|
Turk
|
(f)
|
Arkansas
|
|
|
|
1,522 |
|
(f)
|
|
|
407 |
|
|
Coal
|
|
Ultra-supercritical
|
|
|
600 |
|
(f)
|
2012
|
APCo
|
|
Mountaineer
|
(g)
|
West
Virginia
|
|
|
|
2,230 |
|
(g)
|
|
|
- |
|
|
Coal
|
|
IGCC
|
|
|
629 |
|
|
2012(g)
|
CSPCo/OPCo
|
|
Great
Bend
|
(g)
|
Ohio
|
|
|
|
2,700 |
|
(g)
|
|
|
- |
|
|
Coal
|
|
IGCC
|
|
|
629 |
|
|
2017(g)
|
(a)
|
Amount
excludes AFUDC.
|
(b)
|
Amount
includes AFUDC. Turk’s CWIP includes joint owners’
share.
|
(c)
|
Southwestern
Units were placed in service on February 29, 2008.
|
(d)
|
The
final Riverside Unit was placed in service on June 15,
2008.
|
(e)
|
In
September 2007, AEGCo purchased the partially completed Dresden plant from
Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85
million, which is included in the “Total Projected Cost” section
above.
|
(f)
|
SWEPCo
plans to own approximately 73%, or 440 MW, totaling $1,110 million in
capital investment. The increase in the cost estimate disclosed
in the 2007 Annual Report relates to cost escalations due to the delay in
receipt of permits and approvals. See “Turk Plant” section
below.
|
(g)
|
Subject
to revision; construction of IGCC plants deferred pending regulatory
approval. See “IGCC Plants” section
below.
|
Turk
Plant
In
November 2007, the APSC granted approval to build the Turk
Plant. Certain landowners filed a notice of appeal to the Arkansas
State Court of Appeals. In March 2008, the LPSC approved the
application to construct the Turk Plant. In July 2008, the PUCT
approved a certificate of convenience and necessity for construction of the
plant. We expect a written order in August 2008 which will also
provide for the conditions of the PUCT’s approval.
SWEPCo is
working with the Arkansas Department of Environmental Quality and the U.S. Army
Corps of Engineers for approval later this year. A request to stop
pre-construction activities at the site was filed in Federal court by the same
Arkansas landowners who appealed the APSC decision to the Arkansas State Court
of Appeals. In July 2008, the Federal court denied the request and
the Arkansas landowners appealed the denial to the U.S. Court of
Appeals.
If SWEPCo
does not receive appropriate authorizations and permits to build the Turk Plant,
SWEPCo could incur significant cancellation fees to terminate its commitments
and would be responsible to reimburse the joint owners for their share of paid
costs. If that occurred, SWEPCo would seek recovery of its
capitalized costs including any cancellation fees and joint owner
reimbursements. As of June 30, 2008, including the joint owners’
share, SWEPCo has capitalized approximately $407 million of expenditures and has
significant contractual construction commitments for an additional $815
million. As of June 30, 2008, if the plant had been canceled,
cancellation fees of $60 million would have been required in order to terminate
these construction commitments. If SWEPCo cannot recover its costs,
it would have an adverse effect on future results of operations, cash flows and
possibly financial condition.
IGCC
Plants
We have
delayed construction of the West Virginia and Ohio IGCC plants. In
May 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia SCC
previous denial of APCo’s request to recover initial costs associated with a
proposed IGCC plant in West Virginia. In July 2008, the WVPSC issued
a notice seeking comments from parties on how the WVPSC should proceed regarding
its earlier approval of the IGCC plant. In July 2008, the IRS awarded
$134 million in future tax credits for the IGCC plant. Management
continues to pursue the ultimate construction of the IGCC plant. If
the West Virginia IGCC plant is canceled, APCo plans to seek recovery of its
prudently incurred deferred pre-construction costs of $19 million. If
the plant is canceled and the deferred costs are not recoverable, it would have
an adverse effect on future results of operations and cash flows.
In Ohio,
CSPCo and OPCo continue to pursue the ultimate construction of the IGCC plant,
but await the result of an Ohio Supreme Court remand to the PUCO regarding
recovery of IGCC pre-construction costs. If CSPCo and OPCo were
required to refund $24 million collected for IGCC pre-construction costs and
those costs were not recoverable in another jurisdiction in connection with the
construction of an IGCC plant, it would have an adverse effect on future results
of operations and cash flows.
Environmental
Matters
The
Registrant Subsidiaries are implementing a substantial capital investment
program and incurring additional operational costs to comply with new
environmental control requirements. The sources of these requirements
include:
·
|
Requirements
under the CAA to reduce emissions of SO2,
NOx,
particulate matter (PM) and mercury from fossil fuel-fired power plants;
and
|
·
|
Requirements
under the Clean Water Act (CWA) to reduce the impacts of water intake
structures on aquatic species at certain power
plants.
|
In
addition, the Registrant Subsidiaries are engaged in litigation with respect to
certain environmental matters, have been notified of potential responsibility
for the clean-up of contaminated sites and incur costs for disposal of spent
nuclear fuel and future decommissioning of I&M’s nuclear
units. Management is also engaged in the development of possible
future requirements to reduce CO2 and other
greenhouse gases (GHG) emissions to address concerns about global climate
change. All of these matters are discussed in the “Environmental
Matters” section of “Combined Management’s Discussion and Analysis of Registrant
Subsidiaries” in the 2007 Annual Report.
Environmental
Litigation
New Source Review (NSR)
Litigation: The Federal EPA, a number of states and certain
special interest groups filed complaints alleging that APCo, CSPCo, I&M,
OPCo and other nonaffiliated utilities, including Cincinnati Gas & Electric
Company, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc.
(Duke), modified certain units at coal-fired generating plants in violation of
the NSR requirements of the CAA.
In 2007,
the AEP System settled their complaints under a consent decree. CSPCo
jointly-owned Beckjord and Stuart Stations with Duke and DP&L. A
jury trial in May 2008 returned a verdict of no liability at the jointly-owned
Beckjord unit. Settlement discussions are ongoing in the citizen suit
action filed by Sierra Club against the jointly-owned units at Stuart
Station. Management believes CSPCo can recover any capital and
operating costs of additional pollution control equipment that may be required
through future regulated rates or market prices for electricity. If
CSPCo is unable to recover such costs or if material penalties are imposed, it
would adversely affect future results of operations and cash flows.
Clean
Air Act Requirements
As
discussed in the 2007 Annual Report under “Clean Air Act Requirements,” various
states and environmental organizations challenged the Clean Air Mercury Rule
(CAMR) in the D. C. Circuit Court of Appeals. The Court ruled that
the Federal EPA’s action delisting fossil fuel-fired power plants did not
conform to the procedures specified in the CAA. The Court vacated and
remanded the model federal rules for both new and existing coal-fired power
plants to the Federal EPA. Management is unable to predict how the
Federal EPA will respond to the remand. In addition, in 2005, the
Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that
requires further reductions in SO2 and
NOx
emissions and assists states developing new state implementation plans to meet
1997 national ambient air quality standards (NAAQS). CAIR reduces
regional emissions of SO2 and
NOx
(which can be transformed into PM and ozone) from power plants in the Eastern
U.S. (29 states and the District of Columbia). CAIR requires power
plants within these states to reduce emissions of SO2 by 50
percent by 2010, and by 65 percent by 2015. NOx emissions
will be subject to additional limits beginning in 2009, and will be reduced by a
total of 70 percent from current levels by 2015. Reduction of both
SO2
and NOx would be
achieved through a cap-and-trade program. In July 2008, the D.C.
Circuit Court of Appeals vacated the CAIR and remanded the rule to the Federal
EPA. Management is unable to predict how the Federal EPA will respond
to the remand which could be stayed or appealed to the U.S. Supreme
Court. The Federal EPA also issued revised NAAQS for both ozone and
PM 2.5
that are more stringent than the 1997 standards used to establish CAIR, which
could increase the levels of SO2 and
NOx
reductions required from the AEP System’s facilities.
In
anticipation of compliance with CAIR in 2009, I&M purchased $8 million of
annual CAIR NOx allowances
which are included in inventory as of June 30, 2008. The market value
of annual CAIR NOx allowances
decreased in the weeks following this court decision. Management
intends to seek recovery of the cost of purchased allowances. If the
recovery is denied, it would have an adverse effect on future results of
operations and cash flows. None of the other Registrant Subsidiaries
purchased any significant number of CAIR allowances. SO2 and
seasonal NOx allowances
allocated to the Registrant Subsidiaries’ facilities under the Acid Rain Program
and the NOX SIP Call
will still be required to comply with existing CAA programs that were not
affected by the court’s decision.
It is too
early to determine the full implication of these decisions on the AEP System’s
environmental compliance strategy. However, independent obligations
under the CAA, including obligations under future state implementation plan
submittals, and actions taken pursuant to the recent settlement of the NSR
enforcement action, are consistent with the actions included in the AEP System’s
least-cost CAIR compliance plan. Consequently, management does
not anticipate making any immediate changes in the near-term compliance plans as
a result of these court decisions.
Global
Climate Change
In July
2008, the Federal EPA issued an advance notice of proposed rulemaking (ANPR)
that requests comments on a wide variety of issues the agency is considering in
formulating its response to the U.S. Supreme Court’s decision in Massachusetts v.
EPA. In that case, the Court determined that CO2 is an “air
pollutant” and that the Federal EPA has authority to regulate mobile sources of
CO2
emissions under the CAA if appropriate findings are made. The Federal
EPA has identified a number of issues that could affect stationary sources, such
as electric generating plants, if the necessary findings are made for mobile
sources, including the potential regulation of CO2 emissions
for both new and existing stationary sources under the NSR programs of the
CAA. Management plans to submit comments and participate in any
subsequent regulatory development processes, but are unable to predict the
outcome of the Federal EPA’s administrative process or its impact on the AEP
System’s business. Also, additional legislative measures to address
CO2
and other GHGs have been introduced in Congress, and such legislative actions
could impact future decisions by the Federal EPA on CO2
regulation.
In
addition, the Federal EPA issued a proposed rule for the underground injection
and storage of CO2 captured
from industrial processes, including electric generating facilities, under the
Safe Drinking Water Act’s Underground Injection Control (UIC)
program. The proposed rules provide a comprehensive set of well
siting, design, construction, operation, closure and post-closure care
requirements. Management plans to submit comments and participate in
any subsequent regulatory development process, but are unable to predict the
outcome of the Federal EPA’s administrative process or its impact on the AEP
System’s business. Permitting for a demonstration project at the
Mountaineer Plant will proceed under the existing UIC rules.
Clean
Water Act Regulation
In 2004,
the Federal EPA issued a final rule requiring all large existing power plants
with once-through cooling water systems to meet certain standards to reduce
mortality of aquatic organisms pinned against the plant’s cooling water intake
screen or entrained in the cooling water. The standards vary based on
the water bodies from which the plants draw their cooling
water. Management expected additional capital and operating expenses,
which the Federal EPA estimated could be $193 million for the AEP System’s
plants. The Registrant Subsidiaries undertook site-specific studies
and have been evaluating site-specific compliance or mitigation measures that
could significantly change these cost estimates. The following table
shows the investment amount per Registrant Subsidiary.
|
|
Estimated
|
|
|
|
Compliance
|
|
|
|
Investments
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
|
$ |
21 |
|
CSPCo
|
|
|
|
19 |
|
I&M
|
|
|
|
118 |
|
OPCo
|
|
|
|
31 |
|
In
January 2007, the Second Circuit Court of Appeals issued a decision remanding
significant portions of the rule to the Federal EPA. In July 2007,
the Federal EPA suspended the 2004 rule, except for the requirement that
permitting agencies develop best professional judgment (BPJ) controls for
existing facility cooling water intake structures that reflect the best
technology available for minimizing adverse environmental impact. The
result is that the BPJ control standard for cooling water intake structures in
effect prior to the 2004 rule is the applicable standard for permitting agencies
pending finalization of revised rules by the Federal EPA. Management
cannot predict further action of the Federal EPA or what effect it may have on
similar requirements adopted by the states. The Registrant
Subsidiaries sought further review and filed for relief from the schedules
included in their permits.
In April
2008, the U.S. Supreme Court agreed to review decisions from the Second Circuit
Court of Appeals that limit the Federal EPA’s ability to weigh the retrofitting
costs against environmental benefits. Management is unable to predict
the outcome of this appeal.
Adoption of New Accounting
Pronouncements
In
September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair
value measurement of assets and liabilities and instruments measured at fair
value that are classified in shareholders’ equity. The statement
defines fair value, establishes a fair value measurement framework and expands
fair value disclosures. It emphasizes that fair value is market-based
with the highest measurement hierarchy level being market prices in active
markets. The standard requires fair value measurements be disclosed
by hierarchy level, an entity includes its own credit standing in the
measurement of its liabilities and modifies the transaction price
presumption. The standard also nullifies the consensus reached in
EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held
for Trading Purposes and Contracts Involved in Energy Trading and Risk
Management Activities” (EITF 02-3) that prohibited the recognition of trading
gains or losses at the inception of a derivative contract, unless the fair value
of such derivative is supported by observable market data. In
February 2008, the FASB issued FSP FAS 157-1 “Application of FASB Statement No.
157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address
Fair Value Measurements for Purposes of Lease Classification or Measurement
under Statement 13” which amends SFAS 157 to exclude SFAS 13 “Accounting for
Leases” and other accounting pronouncements that address fair value measurements
for purposes of lease classification or measurement under SFAS 13. In
February 2008, the FASB issued FSP FAS 157-2 “Effective Date of FASB Statement
No. 157” which delays the effective date of SFAS 157 to fiscal years beginning
after November 15, 2008 for all nonfinancial assets and nonfinancial
liabilities, except those that are recognized or disclosed at fair value in the
financial statements on a recurring basis (at least annually). The
provisions of SFAS 157 are applied prospectively, except for a) changes in fair
value measurements of existing derivative financial instruments measured
initially using the transaction price under EITF 02-3, b) existing hybrid
financial instruments measured initially at fair value using the transaction
price and c) blockage discount factors. The Registrant Subsidiaries
partially adopted SFAS 157 effective January 1, 2008. The Registrant
Subsidiaries will fully adopt SFAS 157 effective January 1, 2009 for items
within the scope of FSP FAS 157-2. Although the statement is applied
prospectively upon adoption, in accordance with the provisions of SFAS 157
related to EITF 02-3, APCo, CSPCo and OPCo reduced beginning retained earnings
by $440 thousand ($286 thousand, net of tax), $486 thousand ($316
thousand, net of tax) and $434 thousand ($282 thousand, net of tax),
respectively, for the transition adjustment. SWEPCo’s transition
adjustment was a favorable $16 thousand ($10 thousand, net of tax) adjustment to
beginning retained earnings. The impact of considering AEP’s credit
risk when measuring the fair value of liabilities, including derivatives, had an
immaterial impact on fair value measurements upon adoption. See “SFAS
157 “Fair Value Measurements” (SFAS 157)” section of Note 2.
In
February 2007, the FASB issued SFAS 159, permitting entities to choose to
measure many financial instruments and certain other items at fair
value. The standard also establishes presentation and disclosure
requirements designed to facilitate comparison between entities that choose
different measurement attributes for similar types of assets and
liabilities. If the fair value option is elected, the effect of the
first remeasurement to fair value is reported as a cumulative effect adjustment
to the opening balance of retained earnings. The statement is applied
prospectively upon adoption. The Registrant Subsidiaries adopted SFAS
159 effective January 1, 2008. At adoption, the Registrant
Subsidiaries did not elect the fair value option for any assets or
liabilities.
In March
2007, the FASB ratified EITF 06-10, a consensus on collateral assignment
split-dollar life insurance arrangements in which an employee owns and controls
the insurance policy. Under EITF 06-10, an employer should recognize
a liability for the postretirement benefit related to a collateral assignment
split-dollar life insurance arrangement in accordance with SFAS 106 “Employers'
Accounting for Postretirement Benefits Other Than Pension” or Accounting
Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has
agreed to maintain a life insurance policy during the employee's retirement or
to provide the employee with a death benefit based on a substantive arrangement
with the employee. In addition, an employer should recognize and
measure an asset based on the nature and substance of the collateral assignment
split-dollar life insurance arrangement. EITF 06-10 requires
recognition of the effects of its application as either (a) a change in
accounting principle through a cumulative effect adjustment to retained earnings
or other components of equity or net assets in the statement of financial
position at the beginning of the year of adoption or (b) a change in accounting
principle through retrospective application to all prior periods. The
Registrant Subsidiaries adopted EITF 06-10 effective January 1,
2008. The impact of this standard was an unfavorable cumulative
effect adjustment, net of tax, to beginning retained earnings as
follows:
|
|
Retained
|
|
|
|
|
|
Earnings
|
|
Tax
|
|
Company
|
|
Reduction
|
|
Amount
|
|
|
|
(in
thousands)
|
|
APCo
|
|
|
$ |
2,181 |
|
|
$ |
1,175 |
|
CSPCo
|
|
|
|
1,095 |
|
|
|
589 |
|
I&M
|
|
|
|
1,398 |
|
|
|
753 |
|
OPCo
|
|
|
|
1,864 |
|
|
|
1,004 |
|
PSO
|
|
|
|
1,107 |
|
|
|
596 |
|
SWEPCo
|
|
|
|
1,156 |
|
|
|
622 |
|
In June
2007, the FASB ratified the EITF Issue No. 06-11 “Accounting for Income Tax
Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11), consensus on
the treatment of income tax benefits of dividends on employee share-based
compensation. The issue is how a company should recognize the income
tax benefit received on dividends that are paid to employees holding
equity-classified nonvested shares, equity-classified nonvested share units or
equity-classified outstanding share options and charged to retained earnings
under SFAS 123R, “Share-Based Payments.” Under EITF 06-11, a realized
income tax benefit from dividends or dividend equivalents that are charged to
retained earnings and are paid to employees for equity-classified nonvested
equity shares, nonvested equity share units and outstanding equity share options
should be recognized as an increase to additional paid-in
capital. The Registrant Subsidiaries adopted EITF 06-11 effective
January 1, 2008. EITF 06-11 is applied prospectively to the income
tax benefits of dividends on equity-classified employee share-based payment
awards that are declared in fiscal years after December 15, 2007. The
adoption of this standard had an immaterial impact on the Registrant
Subsidiaries’ financial statements.
In April
2007, the FASB issued FSP FIN 39-1 “Amendment of FASB Interpretation No. 39”
(FIN 39-1). It amends FASB Interpretation No. 39 “Offsetting of
Amounts Related to Certain Contracts” by replacing the interpretation’s
definition of contracts with the definition of derivative instruments per SFAS
133. It also requires entities that offset fair values of derivatives
with the same party under a netting agreement to net the fair values (or
approximate fair values) of related cash collateral. The entities
must disclose whether or not they offset fair values of derivatives and related
cash collateral and amounts recognized for cash collateral payables and
receivables at the end of each reporting period. The Registrant
Subsidiaries adopted FIN 39-1 effective January 1, 2008. This
standard changed the method of netting certain balance sheet amounts and reduced
assets and liabilities. It requires retrospective application as a
change in accounting principle. See “FSP FIN 39-1 “Amendment of FASB
Interpretation No. 39” (FIN 39-1)” section of Note 2. Consequently,
the Registrant Subsidiaries reduced total assets and liabilities on their
December 31, 2007 balance sheet as follows:
Company
|
|
(in
thousands)
|
|
APCo
|
|
$
|
7,646
|
|
CSPCo
|
|
|
4,423
|
|
I&M
|
|
|
4,251
|
|
OPCo
|
|
|
5,234
|
|
PSO
|
|
|
187
|
|
SWEPCo
|
|
|
229
|
|
During
the second quarter of 2008, management, including the principal executive
officer and principal financial officer of each of AEP, APCo, CSPCo, I&M,
OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’
disclosure controls and procedures. Disclosure controls and
procedures are defined as controls and other procedures of the Registrants that
are designed to ensure that information required to be disclosed by the
Registrants in the reports that they file or submit under the Exchange Act are
recorded, processed, summarized and reported within the time periods specified
in the SEC’s rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that
information required to be disclosed by the Registrants in the reports that they
file or submit under the Exchange Act is accumulated and communicated to the
Registrants’ management, including the principal executive and principal
financial officers, or persons performing similar functions, as appropriate to
allow timely decisions regarding required disclosure.
As of
June 30, 2008 these officers concluded that the disclosure controls and
procedures in place are effective and provide reasonable assurance that the
disclosure controls and procedures accomplished their objectives. The
Registrants continually strive to improve their disclosure controls and
procedures to enhance the quality of their financial reporting and to maintain
dynamic systems that change as events warrant.
There was
no change in the Registrants’ internal control over financial reporting (as such
term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during
the second quarter of 2008 that materially affected, or is reasonably likely to
materially affect, the Registrants’ internal control over financial
reporting.
Item
1. Legal
Proceedings
For a
discussion of material legal proceedings, see Note 4, Commitments, Guarantees and
Contingencies, incorporated herein by reference.
Item
1A. Risk
Factors
Our
Annual Report on Form 10-K for the year ended December 31, 2007 includes a
detailed discussion of our risk factors. The information presented
below amends and restates in their entirety certain of those risk factors that
have been updated and should be read in conjunction with the risk factors and
information disclosed in our 2007 Annual Report on Form 10-K.
General
Risks of Our Regulated Operations
Our request for rate recovery in
Oklahoma may not be approved. (Applies to AEP and
PSO)
In July
2008, PSO filed an application with the OCC to increase its base rates by $133
million on an annual basis (including an estimated $16 million that is being
recovered through a rider). The proposed revenue requirement reflects
a return on equity of 11.25%. If the OCC denies all or part of the
requested rate recovery, it could have an adverse effect on future results of
operations, cash flows and financial condition.
Our request for rate recovery in Ohio
may not be approved. (Applies to AEP, OPCo and
CSPCo)
In July
2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to
establish rates for 2009 through 2011. CSPCo and OPCo each requested
an annual rate increase for 2009 through 2011 that would not exceed
approximately 15% per year. A significant portion of the requested
increases results from the implementation of a fuel cost recovery mechanism that
primarily includes fuel costs, purchased power costs including renewable energy,
consumables such as urea, other variable production costs and gains and losses
on sales of emission allowances. Management expects a PUCO decision
on the ESP filings in the fourth quarter of 2008. If the PUCO denies all or part
of the requested rate recovery, it could have an adverse effect on future
results of operations, cash flows and financial condition.
Risks
Related to Owning and Operating Generation Assets and Selling Power
The different regional power markets
in which we compete or will compete in the future have changing transmission
regulatory structures, which could affect our performance in these
regions. (Applies to AEP, APCo, CSPCo, I&M
and OPCo.)
FERC
allows utilities to sell wholesale power at market-based rates if they can
demonstrate that they lack market power in the markets in which they
participate. In December 2007, AEP filed its most recent triennial
update. In 2008, the PUCO filed comments suggesting that FERC should
further investigate whether certain utilities, including AEP, continue to pass
FERC’s indicative screens for the lack of market power in
PJM. Certain industrial retail customers also urged FERC to further
investigate this matter.
If FERC
limits AEP’s ability to sell power at market based rates in PJM, it could have
an adverse effect on future off-system sales margins, results of operations and
cash flows.
Our costs of compliance with
environmental laws are significant and the cost of compliance with future
environmental laws could harm our cash flow and profitability or cause some of
our electric generating units to be uneconomical to maintain or operate.
(Applies to each
registrant.)
Our
operations are subject to extensive federal, state and local environmental
statutes, rules and regulations relating to air quality, water quality, waste
management, natural resources and health and safety. Emissions of
nitrogen and sulfur oxides, mercury and particulates from fossil fueled
generating plants are potentially subject to increased regulations, controls and
mitigation expenses. Compliance with these legal requirements
requires us to commit significant capital toward environmental monitoring,
installation of pollution control equipment, emission fees and permits at all of
our facilities. These expenditures have been significant in the past,
and we expect that they will increase in the future. Further,
environmental advocacy groups, other organizations and some agencies in the
United States are focusing considerable attention on CO2 emissions
from power generation facilities and their potential role in climate
change. Although several bills have been introduced in Congress that
would compel CO2 emission
reductions, none have advanced through the legislature. In April 2007
the U.S. Supreme Court determined that CO2 is an “air
pollutant” and that the Federal EPA has authority to regulate CO2 emissions
under the CAA. In July 2008 the Federal EPA issued an advance notice
of proposed rulemaking (ANPR) that requests comments on a wide variety of issues
in response to the U.S. Supreme Court’s decision. The ANPR could lead
to regulations limiting the emissions of CO2 from our
generating plants. Costs of compliance with environmental regulations
could adversely affect our results of operations and financial position,
especially if emission and/or discharge limits are tightened, more extensive
permitting requirements are imposed, additional substances become regulated and
the number and types of assets we operate increase. All of our
estimates are subject to significant uncertainties about the outcome of several
interrelated assumptions and variables, including timing of implementation,
required levels of reductions, allocation requirements of the new rules and our
selected compliance alternatives. As a result, we cannot estimate our
compliance costs with certainty. The actual costs to comply could
differ significantly from our estimates. All of the costs are
incremental to our current investment base and operating cost
structure. In addition, any legal obligation that would require us to
substantially reduce our emissions beyond present levels could require extensive
mitigation efforts and, in the case of CO2
legislation, would raise uncertainty about the future viability of fossil fuels,
particularly coal, as an energy source for new and existing electric generation
facilities. While we expect to recover our expenditures for pollution
control technologies, replacement generation and associated operating costs from
customers through regulated rates (in regulated jurisdictions) or market prices
(in Ohio and Texas), without such recovery those costs could adversely affect
future results of operations and cash flows, and possibly financial
condition.
Risks
Related to Market, Economic or Financial Volatility
Downgrades in our credit ratings
could negatively affect our ability to access capital and/or to operate our
power trading businesses. (Applies to each
registrant.)
Since the
bankruptcy of Enron, the credit ratings agencies have periodically reviewed our
capital structure and the quality and stability of our earnings. Any
negative ratings actions could constrain the capital available to our industry
and could limit our access to funding for our operations. Our
business is capital intensive, and we are dependent upon our ability to access
capital at rates and on terms we determine to be attractive. If our
ability to access capital becomes significantly constrained, our interest costs
will likely increase and our financial condition could be harmed and future
results of operations could be adversely affected.
If
Moody’s or S&P were to downgrade the long-term rating of any of the
securities of the registrants, particularly below
investment grade, the borrowing costs of that registrant would increase, which
would diminish its financial results. In addition, the registrant’s
potential pool of investors and funding sources could decrease. In
the first quarter of 2008, Fitch downgraded the senior unsecured debt rating of
PSO and SWEPCo to BBB+ with stable outlook. Moody’s placed the senior
unsecured debt rating of APCo, OPCo, SWEPCo and TCC on negative outlook in
January 2008. Moody’s assigns the following ratings to the senior
unsecured debt of these companies: APCo Baa2, OPCo A3, SWEPCo Baa1
and TCC Baa2.
Our power
trading business relies on the investment grade ratings of our individual public
utility subsidiaries’ senior unsecured long-term debt. Most of our
counterparties require the creditworthiness of an investment grade entity to
stand behind transactions. If those ratings were to decline below
investment grade, our ability to operate our power trading business profitably
would be diminished because we would likely have to deposit cash or cash-related
instruments which would reduce our profits.
In Ohio, we have limited ability to
pass on our fuel costs to our customers. (Applies to AEP, CSPCo
and OPCo.)
See risk
factor above “Our request for rate recovery in Ohio may not be
approved.”
Risks
Relating to State Restructuring
In Ohio, our future rates are
uncertain. (Applies to
AEP, OPCo and CSPCo.)
See risk
factor above “Our request for rate recovery in Ohio may not be
approved.”
Item
2. Unregistered Sales of Equity
Securities and Use of Proceeds
The
following table provides information about purchases by AEP (or its
publicly-traded subsidiaries) during the quarter ended June 30, 2008 of equity
securities that are registered by AEP (or its publicly-traded subsidiaries)
pursuant to Section 12 of the Exchange Act:
ISSUER
PURCHASES OF EQUITY SECURITIES
Period
|
|
Total
Number
of
Shares
Purchased
|
|
Average
Price
Paid
per Share
|
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
|
|
Maximum
Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased
Under the Plans or Programs
|
|
04/01/08
– 04/30/08
|
|
-
|
|
$
|
-
|
|
-
|
|
$
|
-
|
|
05/01/08
– 05/31/08
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
06/01/08
– 06/30/08
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
Item
4. Submission of
Matters to a Vote of Security Holders
AEP
The
annual meeting of shareholders was held in Shreveport, Louisiana, on April 22,
2008. The holders of shares entitled to vote at the meeting or their
proxies cast votes at the meeting with respect to the following three matters,
as indicated below:
1.
|
Election
of eleven directors to hold office until the next annual meeting and until
their successors are duly elected. Each nominee for director
received the votes of shareholders as
follows:
|
|
|
Number
of Shares Voted For
|
|
|
Number
of Shares Abstaining
|
|
|
|
|
|
|
|
|
E.
R. Brooks
|
|
|
312,075,636 |
|
|
|
9,048,078 |
|
Donald
M. Carlton
|
|
|
312,678,087 |
|
|
|
8,445,627 |
|
Ralph
D. Crosby, Jr.
|
|
|
313,030,107 |
|
|
|
8,093,607 |
|
John
P. DesBarres
|
|
|
298,693,953 |
|
|
|
22,429,761 |
|
Linda
A. Goodspeed
|
|
|
312,709,888 |
|
|
|
8,413,826 |
|
Thomas
E. Hoaglin
|
|
|
311,691,406 |
|
|
|
9,432,308 |
|
Lester
A. Hudson, Jr.
|
|
|
312,928,042 |
|
|
|
8,195,672 |
|
Michael
G. Morris
|
|
|
298,827,464 |
|
|
|
22,296,250 |
|
Lionel
L. Nowell, III
|
|
|
311,500,225 |
|
|
|
9,623,489 |
|
Richard
L. Sandor
|
|
|
308,409,310 |
|
|
|
12,714,404 |
|
Kathryn
D. Sullivan
|
|
|
310,429,848 |
|
|
|
10,693,866 |
|
|
2.
|
Ratification
of the appointment of the firm of Deloitte & Touche LLP as the
independent registered public accounting firm for 2008. The
proposal was approved by a vote of the shareholders as
follows:
|
Votes
FOR
|
|
|
313,470,119 |
|
Votes
AGAINST
|
|
|
4,721,969 |
|
Votes
ABSTAINED
|
|
|
2,931,626 |
|
APCo
The
annual meeting of stockholders was held on April 22, 2008 at 1 Riverside Plaza,
Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR each
of the following ten persons for election as directors and there were no votes
withheld and such persons were elected directors to hold office for one year or
until their successors are elected and qualify:
Nicholas
K. Akins
|
Robert
P. Powers
|
Carl
L. English
|
Stephen
P. Smith
|
John
B. Keane
|
Brian
X. Tierney
|
Holly
K. Koeppel
|
Susan
Tomasky
|
Michael
G. Morris
|
Dennis
E. Welch
|
CSPCo
Pursuant
to action by written consent in lieu of an annual meeting of the sole
shareholder dated April 28, 2008, the following ten persons were elected
directors to hold office for one year or until their successors are elected and
qualify:
Nicholas
K. Akins
|
Robert
P. Powers
|
Carl
L. English
|
Stephen
P. Smith
|
John
B. Keane
|
Brian
X. Tierney
|
Holly
K. Koeppel
|
Susan
Tomasky
|
Michael
G. Morris
|
Dennis
E. Welch
|
I&M
Pursuant
to action by written consent in lieu of an annual meeting of the sole
shareholder dated July 24, 2008, the following fifteen persons were elected
directors to hold office for one year or until their successors are elected and
qualify:
Nicholas
K. Akins
|
Marc
E. Lewis
|
Kent
D. Curry
|
Susanne
M. Moorman Rowe
|
John
E. Ehler
|
Michael
G. Morris
|
Carl
L. English
|
Helen
J. Murray
|
Allen
R. Glassburn
|
Robert
P. Powers
|
JoAnn
M. Grevenow
|
Brian
X. Tierney
|
Patrick
C. Hale
|
Susan
Tomasky
|
Holly
K. Koeppel
|
|
OPCo
The
annual meeting of shareholders was held on May 6, 2008 at 1 Riverside Plaza,
Columbus, Ohio. At the meeting there were 27,952,473 votes were cast
FOR each of the following ten persons for election as directors and there were
no votes withheld and such persons were elected directors to hold office for one
year or until their successors are elected and qualify:
Nicholas
K. Akins
|
Robert
P. Powers
|
Carl
L. English
|
Stephen
P. Smith
|
John
B. Keane
|
Brian
X. Tierney
|
Holly
K. Koeppel
|
Susan
Tomasky
|
Michael
G. Morris
|
Dennis
E. Welch
|
PSO
Pursuant
to action by written consent in lieu of an annual meeting of the sole
shareholder dated July 24, 2008, the following ten persons were elected
directors to hold office for one year or until their successors are elected and
qualify:
Nicholas
K. Akins
|
Michael
G. Morris
|
Carl
L. English
|
Richard
E. Munczinski
|
John
B. Keane
|
Robert
P. Powers
|
Holly
K. Koeppel
|
Susan
Tomasky
|
Venita
McCellon-Allen
|
Dennis
E. Welch
|
SWEPCo
Pursuant
to action by written consent in lieu of an annual meeting of the sole
shareholder dated July 24, 2008, the following ten persons were elected
directors to hold office for one year or until their successors are elected and
qualify:
Nicholas
K. Akins
|
Michael
G. Morris
|
Carl
L. English
|
Richard
E. Munczinski
|
John
B. Keane
|
Robert
P. Powers
|
Holly
K. Koeppel
|
Susan
Tomasky
|
Venita
McCellon-Allen
|
Dennis
E. Welch
|
Item
5. Other
Information
NONE
Item
6. Exhibits
PSO
and SWEPCo
3(a) –
Certificate of Amendment to Restated Certificate of Incorporation.
CSPCo
and OPCo
3(b) –
Amended Code of Regulations.
AEP,
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
12 –
Computation of Consolidated Ratio of Earnings to Fixed Charges.
AEP,
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
31(a) –
Certification of Chief Executive Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31(b) –
Certification of Chief Financial Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
AEP,
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
32(a) –
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code.
32(b) –
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code.
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 signature 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/Joseph M.
Buonaiuto
Joseph M.
Buonaiuto
Controller
and Chief Accounting Officer
APPALACHIAN
POWER COMPANY
COLUMBUS
SOUTHERN POWER COMPANY
INDIANA
MICHIGAN POWER COMPANY
OHIO
POWER COMPANY
PUBLIC
SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN
ELECTRIC POWER COMPANY
By: /s/Joseph M.
Buonaiuto
Joseph M.
Buonaiuto
Controller
and Chief Accounting Officer
Date: August
1, 2008