q308aep10q.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE
SECURITIES EXCHANGE ACT OF 1934
For The
Quarterly Period Ended September 30,
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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|
|
|
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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.
|
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.
|
Large
accelerated filer Accelerated
filer
Non-accelerated
filer X Smaller
reporting company
|
|
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
October
30, 2008
|
|
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American
Electric Power Company, Inc.
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403,554,634
|
|
($6.50
par value)
|
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)
|
Public
Service Company of Oklahoma
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9,013,000
|
|
($15
par value)
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Southwestern
Electric Power Company
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7,536,640
|
|
($18
par value)
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AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX
TO QUARTERLY REPORTS ON FORM 10-Q
September
30, 2008
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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
|
|
Ohio
Power Company Consolidated:
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Management’s
Financial Discussion and Analysis
|
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
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
Condensed
Financial Statements
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
Southwestern
Electric Power Company Consolidated:
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Management’s
Financial Discussion and Analysis
|
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
10(a) (AEP)
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Exhibit
10(b) (AEP)
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Exhibit
10(c) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
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Exhibit
10(d) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
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Exhibit
10(e) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
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Exhibit
10(f) (AEP, APCo, CSPCo, I&M, OPCo, PSO,
SWEPCo)
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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
Power Pool
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Members
are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the
generation, cost of generation and resultant wholesale off-system sales of
the member companies.
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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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Cook
Plant
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Donald
C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by
I&M.
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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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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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ETT
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Electric
Transmission Texas, LLC, a 50% equity interest joint venture with
MidAmerican Energy Holding Company formed to own and operate electric
transmission facilities in ERCOT.
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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, a financial instrument that entitles the holder to
receive compensation for
certain
congestion-related
transmission charges that arise when the power grid is congested
resulting in
differences in locational
prices.
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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.
|
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.
|
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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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.
|
PM
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Particulate
Matter.
|
PSO
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|
Public
Service Company of Oklahoma, an AEP electric utility
subsidiary.
|
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
|
|
AEP
subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO
and SWEPCo.
|
REP
|
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Texas
Retail Electric Provider.
|
Risk
Management Contracts
|
|
Trading
and nontrading derivatives, including those derivatives designated as cash
flow and fair value hedges.
|
Rockport
Plant
|
|
A
generating plant, consisting of two 1,300 MW coal-fired generating units
near Rockport, Indiana, owned by AEGCo and I&M.
|
RSP
|
|
Rate
Stabilization Plan.
|
RTO
|
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Regional
Transmission Organization.
|
S&P
|
|
Standard
and Poor’s.
|
SCR
|
|
Selective
Catalytic Reduction.
|
SEC
|
|
United
States Securities and Exchange Commission.
|
SECA
|
|
Seams
Elimination Cost Allocation.
|
SFAS
|
|
Statement
of Financial Accounting Standards issued by the Financial Accounting
Standards Board.
|
SFAS
71
|
|
Statement
of Financial Accounting Standards No. 71, “Accounting for the Effects of
Certain Types of Regulation.”
|
SFAS
133
|
|
Statement
of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities.”
|
SNF
|
|
Spent
Nuclear Fuel.
|
SO2
|
|
Sulfur
Dioxide.
|
SPP
|
|
Southwest
Power Pool.
|
Stall
Unit
|
|
J.
Lamar Stall Unit at Arsenal Hill Plant.
|
Sweeny
|
|
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.
|
SWEPCo
|
|
Southwestern
Electric Power Company, an AEP electric utility
subsidiary.
|
TCC
|
|
AEP
Texas Central Company, an AEP electric utility
subsidiary.
|
TEM
|
|
SUEZ
Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing,
Inc.).
|
Texas
Restructuring Legislation
|
|
Legislation
enacted in 1999 to restructure the electric utility industry in
Texas.
|
TNC
|
|
AEP
Texas North Company, an AEP electric utility
subsidiary.
|
True-up
Proceeding
|
|
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.
|
Turk
Plant
|
|
John
W. Turk, Jr. Plant.
|
Utility
Money Pool
|
|
AEP
System’s Utility Money Pool.
|
VaR
|
|
Value
at Risk, a method to quantify risk exposure.
|
Virginia
SCC
|
|
Virginia
State Corporation Commission.
|
WPCo
|
|
Wheeling
Power Company, an AEP electric distribution subsidiary.
|
WVPSC
|
|
Public
Service Commission of West
Virginia.
|
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 cancelled) 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 or contraction, 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 impacting 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
markets.
|
·
|
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 and the impact on future funding
requirements.
|
·
|
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
|
|
|
|
|
|
(in
millions)
|
|
|
|
APCo
|
|
Virginia
|
|
$
|
208
|
|
October 2008
(a)
|
|
PSO
|
|
Oklahoma
|
|
|
117
|
(b)
|
February
2009
|
|
I&M
|
|
Indiana
|
|
|
80
|
|
June
2009
|
|
(a)
|
Subject
to refund. An
October settlement agreement of $168 million is pending with the Virginia
SCC.
|
(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.
Credit
Markets
In recent
months, the world and U.S. economies have experienced significant
slowdowns. These economic slowdowns have impacted and will continue
to impact our residential, commercial and industrial sales. Concurrently, the
financial markets have become increasingly unstable and constrained at both a
global and domestic level. This systemic marketplace distress is
impacting our access to capital, our liquidity, asset valuations in our trust
funds, the creditworthy status of our customers, suppliers and trading partners
and our cost of capital. Our financial staff actively manages these
factors with oversight from our risk committee. The uncertainties in
the credit markets could have significant implications on our subsidiaries since
they rely on continuing access to capital to fund operations and capital
expenditures.
The
current credit markets are constraining our ability to issue new debt, including
commercial paper, and refinance existing debt. Approximately $120
million and $300 million of our $16 billion of long-term debt as of September
30, 2008 will mature in the remainder of 2008 and 2009,
respectively. We intend to refinance these maturities. To
support our operations, we have $3.9 billion in aggregate credit facility
commitments. These commitments include 27 different banks with no
bank having more than 10% of our total bank commitments. In September
2008 and October 2008, we borrowed $600 million and $1.4 billion, respectively,
under our credit agreements to enhance our cash position during this period of
market disruptions. In October 2008, we also renewed our $600 million
sale of receivables agreement through October 2009. At September 30,
2008, our available liquidity was approximately $3 billion.
We cannot
predict the length of time the current credit situation will continue or the
impact on our future operations and our ability to issue debt at reasonable
interest rates. However, when market conditions improve, we plan to
repay the amounts drawn under the credit facilities, re-enter the commerical
paper market and issue other long-term debt. If there is not an
improvement in access to capital, we believe that we have adequate liquidity to
support our planned business operations and construction program
through 2009.
We have
significant investments in several trust funds to provide for future payments of
pensions, OPEB, nuclear decommissioning and spent nuclear fuel
disposal. All of our trust funds’ investments are well-diversified
and managed in compliance with all laws and regulations. The value of
the investments in these trusts has declined due to the decreases in the equity
and fixed income markets. Although the asset values are currently
lower, this has not affected the funds’ ability to make their required
payments. As of September 30, 2008, the decline in pension asset
values will not require us to make a contribution in 2008 or 2009.
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. Our risk management
organization monitors these exposures on a daily basis to limit our economic and
financial statement impact on a counterparty basis. At September 30,
2008, our credit exposure net of collateral was approximately $827 million of
which approximately 84% is to investment grade counterparties. At
September 30, 2008, our exposure to financial institutions was $145
million, which represents 18% of our total credit exposure net of collateral
(all investment grade).
Capital
Expenditures
Due to
recent credit market instability, we are currently reviewing our projections for
capital expenditures from our previous projection of $6.75 billion for 2009
through 2010. We plan to identify reductions of approximately $750
million for 2009. We are evaluating possible additional
capital reductions for 2010. We are also reviewing our
projections for operation and maintenance expense. Our intent is to
keep operation and maintenance expense flat in 2009 as compared to
2008.
Cook
Plant Unit 1 Fire and Shutdown
Cook
Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in
Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due
to turbine vibrations likely caused by blade failure which resulted in
a fire on the electric generator. This equipment is in the turbine
building and is separate and isolated from the nuclear reactor. The
steam turbines that caused the vibration were installed in 2006 and are under
warranty from the vendor. The warranty provides for the replacement
of the turbines if the damage was caused by a defect in the design or assembly
of the turbines. I&M is also working with its insurance company,
Nuclear Electric Insurance Limited (NEIL), and turbine vendor to evaluate
the extent of the damage resulting from the incident and the costs to return the
unit to service. We cannot estimate the ultimate costs of the outage
at this time. Management believes that I&M should recover a
significant portion of these costs through the turbine vendor’s warranty,
insurance and the regulatory process. Our
preliminary analysis indicates that Unit 1 could resume operations as early as
late first quarter/early second quarter of 2009 or as late as the second half of
2009, depending upon whether the damaged components can be repaired or whether
they need to be replaced.
I&M
maintains property insurance through NEIL with a $1 million
deductible. I&M also maintains a separate accidental outage
policy with NEIL whereby, after a 12 week deductible period, I&M is
entitled to weekly payments of $3.5 million during the outage period for a
covered loss. If the ultimate costs of the incident are not covered
by warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.
Hurricanes
During
the third quarter of 2008, our CSPCo, OPCo, SWEPCo and TCC service territories
were significantly impacted by Hurricanes Dolly, Gustav and/or
Ike. Through September 30, 2008, we had incurred $54 million in total
incremental operation and maintenance costs related to the three
hurricanes. Since we believe that cost recovery related to the
hurricanes is probable for most of these costs in our CSPCo, OPCo, and TCC
service territories, we recorded $37 million in regulatory assets for these
hurricane costs as of September 30, 2008. We intend
to pursue the recovery of $11 million of incremental hurricane costs incurred in
our SWEPCo service territory.
New
Generation
In May
2006, we announced plans to build the Stall Unit, a new intermediate load, 500
MW, natural gas-fired generating unit at SWEPCo’s existing Arsenal Hill Plant
location in Shreveport, Louisiana. SWEPCo has received approvals from
the Louisiana Public Service Commission (LPSC) and the Public Utility Commission
of Texas (PUCT) to construct the Stall Unit and is currently waiting for
approval from the APSC. The Stall Unit is estimated to cost $378
million, excluding AFUDC, and is expected to be in-service in
mid-2010.
In August
2006, we announced plans to jointly build the Turk Plant, a new base load, 600
MW, pulverized coal, ultra-supercritical generating unit in
Arkansas. SWEPCo has received approvals from the APSC and the LPSC to
construct the Turk Plant. In August 2008, the PUCT issued an order
approving the Turk Plant subject to certain conditions, including the capping of
capital costs of the Turk Plant at the $1.5 billion projected construction
cost. SWEPCo is also working with the Arkansas Department of
Environmental Quality for the approval of an air permit and the U.S. Army Corps
of Engineers for the approval of a wetlands and stream impact permit. Once
SWEPCo receives the air permit, they will commence construction. The
Turk Plant is estimated to cost $1.5 billion, excluding AFUDC, with SWEPCo’s
portion estimated to cost $1.1 billion. If these permits are approved
on a timely basis, the plant is expected to be in-service in 2012.
Fuel
Costs
We
currently estimate 2008 coal prices to increase by approximately 28% due to
escalating domestic prices and increased needs, primarily in the
east. We had initially 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. We have price risk exposure in Ohio, representing
approximately 20% of our fuel costs, since we do not have an active fuel cost
recovery mechanism. 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.
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.
|
AEP
River 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 nine months ended September 30,
2008 and 2007.
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Utility
Operations
|
|
$ |
357 |
|
|
$ |
388 |
|
|
$ |
1,030 |
|
|
$ |
879 |
|
AEP River
Operations
|
|
|
11 |
|
|
|
18 |
|
|
|
21 |
|
|
|
40 |
|
Generation
and Marketing
|
|
|
16 |
|
|
|
3 |
|
|
|
43 |
|
|
|
17 |
|
All
Other (a)
|
|
|
(10 |
) |
|
|
(2 |
) |
|
|
133 |
|
|
|
(1 |
) |
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$ |
374 |
|
|
$ |
407 |
|
|
$ |
1,227 |
|
|
$ |
935 |
|
(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 of 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
Third Quarter of 2008
Compared to Third Quarter of 2007
Income
Before Discontinued Operations and Extraordinary Loss in 2008 decreased $33
million compared to 2007 primarily due to a decrease in Utility Operations
segment earnings of $31 million. The decrease in Utility Operations
segment earnings primarily relates to an increase in fuel and consumables
expense in Ohio and a decrease in cooling degree days throughout our service
territories, partially offset by increases in retail margins due to rate
increases in Ohio, Virginia, West Virginia, Texas and Oklahoma.
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 403
million as of September 30, 2008.
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss in 2008 increased $292
million compared to 2007 primarily due to income of $163 million (net of tax)
from the cash settlement received in 2008 related to a power purchase-and-sale
agreement with TEM and an increase in Utility Operations segment earnings of
$151 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 and higher off-system
sales, partially offset by higher interest and fuel expenses.
Average
basic shares outstanding increased to 402 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 403
million as of September 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 Nine Months Ended September 30, 2008 and 2007
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Revenues
|
|
$ |
3,968 |
|
|
$ |
3,600 |
|
|
$ |
10,575 |
|
|
$ |
9,587 |
|
Fuel
and Purchased Power
|
|
|
1,841 |
|
|
|
1,413 |
|
|
|
4,428 |
|
|
|
3,641 |
|
Gross
Margin
|
|
|
2,127 |
|
|
|
2,187 |
|
|
|
6,147 |
|
|
|
5,946 |
|
Depreciation
and Amortization
|
|
|
379 |
|
|
|
374 |
|
|
|
1,099 |
|
|
|
1,122 |
|
Other
Operating Expenses
|
|
|
1,034 |
|
|
|
1,037 |
|
|
|
3,001 |
|
|
|
2,985 |
|
Operating
Income
|
|
|
714 |
|
|
|
776 |
|
|
|
2,047 |
|
|
|
1,839 |
|
Other
Income, Net
|
|
|
46 |
|
|
|
27 |
|
|
|
135 |
|
|
|
72 |
|
Interest
Charges and Preferred Stock Dividend Requirements
|
|
|
225 |
|
|
|
213 |
|
|
|
653 |
|
|
|
599 |
|
Income
Tax Expense
|
|
|
178 |
|
|
|
202 |
|
|
|
499 |
|
|
|
433 |
|
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$ |
357 |
|
|
$ |
388 |
|
|
$ |
1,030 |
|
|
$ |
879 |
|
Summary
of Selected Sales Data
For
Utility Operations
For
the Three and Nine Months Ended September 30, 2008 and 2007
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
Energy/Delivery
Summary
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions of KWH)
|
|
Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
12,754 |
|
|
|
13,749 |
|
|
|
37,084 |
|
|
|
38,015 |
|
Commercial
|
|
|
10,794 |
|
|
|
11,164 |
|
|
|
30,249 |
|
|
|
30,750 |
|
Industrial
|
|
|
14,761 |
|
|
|
14,697 |
|
|
|
44,171 |
|
|
|
43,110 |
|
Miscellaneous
|
|
|
668 |
|
|
|
686 |
|
|
|
1,916 |
|
|
|
1,932 |
|
Total
Retail
|
|
|
38,977 |
|
|
|
40,296 |
|
|
|
113,420 |
|
|
|
113,807 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
|
13,130 |
|
|
|
13,493 |
|
|
|
35,728 |
|
|
|
31,648 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivery
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
Wires – Energy delivered to customers served by
AEP’s Texas Wires Companies
|
|
|
7,961 |
|
|
|
7,721 |
|
|
|
20,916 |
|
|
|
20,297 |
|
Total
KWHs
|
|
|
60,068 |
|
|
|
61,510 |
|
|
|
170,064 |
|
|
|
165,752 |
|
Cooling
degree days and heating degree days are metrics commonly used in the utility
industry as a measure of the impact of weather on net income. In
general, degree day changes in our eastern region have a larger effect on net
income 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 Weather Data
Summary
of Heating and Cooling Degree Days for Utility Operations
For
the Three and Nine Months Ended September 30, 2008 and 2007
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
degree days)
|
|
Weather
Summary
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Heating (a)
|
|
|
- |
|
|
|
2 |
|
|
|
1,960 |
|
|
|
2,041 |
|
Normal
– Heating (b)
|
|
|
7 |
|
|
|
7 |
|
|
|
1,950 |
|
|
|
1,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Cooling (c)
|
|
|
651 |
|
|
|
808 |
|
|
|
924 |
|
|
|
1,189 |
|
Normal
– Cooling (b)
|
|
|
687 |
|
|
|
685 |
|
|
|
969 |
|
|
|
963 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Region (d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Heating (a)
|
|
|
- |
|
|
|
- |
|
|
|
989 |
|
|
|
994 |
|
Normal
– Heating (b)
|
|
|
2 |
|
|
|
2 |
|
|
|
967 |
|
|
|
993 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Cooling (c)
|
|
|
1,250 |
|
|
|
1,406 |
|
|
|
1,951 |
|
|
|
2,084 |
|
Normal
– Cooling (b)
|
|
|
1,402 |
|
|
|
1,411 |
|
|
|
2,074 |
|
|
|
2,084 |
|
(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.
|
Third Quarter of 2008
Compared to Third Quarter of 2007
Reconciliation
of Third Quarter of 2007 to Third Quarter of 2008
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss
(in
millions)
Third
Quarter of 2007
|
|
|
|
|
$ |
388 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(81 |
) |
|
|
|
|
Off-system
Sales
|
|
|
(7 |
) |
|
|
|
|
Transmission
Revenues
|
|
|
4 |
|
|
|
|
|
Other
|
|
|
24 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(60 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
- |
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(5 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
2 |
|
|
|
|
|
Carrying
Costs Income
|
|
|
7 |
|
|
|
|
|
Interest
Income
|
|
|
8 |
|
|
|
|
|
Other
Income, Net
|
|
|
5 |
|
|
|
|
|
Interest
and Other Charges
|
|
|
(12 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2008
|
|
|
|
|
|
$ |
357 |
|
Income
from Utility Operations Before Discontinued Operations and Extraordinary Loss
decreased $31 million to $357 million in 2008. The key drivers of the
decrease were a $60 million decrease in Gross Margin offset by a $5 million
decrease in Operating Expenses and Other and a $24 million decrease in Income
Tax Expense.
The major
components of the net decrease in Gross Margin were as follows:
·
|
Retail
Margins decreased $81 million primarily due to the
following:
|
|
·
|
A
$78 million increase in related to increased fuel and consumable expenses
in Ohio. CSPCo
and OPCo have applied for an active fuel clause in their Ohio ESP to be
effective January 1, 2009.
|
|
·
|
An
$80 million decrease in usage primarily due to a 19% decrease in cooling
degree days in our eastern region, an 11% decrease in cooling degree days
in our western region as well as outages caused by Hurricanes Dolly,
Gustav and Ike. Approximately 17% of our reduction in load was
attributable to these storms.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$61 million increase related to net rate increases implemented in our Ohio
jurisdictions, an $8 million increase related to recovery of E&R costs
in Virginia and the construction financing costs rider in West Virginia, a
$6 million increase in base rates in Texas and a $6 million increase in
base rates in Oklahoma.
|
|
·
|
A
$9 million increase related to increased usage by Ormet, an industrial
customer in Ohio. See “Ormet” section of Note
3.
|
·
|
Margins
from Off-system Sales decreased $7 million primarily due to lower trading
margins and the favorable effects of a fuel reconciliation recorded in our
western service territory in the third quarter of 2007, partially offset
by increases in East physical off-system sales margins due mostly to
higher prices.
|
·
|
Transmission
Revenues increased $4 million primarily due to increased rates in the SPP
region.
|
·
|
Other
revenues increased $24 million primarily due to increased third-party
engineering and construction work and an increase in pole attachment
revenue.
|
Utility
Operating Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses were flat in comparison to
2007. We experienced decreases related to the
following:
|
|
·
|
A
$77 million decrease related to the recording of the NSR settlement in the
third quarter of 2007. We are evaluating methods to pursue recovery
in all of our affected jurisdictions.
|
|
·
|
A
$9 million decrease related to the establishment of a regulatory asset in
the third quarter of 2008 for Virginia’s share of previously expended NSR
settlement costs.
|
|
These
decreases were offset by:
|
|
·
|
A
$24 million increase in non-storm system improvements, customer work and
other distribution expenses.
|
|
·
|
A
$21 million increase in storm restoration costs, primarily related to
Hurricanes Dolly, Gustav and Ike.
|
|
·
|
A
$15 million increase in recoverable PJM expenses in
Ohio.
|
|
·
|
A
$10 million increase in generation plant maintenance.
|
|
·
|
An
$8 million increase in recoverable customer account expenses related to
the Universal Service Fund for Ohio customers who qualify for payment
assistance.
|
|
·
|
An
$8 million increase in transmission expenses for tree trimming and
reliability.
|
·
|
Depreciation
and Amortization expense increased $5 million primarily due to higher
depreciable property balances from the installation of environmental
upgrades.
|
·
|
Carrying
Costs Income increased $7 million primarily due to increased carrying cost
income on cost deferrals in Virginia and Oklahoma.
|
·
|
Interest
Income increased $8 million primarily due to the favorable effect of
claims for refund filed with the IRS.
|
·
|
Interest
and Other Charges increased $12 million primarily due to additional debt
issued and higher interest rates on variable rate debt.
|
·
|
Income
Tax Expense decreased $24 million due to a decrease in pretax
income.
|
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Reconciliation
of Nine Months Ended September 30, 2007 to Nine Months Ended September 30,
2008
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss
(in
millions)
Nine
Months Ended September 30, 2007
|
|
|
|
|
$ |
879 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
79 |
|
|
|
|
|
Off-system
Sales
|
|
|
73 |
|
|
|
|
|
Transmission
Revenues
|
|
|
22 |
|
|
|
|
|
Other
Revenues
|
|
|
27 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
201 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
11 |
|
|
|
|
|
Gain
on Dispositions of Assets, Net
|
|
|
(18 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
23 |
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(9 |
) |
|
|
|
|
Carrying
Costs Income
|
|
|
26 |
|
|
|
|
|
Interest
Income
|
|
|
25 |
|
|
|
|
|
Other
Income, Net
|
|
|
12 |
|
|
|
|
|
Interest
and Other Charges
|
|
|
(54 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(66 |
) |
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2008
|
|
|
|
|
|
$ |
1,030 |
|
Income
from Utility Operations Before Discontinued Operations and Extraordinary Loss
increased $151 million to $1,030 million in 2008. The key drivers of
the increase were a $201 million increase in Gross Margin and a $16 million
decrease in Operating Expenses and Other offset by a $66 million increase in
Income Tax Expense.
The major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $79 million primarily due to the
following:
|
|
·
|
A
$148 million increase related to net rate increases implemented in our
Ohio jurisdictions, a $39 million increase related to recovery of E&R
costs in Virginia and the construction financing costs rider in West
Virginia, a $20 million increase in base rates in Oklahoma and a $17
million increase in base rates in Texas.
|
|
·
|
A
$42 million increase related to increased usage by Ormet, an industrial
customer in Ohio. See “Ormet” section of Note
3.
|
|
·
|
A
$37 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
$29 million increase due to coal contract amendments in
2008.
|
|
These
increases were partially offset by:
|
|
·
|
A
$164 million decrease related to increased fuel and consumable expenses in
Ohio. CSPCo
and OPCo have applied for an active fuel clause in their Ohio ESP to be
effective January 1, 2009.
|
|
·
|
A
$65 million decrease in usage primarily due to a 22% decrease in cooling
degree days in our eastern region and
a 6% decrease in cooling degree days in our western
region.
|
|
·
|
A
$29 million increase in the sharing of off-system sales margins with
customers due
to an increase in total off-system
sales.
|
·
|
Margins
from Off-system Sales increased $73 million primarily due to higher
physical off-system sales in our eastern territory as the result of higher
volumes and higher prices, aided by additional generation available in
2008 due to fewer planned outages and lower internal load. This
increase was partially offset by lower trading margins and the favorable
effects of a fuel reconciliation recorded in our western territory in the
third quarter of 2007.
|
·
|
Transmission
Revenues increased $22 million primarily due to increased rates in the
ERCOT and SPP regions.
|
·
|
Other
Revenues increased $27 million primarily due to increased third-party
engineering and construction work, an increase in pole attachment revenue
and the recording of an unfavorable provision for TCC for the refund of
bonded rates recorded in 2007.
|
Utility
Operating Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses decreased $11 million primarily due to
the following:
|
|
·
|
A
$77 million decrease related to the recording of NSR settlement costs in
September 2007. We are evaluating methods to pursue recovery in all
of our affected jurisdictions.
|
|
·
|
A
$62 million decrease related to the deferral of Oklahoma storm restoration
costs in the first quarter of 2008, net of amortization, as a result of a
rate settlement to recover 2007 storm restoration
costs.
|
|
·
|
A
$19 million decrease in generation plant removal costs.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$33 million increase in tree trimming, reliability and system improvement
expense.
|
|
·
|
A
$29 million increase in recoverable PJM expenses in
Ohio.
|
|
·
|
A
$23 million increase in generation plant operations and maintenance
expense.
|
|
·
|
A
$21 million increase in recoverable customer account expenses related to
the Universal Service Fund for Ohio customers who qualify for payment
assistance.
|
|
·
|
A
$16 million increase in storm restoration costs, primarily related to
Hurricanes Dolly, Gustav and Ike, which occurred in the third quarter of
2008.
|
|
·
|
A
$16 million increase in maintenance expense at the Cook
Plant.
|
|
·
|
A
$10 million increase related to the write-off of the unrecoverable
pre-construction costs for PSO’s cancelled Red Rock Generating Facility in
the first quarter of 2008.
|
·
|
Gain
on Disposition of Assets, Net decreased $18 million primarily due to the
expiration 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 $23 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 $9 million primarily due to favorable
adjustments to property tax returns recorded in the prior
year.
|
·
|
Carrying
Costs Income increased $26 million primarily due to increased carrying
cost income on cost deferrals in Virginia and Oklahoma.
|
·
|
Interest
Income increased $25 million primarily due to the favorable effect of
claims for refund filed with the IRS.
|
·
|
Other
Income, Net increased $12 million primarily due to an increase in the
equity component of AFUDC as a result of new generation
projects.
|
·
|
Interest
and Other Charges increased $54 million primarily due to additional debt
issued and higher interest rates on variable rate debt.
|
·
|
Income
Tax Expense increased $66 million due to an increase in pretax
income.
|
AEP River
Operations
Third Quarter of 2008
Compared to Third Quarter of 2007
Income
Before Discontinued Operations and Extraordinary Loss from our AEP River
Operations segment decreased to $11 million in 2008 from $18 million in 2007
primarily due to significant disruptions of ship arrivals and departures as the
result of an oil spill in the New Orleans Harbor. Ship arrivals were
further disrupted by the impacts of Hurricanes Gustav and Ike, which caused
severe flooding on the Mississippi and Illinois Rivers. The decrease
in income was also due to higher diesel fuel prices. Additionally,
decreases in import demand and grain export demand have resulted in lower
freight demand, partially offset by increased coal exports.
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss from our AEP River
Operations segment decreased to $21 million in 2008 from $40 million in 2007
primarily due to significant flooding on various inland waterways throughout
2008 and rising diesel fuel prices. Additionally, decreases in import
demand and grain export demand have resulted in lower freight demand, largely
the result of a slowing U.S. economy and a weak U.S. dollar. The
impact of Hurricanes Gustav and Ike and the oil spill in the New Orleans Harbor,
all of which occurred during the third quarter of 2008, also contributed to the
unfavorable variance.
Generation and
Marketing
Third Quarter of 2008
Compared to Third Quarter of 2007
Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment increased to $16 million in 2008 from $3 million in 2007
primarily due to higher gross margins from its marketing activities and higher
gross margins due to improved price realization, plant performance and hedging
activities from its share of the Oklaunion Power Station.
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment increased to $43 million in 2008 from $17 million in 2007
primarily due to higher gross margins from its marketing activities and higher
gross margins due to improved price realization, plant performance and hedging
activities from its share of the Oklaunion Power Station.
All
Other
Third Quarter of 2008
Compared to Third Quarter of 2007
Loss
Before Discontinued Operations and Extraordinary Loss from All Other increased
to $10 million in 2008 from $2 million in 2007. The increase in the
loss primarily relates to higher interest expenses due to the issuance of AEP
Junior Subordinated Debentures and lower interest income from
affiliates.
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss from All Other increased
to $133 million in 2008 from a $1 million loss 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 Charges
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 decreased $13 million in the third quarter of 2008 compared to the
third quarter of 2007 primarily due to a decrease in pretax income.
Income
Tax Expense increased $165 million in the nine-month period ended September 30,
2008 compared to the nine-month period ended September 30, 2007 primarily due to
an increase in pretax income.
FINANCIAL
CONDITION
We
measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.
Debt and Equity
Capitalization
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
|
|
($
in millions)
|
|
Long-term
Debt, including amounts due within one year
|
|
$ |
16,007 |
|
|
|
56.6 |
%
|
|
$ |
14,994 |
|
|
|
58.1 |
% |
Short-term
Debt
|
|
|
1,302 |
|
|
|
4.6 |
|
|
|
660 |
|
|
|
2.6 |
|
Total
Debt
|
|
|
17,309 |
|
|
|
61.2 |
|
|
|
15,654 |
|
|
|
60.7 |
|
Common
Equity
|
|
|
10,917 |
|
|
|
38.6 |
|
|
|
10,079 |
|
|
|
39.1 |
|
Preferred
Stock
|
|
|
61 |
|
|
|
0.2 |
|
|
|
61 |
|
|
|
0.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt and Equity Capitalization
|
|
$ |
28,287 |
|
|
|
100.0 |
% |
|
$ |
25,794 |
|
|
|
100.0 |
% |
Our ratio
of debt to total capital increased from 60.7% to 61.2% in 2008 due to our
issuance of debt to fund construction and our strategy to deal with the credit
situation by drawing cash from our credit facilities.
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
In recent
months, the financial markets have become increasingly unstable and constrained
at both a global and domestic level. This systemic marketplace
distress is impacting our access to capital, our liquidity and our cost of
capital. The uncertainties in the credit markets could have
significant implications on our subsidiaries since they rely on continuing
access to capital to fund operations and capital expenditures. The
current credit markets are constraining our ability to issue new debt, including
commercial paper, and refinance existing debt.
We
believe that we have adequate liquidity under our credit
facilities. In September 2008, in response to the bankruptcy of
certain companies and tightening of credit markets, we borrowed $600 million
under our credit lines to assure that cash is available to meet our working
capital needs. In October 2008, we borrowed an additional $1.4
billion under our existing credit facilities. We took this proactive
step to enhance our cash position during this period of market
disruptions.
We cannot
predict the length of time the current credit situation will continue or the
impact on our future operations and our ability to issue debt at reasonable
interest rates. However, when market conditions improve, we plan to
repay the amounts drawn under the credit facilities and issue other long-term
debt. If there is not an improvement in access to capital, we believe
that we have adequate liquidity to support our planned business operations and
construction program through 2009.
In the
first quarter of 2008, due to the exposure that bond insurers like Ambac
Assurance Corporation and Financial Guaranty Insurance Co. had in connection
with developments in the subprime credit market, the credit ratings of those
insurers were downgraded or placed on negative outlook. These market
factors contributed to higher interest rates in successful auctions and
increasing occurrences of failed auctions for tax-exempt long-term debt sold at
auction rates, including auctions of our tax-exempt long-term
debt. Consequently, we chose to exit the auction-rate debt
market. Through September 30, 2008, we reduced our outstanding
auction rate securities by $1.2 billion. As of September 30, 2008, we
had $272 million outstanding of tax-exempt long-term debt sold at auction rates
(rates range between 4.353% and 13%) that reset every 35 days. Approximately
$218 million of this debt relates to a lease structure with JMG that we are
unable to refinance at this time. In order to refinance this debt, we
need the lessor’s consent. This debt is insured by the previously
AAA-rated bond insurers. 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. We plan to continue
the conversion and refunding process to other permitted modes, including
term-put structures, variable-rate and fixed-rate structures, as opportunities
arise. As of September 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 6.5% to 8.25%, $495 million was issued at
fixed rates ranging from 4.5% to 5.625% and trustees held, on our behalf,
approximately $330 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 September 30, 2008, our available liquidity was
approximately $3 billion as illustrated in the table below:
|
|
Amount
|
|
Maturity
|
|
|
(in
millions)
|
|
|
Commercial
Paper Backup:
|
|
|
|
|
Revolving
Credit Facility
|
|
$ |
1,500 |
|
March
2011
|
Revolving
Credit Facility
|
|
|
1,454 |
(a)
|
April
2012
|
Revolving
Credit Facility
|
|
|
627 |
(a)
|
April
2011
|
Revolving
Credit Facility
|
|
|
338 |
(a)
|
April
2009
|
Total
|
|
|
3,919 |
|
|
Short-term
Investments
|
|
|
490 |
|
|
Cash
and Cash Equivalents
|
|
|
338 |
|
|
Total
Liquidity Sources
|
|
|
4,747 |
|
|
Less:
AEP Commercial Paper Outstanding
|
|
|
701 |
|
|
Cash Drawn on Credit Facilities
|
|
|
591 |
|
|
Letters of Credit Drawn
|
|
|
439 |
|
|
|
|
|
|
|
|
Net
Available Liquidity
|
|
$ |
3,016 |
|
|
(a)
|
Reduced
by Lehman Brothers Holdings Inc.’s commitment amount of $81 million
following its bankruptcy.
|
The
revolving credit facilities for commercial paper backup were structured as two
$1.5 billion credit facilities which were reduced by Lehman Brothers Holdings
Inc.’s commitment amount of $46 million following its bankruptcy. 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 September 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 nine months of 2008 was $1.2 billion. The weighted-average
interest rate of our commercial paper during the first nine months of 2008 was
3.25%.
In April
2008, we entered into a $650 million 3-year credit agreement and a $350 million
364-day credit agreement which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $23 million and $12 million, respectively, following its
bankruptcy. Under the facilities, we may issue letters of
credit. As of September 30, 2008, $372 million of letters of credit
were issued under the 3-year credit agreement to support variable rate demand
notes.
Investments
in Auction-Rate Securities
Prior to
June 30, 2008, we sold all of our investment in auction-rate securities at
par.
Sale
of Receivables
In
October 2008, we renewed our sale of receivables agreement. The sale
of receivables agreement provides a commitment of $600 million from bank
conduits to purchase receivables. This agreement will expire in
October 2009.
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 September 30, 2008, this
contractually-defined percentage was 57.3%. Nonperformance of these
covenants could result in an event of default under these credit
agreements. At September 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 September 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 October 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 net income, 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
rated 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.
|
Nine
Months Ended
|
|
|
September
30,
|
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$ |
178 |
|
|
$ |
301 |
|
Net
Cash Flows from Operating Activities
|
|
|
2,053 |
|
|
|
1,630 |
|
Net
Cash Flows Used for Investing Activities
|
|
|
(3,061 |
) |
|
|
(2,935 |
) |
Net
Cash Flows from Financing Activities
|
|
|
1,168 |
|
|
|
1,200 |
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
160 |
|
|
|
(105 |
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
338 |
|
|
$ |
196 |
|
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
|
Nine
Months Ended
|
|
|
September
30,
|
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Net
Income
|
|
$ |
1,228 |
|
|
$ |
858 |
|
Less: Discontinued
Operations, Net of Tax
|
|
|
(1 |
) |
|
|
(2 |
) |
Income
Before Discontinued Operations
|
|
|
1,227 |
|
|
|
856 |
|
Depreciation
and Amortization
|
|
|
1,123 |
|
|
|
1,144 |
|
Other
|
|
|
(297 |
) |
|
|
(370 |
) |
Net
Cash Flows from Operating Activities
|
|
$ |
2,053 |
|
|
$ |
1,630 |
|
Net Cash
Flows from Operating Activities increased in 2008 primarily due to the TEM
settlement.
Net Cash
Flows from Operating Activities were $2.1 billion in 2008 consisting primarily
of Income Before Discontinued Operations of $1.2 billion and $1.1 billion 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
coal and natural gas prices.
Net Cash
Flows from Operating Activities were $1.6 billion in 2007 consisting primarily
of Income Before Discontinued Operations of $856 million and $1.1 billion
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
|
Nine
Months Ended
|
|
|
September
30,
|
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Construction
Expenditures
|
|
$ |
(2,576 |
) |
|
$ |
(2,595 |
) |
Purchases/Sales
of Investment Securities, Net
|
|
|
(474 |
) |
|
|
217 |
|
Acquisition
of Assets
|
|
|
(97 |
) |
|
|
(512 |
) |
Proceeds
from Sales of Assets
|
|
|
83 |
|
|
|
78 |
|
Other
|
|
|
3 |
|
|
|
(123 |
) |
Net
Cash Flows Used for Investing Activities
|
|
$ |
(3,061 |
) |
|
$ |
(2,935 |
) |
Net Cash
Flows Used for Investing Activities were $3.1 billion in 2008 primarily due to
Construction Expenditures for our environmental, distribution and new generation
investment plan.
Net Cash
Flows Used for Investing Activities were $2.9 billion in 2007 primarily due to
Construction Expenditures for our environmental, distribution and new generation
investment plan. We paid $512 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 including the cash drawn against our credit
facilities in 2008. We also purchase and sell investment securities within
our nuclear trusts.
We
forecast approximately $1.2 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 cash flows from operations and financing activities.
Financing
Activities
|
Nine
Months Ended
|
|
|
September
30,
|
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Issuance
of Common Stock
|
|
$ |
106 |
|
|
$ |
116 |
|
Issuance/Retirement
of Debt, Net
|
|
|
1,621 |
|
|
|
1,623 |
|
Dividends
Paid on Common Stock
|
|
|
(494 |
) |
|
|
(467 |
) |
Other
|
|
|
(65 |
) |
|
|
(72 |
) |
Net
Cash Flows from Financing Activities
|
|
$ |
1,168 |
|
|
$ |
1,200 |
|
Net Cash
Flows from Financing Activities in 2008 were $1.2 billion primarily due to
the issuance of additional debt including $315 million of Junior Subordinated
Debentures and a net increase of $1.3 billion in outstanding Senior
Unsecured Notes partially offset, by the reacquisition of a net $370 million of
Pollution Control Bonds and $125 million of Securitization Bonds. In
September 2008, we borrowed $600 million under our credit
agreements. 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 $1.2 billion primarily due to
issuing $1.9 billion of debt securities including $1 billion of new debt for
plant acquisitions and construction and increasing short-term commercial paper
borrowings.
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:
|
September
30,
2008
|
|
December
31,
2007
|
|
|
(in
millions)
|
|
AEP
Credit Accounts Receivable Purchase Commitments
|
|
$ |
555 |
|
|
$ |
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 the drawdowns 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
net income, 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. An 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 after the PUCO approves an
MRO. 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 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 and purchased power 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 an
optional MRO. 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 (which excludes off-system
sales) 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-purchased power cost recovery
mechanism would be phased-in over the three year period from 2009 through
2011. If the ESP is approved as filed, effective with January 2009
billings, CSPCo and OPCo will defer any fuel cost under-recoveries and related
carrying costs for future recovery. The under-recoveries and related
carrying costs that exist at the end of 2011 will be recovered 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 distribution reliability costs and for unexpected
non-fuel generation costs. The filings also include programs for
smart metering initiatives and economic development and mandated energy
efficiency and peak demand reduction programs. In September 2008, the
PUCO issued a finding and order tentatively adopting rules governing MRO and ESP
applications. CSPCo and OPCo filed their ESP applications based on
proposed rules and requested waivers for portions of the proposed
rules. The PUCO denied the waiver requests in September 2008 and
ordered CSPCo and OPCo to submit information consistent with the tentative
rules. In October 2008, CSPCo and OPCo submitted additional
information related to proforma financial statements and information concerning
CSPCo and OPCo’s fuel procurement process. In October 2008, CSPCo and
OPCo filed an application for rehearing with the PUCO to challenge certain
aspects of the proposed rules.
Within
the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $46
million and $38 million, respectively, for customer choice implementation and
line extension carrying costs. In addition, CSPCo and OPCo would
recover related unrecorded equity carrying costs of $30 million and $21 million,
respectively. Such costs would be recovered over an 8-year period
beginning January 2011. Hearings are scheduled for November 2008 and
an order is expected in the fourth quarter of 2008. If an order is
not received prior to January 1, 2009, CSPCo and OPCo have requested retroactive
application of the new rates back to January 1, 2009 upon
approval. Failure of the PUCO to ultimately approve the recovery of
the regulatory assets would have an adverse effect on future net income and cash
flows.
Cook Plant Unit 1 Fire and
Shutdown
Cook
Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in
Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine
vibrations likely caused by blade failure which resulted in a fire on the
electric generator. This equipment is in the turbine building and is
separate and isolated from the nuclear reactor. The steam turbines
that caused the vibration were installed in 2006 and are under warranty from the
vendor. The warranty provides for the replacement of the turbines if
the damage was caused by a defect in the design or assembly of the
turbines. I&M is also working with its insurance
company, Nuclear Electric Insurance Limited (NEIL), and turbine
vendor to evaluate the extent of the damage resulting from the incident and the
costs to return the unit to service. We cannot estimate the ultimate
costs of the outage at this time. Management believes that I&M should
recover a significant portion of these costs through the turbine vendor’s
warranty, insurance and the regulatory process. Our
preliminary analysis indicates that Unit 1 could resume operations as early as
late first quarter/early second quarter of 2009 or as late as the second half of
2009, depending upon whether the damaged components can be repaired or whether
they need to be replaced.
I&M
maintains property insurance through NEIL with a $1 million
deductible. I&M also maintains a separate accidental outage
policy with NEIL whereby, after a 12 week deductible period, I&M is entitled
to weekly payments of $3.5 million during the outage period for a covered
loss. If the ultimate costs of the incident are not covered by
warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.
TCC Texas Restructuring
Appeals
Pursuant
to PUCT orders, TCC securitized its net recoverable stranded generation costs of
$2.5 billion and is recovering the principal and interest on the securitization
bonds over a period ending in 2020. TCC has refunded its net other
true-up regulatory liabilities of $375 million during the period October 2006
through June 2008 via a CTC credit rate rider. Cash paid for these
CTC refunds for the nine months ended September 30, 2008 and 2007 was $75
million and $207 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 orders seeking to further reduce TCC’s true-up
recoveries.
In March
2007, the Texas District Court judge hearing the appeals 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 unfavorable decision finding that the PUCT erred by applying an
invalid rule to determine the carrying cost rate. The favorable
commercial unreasonableness decision was not reversed. The Texas
Court of Appeals denied intervenors’ motion for rehearing. In May
2008, TCC, the PUCT and intervenors filed petitions for review with the Texas
Supreme Court.
Management
cannot predict the outcome of these court proceedings and PUCT remand
decisions. If TCC ultimately succeeds in its appeals, it could have a
material favorable effect on future net income, cash flows and financial
condition. If municipal customers and other intervenors succeed in
their appeals it could have a substantial adverse effect on future net income,
cash flows and financial condition.
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
|
(h)
|
|
149
|
|
Gas
|
|
Combined-cycle
|
|
580
|
|
2010
|
(h)
|
SWEPCo
|
|
Stall
|
|
Louisiana
|
|
|
378
|
|
|
158
|
|
Gas
|
|
Combined-cycle
|
|
500
|
|
2010
|
|
SWEPCo
|
|
Turk
|
(f)
|
Arkansas
|
|
|
1,522
|
(f)
|
|
448
|
|
Coal
|
|
Ultra-supercritical
|
|
600
|
(f)
|
2012
|
|
APCo
|
|
Mountaineer
|
(g)
|
West
Virginia
|
|
|
|
(g)
|
|
|
|
Coal
|
|
IGCC
|
|
629
|
|
(g)
|
|
CSPCo/OPCo
|
|
Great
Bend
|
(g)
|
Ohio
|
|
|
|
(g)
|
|
|
|
Coal
|
|
IGCC
|
|
629
|
|
(g)
|
|
(a)
|
Amount
excludes AFUDC.
|
(b)
|
Amount
includes AFUDC.
|
(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 $1.1 billion 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)
|
Construction
of IGCC plants are pending necessary permits and regulatory
approval. See “IGCC Plants” section below.
|
(h)
|
Projected
completion date of the Dresden Plant is currently under
review. To the extent that the completion date is delayed, the
total projected cost of the Dresden Plant could
change.
|
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 August
2008, the PUCT issued an order approving the Turk Plant with the following four
conditions: (a) the capping of capital costs for the Turk Plant at the $1.5
billion projected construction cost, excluding AFUDC, (b) capping CO2 emission
costs at $28 per ton through the year 2030, (c) holding Texas ratepayers
financially harmless from any adverse impact related to the Turk Plant not being
fully subscribed to by other utilities or wholesale customers and (d) providing
the PUCT all updates, studies, reviews, reports and analyses as previously
required under the Louisiana and Arkansas orders. An intervenor filed
a motion for rehearing seeking reversal of the PUCT’s
decision. SWEPCo filed a motion for rehearing stating that the two
cost cap restrictions are unlawful. In September 2008, the motions
for rehearing were denied. In October 2008, SWEPCo appealed the
PUCT’s order regarding the two cost cap restrictions. If the cost cap
restrictions are upheld and construction or emissions costs exceed the
restrictions, it could have a material adverse impact on future net income and
cash flows. In October 2008, an intervenor filed an appeal contending
that the PUCT’s grant of a conditional Certificate of Public Convenience and
Necessity for the Turk Plant was not necessary to serve retail
customers.
SWEPCo is
also working with the Arkansas Department of Environmental Quality for the
approval of an air permit and the U.S. Army Corps of Engineers for
the approval of a wetlands
and stream impact permit. Once SWEPCo receives the air permit, they
will commence construction. 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.
In
January 2008 and July 2008, SWEPCo filed applications for authority with the
APSC to construct transmission lines necessary for service from the Turk
Plant. Several landowners filed for intervention status and one
landowner also contended he should be permitted to re-litigate Turk Plant
issues, including the need for the generation. The APSC granted their
intervention but denied the request to re-litigate the Turk Plant
issues. The landowner filed an appeal to the Arkansas State Court of
Appeals in June 2008.
The
Arkansas Governor’s Commission on Global Warming is scheduled to issue its final
report to the Governor by November 1, 2008. The Commission was
established to set a global warming pollution reduction goal together with a
strategic plan for implementation in Arkansas. If legislation is
passed as a result of the findings in the Commission’s report, it could impact
SWEPCo’s proposal to build the Turk Plant.
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 September 30, 2008, SWEPCo has capitalized
approximately $448 million of expenditures and has significant contractual
construction commitments for an additional $771 million. As of
September 30, 2008, if the plant had been cancelled, cancellation fees of $61
million would have been required in order to terminate these construction
commitments. If the Turk Plant does not receive all necessary
approvals on reasonable terms and SWEPCo cannot recover its capitalized costs,
including any cancellation fees, it would have an adverse effect on future net
income, cash flows and possibly financial condition.
IGCC
Plants
The
construction of the West Virginia and Ohio IGCC plants are pending necessary
permits and regulatory approvals. 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 allocated $134 million in
future tax credits to APCo for the planned IGCC plant contingent upon the
commencement of construction, qualifying expenses being incurred and
certification of the IGCC plant prior to July 2010. Through September
30, 2008, APCo deferred for future recovery preconstruction IGCC costs of $19
million. If the West Virginia IGCC plant is cancelled, APCo plans to
seek recovery of its prudently incurred deferred pre-construction
costs. If the plant is cancelled and if the deferred costs are not
recoverable, it would have an adverse effect on future net income and cash
flows.
In Ohio,
CSPCo and OPCo continue to pursue the ultimate construction of the IGCC
plant. In September 2008, the Ohio Consumers’ Counsel filed a motion
with the PUCO requesting all Phase 1 cost recoveries be refunded to Ohio
ratepayers with interest. CSPCo and OPCo filed a response with the
PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit
and contrary to past precedent. If CSPCo and OPCo were required to
refund some or all of the $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 net
income 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 net
income.
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. In October 2008, the court approved a settlement in
the citizen suit action filed by Sierra Club against the jointly-owned units at
Stuart Station. Under the settlement, the joint-owners of Stuart
Station agreed to certain emission targets related to NOx, SO2 and
PM. We also agreed to make energy efficiency and renewable energy
commitments that are conditioned on PUCO approval for recovery of
costs. The joint-owners also agreed to forfeit 5,500 SO2 allowances
and provide $300 thousand to a third party organization to establish a
solar water heater rebate program.
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, 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 gas (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. The Federal EPA filed a petition for
review by the U.S. Supreme Court. We are unable to predict the
outcome of this appeal or 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% by
2010, and by 65% by 2015. NOx emissions
will be subject to additional limits beginning in 2009, and will be reduced by a
total of 70% 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. The Federal EPA and other parties petitioned for
rehearing. We are unable to predict the outcome of the rehearing
petitions or 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 $9 million of
annual CAIR NOx allowances
which are included in Deferred Charges and Other on our Condensed Consolidated
Balance Sheet as of September 30, 2008. The market value of annual
CAIR NOx allowances
decreased following this court decision. However, our
weighted-average cost of these allowances is below market. If CAIR
remains vacated, management intends to seek partial recovery of the cost of
purchased allowances. Any unrecovered portion would have an adverse
effect on future net income 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 state
implementation plan (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 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 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” 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 SFAS
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). In October 2008, the FASB issued FSP SFAS
157-3 “Determining the Fair Value of a Financial Asset When the Market for That
Asset is Not Active” which clarifies application of SFAS 157 in markets that are
not active and provides an illustrative example. 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. FSP SFAS 157-3
is effective upon issuance. We will fully adopt SFAS 157 effective
January 1, 2009 for items within the scope of FSP SFAS 157-2. We
expect that the adoption of FSP SFAS 157-2 will have an immaterial impact on our
financial statements. 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.
The
Committee of Chief Risk Officers (CCRO) adopted disclosure standards for risk
management contracts to improve clarity, understanding and consistency of
information reported. 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 September 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
September
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
|
|
$ |
246 |
|
|
$ |
52 |
|
|
$ |
43 |
|
|
$ |
341 |
|
|
$ |
25 |
|
|
$ |
(26 |
) |
|
$ |
340 |
|
Noncurrent
Assets
|
|
|
164 |
|
|
|
128 |
|
|
|
40 |
|
|
|
332 |
|
|
|
6 |
|
|
|
(24 |
) |
|
|
314 |
|
Total
Assets
|
|
|
410 |
|
|
|
180 |
|
|
|
83 |
|
|
|
673 |
|
|
|
31 |
|
|
|
(50 |
) |
|
|
654 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(209 |
) |
|
|
(65 |
) |
|
|
(47 |
) |
|
|
(321 |
) |
|
|
(18 |
) |
|
|
9 |
|
|
|
(330 |
) |
Noncurrent
Liabilities
|
|
|
(69 |
) |
|
|
(57 |
) |
|
|
(43 |
) |
|
|
(169 |
) |
|
|
(4 |
) |
|
|
8 |
|
|
|
(165 |
) |
Total
Liabilities
|
|
|
(278 |
) |
|
|
(122 |
) |
|
|
(90 |
) |
|
|
(490 |
) |
|
|
(22 |
) |
|
|
17 |
|
|
|
(495 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MTM Derivative Contract Net Assets
(Liabilities)
|
|
$ |
132 |
|
|
$ |
58 |
|
|
$ |
(7 |
) |
|
$ |
183 |
|
|
$ |
9 |
|
|
$ |
(33 |
) |
|
$ |
159 |
|
MTM
Risk Management Contract Net Assets (Liabilities)
Nine
Months Ended September 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
|
|
|
(57 |
) |
|
|
4 |
|
|
|
1 |
|
|
|
(52 |
) |
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
2 |
|
|
|
17 |
|
|
|
- |
|
|
|
19 |
|
Changes
in Fair Value Due to Valuation Methodology Changes on Forward Contracts
(b)
|
|
|
3 |
|
|
|
3 |
|
|
|
1 |
|
|
|
7 |
|
Changes
in Fair Value Due to Market Fluctuations During the
Period (c)
|
|
|
18 |
|
|
|
(9 |
) |
|
|
(1 |
) |
|
|
8 |
|
Changes
in Fair Value Allocated to Regulated Jurisdictions
(d)
|
|
|
10 |
|
|
|
- |
|
|
|
- |
|
|
|
10 |
|
Total
MTM Risk Management Contract Net Assets (Liabilities) at September
30, 2008
|
|
$ |
132 |
|
|
$ |
58 |
|
|
$ |
(7 |
) |
|
|
183 |
|
Net
Cash Flow and Fair Value Hedge Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
Collateral
Deposits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33 |
) |
Ending
Net Risk Management Assets at September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
159 |
|
(a)
|
Reflects
fair value on long-term structured 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.
|
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 September 30, 2008
(in
millions)
|
|
Remainder
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
After
2012
(f)
|
|
|
Total
|
|
Utility
Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1 (a)
|
|
$ |
(2 |
) |
|
$ |
(8 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(10 |
) |
Level
2 (b)
|
|
|
5 |
|
|
|
62 |
|
|
|
43 |
|
|
|
5 |
|
|
|
1 |
|
|
|
- |
|
|
|
116 |
|
Level
3 (c)
|
|
|
(15 |
) |
|
|
2 |
|
|
|
(6 |
) |
|
|
1 |
|
|
|
1 |
|
|
|
- |
|
|
|
(17 |
) |
Total
|
|
|
(12 |
) |
|
|
56 |
|
|
|
37 |
|
|
|
6 |
|
|
|
2 |
|
|
|
- |
|
|
|
89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
and Marketing:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1 (a)
|
|
|
(1 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
Level
2 (b)
|
|
|
(21 |
) |
|
|
2 |
|
|
|
11 |
|
|
|
12 |
|
|
|
11 |
|
|
|
20 |
|
|
|
35 |
|
Level
3 (c)
|
|
|
5 |
|
|
|
2 |
|
|
|
3 |
|
|
|
2 |
|
|
|
2 |
|
|
|
10 |
|
|
|
24 |
|
Total
|
|
|
(17 |
) |
|
|
4 |
|
|
|
14 |
|
|
|
14 |
|
|
|
13 |
|
|
|
30 |
|
|
|
58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
(3 |
) |
|
|
(8 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(11 |
) |
Level
2 (b)
|
|
|
(17 |
) |
|
|
60 |
|
|
|
50 |
|
|
|
19 |
|
|
|
12 |
|
|
|
20 |
|
|
|
144 |
|
Level
3 (c) (d)
|
|
|
(10 |
) |
|
|
4 |
|
|
|
(3 |
) |
|
|
3 |
|
|
|
3 |
|
|
|
10 |
|
|
|
7 |
|
Total
|
|
|
(30 |
) |
|
|
56 |
|
|
|
47 |
|
|
|
22 |
|
|
|
15 |
|
|
|
30 |
|
|
|
140 |
|
Dedesignated
Risk Management
Contracts (e)
|
|
|
4 |
|
|
|
14 |
|
|
|
14 |
|
|
|
6 |
|
|
|
5 |
|
|
|
- |
|
|
|
43 |
|
Total
MTM Risk Management
Contract Net Assets (Liabilities)
|
|
$ |
(26 |
) |
|
$ |
70 |
|
|
$ |
61 |
|
|
$ |
28 |
|
|
$ |
20 |
|
|
$ |
30 |
|
|
$ |
183 |
|
(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 $30 million in individual periods beyond
2012. $14 million of this mark-to-market value is in 2013, $8
million is in 2014, $3 million is in 2015, $2 million is in 2016 and $3
million is in 2017.
|
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 September 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
Nine
Months Ended September 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
|
|
|
7 |
|
|
|
(5 |
) |
|
|
2 |
|
Reclassifications
from AOCI for Cash Flow
Hedges
Settled
|
|
|
2 |
|
|
|
3 |
|
|
|
5 |
|
Ending
Balance in AOCI, September 30, 2008
|
|
$ |
8 |
|
|
$ |
(27 |
) |
|
$ |
(19 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
After
Tax Portion Expected to be Reclassified to
Earnings
During Next 12 Months
|
|
$ |
6 |
|
|
$ |
(5 |
) |
|
$ |
1 |
|
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 September 30,
2008, our credit exposure net of collateral to sub investment grade
counterparties was approximately 14.5%, 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. Approximately 57% of our credit exposure net of
collateral to sub investment grade counterparties is short-term exposure of less
than one year. As of September 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
|
|
$ |
626 |
|
|
$ |
42 |
|
|
$ |
584 |
|
|
|
2 |
|
|
$ |
146 |
|
Split
Rating
|
|
|
14 |
|
|
|
- |
|
|
|
14 |
|
|
|
2 |
|
|
|
14 |
|
Noninvestment
Grade
|
|
|
81 |
|
|
|
8 |
|
|
|
73 |
|
|
|
2 |
|
|
|
66 |
|
No
External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internal
Investment Grade
|
|
|
110 |
|
|
|
- |
|
|
|
110 |
|
|
|
2 |
|
|
|
77 |
|
Internal
Noninvestment Grade
|
|
|
46 |
|
|
|
- |
|
|
|
46 |
|
|
|
2 |
|
|
|
40 |
|
Total
as of September 30, 2008
|
|
$ |
877 |
|
|
$ |
50 |
|
|
$ |
827 |
|
|
|
10 |
|
|
$ |
343 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
as of December 31, 2007
|
|
$ |
673 |
|
|
$ |
42 |
|
|
$ |
631 |
|
|
|
6 |
|
|
$ |
74 |
|
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 September 30, 2008, a near
term typical change in commodity prices is not expected to have a material
effect on our net income, 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
Nine
Months Ended
September
30, 2008
|
|
Twelve
Months Ended
December
31, 2007
|
(in
millions)
|
|
(in
millions)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$2
|
|
$3
|
|
$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 $51 million.
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2008 and 2007
(in
millions, except per-share amounts and shares outstanding)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
$ |
4,108 |
|
|
$ |
3,423 |
|
|
$ |
10,318 |
|
|
$ |
9,127 |
|
Other
|
|
|
83 |
|
|
|
366 |
|
|
|
886 |
|
|
|
977 |
|
TOTAL
|
|
|
4,191 |
|
|
|
3,789 |
|
|
|
11,204 |
|
|
|
10,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
1,480 |
|
|
|
1,099 |
|
|
|
3,513 |
|
|
|
2,853 |
|
Purchased
Electricity for Resale
|
|
|
394 |
|
|
|
358 |
|
|
|
1,023 |
|
|
|
895 |
|
Other
Operation and Maintenance
|
|
|
1,010 |
|
|
|
964 |
|
|
|
2,870 |
|
|
|
2,783 |
|
Gain
on Disposition of Assets, Net
|
|
|
(6 |
) |
|
|
(2 |
) |
|
|
(14 |
) |
|
|
(28 |
) |
Asset
Impairments and Other Related Charges
|
|
|
- |
|
|
|
- |
|
|
|
(255 |
) |
|
|
- |
|
Depreciation
and Amortization
|
|
|
387 |
|
|
|
381 |
|
|
|
1,123 |
|
|
|
1,144 |
|
Taxes
Other Than Income Taxes
|
|
|
189 |
|
|
|
191 |
|
|
|
578 |
|
|
|
565 |
|
TOTAL
|
|
|
3,454 |
|
|
|
2,991 |
|
|
|
8,838 |
|
|
|
8,212 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
737 |
|
|
|
798 |
|
|
|
2,366 |
|
|
|
1,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
and Investment Income
|
|
|
14 |
|
|
|
8 |
|
|
|
45 |
|
|
|
39 |
|
Carrying
Costs Income
|
|
|
21 |
|
|
|
14 |
|
|
|
64 |
|
|
|
38 |
|
Allowance
For Equity Funds Used During Construction
|
|
|
11 |
|
|
|
9 |
|
|
|
32 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST
AND OTHER CHARGES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
|
216 |
|
|
|
216 |
|
|
|
670 |
|
|
|
615 |
|
Preferred
Stock Dividend Requirements of Subsidiaries
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
2 |
|
TOTAL
|
|
|
217 |
|
|
|
217 |
|
|
|
672 |
|
|
|
617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE, MINORITY
INTEREST EXPENSE AND
EQUITY EARNINGS
|
|
|
566 |
|
|
|
612 |
|
|
|
1,835 |
|
|
|
1,375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
192 |
|
|
|
205 |
|
|
|
608 |
|
|
|
443 |
|
Minority
Interest Expense
|
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
3 |
|
Equity
Earnings of Unconsolidated Subsidiaries
|
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS AND
EXTRAORDINARY LOSS
|
|
|
374 |
|
|
|
407 |
|
|
|
1,227 |
|
|
|
935 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DISCONTINUED
OPERATIONS, NET OF TAX
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE EXTRAORDINARY LOSS
|
|
|
374 |
|
|
|
407 |
|
|
|
1,228 |
|
|
|
937 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXTRAORDINARY
LOSS, NET OF TAX
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(79 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
374 |
|
|
$ |
407 |
|
|
$ |
1,228 |
|
|
$ |
858 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING
|
|
|
402,286,779 |
|
|
|
399,222,569 |
|
|
|
401,535,661 |
|
|
|
398,412,473 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$ |
0.93 |
|
|
$ |
1.02 |
|
|
$ |
3.06 |
|
|
$ |
2.35 |
|
Discontinued
Operations, Net of Tax
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Income
Before Extraordinary Loss
|
|
|
0.93 |
|
|
|
1.02 |
|
|
|
3.06 |
|
|
|
2.35 |
|
Extraordinary
Loss, Net of Tax
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(0.20 |
) |
TOTAL
BASIC EARNINGS PER SHARE
|
|
$ |
0.93 |
|
|
$ |
1.02 |
|
|
$ |
3.06 |
|
|
$ |
2.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING
|
|
|
403,910,309 |
|
|
|
400,215,911 |
|
|
|
402,925,534 |
|
|
|
399,552,630 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$ |
0.93 |
|
|
$ |
1.02 |
|
|
$ |
3.05 |
|
|
$ |
2.34 |
|
Discontinued
Operations, Net of Tax
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
0.01 |
|
Income
Before Extraordinary Loss
|
|
|
0.93 |
|
|
|
1.02 |
|
|
|
3.05 |
|
|
|
2.35 |
|
Extraordinary
Loss, Net of Tax
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(0.20 |
) |
TOTAL
DILUTED EARNINGS PER SHARE
|
|
$ |
0.93 |
|
|
$ |
1.02 |
|
|
$ |
3.05 |
|
|
$ |
2.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
DIVIDENDS PAID PER SHARE
|
|
$ |
0.41 |
|
|
$ |
0.39 |
|
|
$ |
1.23 |
|
|
$ |
1.17 |
|
See Condensed
Notes to Condensed Consolidated Financial
Statements.
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2008 and December 31, 2007
(in
millions)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
338 |
|
|
$ |
178 |
|
Other
Temporary Investments
|
|
|
670 |
|
|
|
365 |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
805 |
|
|
|
730 |
|
Accrued
Unbilled Revenues
|
|
|
370 |
|
|
|
379 |
|
Miscellaneous
|
|
|
71 |
|
|
|
60 |
|
Allowance
for Uncollectible Accounts
|
|
|
(59 |
) |
|
|
(52 |
) |
Total
Accounts Receivable
|
|
|
1,187 |
|
|
|
1,117 |
|
Fuel,
Materials and Supplies
|
|
|
1,018 |
|
|
|
967 |
|
Risk
Management Assets
|
|
|
340 |
|
|
|
271 |
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
240 |
|
|
|
11 |
|
Margin
Deposits
|
|
|
67 |
|
|
|
47 |
|
Prepayments
and Other
|
|
|
124 |
|
|
|
70 |
|
TOTAL
|
|
|
3,984 |
|
|
|
3,026 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
20,948 |
|
|
|
20,233 |
|
Transmission
|
|
|
7,734 |
|
|
|
7,392 |
|
Distribution
|
|
|
12,561 |
|
|
|
12,056 |
|
Other
(including nuclear fuel and coal mining)
|
|
|
3,633 |
|
|
|
3,445 |
|
Construction
Work in Progress
|
|
|
3,516 |
|
|
|
3,019 |
|
Total
|
|
|
48,392 |
|
|
|
46,145 |
|
Accumulated
Depreciation and Amortization
|
|
|
16,603 |
|
|
|
16,275 |
|
TOTAL
- NET
|
|
|
31,789 |
|
|
|
29,870 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
2,239 |
|
|
|
2,199 |
|
Securitized
Transition Assets
|
|
|
2,080 |
|
|
|
2,108 |
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,292 |
|
|
|
1,347 |
|
Goodwill
|
|
|
76 |
|
|
|
76 |
|
Long-term
Risk Management Assets
|
|
|
314 |
|
|
|
319 |
|
Employee
Benefits and Pension Assets
|
|
|
479 |
|
|
|
486 |
|
Deferred
Charges and Other
|
|
|
785 |
|
|
|
888 |
|
TOTAL
|
|
|
7,265 |
|
|
|
7,423 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
43,038 |
|
|
$ |
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
September
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
millions)
|
|
Accounts
Payable
|
|
$ |
1,447 |
|
|
$ |
1,324 |
|
Short-term
Debt
|
|
|
1,302 |
|
|
|
660 |
|
Long-term
Debt Due Within One Year
|
|
|
682 |
|
|
|
792 |
|
Risk
Management Liabilities
|
|
|
330 |
|
|
|
240 |
|
Customer
Deposits
|
|
|
288 |
|
|
|
301 |
|
Accrued
Taxes
|
|
|
564 |
|
|
|
601 |
|
Accrued
Interest
|
|
|
235 |
|
|
|
235 |
|
Other
|
|
|
874 |
|
|
|
1,008 |
|
TOTAL
|
|
|
5,722 |
|
|
|
5,161 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt
|
|
|
15,325 |
|
|
|
14,202 |
|
Long-term
Risk Management Liabilities
|
|
|
165 |
|
|
|
188 |
|
Deferred
Income Taxes
|
|
|
5,150 |
|
|
|
4,730 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
2,827 |
|
|
|
2,952 |
|
Asset
Retirement Obligations
|
|
|
1,090 |
|
|
|
1,075 |
|
Employee
Benefits and Pension Obligations
|
|
|
672 |
|
|
|
712 |
|
Deferred
Gain on Sale and Leaseback – Rockport Plant Unit 2
|
|
|
132 |
|
|
|
139 |
|
Deferred
Credits and Other
|
|
|
977 |
|
|
|
1,020 |
|
TOTAL
|
|
|
26,338 |
|
|
|
25,018 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
32,060 |
|
|
|
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
|
|
|
424,538,502 |
|
|
|
421,926,696 |
|
|
|
|
|
|
|
|
|
(21,499,992
shares were held in treasury at September 30, 2008 and December
31, 2007)
|
|
|
2,760 |
|
|
|
2,743 |
|
Paid-in
Capital
|
|
|
4,444 |
|
|
|
4,352 |
|
Retained
Earnings
|
|
|
3,861 |
|
|
|
3,138 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(148 |
) |
|
|
(154 |
) |
TOTAL
|
|
|
10,917 |
|
|
|
10,079 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
43,038 |
|
|
$ |
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 Nine Months Ended September 30, 2008 and 2007
(in
millions)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
1,228 |
|
|
$ |
858 |
|
Less: Discontinued
Operations, Net of Tax
|
|
|
(1 |
) |
|
|
(2 |
) |
Income
Before Discontinued Operations
|
|
|
1,227 |
|
|
|
856 |
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
1,123 |
|
|
|
1,144 |
|
Deferred
Income Taxes
|
|
|
397 |
|
|
|
44 |
|
Extraordinary
Loss, Net of Tax
|
|
|
- |
|
|
|
79 |
|
Carrying
Costs Income
|
|
|
(64 |
) |
|
|
(38 |
) |
Allowance
for Equity Funds Used During Construction
|
|
|
(32 |
) |
|
|
(23 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
14 |
|
|
|
(7 |
) |
Amortization
of Nuclear Fuel
|
|
|
72 |
|
|
|
48 |
|
Deferred
Property Taxes
|
|
|
136 |
|
|
|
118 |
|
Fuel
Over/Under-Recovery, Net
|
|
|
(284 |
) |
|
|
(133 |
) |
Gain
on Sales of Assets and Equity Investments, Net
|
|
|
(14 |
) |
|
|
(28 |
) |
Change
in Other Noncurrent Assets
|
|
|
(160 |
) |
|
|
(64 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
(74 |
) |
|
|
98 |
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(69 |
) |
|
|
(209 |
) |
Fuel,
Materials and Supplies
|
|
|
(49 |
) |
|
|
(13 |
) |
Margin
Deposits
|
|
|
(20 |
) |
|
|
39 |
|
Accounts
Payable
|
|
|
77 |
|
|
|
(54 |
) |
Customer
Deposits
|
|
|
(14 |
) |
|
|
36 |
|
Accrued
Taxes, Net
|
|
|
(40 |
) |
|
|
(119 |
) |
Accrued
Interest
|
|
|
(5 |
) |
|
|
22 |
|
Other
Current Assets
|
|
|
(43 |
) |
|
|
(33 |
) |
Other
Current Liabilities
|
|
|
(125 |
) |
|
|
(133 |
) |
Net
Cash Flows from Operating Activities
|
|
|
2,053 |
|
|
|
1,630 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(2,576 |
) |
|
|
(2,595 |
) |
Change
in Other Temporary Investments, Net
|
|
|
106 |
|
|
|
(50 |
) |
Purchases
of Investment Securities
|
|
|
(1,386 |
) |
|
|
(8,632 |
) |
Sales
of Investment Securities
|
|
|
912 |
|
|
|
8,849 |
|
Acquisitions
of Nuclear Fuel
|
|
|
(99 |
) |
|
|
(73 |
) |
Acquisitions
of Assets
|
|
|
(97 |
) |
|
|
(512 |
) |
Proceeds
from Sales of Assets
|
|
|
83 |
|
|
|
78 |
|
Other
|
|
|
(4 |
) |
|
|
- |
|
Net
Cash Flows Used for Investing Activities
|
|
|
(3,061 |
) |
|
|
(2,935 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Common Stock
|
|
|
106 |
|
|
|
116 |
|
Issuance
of Long-term Debt
|
|
|
2,561 |
|
|
|
1,924 |
|
Change
in Short-term Debt, Net
|
|
|
642 |
|
|
|
569 |
|
Retirement
of Long-term Debt
|
|
|
(1,582 |
) |
|
|
(870 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(76 |
) |
|
|
(49 |
) |
Dividends
Paid on Common Stock
|
|
|
(494 |
) |
|
|
(467 |
) |
Other
|
|
|
11 |
|
|
|
(23 |
) |
Net
Cash Flows from Financing Activities
|
|
|
1,168 |
|
|
|
1,200 |
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
160 |
|
|
|
(105 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
178 |
|
|
|
301 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
338 |
|
|
$ |
196 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
657 |
|
|
$ |
549 |
|
Net
Cash Paid for Income Taxes
|
|
|
126 |
|
|
|
363 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
47 |
|
|
|
59 |
|
Noncash
Acquisition of Land/Mineral Rights
|
|
|
42 |
|
|
|
- |
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
373 |
|
|
|
265 |
|
Acquisition
of Nuclear Fuel Included in Accounts Payable at September
30,
|
|
|
66 |
|
|
|
1 |
|
Noncash
Assumption of Liabilities Related to Acquisitions of Darby, Lawrenceburg
and Dresden Plants
|
|
|
- |
|
|
|
8 |
|
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 Nine Months Ended September 30, 2008 and 2007
(in
millions)
(Unaudited)
|
|
Common
Stock
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Paid-in
Capital
|
|
|
Retained
Earnings
|
|
|
Other
Comprehensive Income (Loss)
|
|
|
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 |
|
|
|
21 |
|
|
|
95 |
|
|
|
|
|
|
|
|
|
|
|
116 |
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(467 |
) |
|
|
|
|
|
|
(467 |
) |
Other
|
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
12 |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive
Income (Loss), Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11 |
) |
|
|
(11 |
) |
Securities
Available for Sale, Net of Tax of $3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5 |
) |
|
|
(5 |
) |
SFAS
158 Costs Established as a Regulatory Asset Related to the Reapplication
of SFAS 71, Net of Tax of $6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
11 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
858 |
|
|
|
|
|
|
|
858 |
|
TOTAL COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
853 |
|
SEPTEMBER
30, 2007
|
|
|
421 |
|
|
$ |
2,739 |
|
|
$ |
4,328 |
|
|
$ |
3,070 |
|
|
$ |
(228 |
) |
|
$ |
9,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
3 |
|
|
|
17 |
|
|
|
89 |
|
|
|
|
|
|
|
|
|
|
|
106 |
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(494 |
) |
|
|
|
|
|
|
(494 |
) |
Other
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
3 |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,683 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income
(Loss), Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
7 |
|
Securities
Available for Sale, Net of Tax of $5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
|
(10 |
) |
Amortization
of Pension and OPEB Deferred Costs, Net of Tax of $5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
9 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,228 |
|
|
|
|
|
|
|
1,228 |
|
TOTAL COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,234 |
|
SEPTEMBER
30, 2008
|
|
|
425 |
|
|
$ |
2,760 |
|
|
$ |
4,444 |
|
|
$ |
3,861 |
|
|
$ |
(148 |
) |
|
$ |
10,917 |
|
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
|
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 net income, financial position and cash flows for the interim
periods. The net income for the three and nine months ended September
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 September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
|
$/share
|
|
|
|
|
|
$/share
|
|
Earnings
Applicable to Common Stock
|
|
$ |
374 |
|
|
|
|
|
$ |
407 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Basic Shares Outstanding
|
|
|
402.3 |
|
|
$ |
0.93 |
|
|
|
399.2 |
|
|
$ |
1.02 |
|
Average
Dilutive Effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
1.3 |
|
|
|
- |
|
|
|
0.5 |
|
|
|
- |
|
Stock
Options
|
|
|
0.1 |
|
|
|
- |
|
|
|
0.3 |
|
|
|
- |
|
Restricted
Stock Units
|
|
|
0.1 |
|
|
|
- |
|
|
|
0.1 |
|
|
|
- |
|
Restricted
Shares
|
|
|
0.1 |
|
|
|
- |
|
|
|
0.1 |
|
|
|
- |
|
Average
Number of Diluted Shares Outstanding
|
|
|
403.9 |
|
|
$ |
0.93 |
|
|
|
400.2 |
|
|
$ |
1.02 |
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
|
$/share
|
|
|
|
|
|
$/share
|
|
Earnings
Applicable to Common Stock
|
|
$ |
1,228 |
|
|
|
|
|
$ |
858 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Basic Shares Outstanding
|
|
|
401.5 |
|
|
$ |
3.06 |
|
|
|
398.4 |
|
|
$ |
2.15 |
|
Average
Dilutive Effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
1.0 |
|
|
|
(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
|
|
|
402.9 |
|
|
$ |
3.05 |
|
|
|
399.6 |
|
|
$ |
2.15 |
|
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 83,550 shares of common stock were outstanding at
September 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
September
30,
|
|
|
Nine
Months Ended
September
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)
|
|
$ |
(14 |
) |
|
$ |
(12 |
) |
|
$ |
(40 |
) |
|
$ |
(16 |
) |
AEP
Consolidated Revenues – Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
Valley Electric Corporation – Barging and Other Transportation
Services (43.47% Owned)
|
|
|
7 |
|
|
|
7 |
|
|
|
21 |
|
|
|
24 |
|
AEP
Consolidated Expenses – Purchased Energy for Resale:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
Valley Electric Corporation (43.47% Owned)
|
|
|
70 |
|
|
|
59 |
|
|
|
194 |
|
|
|
164 |
|
Sweeny
Cogeneration Limited Partnership (a)
|
|
|
- |
|
|
|
27 |
|
|
|
- |
|
|
|
86 |
|
(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 net income 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).
In
October 2008, the FASB issued FSP SFAS 157-3 “Determining the Fair Value of a
Financial Asset When the Market for That Asset is Not Active” which clarifies
application of SFAS 157 in markets that are not active and provides an
illustrative example. The FSP was effective upon
issuance. The adoption of this standard had no impact on our
financial statements.
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. We expect that the adoption of FSP SFAS 157-2 will have an
immaterial impact on our financial statements. 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
derivative fair values are verified using broker or dealer quotations, similar
observable market transactions in either the listed or OTC markets, or valued
using 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 September 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
September 30, 2008
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents (a)
|
|
$ |
271 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
67 |
|
|
$ |
338 |
|
Other
Temporary Investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents (b)
|
|
$ |
147 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
22 |
|
|
$ |
169 |
|
Debt
Securities (c)
|
|
|
- |
|
|
|
490 |
|
|
|
- |
|
|
|
- |
|
|
|
490 |
|
Equity
Securities (d)
|
|
|
11 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
11 |
|
Total Other Temporary
Investments
|
|
$ |
158 |
|
|
$ |
490 |
|
|
$ |
- |
|
|
$ |
22 |
|
|
$ |
670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (e)
|
|
$ |
41 |
|
|
$ |
2,423 |
|
|
$ |
75 |
|
|
$ |
(1,959 |
) |
|
$ |
580 |
|
Cash
Flow and Fair Value Hedges (e)
|
|
|
9 |
|
|
|
37 |
|
|
|
- |
|
|
|
(15 |
) |
|
|
31 |
|
Dedesignated
Risk Management Contracts (f)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
43 |
|
|
|
43 |
|
Total
Risk Management Assets
|
|
$ |
50 |
|
|
$ |
2,460 |
|
|
$ |
75 |
|
|
$ |
(1,931 |
) |
|
$ |
654 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spent
Nuclear Fuel and Decommissioning Trusts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents (g)
|
|
$ |
- |
|
|
$ |
4 |
|
|
$ |
- |
|
|
$ |
6 |
|
|
$ |
10 |
|
Debt
Securities (h)
|
|
|
- |
|
|
|
837 |
|
|
|
- |
|
|
|
- |
|
|
|
837 |
|
Equity
Securities (d)
|
|
|
445 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
445 |
|
Total Spent Nuclear Fuel and
Decommissioning Trusts
|
|
$ |
445 |
|
|
$ |
841 |
|
|
$ |
- |
|
|
$ |
6 |
|
|
$ |
1,292 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
924 |
|
|
$ |
3,791 |
|
|
$ |
75 |
|
|
$ |
(1,836 |
) |
|
$ |
2,954 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (e)
|
|
$ |
52 |
|
|
$ |
2,279 |
|
|
$ |
68 |
|
|
$ |
(1,926 |
) |
|
$ |
473 |
|
Cash
Flow and Fair Value Hedges (e)
|
|
|
- |
|
|
|
37 |
|
|
|
- |
|
|
|
(15 |
) |
|
|
22 |
|
Total
Risk Management Liabilities
|
|
$ |
52 |
|
|
$ |
2,316 |
|
|
$ |
68 |
|
|
$ |
(1,941 |
) |
|
$ |
495 |
|
(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
represent Variable Rate Demand Notes.
|
(d)
|
Amounts
represent publicly traded equity securities.
|
(e)
|
Amounts
in “Other” column primarily represent counterparty netting of risk
management contracts and associated cash collateral under FSP FIN
39-1.
|
(f)
|
“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.
|
(g)
|
Amounts
in “Other” column primarily represent accrued interest receivables to/from
financial institutions. Level 2 amounts primarily represent
investments in money market funds.
|
(h)
|
Amounts
represent corporate, municipal and treasury
bonds.
|
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 September 30, 2008
|
|
Net
Risk Management Assets (Liabilities)
|
|
|
Other
Temporary Investments
|
|
|
Investments
in Debt Securities
|
|
|
|
(in
millions)
|
|
Balance
as of July 1, 2008
|
|
$ |
(8 |
) |
|
$ |
- |
|
|
$ |
- |
|
Realized
(Gain) Loss Included in Earnings (or Changes in Net Assets)
(a)
|
|
|
17 |
|
|
|
- |
|
|
|
- |
|
Unrealized
Gain (Loss) Included in Earnings (or Changes in Net
Assets)
Relating to Assets Still Held at the Reporting Date (a)
|
|
|
(7 |
) |
|
|
- |
|
|
|
- |
|
Realized
and Unrealized Gains (Losses) Included in Other
Comprehensive
Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Purchases,
Issuances and Settlements
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Transfers
in and/or out of Level 3 (b)
|
|
|
(10 |
) |
|
|
- |
|
|
|
- |
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
15 |
|
|
|
- |
|
|
|
- |
|
Balance
as of September 30, 2008
|
|
$ |
7 |
|
|
$ |
- |
|
|
$ |
- |
|
Nine
Months Ended September 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)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Unrealized
Gain (Loss) Included in Earnings (or Changes in Net
Assets)
Relating to Assets Still Held at the Reporting Date (a)
|
|
|
4 |
|
|
|
- |
|
|
|
- |
|
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)
|
|
|
(35 |
) |
|
|
118 |
|
|
|
17 |
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(11 |
) |
|
|
- |
|
|
|
- |
|
Balance
as of September 30, 2008
|
|
$ |
7 |
|
|
$ |
- |
|
|
$ |
- |
|
(a)
|
Included
in revenues on our Condensed Consolidated Statements 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.
|
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. 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.
EITF
Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with
a Third-Party Credit Enhancement” (EITF 08-5)
In
September 2008, the FASB ratified the EITF consensus on liabilities with
third-party credit enhancements when the liability is measured and disclosed at
fair value. The consensus treats the liability and the credit
enhancement as two units of accounting. Under the consensus, the fair
value measurement of the liability does not include the effect of the
third-party credit enhancement. Consequently, changes in the issuer’s
credit standing without the support of the credit enhancement affect the fair
value measurement of the issuer’s liability. Entities will need to
provide disclosures about the existence of any third-party credit enhancements
related to their liabilities.
EITF 08-5
is effective for the first reporting period beginning after December 15,
2008. It will be applied prospectively upon adoption with the effect
of initial application included as a change in fair value of the liability in
the period of adoption. In the period of adoption, entities must
disclose the valuation method(s) used to measure the fair value of liabilities
within its scope and any change in the fair value measurement method that occurs
as a result of its initial application. Early adoption is
permitted. 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 this standard effective January
1, 2009.
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 133-1 and FIN 45-4 “Disclosures about Credit Derivatives and Certain
Guarantees: An Amendment
of FASB
Statement No. 133 and FASB Interpretation No. 45; and Clarification of the
Effective Date of
FASB
Statement No. 161” (SFAS 133-1 and FIN 45-4)
In
September 2008, the FASB issued SFAS 133-1 and FIN 45-4 as amendments to
original statements SFAS 133 and FIN 45 “Guarantor’s Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others.” Under the SFAS 133 requirements, the seller of a credit derivative
shall disclose the following information for each derivative, including credit
derivatives embedded in a hybrid instrument, even if the likelihood of payment
is remote:
(a)
|
The
nature of the credit derivative.
|
(b)
|
The
maximum potential amount of future payments.
|
(c)
|
The
fair value of the credit derivative.
|
(d)
|
The
nature of any recourse provisions and any assets held as collateral or by
third parties.
|
Further,
the standard requires the disclosure of current payment status/performance risk
of all FIN 45 guarantees. In the event an entity uses internal
groupings, the entity shall disclose how those groupings are determined and used
for managing risk.
The
standard is effective for interim and annual reporting periods ending after
November 15, 2008. Upon adoption, the guidance will be prospectively
applied. We expect that the adoption of this standard will have an
immaterial impact on our financial statements but increase our FIN 45
guarantees disclosure requirements. We will adopt the standard
effective December 31, 2008.
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
September 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 September 30, 2008 balance sheet, we netted $50
million of cash collateral received from third parties against short-term and
long-term risk management assets and $17 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,
consolidation policy, 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 net income 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 net income, 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 after the PUCO approves a
MRO. The PUCO has the authority to approve or modify each utilities’
ESP request. The PUCO is required to approve an ESP if, in the
aggregate, the ESP is more favorable to ratepayers than a 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 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 and purchased power 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 an
optional MRO. 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 (which excludes off-system
sales) 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-purchased power cost recovery
mechanism would be phased-in over the three year period from 2009 through
2011. If the ESP is approved as filed, effective with January 2009
billings, CSPCo and OPCo will defer any fuel cost under-recoveries and related
carrying costs for future recovery. The under-recoveries and related
carrying costs that exist at the end of 2011 will be recovered 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 distribution reliability costs and for unexpected
non-fuel generation costs. The filings also include programs for
smart metering initiatives and economic development and mandated energy
efficiency and peak demand reduction programs. In September 2008, the
PUCO issued a finding and order tentatively adopting rules governing MRO and ESP
applications. CSPCo and OPCo filed their ESP applications based on
proposed rules and requested waivers for portions of the proposed
rules. The PUCO denied the waiver requests in September 2008 and
ordered CSPCo and OPCo to submit information consistent with the tentative
rules. In October 2008, CSPCo and OPCo submitted additional
information related to proforma financial statements and information concerning
CSPCo and OPCo’s fuel procurement process. In October 2008, CSPCo and
OPCo filed an application for rehearing with the PUCO to challenge certain
aspects of the proposed rules.
Within
the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $46
million and $38 million, respectively, for customer choice implementation and
line extension carrying costs. In addition, CSPCo and OPCo would
recover related unrecorded equity carrying costs of $30 million and $21 million,
respectively. Such costs would be recovered over an 8-year period
beginning January 2011. Hearings are scheduled for November 2008 and
an order is expected in the fourth quarter of 2008. If an order is
not received prior to January 1, 2009, CSPCo and OPCo have requested retroactive
application of the new rates back to January 1, 2009 upon
approval. Failure of the PUCO to ultimately approve the recovery of
the regulatory assets would have an adverse effect on future net income 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 during the first quarter of
2008 of $12 million and $14 million, respectively, related to the future
recovery of increased PJM billings previously expensed from June 2007 to
December 2007 for transmission line losses. 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 recoveries are under/over actual net costs, CSPCo and
OPCo will defer the difference as a regulatory asset or regulatory liability and
adjust future customer billings to reflect actual costs, including carrying
costs on the 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.
Also, 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. Upon PUCO approval of an unrelated amendment to the Ormet
contract, Ormet withdrew its rehearing application in August 2008.
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 and incurred $11 million in
pre-construction costs. As a result, CSPCo and OPCo each established
a net regulatory liability of approximately $1 million.
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 cost recoveries 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. In September 2008, the Ohio Consumers’
Counsel filed a motion with the PUCO requesting all Phase 1 costs be refunded to
Ohio ratepayers with interest because the Ohio Supreme Court invalidated the
underlying foundation for the Phase 1 recovery. CSPCo and OPCo filed
a motion with the PUCO that argued the Ohio Consumers’ Counsel’s motion was
without legal merit and contrary to past precedent. 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 net income and cash
flows.
As of
December 31, 2007, the cost of the plant was estimated at $2.7
billion. The estimated cost of the plant has continued to increase
significantly. Management continues to pursue the ultimate
construction of the IGCC plant. CSPCo and OPCo will not start
construction of the IGCC plant until sufficient assurance of regulatory cost
recovery exists.
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 $8 million of this regulatory liability to income for the
nine months ended September 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 2008 market price. If the PUCO approves a market
price for 2008 below $47.69, it could have an adverse effect on future net
income 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.
Hurricane
Ike
In
September 2008, the service territories of CSPCo and OPCo were impacted by
strong winds from the remnants of Hurricane Ike. CSPCo and OPCo
incurred approximately $18 million and $13 million, respectively, in incremental
distribution operation and maintenance costs related to service restoration
efforts. Under the current RSP, CSPCo and OPCo can seek a
distribution rate adjustment to recover incremental distribution expenses
related to major storm service restoration efforts. In September
2008, CSPCo and OPCo established regulatory assets of $17 million and $10
million, respectively, for the incremental distribution operation and
maintenance costs related to service restoration efforts. The
regulatory assets represent the excess above the average of the last three years
of distribution storm expenses excluding Hurricane Ike, which was the
methodology used by the PUCO to determine the recoverable amount of storm
restoration expenses in the most recent 2006 PUCO storm damage recovery
decision. Prior to December 31, 2008, which is the expiration of the
RSP, CSPCo and OPCo will file for recovery of the regulatory
assets. As a result of the past favorable treatment of storm
restoration costs and the favorable RSP provisions, management believes the
recovery of the regulatory assets is probable. If these regulatory
assets are not recoverable, it would have an adverse effect on future net income
and cash flows.
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 the principal and interest on the securitization
bonds over a period ending in 2020. TCC has refunded its net other
true-up regulatory liabilities of $375 million during the period October 2006
through June 2008 via a CTC credit rate rider. Cash paid for these
CTC refunds for the nine months ended September 30, 2008 and 2007 was $75
million and $207 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 orders seeking to
further reduce TCC’s true-up recoveries.
In March
2007, the Texas District Court judge hearing the appeals 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 unfavorable decision finding that the PUCT erred by applying an
invalid rule to determine the carrying cost rate. The favorable
commercial unreasonableness decision was not reversed. The Texas
Court of Appeals denied intervenors’ motion for rehearing. In May
2008, TCC, the PUCT and intervenors filed petitions for review with the Texas
Supreme Court.
Management
cannot predict the outcome of these court proceedings and PUCT remand
decisions. If TCC ultimately succeeds in its appeals, it could have a
material favorable effect on future net income, cash flows and financial
condition. If municipal customers and other intervenors succeed in
their appeals it could have a substantial adverse effect on future net income,
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 $103 million of the
CTC other true-up items to 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 securitization
refund is an IRS normalization violation. The deferral of the CTC
refund negates the securitization reduction pending resolution of the
normalization violation issue.
In March
2008, the IRS issued final regulations addressing Accumulated Deferred
Investment Tax Credit (ADITC) and Excess Deferred Federal Income Tax (EDFIT)
normalization requirements. Consistent with a 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. 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
this additional evidence.
TCC
expects that the PUCT will allow TCC to retain and not refund these
amounts. This will have a favorable effect on future net income 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. Since management expects that the PUCT will allow TCC to
retain the deferred CTC refund amounts in order to avoid an IRS normalization
violation, management has not accrued any related interest expense should TCC
ultimately be required to refund these amounts. If accrued,
management estimates the interest expense would be approximately $2 million
higher for the period July 1, 2008 through September 30, 2008 based on a CTC
interest rate of 7.5%.
However,
if the PUCT orders TCC to flow the tax benefits to customers, thereby causing
TCC to violate the IRS’ normalization regulations, it could result in TCC’s
repayment to the IRS of ADITC on all property, including transmission and
distribution property. This amount approximates $103 million as of
September 30, 2008. It will also lead to a loss of TCC’s right to
claim accelerated tax depreciation in future tax returns. If TCC is
required to repay to the IRS its ADITC and is also required to refund ADITC to
customers, it would have an unfavorable effect on future net income and cash
flows. 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 to work with the PUCT to
resolve the issue and avoid the adverse effects of a normalization violation on
future net income, cash flows and financial condition.
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. It is possible that TCC’s stranded cost recovery, which
is currently on appeal, may be affected by a PUCT remedy.
In May
2008, the Texas Court of Appeals issued a decision in TCC’s True-up Proceeding
determining that even though excess earnings had been previously refunded to
REPs, TCC 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 net income 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 the excess earnings remand and whether it will adversely
affect future net income and cash flows.
OTHER
TEXAS RATE MATTERS
Hurricanes
Dolly and Ike
In July
and September 2008, TCC’s service territory in south Texas was hit by Hurricanes
Dolly and Ike, respectively. TCC incurred $11 million and $1 million
in incremental operation and maintenance costs related to service restoration
efforts for Hurricanes Dolly and Ike, respectively. TCC has a
PUCT-approved catastrophe reserve which permits TCC to collect $1.3 million on
an annual basis with authority to continue the collection until the catastrophe
reserve reaches $13 million. Any incremental operation and
maintenance costs can be charged against the catastrophe reserve if the total
incremental operation and maintenance costs for a storm exceed $500
thousand. In June 2008, prior to these hurricanes, TCC had
approximately $2 million recorded in the catastrophe reserve
account. Since the catastrophe reserve balance was less than the
incremental operation and maintenance costs related to Hurricanes Dolly and Ike,
TCC established a net regulatory asset for $10 million.
Under
Texas law and as previously approved by the PUCT in prior base rate cases, the
regulatory asset will be included in rate base in the next base rate
filing. At that time, TCC will evaluate the existing catastrophe
reserve amounts and review potential future events to determine the appropriate
funding level to request.
ETT
In
December 2007, TCC contributed $70 million of transmission facilities to ETT, a
newly-formed joint venture which will own and operate transmission assets in
ERCOT. The PUCT approved ETT's initial rates, its request for a
transfer of facilities and a certificate of convenience and necessity to operate
as a stand alone transmission utility in the ERCOT region. ETT was
awarded a 9.96% after tax return on equity rate in those
approvals. In 2008, intervenors filed a notice of appeal to the
Travis County District Court. In October 2008, the court ruled that
the PUCT exceeded its authority by approving ETT’s application as a stand alone
transmission utility without a service area under the wrong section of the
statute. Management believes that ruling is
incorrect. Moreover, ETT provided evidence in its application that
ETT has complied with what the court determined was the proper section of the
statute. As of September 30, 2008, AEP’s net investment in ETT was
$16 million. ETT is considering its options for responding to the
ruling including an appeal of the Travis County District Court
ruling. Depending upon the ultimate outcome of the Travis County
District Court ruling, TCC may be required to repurchase the $70 million of
transmission facilities TCC contributed to ETT. Management cannot
predict the outcome of this proceeding or its future effect on net income and
cash flows.
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. This 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%. Hearings began in October 2008. As permitted under
Virginia law, APCo implemented these new base rates, subject to refund,
effective October 28, 2008.
In
September 2008, the Attorney General’s office filed testimony recommending the
proposed $208 million annual increase in base rate be reduced to $133
million. The decrease is principally due to the use of a return on
equity approved in the last base rate case of 10% and various rate base and
operating income adjustments, including a $25 million proposed disallowance of
capacity equalization charges payable by APCo as a deficit member of the FERC
approved AEP Power Pool.
In
October 2008, the Virginia SCC staff filed testimony recommending the proposed
$208 million annual increase in base rate be reduced to $157
million. The decrease is principally due to the use of a recommended
return on equity of 10.1%. In October 2008, hearings were held in
which APCo filed a $168 million settlement agreement which was accepted by all
parties except one industrial customer. APCo expects to receive a
final order from the Virginia SCC in November 2008.
Virginia
E&R Costs Recovery Filing
As of
September 2008, APCo has $118 million of deferred Virginia incremental E&R
costs (excluding $25 million of unrecognized equity carrying
costs). The $118 million consists of $6 million already approved by
the Virginia SCC to be collected during the fourth quarter 2008, $54 million
relating to APCo’s May 2008 filing for recovery in 2009, and $58 million,
representing costs deferred in 2008 to date, to be included (along with the
fourth quarter 2008 E&R deferrals) in the 2009 E&R filing, to be
collected in 2010.
In
September 2008, a settlement was reached between the parties to the 2008 filing
and a stipulation agreement (stipulation) was submitted to the hearing
examiner. The stipulation provides for recovery of $61 million of
incremental E&R costs in 2009 which is an increase of $12 million over the
level of E&R surcharge revenues being collected in 2008. The
stipulation included an unfavorable $1 million adjustment related to certain
costs considered not recoverable E&R costs and recovery of $4.5 million
representing one-half of a $9 million Virginia jurisdictional portion of NSR
settlement expenses recorded in 2007. In accordance with the
stipulation, APCo will request the remaining one-half of the $9 million of NSR
settlement expenses in APCo’s 2009 E&R filing. The stipulation
also specifies that APCo will remove $3 million of the $9 million of NSR
settlement expenses requested to be recovered over 3 years in the current base
rate case from the base rate case’s revenue requirement.
In
September 2008, the hearing examiner recommended that the Virginia SCC accept
the stipulation. As a result, in September 2008, APCo deferred as a
regulatory asset $9 million of NSR settlement expenses it had expensed in 2007
that have become probable of future recovery. In October 2008, the
Virginia SCC approved the stipulation which will have a favorable effect on 2009
future cash flows of $61 million and on net income for the previously
unrecognized equity costs of approximately $11 million. If the
Virginia SCC were to disallow a material portion of APCo’s 2008 deferral, it
would have an adverse effect on future net income and 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. The adjusted factor increases annual fuel clause 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 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. In August 2008, the Virginia SCC issued an order to allow APCo
to implement the increased fuel factor on an interim basis for services rendered
after August 2008. In September 2008, the Virginia SCC staff filed
testimony recommending a lower fuel factor which will result in an annualized
increase of $117 million, which includes the PJM transmission line loss costs,
instead of APCo’s proposed $132 million. In October 2008, the
Virginia SCC ordered an annualized increase of $117 million for services
rendered on and after October 20, 2008.
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
September 30, 2008, APCo has deferred for future recovery pre-construction IGCC
costs of approximately $9 million allocated to Virginia jurisdictional
operations.
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 allocated $134
million in future tax credits to APCo for the planned IGCC plant contingent upon
the commencement of construction, qualifying expense being incurred and
certification of the IGCC plant prior to July 2010. Although
management continues to pursue the construction of the IGCC plant, APCo will not
start construction of the IGCC plant until sufficient assurance of cost recovery
exists. If the plant is cancelled, APCo plans to seek recovery of its
prudently incurred deferred pre-construction costs. If the plant is
cancelled and if the deferred costs are not recoverable, it would have an
adverse effect on future net income and cash flows.
Mountaineer
Carbon Capture Project
In
January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party,
entered into an agreement to jointly construct a CO2 capture
facility. APCo and Alstom will each own part of the CO2 capture
facility. APCo will also construct and own the necessary facilities
to store the CO2. APCo’s
estimated cost for its share of the facilities is $76
million. Through September 30, 2008, APCo incurred $13 million in
capitalized project costs which is included in Regulatory
Assets. APCo plans to seek recovery for the CO2 capture
and storage project costs in its next Virginia and West Virginia base rate
filings which are expected to be filed in 2009. APCo is presently
seeking a return on the capitalized project costs in its current Virginia base
rate filing. The Attorney General has recommended that the project
costs should be shared by all affiliated operating companies with coal-fired
generation plants. If a significant portion of the project costs are
excluded from base rates and ultimately disallowed in Virginia and/or West
Virginia, it could have an adverse effect on future net income 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 rate increases,
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 if
actual costs exceed the recoveries due to the deferral of any
over/under-recovery of ENEC costs. The construction cost and
reliability surcharges are not subject to a true-up to actual costs and could
impact future net income and cash flows.
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. Also, in March 2008, various
intervenors filed petitions with the WVPSC to reconsider the
order. No action has been taken on the requests for
rehearing. At the time of the filing, the cost of the plant was
estimated at $2.2 billion. As of September 30, 2008, the estimated
cost of the plant has continued to significantly increase. In July
2008, based on the unfavorable 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 September 30, 2008, APCo deferred for future
recovery pre-construction IGCC costs of approximately $9 million applicable to
the West Virginia jurisdiction and approximately $2 million applicable to the
FERC jurisdiction. In July 2008, the
IRS allocated $134 million in future tax credits to APCo for the planned IGCC
plant. Although management continues to pursue the ultimate
construction of the IGCC plant, APCo will not start construction of the IGCC
plant until sufficient assurance of cost recovery exists. If the plant is
cancelled, APCo plans to seek recovery of its prudently incurred deferred
pre-construction costs. If the plant is cancelled and if the deferred
costs are not recoverable, it would have an adverse effect on future net income
and cash flows.
Indiana Rate
Matters
Indiana Base
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 and will
adversely affect cash flows when tariff rates are revised to reflect the effect
of the depreciation expense reduction. The filing also 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.
In
September 2008, the Indiana Office of Utility Consumer Counselor (OUCC) and the
Industrial Customer Coalition filed testimony recommending a $14 million and $37
million decrease in revenue, respectively. Two other intervenors
filed testimony on limited issues. The OUCC and the Industrial
Customer Coalition recommended that the IURC reduce the ROE proposed by I&M,
reduce or limit the amount of off-system sales margin sharing, deny the recovery
of reliability enhancement costs and reject the proposed environmental
compliance cost recovery trackers. In October 2008, I&M filed
testimony rebutting the recommendations of the OUCC. Hearings are
scheduled for December 2008. A decision is expected from the IURC by
June 2009.
Michigan Rate
Matters
Michigan
Restructuring
Although
customer choice commenced for I&M’s Michigan customers on January 1, 2002,
I&M’s rates for generation in Michigan continued to be cost-based regulated
because none of I&M's customers elected to change suppliers and no
alternative electric suppliers were registered to compete in I&M's Michigan
service territory. In October 2008, the Governor of Michigan signed
legislation to limit customer choice load to no more than 10% of the annual
retail load for the preceding calendar year and to require the remaining 90% of
annual retail load to be phased into cost-based rates. The new legislation
also requires utilities to meet certain energy efficiency and renewable
portfolio standards and requires cost recovery of meeting those
standards. Management continues to conclude that I&M's rates for
generation in Michigan are cost-based regulated.
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. Both 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, the 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.
We expect
any adverse court of appeals decision could be applied prospectively but it is
possible that a retrospective refund could also be ordered. KPCo’s
exposure is indeterminable at this time although an adverse decision would have
an unfavorable effect on future net income and cash flows, assuming the
legislature does not enact legislation that authorizes such
surcharges.
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. For the nine months ended September 30, 2008, KPCo recorded $16
million of income and the related Regulatory Asset for Under-Recovered Fuel
Costs for transmission line losses incurred from June 2007 through September
2008 of which $7 million related to 2007.
Oklahoma Rate
Matters
PSO
Fuel and Purchased Power
The
Oklahoma Industrial Energy Consumers appealed an ALJ recommendation in June 2008
regarding a pending fuel case involving the reallocation of $42 million of
purchased power costs among AEP West companies in 2002. The Oklahoma
Industrial Energy Consumers requested that PSO be required to refund this $42
million of reallocated purchased power costs through its fuel
clause. PSO had recovered the $42 million during the period June 2007
through May 2008. In August 2008, the OCC heard the appeal and a
decision is pending.
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 previously was determined not to be jurisdictional to the
OCC. See “Allocation of Off-system Sales Margins” section within
“FERC Rate Matters”. Consistent with the prior OCC determination, the
ALJ found that the OCC lacked authority to alter the FERC-approved allocation
methodology and that PSO’s fuel costs were prudent. The intervenors
appealed the ALJ recommendation and the OCC heard the appeal in August
2008. In August 2008, the OCC filed a complaint at the FERC alleging
that AEPSC inappropriately allocated off-system trading margins between the AEP
East companies and the AEP West companies and did not properly allocate
off-system trading margins within the AEP West companies.
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. In August 2008, the OCC issued
a final order that PSO’s calculations of fuel and purchased power costs were
accurate and are consistent with PSO’s fuel tariff.
In
September 2008, the OCC initiated a review of PSO’s generation, purchased power
and fuel procurement processes and costs for 2007. Under the OCC
minimum filing requirements, PSO is required to file testimony and supporting
data within 60 days which will occur in the fourth quarter of
2008. Management cannot predict the outcome of the pending fuel and
purchased power cost recovery filings or prudence reviews. However,
PSO believes its fuel and purchased power procurement practices and costs were
prudent and properly incurred and therefore are legally
recoverable.
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 pre-approval to construct the coal-fired Red Rock Generating
Facility (Red Rock) 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
pre-approval. The OCC stated that PSO failed to fully study other
alternatives to a coal-fired plant. Since PSO and OG&E could not
obtain pre-approval to build Red Rock, PSO and OG&E cancelled the third
party construction contract and their joint venture development
contract. In June 2008, PSO 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 $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 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. In July 2008, PSO filed a base rate case which included $11
million of deferred Red Rock costs plus carrying charges at PSO’s AFUDC rate
beginning in March 2008. See “2008 Oklahoma Base Rate Filing” section
below.
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 the December 2007 ice
storm.
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. The settlement also provided for PSO to 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 actual
costs. After the true-up, application of proceeds from to-date sales
of excess SO2 emission
allowances and carrying costs, the ice storm regulatory asset was $64
million. 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. In July 2008, as required by the settlement
agreement, PSO filed its reconciliation of the December 2007 storm restoration
costs along with a proposed tariff to recover the amounts not offset by the
sales of SO2 emission
allowances. In September 2008, the OCC staff filed testimony
supporting PSO’s filing with minor changes. In October 2008, an ALJ
recommended that PSO recover $62 million of the December 2007 storm restoration
costs before consideration of emission allowance gains and carrying
costs. In October 2008, the OCC approved the filing which allows PSO
to recover $62 million of the December 2007 storm restoration costs beginning in
November 2008.
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 costs, 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 actually $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 base rates to become effective in the
first quarter of 2009. In
October 2008, the OCC staff, the Attorney General’s office, and a group of
industrial customers filed testimony recommending annual base rate increases of
$86 million, $68 million and $29 million, respectively. The
differences are principally due to the use of recommended return on equity of
10.88%, 10% and 9.5% by the OCC staff, the Attorney General’s office, and a
group of industrial customers. The OCC staff and the Attorney
General’s office recommended $22 million and $8 million, respectively, of costs
included in the filing be recovered through the fuel adjustment clause and
riders outside of base rates.
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. Under the plan, beginning in 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 August 2008, the LPSC issued
an order approving the settlement.
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 accordance with the settlement, SWEPCo recorded
a $4 million regulatory liability related to the reduction in generation
depreciation rates. The amount of the unamortized regulatory
liability for the reduction in generation depreciation was $4 million as of
September 30, 2008. In August 2008, SWEPCo implemented the FRP rates,
subject to refund, as the LPSC staff reviews SWEPCo’s FRP filing and the
production depreciation study.
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 currently
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 September 2008, the LPSC approved
SWEPCo’s request for certification to construct the Stall Plant. 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 September 30, 2008, SWEPCo has capitalized
pre-construction costs of $158 million and has contractual construction
commitments of an additional $145 million. As of September 30, 2008,
if the plant had been cancelled, cancellation fees of $61 million would have
been required in order to terminate these construction
commitments. If SWEPCo cancels the plant and cannot recover its
capitalized costs, including any cancellation fees, it would have an adverse
effect on future net income, cash flows and possibly financial
condition.
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 currently
estimated to cost $1.5 billion, excluding AFUDC, with SWEPCo’s portion estimated
to cost $1.1 billion. 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 August
2008, the PUCT issued an order approving the Turk Plant with the following four
conditions: (a) the capping of capital costs for the Turk Plant at the $1.5
billion projected construction cost, excluding AFUDC, (b) capping CO2 emission
costs at $28 per ton through the year 2030, (c) holding Texas ratepayers
financially harmless from any adverse impact related to the Turk Plant not being
fully subscribed to by other utilities or wholesale customers and (d) providing
the PUCT all updates, studies, reviews, reports and analyses as previously
required under the Louisiana and Arkansas orders. An intervenor filed
a motion for rehearing seeking reversal of the PUCT’s
decision. SWEPCo filed a motion for rehearing stating that the two
cost cap restrictions are unlawful. In September 2008, the motions
for rehearing were denied. In October 2008, SWEPCo appealed the
PUCT’s order regarding the two cost cap restrictions. If the cost cap
restrictions are upheld and construction or emissions costs exceed the
restrictions, it could have a material adverse impact on future net income and
cash flows. In October 2008, an intervenor filed an appeal contending
that the PUCT’s grant of a conditional Certificate of Public Convenience and
Necessity for the Turk Plant was not necessary to serve retail
customers.
SWEPCo is
also working with the Arkansas Department of Environmental Quality for the
approval of an air permit and the U.S. Army Corps of Engineers for
the approval of a wetlands and stream impact permit. Once SWEPCo
receives the air permit, they will commence construction. 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.
In
January 2008 and July 2008, SWEPCo filed applications for authority with the
APSC to construct transmission lines necessary for service from the Turk
Plant. Several landowners filed for intervention status and one
landowner also contended he should be permitted to re-litigate Turk Plant
issues, including the need for the generation. The APSC granted their
intervention but denied the request to re-litigate the Turk Plant
issues. The landowner filed an appeal to the Arkansas State Court of
Appeals in June 2008.
The
Arkansas Governor’s Commission on Global Warming is scheduled to issue its final
report to the Governor by November 1, 2008. The Commission was
established to set a global warming pollution reduction goal together with a
strategic plan for implementation in Arkansas. If legislation is
passed as a result of the findings in the Commission’s report, it could impact
SWEPCo’s proposal to build the Turk Plant.
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 September 30, 2008, SWEPCo has capitalized
approximately $448 million of expenditures and has significant contractual
construction commitments for an additional $771 million. As of
September 30, 2008, if the plant had been cancelled, SWEPCo would have incurred
cancellation fees of $61 million. If the Turk Plant does not receive
all necessary approvals on reasonable terms and SWEPCo cannot recover its
capitalized costs, including any cancellation fees, it would have an adverse
effect on future net income, 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, based on advice of legal
counsel, 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, based on anticipated settlements, the AEP East companies provided reserves
for net refunds for current and future SECA settlements totaling $37 million and
$5 million in 2006 and 2007, respectively, applicable to a total of $220 million
of SECA revenues. AEP has completed settlements totaling $7 million
applicable to $75 million of SECA revenues. The balance in the
reserve for future settlements as of September 2008 was $35
million. In-process settlements total $3 million applicable to $37
million of SECA revenues. Management believes that the available $32
million of reserves for possible refunds are sufficient to settle the remaining
$108 million of contested SECA revenues.
If the
FERC adopts the ALJ’s decision and/or AEP cannot settle all of the remaining
unsettled claims within the remaining amount reserved for refund, it will have
an adverse effect on future net income 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 $32 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 necessary.
The FERC PJM Regional
Transmission Rate Proceeding
With the
elimination of T&O rates, the expiration of SECA rates and after
considerable administrative litigation at the FERC in which AEP sought to
mitigate the effect of the 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 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, net income and cash flows.
The AEP
East companies filed for and in 2006 obtained increases in their 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 80% 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 net income and cash flows will
continue to be adversely affected in Indiana and Michigan until the remaining
20% 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 argued 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 of time due to regulatory lag until the AEP East companies 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 by $63 million
annually. 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. The remaining $54 million requested would be billed to the AEP
East companies to be recovered in retail rates. Retail rates for
jurisdictions other than Ohio are not affected until the next base rate filing
at FERC. Retail rates for CSPCo and OPCo would be adjusted through
the Transmission Cost Recovery Rider (TCRR) totaling approximately $10 million
and $12 million, respectively. The TCRR includes a true-up mechanism
so CSPCo’s and OPCo’s net income will not be adversely affected by a FERC
ordered transmission rate increase. Other jurisdictions would be
recoverable on a lag basis as base rates are changed. AEP requested
an effective date of October 1, 2008. In September 2008, the FERC
issued an order conditionally accepting AEP’s proposed formula rate, subject to
a compliance filing, suspended the effective date until March 1, 2009 and
established a settlement proceeding with an ALJ. Management is unable
to predict the outcome of this filing.
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 requested 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. In September 2008, the FERC issued
an order accepting AEP’s market-based rates with minor changes and rejected the
PUCO’s and the industrial retail customers’ suggestions to further investigate
AEP’s lack of market power.
In an
unrelated matter, in May 2008, the FERC issued an order in response to a
complaint from the state of Maryland’s Public Service Commission to hold a
future hearing to review the structure of the three pivotal market power
supplier tests in PJM. In September 2008, PJM filed a report on the
results of the PJM stakeholder process concerning the three pivotal supplier
market power tests which recommended the FERC not make major revisions to the
test because the test is not unjust or unreasonable.
The
FERC’s order will become final if no requests for rehearing are
filed. If a request for rehearing is filed and ultimately results in
a further investigation by the FERC which 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 and cash flows.
Allocation
of Off-system Sales Margins
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 the 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 net income and cash flows for AEP
Consolidated, the AEP East companies and the AEP West 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. In June 2008, the Oklahoma Industrial
Energy Consumers appealed the ALJ recommendation to the OCC. In
August 2008, the OCC heard the appeal and a decision is pending. See
“PSO Fuel and Purchased Power” section within “Oklahoma Rate
Matters”. In August 2008, the OCC filed a complaint at the FERC
alleging that AEPSC inappropriately allocated off-system trading margins between
the AEP East companies and the AEP West companies and did not properly allocate
off-system trading margins within the AEP West companies. The PUCT,
the APSC and the Oklahoma Industrial Energy Consumers have all intervened in
this filing.
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 the final
fuel reconciliation in Texas under the restructuring
legislation. 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.
Management
cannot predict the outcome of these proceedings. However, 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. The results of these proceedings could
have an adverse effect on future net income and cash flows for AEP Consolidated,
the AEP East companies and the AEP West companies.
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 September 30,
2008, the maximum future payments for LOCs issued under the two $1.5 billion
credit facilities are $67 million with maturities ranging from October 2008 to
October 2009. The two $1.5 billion credit facilities were reduced by
Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its
bankruptcy.
In April
2008, we entered into a $650 million 3-year credit agreement and a $350 million
364-day credit agreement which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $23 million and $12 million, respectively, following its
bankruptcy. As of September 30, 2008, $372 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 September 30, 2008, SWEPCo has collected approximately
$37 million through a rider for final mine closure costs, of which approximately
$7 million is recorded in Other Current Liabilities, $5 million is recorded in
Asset Retirement Obligations and $25 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 September 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 $20
million for I&M and $23 million for SWEPCo as of September 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) assuming the fair
market value of the equipment is zero at the end of the current lease
term. However, we believe that the fair market value would produce a
sufficient sales price to avoid any loss.
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. In October 2008, the court
approved a consent decree for a settlement reached with the Sierra Club in a
case involving 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. Under the terms of the settlement, the joint-owners agreed
to certain emission targets related to NOx, SO2 and
PM. They also agreed to make energy efficiency and renewable energy
commitments that are conditioned on receiving PUCO approval for recovery of
costs. The joint-owners also agreed to forfeit 5,500 SO2 allowances
and provide $300 thousand to a third party organization to establish
a solar water heater rebate program. 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.
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. In October 2008, TCEQ approved the
settlement.
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 net income, 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. The defendants filed
motions to dismiss the action. The motions are pending before the
court. 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 issued a decision that would vacate the CAIR and remand
the rule to the Federal EPA. In September 2008, the Federal EPA and
other parties petitioned for rehearing. We are unable to predict the
outcome of the rehearing petitions or 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 $9 million of
annual CAIR NOx allowances
which are included in Deferred Charges and Other on our Condensed Consolidated
Balance Sheet as of September 30, 2008. The market value of annual
CAIR NOx allowances
decreased following this court decision. However, our
weighted-average cost of these allowances is below market. If CAIR
remains vacated, management intends to seek partial recovery of the cost of
purchased allowances. Any unrecovered portion would have an adverse
effect on future net income 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 state
implementation plan (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 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. I&M recorded
approximately $4 million of expense through September 30, 2008. 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.
Cook
Plant Unit 1 Fire and Shutdown
Cook
Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in
Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine
vibrations likely caused by blade failure which resulted in a fire on the
electric generator. This equipment is in the turbine building and is
separate and isolated from the nuclear reactor. The steam turbines
that caused the vibration were installed in 2006 and are under warranty from the
vendor. The warranty provides for the replacement of the turbines if
the damage was caused by a defect in the design or assembly of the
turbines. I&M is also working with its insurance company, Nuclear
Electric Insurance Limited (NEIL), and turbine vendor to evaluate the extent of
the damage resulting from the incident and the costs to return the unit to
service. We cannot estimate the ultimate costs of the outage at this
time. Management believes that I&M should recover a significant
portion of these costs through the turbine vendor’s warranty, insurance and
the regulatory process. Our
preliminary analysis indicates that Unit 1 could resume operations as early as
late first quarter/early second quarter of 2009 or as late as the second half of
2009, depending upon whether the damaged components can be repaired or whether
they need to be replaced.
I&M
maintains property insurance through NEIL with a $1 million
deductible. I&M also maintains a separate accidental outage
policy with NEIL whereby, after a 12 week deductible period, I&M is entitled
to weekly payments of $3.5 million during the outage period for a covered
loss. If the ultimate costs of the incident are not covered by
warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.
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 Charges 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 ($427
million including interest at December 31, 2007). In August 2008, the
court entered a final judgment of $346 million (the original judgment less $1
million BOA would have incurred to remove 55 BCF of natural gas from the Bammel
storage facility) and clarified the interest calculation method. We
appealed and posted a bond 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. After recalculation for the final judgment, the liability for
the BOA litigation was $431 million at September 30, 2008. The
liability for the BOA litigation was $427 million at December 31,
2007. These liabilities 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. In September 2008,
the trial court denied the plaintiff’s motion for class certification and
ordered briefing on whether the plaintiff may maintain an ERISA claim on behalf
of the Plan in the absence of class certification. In October 2008,
Counsel for the plaintiff filed a motion to intervene on behalf of an individual
seeking to intervene as a new plaintiff. We intend to oppose this
motion and 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.
Rail
Transportation Litigation
In
October 2008, the Oklahoma Municipal Power Authority and the Public Utilities
Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed
a lawsuit in United States District Court, Western District of Oklahoma against
AEP alleging breach of contract and breach of fiduciary duties related to
negotiations for rail transportation services for the plant. The
plaintiffs allege that AEP took the duty of the project manager, PSO, and
operated the plant for the project manager and is therefore responsible for the
alleged breaches. We intend to vigorously defend against these
allegations.
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 net income and cash flows. We
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 (AEP River Operations segment)
In June
2008, AEP River Operations 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 AEP River Operations’
business 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.
Dresden
Plant (Utility Operations segment)
In August
2007, AEGCo agreed to purchase the partially completed Dresden Plant from
Dominion Resources, Inc. for $85 million and the assumption of liabilities of $2
million. AEGCo completed the purchase in September
2007. As of September 30, 2008, AEGCo has incurred approximately $53
million in construction costs (excluding AFUDC) at the Dresden Plant and expects
to incur approximately $169 million in additional costs (excluding AFUDC) prior
to completion in 2010. The projected completion date of the Dresden
Plant is currently under review. To the extent that the completion of
the Dresden Plant is delayed, the total projected cost of the Dresden Plant
could change. The Dresden Plant is located near Dresden, Ohio and is
a natural gas, combined cycle power plant. When completed, the
Dresden Plant will have a generating capacity of 580 MW.
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 net income nor do
we expect any remaining litigation to have a significant effect on our net
income.
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
September 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.
Sweeny
Cogeneration Plant (Generation and Marketing segment)
In
October 2007, we sold our 50% equity interest in the Sweeny Cogeneration Plant
(Sweeny) to ConocoPhillips for approximately $80 million, including working
capital and the buyer’s assumption of project debt. The Sweeny
Cogeneration Plant is a 480 MW cogeneration plant located within ConocoPhillips’
Sweeny refinery complex southwest of Houston, Texas. We were the
managing partner of the plant, which is co-owned by General Electric
Company. As a result of the sale, we recognized a $47 million pretax
gain ($30 million, net of tax) in the fourth quarter of 2007, which is reflected
in Gain on Disposition of Equity Investments, Net on our 2007 Consolidated
Statement of Income.
In
addition to the sale of our interest in Sweeny, we agreed to separately sell our
purchase power contract for our share of power generated by Sweeny through 2014
for $11 million to ConocoPhillips. ConocoPhillips also agreed to assume certain
related third-party power obligations. These transactions were
completed in conjunction with the sale of our 50% equity interest in October
2007. As a result of this sale, we recognized an $11 million pretax
gain ($7 million, net of tax) in the fourth quarter of 2007, which is included
in Other revenues on our 2007 Consolidated Statement of Income. In
the fourth quarter of 2007, we recognized a total of $58 million in pretax gains
($37 million, net of tax).
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 September 30,
|
|
(in
millions)
|
|
2008
Revenue
|
|
$ |
- |
|
2008
Pretax Income
|
|
|
- |
|
2008
Earnings, Net of Tax
|
|
|
- |
|
|
|
|
|
|
2007
Revenue
|
|
$ |
- |
|
2007
Pretax Income
|
|
|
- |
|
2007
Earnings, Net of Tax
|
|
|
- |
|
|
|
U.K.
Generation (a)
|
|
Nine
Months Ended September 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 nine months ended
September 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 nine months ended September 30, 2008 and
2007:
|
|
|
Other
Postretirement
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
Three
Months Ended September 30,
|
|
Three
Months Ended September 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
25 |
|
|
$ |
24 |
|
|
$ |
10 |
|
|
$ |
11 |
|
Interest
Cost
|
|
|
62 |
|
|
|
59 |
|
|
|
28 |
|
|
|
26 |
|
Expected
Return on Plan Assets
|
|
|
(84 |
) |
|
|
(85 |
) |
|
|
(27 |
) |
|
|
(26 |
) |
Amortization
of Transition Obligation
|
|
|
- |
|
|
|
- |
|
|
|
7 |
|
|
|
6 |
|
Amortization
of Net Actuarial Loss
|
|
|
10 |
|
|
|
15 |
|
|
|
3 |
|
|
|
3 |
|
Net
Periodic Benefit Cost
|
|
$ |
13 |
|
|
$ |
13 |
|
|
$ |
21 |
|
|
$ |
20 |
|
|
|
|
Other
Postretirement
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
Nine
Months Ended September 30,
|
|
Nine
Months Ended September 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
75 |
|
|
$ |
72 |
|
|
$ |
31 |
|
|
$ |
32 |
|
Interest
Cost
|
|
|
187 |
|
|
|
176 |
|
|
|
84 |
|
|
|
78 |
|
Expected
Return on Plan Assets
|
|
|
(252 |
) |
|
|
(254 |
) |
|
|
(83 |
) |
|
|
(78 |
) |
Amortization
of Transition Obligation
|
|
|
- |
|
|
|
- |
|
|
|
21 |
|
|
|
20 |
|
Amortization
of Net Actuarial Loss
|
|
|
29 |
|
|
|
44 |
|
|
|
8 |
|
|
|
9 |
|
Net
Periodic Benefit Cost
|
|
$ |
39 |
|
|
$ |
38 |
|
|
$ |
61 |
|
|
$ |
61 |
|
We have
significant investments in several trust funds to provide for future pension and
OPEB payments. All of our trust funds’ investments are
well-diversified and managed in compliance with all laws and
regulations. The value of the investments in these trusts has
declined due to the decreases in the equity and fixed income
markets. Although the asset values are currently lower, this decline
has not affected the funds’ ability to make their required
payments.
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 AEP
River 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.
|
AEP
River 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 nine
months ended September 30, 2008 and 2007 and balance sheet information as of
September 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
|
|
AEP River
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
Three
Months Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
4,108
|
(d)
|
$
|
160
|
|
$
|
1
|
|
$
|
(78
|
)
|
$
|
-
|
|
$
|
4,191
|
|
Other
Operating Segments
|
|
|
(140
|
)(d)
|
|
7
|
|
|
95
|
|
|
83
|
|
|
(45
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
3,968
|
|
$
|
167
|
|
$
|
96
|
|
$
|
5
|
|
$
|
(45
|
)
|
$
|
4,191
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued Operations and Extraordinary
Loss
|
|
$
|
357
|
|
$
|
11
|
|
$
|
16
|
|
$
|
(10
|
)
|
$
|
-
|
|
$
|
374
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Net
Income (Loss)
|
|
$
|
357
|
|
$
|
11
|
|
$
|
16
|
|
$
|
(10
|
)
|
$
|
-
|
|
$
|
374
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
AEP River
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
Three
Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
3,423
|
(d)
|
$
|
134
|
|
$
|
241
|
|
$
|
(9
|
)
|
$
|
-
|
|
$
|
3,789
|
|
Other
Operating Segments
|
|
|
177
|
(d)
|
|
4
|
|
|
(161
|
)
|
|
19
|
|
|
(39
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
3,600
|
|
$
|
138
|
|
$
|
80
|
|
$
|
10
|
|
$
|
(39
|
)
|
$
|
3,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$
|
388
|
|
$
|
18
|
|
$
|
3
|
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
407
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
AEP River
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
Nine
Months Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
10,318
|
(d)
|
$
|
442
|
|
$
|
409
|
|
$
|
35
|
|
$
|
-
|
|
$
|
11,204
|
|
Other
Operating Segments
|
|
|
257
|
(d)
|
|
18
|
|
|
(143
|
)
|
|
(17
|
)
|
|
(115
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
10,575
|
|
$
|
460
|
|
$
|
266
|
|
$
|
18
|
|
$
|
(115
|
)
|
$
|
11,204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$
|
1,030
|
|
$
|
21
|
|
$
|
43
|
|
$
|
133
|
|
$
|
-
|
|
$
|
1,227
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
-
|
|
|
1
|
|
Net
Income
|
|
$
|
1,030
|
|
$
|
21
|
|
$
|
43
|
|
$
|
134
|
|
$
|
-
|
|
$
|
1,228
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
AEP River
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
9,127
|
(d)
|
$
|
367
|
|
$
|
574
|
|
$
|
36
|
|
$
|
-
|
|
$
|
10,104
|
|
|
Other
Operating Segments
|
|
|
460
|
(d)
|
|
10
|
|
|
(347
|
)
|
|
(14
|
)
|
|
(109
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
9,587
|
|
$
|
377
|
|
$
|
227
|
|
|
22
|
|
|
(109
|
)
|
$
|
10,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued Operations and Extraordinary
Loss
|
|
$
|
879
|
|
$
|
40
|
|
$
|
17
|
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
935
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
-
|
|
|
2
|
|
Extraordinary
Loss, Net of Tax
|
|
|
(79
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(79
|
)
|
Net
Income
|
|
$
|
800
|
|
$
|
40
|
|
$
|
17
|
|
$
|
1
|
|
$
|
-
|
|
$
|
858
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
AEP River
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
(c)
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
September
30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Property, Plant and Equipment
|
|
$
|
47,699
|
|
$
|
316
|
|
$
|
577
|
|
$
|
45
|
|
$
|
(245
|
)
|
$
|
48,392
|
|
Accumulated
Depreciation and Amortization
|
|
|
16,413
|
|
|
69
|
|
|
133
|
|
|
8
|
|
|
(20
|
)
|
|
16,603
|
|
Total
Property, Plant and Equipment – Net
|
|
$
|
31,286
|
|
$
|
247
|
|
$
|
444
|
|
$
|
37
|
|
$
|
(225
|
)
|
$
|
31,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
41,322
|
|
$
|
380
|
|
$
|
771
|
|
$
|
13,905
|
|
$
|
(13,340
|
)(b)
|
$
|
43,038
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
AEP River
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 or sales activity for these energy marketing contracts as
Revenues from External Customers for the Utility Operations
segment. This is offset by the Utility Operations segment’s
related net sales (purchases) for these contracts to AEPEP in
Revenues from Other Operating Segments of $(95) million and $161 million
for the three months ended September 30, 2008 and 2007, respectively, and
$143 million and $347 million for the nine months ended September 30, 2008
and 2007, respectively. The Generation and Marketing segment
also reports these purchase or sales contracts with Utility Operations as
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 we are pursuing 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 net income.
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 net income. 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 allocated 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 allocated
the project $134 million in credits. In September 2008, we entered
into a memorandum of understanding with the IRS concerning the requirements of
claiming the credits.
In
October 2008, the Emergency Economic Stabilization Act of 2008 (the Act) was
signed into law. The Act extended several expiring tax provisions and
added new energy incentive provisions. The legislation impacted the availability
of research credits, accelerated depreciation of smart meters, production tax
credits and energy efficient commercial building deductions. We have
evaluated the impact of the law change and the application of the law change
will not materially impact our net income, cash flows or financial
condition.
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 net income, cash
flows or financial condition.
Long-term
Debt
|
|
September
30,
|
|
|
December
31,
|
|
Type
of Debt
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Senior
Unsecured Notes
|
|
$ |
11,186 |
|
|
$ |
9,905 |
|
Pollution
Control Bonds
|
|
|
1,817 |
|
|
|
2,190 |
|
First
Mortgage Bonds
|
|
|
- |
|
|
|
19 |
|
Notes
Payable
|
|
|
244 |
|
|
|
311 |
|
Securitization
Bonds
|
|
|
2,132 |
|
|
|
2,257 |
|
Junior
Subordinated Debentures
|
|
|
315 |
|
|
|
- |
|
Notes
Payable To Trust
|
|
|
113 |
|
|
|
113 |
|
Spent
Nuclear Fuel Obligation (a)
|
|
|
264 |
|
|
|
259 |
|
Other
Long-term Debt
|
|
|
2 |
|
|
|
2 |
|
Unamortized
Discount (net)
|
|
|
(66 |
) |
|
|
(62 |
) |
Total
Long-term Debt Outstanding
|
|
|
16,007 |
|
|
|
14,994 |
|
Less
Portion Due Within One Year
|
|
|
682 |
|
|
|
792 |
|
Long-term
Portion
|
|
$ |
15,325 |
|
|
$ |
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 $297 million and $285 million at September
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 nine 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
|
|
|
40
|
|
4.85
|
|
2019
|
APCo
|
|
Pollution
Control Bonds
|
|
|
30
|
|
4.85
|
|
2019
|
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
|
OPCo
|
|
Senior
Unsecured Notes
|
|
|
250
|
|
5.75
|
|
2013
|
SWEPCo
|
|
Pollution
Control Bonds
|
|
|
41
|
|
4.50
|
|
2011
|
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
|
|
|
|
$
|
2,594
|
(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 $2,561 million is net of
issuance costs and premium or
discount.
|
The net
proceeds from the sale of Junior Subordinated Debentures were 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
|
|
|
12
|
|
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
|
|
Pollution
Control Bonds
|
|
|
41
|
|
Variable
|
|
2011
|
SWEPCo
|
|
Notes
Payable
|
|
|
2
|
|
Variable
|
|
2008
|
SWEPCo
|
|
Notes
Payable
|
|
|
3
|
|
4.47
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
Non-Registrant:
|
|
|
|
|
|
|
|
|
|
AEP
Subsidiaries
|
|
Notes
Payable
|
|
|
4
|
|
5.88
|
|
2011
|
AEP
Subsidiaries
|
|
Notes
Payable
|
|
|
10
|
|
Variable
|
|
2017
|
AEGCo
|
|
Senior
Unsecured Notes
|
|
|
7
|
|
6.33
|
|
2037
|
AEPSC
|
|
Notes
Payable
|
|
|
34
|
|
9.60
|
|
2008
|
TCC
|
|
First
Mortgage Bonds
|
|
|
19
|
|
7.125
|
|
2008
|
TCC
|
|
Securitization
Bonds
|
|
|
29
|
|
5.01
|
|
2008
|
TCC
|
|
Securitization
Bonds
|
|
|
21
|
|
5.56
|
|
2010
|
TCC
|
|
Securitization
Bonds
|
|
|
75
|
|
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
|
|
|
$
|
1,582
|
|
|
|
|
In
October 2008, SWEPCo retired $113 million of 5.25% Notes Payable due in
2043.
As of
September 30, 2008, we had $272 million outstanding of tax-exempt long-term debt
sold at auction rates (rates range between 4.353% and 13%) that reset every 35
days. Approximately $218 million of this debt relates to a lease structure
with JMG that we are unable to refinance at this time. In order to
refinance this debt, we need the lessor's consent. 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 had in connection with developments in the subprime
credit market, the credit ratings of these insurers were downgraded or placed on
negative outlook. These market factors 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. Consequently, we chose to exit the auction-rate debt
market. 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 September 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 $272 million to
other permitted modes, including term-put structures, variable-rate and
fixed-rate structures, as opportunities arise.
As of
September 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 6.5% to 8.25% and $495 million was issued at fixed rates ranging
from 4.5% to 5.625%. As of September 30, 2008, trustees held, on our
behalf, approximately $330 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 net income, cash flows, financial condition or
limit any dividend payments in the foreseeable future.
Short-term
Debt
Our
outstanding short-term debt is as follows:
|
|
September
30, 2008
|
|
December
31, 2007
|
|
|
|
Outstanding
|
|
Interest
|
|
Outstanding
|
|
Interest
|
|
|
|
Amount
|
|
Rate
|
|
Amount
|
|
Rate
|
|
Type
of Debt
|
|
(in
thousands)
|
|
|
|
(in
thousands)
|
|
|
|
Commercial
Paper – AEP
|
|
$
|
701,416
|
|
3.25%
|
(a)
|
$
|
659,135
|
|
5.54%
|
(a)
|
Commercial
Paper – JMG (b)
|
|
|
-
|
|
-
|
|
|
701
|
|
5.35%
|
(a)
|
Line
of Credit – Sabine Mining Company (c)
|
|
|
9,520
|
|
7.75%
|
(a)
|
|
285
|
|
5.25%
|
(a)
|
Line
of Credit – AEP (e)
|
|
|
590,700
|
|
3.4813%
|
(d)
|
|
-
|
|
-
|
|
Total
|
|
$
|
1,301,636
|
|
|
|
$
|
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.
|
(d)
|
Rate
based on 1-month LIBOR. In October 2008, this rate was
converted to 4.55% based on prime.
|
(e)
|
In
October 2008, we borrowed an additional $1.4 billion at 4.55% based on
prime.
|
Credit
Facilities
As of
September 30, 2008, in support of our commercial paper program, we had two $1.5
billion credit facilities which were reduced by Lehman Brothers Holdings
Inc.’s commitment amount of $46 million following its bankruptcy. 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 which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $23 million and $12 million, respectively, following its
bankruptcy. Under the facilities, we may issue letters of
credit. As of September 30, 2008, $372 million of letters of credit
were issued by subsidiaries under the 3-year credit agreement to support
variable rate demand notes.
Sale
of Receivables – AEP Credit
In
October 2008, we renewed AEP Credit’s sale of receivables
agreement. The sale of receivables agreement provides a commitment of
$600 million from bank conduits to purchase receivables from AEP
Credit. This agreement will expire in October 2009.
APPALACHIAN
POWER COMPANY
AND
SUBSIDIARIES
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS
Results of
Operations
Third Quarter of 2008
Compared to Third Quarter of 2007
Reconciliation
of Third Quarter of 2007 to Third Quarter of 2008
Income
Before Extraordinary Loss
(in
millions)
Third
Quarter of 2007
|
|
|
|
|
$ |
24 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(9 |
) |
|
|
|
|
Off-system
Sales
|
|
|
8 |
|
|
|
|
|
Other
|
|
|
1 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
26 |
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(10 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1 |
) |
|
|
|
|
Carrying
Costs Income
|
|
|
3 |
|
|
|
|
|
Other
Income
|
|
|
2 |
|
|
|
|
|
Interest
Expense
|
|
|
(2 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
18 |
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
Third
Quarter of 2008
|
|
|
|
|
|
$ |
39 |
|
Income
Before Extraordinary Loss increased $15 million to $39 million in 2008 primarily
due to a decrease in Operating Expenses and Other of $18 million, partially
offset by an increase in Income Tax Expense of $3 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 decreased $9 million primarily due to an increase in sharing of
off-system sales margins with customers and higher capacity settlement
expenses under the Interconnection Agreement. These unfavorable
effects were partially offset by the impact of the Virginia base rate
order issued in May 2007 which included a 2007 provision for revenue
refund in addition to an increase in the recovery of E&R costs in
Virginia.
|
·
|
Margins
from Off-system Sales increased $8 million primarily due to increased
physical sales margins driven by higher prices, 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 $26 million primarily due to
the following:
|
|
·
|
A
$26 million decrease resulting from a settlement agreement in the third
quarter 2007 related to alleged violations of the NSR provisions of the
CAA. The $26 million represents APCo’s allocation of the
settlement.
|
|
·
|
A
$9 million decrease related to the establishment of a regulatory asset in
the third quarter 2008 for Virginia’s share of previously expended NSR
settlement costs. See “Virginia E&R Cost Recovery Filing”
section of Note 3.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$6 million increase in employee-related expenses.
|
|
·
|
A
$5 million increase in overhead line maintenance expense primarily due to
right-of-way clearing.
|
·
|
Depreciation
and Amortization expenses increased $10 million primarily due to a $6
million increase in the amortization of carrying charges and depreciation
expense that are being collected through the Virginia E&R surcharges
and a $3 million increase in depreciation expense primarily from the
installation of environmental upgrades at the Mountaineer
Plant.
|
·
|
Carrying
Costs Income increased $3 million due to an increase in Virginia E&R
deferrals.
|
·
|
Income
Tax Expense increased $3 million primarily due to an increase in pretax
book income, partially offset by changes in certain book/tax differences
accounted for on a flow-through
basis.
|
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Reconciliation
of Nine Months Ended September 30, 2007 to Nine Months Ended September 30,
2008
Income
Before Extraordinary Loss
(in
millions)
Nine
Months Ended September 30, 2007
|
|
|
|
|
$ |
98 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
19 |
|
|
|
|
|
Off-system
Sales
|
|
|
32 |
|
|
|
|
|
Other
|
|
|
1 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
52 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
12 |
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(44 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(5 |
) |
|
|
|
|
Carrying
Costs Income
|
|
|
16 |
|
|
|
|
|
Other
Income
|
|
|
7 |
|
|
|
|
|
Interest
Expense
|
|
|
(17 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(31 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2008
|
|
|
|
|
|
$ |
121 |
|
Income
Before Extraordinary Loss increased $23 million to $121 million in 2008
primarily due to an increase in Gross Margin of $52 million, partially offset by
a $31 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 $19 million primarily due to the impact of the Virginia
base rate order issued in May 2007 which included a 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 $32 million primarily due to increased
physical sales margins driven by higher prices, 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 $12 million primarily due to
the following:
|
|
·
|
A
$26 million decrease resulting from a settlement agreement in the third
quarter 2007 related to alleged violations of the NSR provisions of the
CAA. The $26 million represents APCo’s allocation of the
settlement.
|
|
·
|
A
$9 million decrease related to the establishment of a regulatory asset in
the third quarter 2008 for Virginia’s share of previously expended NSR
settlement costs. See “Virginia E&R Cost Recovery Filing”
section of Note 3.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$7 million increase in employee-related expenses.
|
|
·
|
A
$10 million increase in overhead line maintenance expense due to
right-of-way clearing and storm damage.
|
·
|
Depreciation
and Amortization expenses increased $44 million primarily due to $22
million in favorable adjustments made in the second quarter 2007 for
APCo’s Virginia base rate order and a $15 million increase in amortization
of carrying charges and depreciation expense that are being collected
through the Virginia E&R surcharges.
|
·
|
Taxes
Other Than Income Taxes increased $5 million primarily due to favorable
franchise tax return adjustments recorded in 2007.
|
·
|
Carrying
Costs Income increased $16 million due to an increase in Virginia E&R
deferrals.
|
·
|
Other
Income increased $7 million primarily due to higher interest income
related to a tax refund in 2008 and other tax
adjustments.
|
·
|
Interest
Expense increased $17 million primarily due to a $26 million increase in
interest expense from long-term debt issuances, partially offset by a $7
million decrease in interest expense primarily related to interest on the
Virginia provision for refund recorded in the second quarter of
2007.
|
·
|
Income
Tax Expense decreased $2 million primarily due to a decrease in state
income taxes and changes in certain book/tax differences accounted for on
a flow-through basis, partially offset by an increase in pretax book
income.
|
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 nine months ended September 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
|
|
|
208,445 |
|
|
|
221,534 |
|
Investing
Activities
|
|
|
(472,029 |
) |
|
|
(570,019 |
) |
Financing
Activities
|
|
|
263,376 |
|
|
|
347,436 |
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(208 |
) |
|
|
(1,049 |
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,987 |
|
|
$ |
1,269 |
|
Operating
Activities
Net Cash
Flows from Operating Activities were $208 million in 2008. APCo
produced income of $121 million during the period and had noncash expense items
of $187 million for Depreciation and Amortization, $111 million for Deferred
Income Taxes and $39 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 $114 million outflow in Fuel Over/Under-Recovery, Net as a result
of 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 $222 million in 2007. APCo
produced income of $19 million during the period and had noncash expense items
of $142 million for Depreciation and Amortization, $79 million for Extraordinary
Loss for the Reapplication of Regulatory Accounting for Generation and $23
million for Carrying Cost Income. 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 $472 million and
$570 million, respectively. Construction Expenditures were $488
million and $538 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 $250 million.
Financing
Activities
Net Cash
Flows from Financing Activities were $263 million in 2008. APCo
received capital contributions from the Parent of $175 million. APCo
issued $500 million of Senior Unsecured Notes in March 2008, $125 million of
Pollution Control Bonds in June 2008 and $70 million of Pollution Control Bonds
in September 2008. These increases were partially offset by the
retirement of $213 million of Pollution Control Bonds and $200 million of Senior
Unsecured Notes in the second quarter of 2008. In addition, APCo had
a net decrease of $182 million in borrowings from the Utility Money
Pool.
Net Cash
Flows from Financing Activities in 2007 were $347 million primarily due to the
issuance of $75 million of Pollution Control Bonds in May 2007 and the issuance
of $500 million of Senior Unsecured Notes in August 2007, net of retirement of
$125 million of Senior Unsecured Notes in June 2007. APCo also
reduced its short-term borrowings from the Utility Money Pool by $35
million.
Financing
Activity
Long-term
debt issuances, retirements and principal payments made during the first nine
months of 2008 were:
Issuances
|
|
Principal
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
Amount
|
|
Rate
|
|
Date
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$
|
40,000
|
|
4.85
|
|
2019
|
Pollution
Control Bonds
|
|
|
30,000
|
|
4.85
|
|
2019
|
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
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
Amount
Paid
|
|
Rate
|
|
Date
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$
|
40,000
|
|
Variable
|
|
2019
|
Pollution
Control Bonds
|
|
|
30,000
|
|
Variable
|
|
2019
|
Pollution
Control Bonds
|
|
|
17,500
|
|
Variable
|
|
2021
|
Pollution
Control Bonds
|
|
|
50,275
|
|
Variable
|
|
2036
|
Pollution
Control Bonds
|
|
|
75,000
|
|
Variable
|
|
2037
|
Senior
Unsecured Notes
|
|
|
200,000
|
|
3.60
|
|
2008
|
Other
|
|
|
11
|
|
13.718
|
|
2026
|
Liquidity
In recent
months, the financial markets have become increasingly unstable and constrained
at both a global and domestic level. This systemic marketplace
distress is impacting APCo’s access to capital, liquidity and cost of
capital. The uncertainties in the credit markets could have
significant implications on APCo since it relies on continuing access to capital
to fund operations and capital expenditures.
APCo
participates in the Utility Money Pool, which provides access to AEP’s
liquidity. APCo has $150 million of Senior Unsecured Notes that will
mature in 2009. To the extent refinancing is unavailable due to the
challenging credit markets, APCo will rely upon cash flows from operations and
access to the Utility Money Pool to fund its maturity, continuing operations and
capital expenditures.
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 which were reduced by
Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12
million, respectively, following its bankruptcy. As of September 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”. Adverse results in these proceedings have the
potential to materially affect net income, financial condition and cash
flows.
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries” 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” 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 September 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 September 30, 2008
(in
thousands)
|
|
|
|
|
Cash
Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
MTM
Risk
|
|
|
&
|
|
|
DETM
|
|
|
|
|
|
|
|
|
|
Management
|
|
|
Fair
Value
|
|
|
Assignment
|
|
|
Collateral
|
|
|
|
|
|
|
Contracts
|
|
|
Hedges
|
|
|
(a)
|
|
|
Deposits
|
|
|
Total
|
|
Current
Assets
|
|
$ |
81,386 |
|
|
$ |
4,104 |
|
|
$ |
- |
|
|
$ |
(3,532 |
) |
|
$ |
81,958 |
|
Noncurrent
Assets
|
|
|
58,881 |
|
|
|
1,036 |
|
|
|
- |
|
|
|
(4,718 |
) |
|
|
55,199 |
|
Total
MTM Derivative Contract Assets
|
|
|
140,267 |
|
|
|
5,140 |
|
|
|
- |
|
|
|
(8,250 |
) |
|
|
137,157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(69,529 |
) |
|
|
(2,996 |
) |
|
|
(3,127 |
) |
|
|
547 |
|
|
|
(75,105 |
) |
Noncurrent
Liabilities
|
|
|
(29,631 |
) |
|
|
- |
|
|
|
(3,194 |
) |
|
|
50 |
|
|
|
(32,775 |
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(99,160 |
) |
|
|
(2,996 |
) |
|
|
(6,321 |
) |
|
|
597 |
|
|
|
(107,880 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$ |
41,107 |
|
|
$ |
2,144 |
|
|
$ |
(6,321 |
) |
|
$ |
(7,653 |
) |
|
$ |
29,277 |
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 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
|
|
|
(13,569 |
) |
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)
|
|
|
564 |
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(c)
|
|
|
(165 |
) |
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
8,407 |
|
Total
MTM Risk Management Contract Net Assets
|
|
|
41,107 |
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
2,144 |
|
DETM
Assignment (e)
|
|
|
(6,321 |
) |
Collateral
Deposits
|
|
|
(7,653 |
) |
Ending
Net Risk Management Assets at September 30, 2008
|
|
$ |
29,277 |
|
(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. Inception value is only recorded if observable market
data can be obtained for valuation inputs for the entire contract
term. 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.
|
(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 September 30, 2008
(in
thousands)
|
|
Remainder
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2012
|
|
|
Total
|
|
Level
1 (a)
|
|
$ |
(998 |
) |
|
$ |
(2,295 |
) |
|
$ |
(21 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(3,314 |
) |
Level
2 (b)
|
|
|
1,480 |
|
|
|
18,258 |
|
|
|
12,918 |
|
|
|
1,662 |
|
|
|
485 |
|
|
|
- |
|
|
|
34,803 |
|
Level
3 (c)
|
|
|
(3,850 |
) |
|
|
666 |
|
|
|
(1,881 |
) |
|
|
272 |
|
|
|
152 |
|
|
|
- |
|
|
|
(4,641 |
) |
Total
|
|
|
(3,368 |
) |
|
|
16,629 |
|
|
|
11,016 |
|
|
|
1,934 |
|
|
|
637 |
|
|
|
- |
|
|
|
26,848 |
|
Dedesignated
Risk Management Contracts (d)
|
|
|
1,403 |
|
|
|
4,720 |
|
|
|
4,681 |
|
|
|
1,823 |
|
|
|
1,632 |
|
|
|
- |
|
|
|
14,259 |
|
Total
MTM Risk Management Contract Net Assets (Liabilities)
|
|
$ |
(1,965 |
) |
|
$ |
21,349 |
|
|
$ |
15,697 |
|
|
$ |
3,757 |
|
|
$ |
2,269 |
|
|
$ |
- |
|
|
$ |
41,107 |
|
(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 September 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
Nine
Months Ended September 30, 2008
(in
thousands)
|
|
|
|
|
Interest
|
|
|
Foreign
|
|
|
|
|
|
Power
|
|
|
Rate
|
|
|
Currency
|
|
|
Total
|
Beginning
Balance in AOCI December 31, 2007
|
|
$
|
783
|
|
|
$
|
(6,602)
|
|
|
$
|
(125)
|
|
|
$
|
(5,944)
|
Changes
in Fair Value
|
|
|
670
|
|
|
|
(3,114)
|
|
|
|
68
|
|
|
|
(2,376)
|
Reclassifications
from AOCI for Cash Flow Hedges Settled
|
|
|
(118)
|
|
|
|
1,231
|
|
|
|
5
|
|
|
|
1,118
|
Ending
Balance in AOCI September 30, 2008
|
|
$
|
1,335
|
|
|
$
|
(8,485)
|
|
|
$
|
(52)
|
|
|
$
|
(7,202)
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1 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 September 30, 2008, a near
term typical change in commodity prices is not expected to have a material
effect on APCo’s net income, 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:
Nine
Months Ended
September
30, 2008
|
|
|
|
|
Twelve
Months Ended
December
31, 2007
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$725
|
|
$1,096
|
|
$416
|
|
$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 $4.3 million.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
719,295 |
|
|
$ |
639,830 |
|
|
$ |
1,926,841 |
|
|
$ |
1,740,565 |
|
Sales
to AEP Affiliates
|
|
|
74,632 |
|
|
|
64,099 |
|
|
|
262,230 |
|
|
|
181,015 |
|
Other
|
|
|
4,906 |
|
|
|
2,647 |
|
|
|
12,186 |
|
|
|
8,134 |
|
TOTAL
|
|
|
798,833 |
|
|
|
706,576 |
|
|
|
2,201,257 |
|
|
|
1,929,714 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
220,955 |
|
|
|
200,702 |
|
|
|
554,022 |
|
|
|
535,906 |
|
Purchased
Electricity for Resale
|
|
|
71,075 |
|
|
|
47,430 |
|
|
|
167,205 |
|
|
|
117,708 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
219,595 |
|
|
|
171,288 |
|
|
|
595,433 |
|
|
|
443,519 |
|
Other
Operation
|
|
|
66,316 |
|
|
|
94,190 |
|
|
|
210,262 |
|
|
|
236,944 |
|
Maintenance
|
|
|
51,292 |
|
|
|
49,708 |
|
|
|
161,371 |
|
|
|
146,875 |
|
Depreciation
and Amortization
|
|
|
62,364 |
|
|
|
51,864 |
|
|
|
186,528 |
|
|
|
142,100 |
|
Taxes
Other Than Income Taxes
|
|
|
24,319 |
|
|
|
23,561 |
|
|
|
72,414 |
|
|
|
67,811 |
|
TOTAL
|
|
|
715,916 |
|
|
|
638,743 |
|
|
|
1,947,235 |
|
|
|
1,690,863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
82,917 |
|
|
|
67,833 |
|
|
|
254,022 |
|
|
|
238,851 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
1,945 |
|
|
|
510 |
|
|
|
7,541 |
|
|
|
1,539 |
|
Carrying
Costs Income
|
|
|
11,924 |
|
|
|
8,701 |
|
|
|
38,921 |
|
|
|
22,817 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
2,130 |
|
|
|
1,084 |
|
|
|
6,278 |
|
|
|
5,442 |
|
Interest
Expense
|
|
|
(47,385 |
) |
|
|
(44,980 |
) |
|
|
(138,644 |
) |
|
|
(121,758 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE
|
|
|
51,531 |
|
|
|
33,148 |
|
|
|
168,118 |
|
|
|
146,891 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
12,516 |
|
|
|
9,090 |
|
|
|
47,508 |
|
|
|
49,325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE EXTRAORDINARY LOSS
|
|
|
39,015 |
|
|
|
24,058 |
|
|
|
120,610 |
|
|
|
97,566 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extraordinary
Loss – Reapplication of Regulatory Accounting for Generation, Net of
Tax
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(78,763 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
39,015 |
|
|
|
24,058 |
|
|
|
120,610 |
|
|
|
18,803 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements Including Capital Stock
Expense
|
|
|
238 |
|
|
|
238 |
|
|
|
714 |
|
|
|
714 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
38,777 |
|
|
$ |
23,820 |
|
|
$ |
119,896 |
|
|
$ |
18,089 |
|
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 Nine Months Ended September 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
|
|
|
|
|
|
|
|
|
|
|
(600 |
) |
|
|
|
|
|
|
(600 |
) |
Capital
Stock Expense
|
|
|
|
|
|
|
117 |
|
|
|
(114 |
) |
|
|
|
|
|
|
3 |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,007,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $539
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,000 |
) |
|
|
(1,000 |
) |
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
INCOME
|
|
|
|
|
|
|
|
|
|
|
18,803 |
|
|
|
|
|
|
|
18,803 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,048 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
260,458 |
|
|
$ |
1,025,111 |
|
|
$ |
795,917 |
|
|
$ |
(44,546 |
) |
|
$ |
2,036,940 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
175,000 |
|
|
|
|
|
|
|
|
|
|
|
175,000 |
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(599 |
) |
|
|
|
|
|
|
(599 |
) |
Capital
Stock Expense
|
|
|
|
|
|
|
115 |
|
|
|
(115 |
) |
|
|
|
|
|
|
- |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,253,966 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of
$677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,258 |
) |
|
|
(1,258 |
) |
Amortization
of Pension and OPEB Deferred Costs, Net of Tax of $1,346
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,499 |
|
|
|
2,499 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
120,610 |
|
|
|
|
|
|
|
120,610 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
121,851 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2008
|
|
$ |
260,458 |
|
|
$ |
1,200,264 |
|
|
$ |
949,041 |
|
|
$ |
(33,946 |
) |
|
$ |
2,375,817 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,987 |
|
|
$ |
2,195 |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
204,692 |
|
|
|
176,834 |
|
Affiliated
Companies
|
|
|
96,277 |
|
|
|
113,582 |
|
Accrued
Unbilled Revenues
|
|
|
43,333 |
|
|
|
38,397 |
|
Miscellaneous
|
|
|
1,923 |
|
|
|
2,823 |
|
Allowance
for Uncollectible Accounts
|
|
|
(16,224 |
) |
|
|
(13,948 |
) |
Total
Accounts Receivable
|
|
|
330,001 |
|
|
|
317,688 |
|
Fuel
|
|
|
80,853 |
|
|
|
82,203 |
|
Materials
and Supplies
|
|
|
74,552 |
|
|
|
76,685 |
|
Risk
Management Assets
|
|
|
81,958 |
|
|
|
62,955 |
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
90,111 |
|
|
|
- |
|
Prepayments
and Other
|
|
|
60,431 |
|
|
|
16,369 |
|
TOTAL
|
|
|
719,893 |
|
|
|
558,095 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
3,655,253 |
|
|
|
3,625,788 |
|
Transmission
|
|
|
1,739,018 |
|
|
|
1,675,081 |
|
Distribution
|
|
|
2,453,323 |
|
|
|
2,372,687 |
|
Other
|
|
|
362,985 |
|
|
|
351,827 |
|
Construction
Work in Progress
|
|
|
947,101 |
|
|
|
713,063 |
|
Total
|
|
|
9,157,680 |
|
|
|
8,738,446 |
|
Accumulated
Depreciation and Amortization
|
|
|
2,662,328 |
|
|
|
2,591,833 |
|
TOTAL
- NET
|
|
|
6,495,352 |
|
|
|
6,146,613 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
712,001 |
|
|
|
652,739 |
|
Long-term
Risk Management Assets
|
|
|
55,199 |
|
|
|
72,366 |
|
Deferred
Charges and Other
|
|
|
179,054 |
|
|
|
191,871 |
|
TOTAL
|
|
|
946,254 |
|
|
|
916,976 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
8,161,499 |
|
|
$ |
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
September
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
93,558 |
|
|
$ |
275,257 |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
290,320 |
|
|
|
241,871 |
|
Affiliated
Companies
|
|
|
105,647 |
|
|
|
106,852 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
150,016 |
|
|
|
239,732 |
|
Risk
Management Liabilities
|
|
|
75,105 |
|
|
|
51,708 |
|
Customer
Deposits
|
|
|
51,243 |
|
|
|
45,920 |
|
Accrued
Taxes
|
|
|
34,154 |
|
|
|
58,519 |
|
Accrued
Interest
|
|
|
68,110 |
|
|
|
41,699 |
|
Other
|
|
|
98,950 |
|
|
|
139,476 |
|
TOTAL
|
|
|
967,103 |
|
|
|
1,201,034 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
2,873,980 |
|
|
|
2,507,567 |
|
Long-term
Debt – Affiliated
|
|
|
100,000 |
|
|
|
100,000 |
|
Long-term
Risk Management Liabilities
|
|
|
32,775 |
|
|
|
47,357 |
|
Deferred
Income Taxes
|
|
|
1,073,269 |
|
|
|
948,891 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
509,068 |
|
|
|
505,556 |
|
Deferred
Credits and Other
|
|
|
211,735 |
|
|
|
211,495 |
|
TOTAL
|
|
|
4,800,827 |
|
|
|
4,320,866 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
5,767,930 |
|
|
|
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
|
|
|
1,200,264 |
|
|
|
1,025,149 |
|
Retained
Earnings
|
|
|
949,041 |
|
|
|
831,612 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(33,946 |
) |
|
|
(35,187 |
) |
TOTAL
|
|
|
2,375,817 |
|
|
|
2,082,032 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
8,161,499 |
|
|
$ |
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 Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
120,610 |
|
|
$ |
18,803 |
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
186,528 |
|
|
|
142,100 |
|
Deferred
Income Taxes
|
|
|
111,297 |
|
|
|
32,021 |
|
Extraordinary
Loss, Net of Tax
|
|
|
- |
|
|
|
78,763 |
|
Carrying
Costs Income
|
|
|
(38,921 |
) |
|
|
(22,817 |
) |
Allowance
for Equity Funds Used During Construction
|
|
|
(6,278 |
) |
|
|
(5,442 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
7,450 |
|
|
|
(1,949 |
) |
Change
in Other Noncurrent Assets
|
|
|
(24,670 |
) |
|
|
(9,185 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
(12,565 |
) |
|
|
27,247 |
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(12,313 |
) |
|
|
(87 |
) |
Fuel,
Materials and Supplies
|
|
|
3,483 |
|
|
|
(11,387 |
) |
Accounts
Payable
|
|
|
41,869 |
|
|
|
(38,724 |
) |
Accrued
Taxes, Net
|
|
|
(51,208 |
) |
|
|
(9,990 |
) |
Accrued
Interest
|
|
|
26,411 |
|
|
|
28,596 |
|
Fuel
Over/Under-Recovery, Net
|
|
|
(113,748 |
) |
|
|
35,770 |
|
Other
Current Assets
|
|
|
(17,202 |
) |
|
|
(21,483 |
) |
Other
Current Liabilities
|
|
|
(12,298 |
) |
|
|
(20,702 |
) |
Net
Cash Flows from Operating Activities
|
|
|
208,445 |
|
|
|
221,534 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(487,797 |
) |
|
|
(537,930 |
) |
Change
in Other Cash Deposits, Net
|
|
|
(18 |
) |
|
|
(29 |
) |
Change
in Advances to Affiliates, Net
|
|
|
- |
|
|
|
(38,573 |
) |
Proceeds
from Sales of Assets
|
|
|
15,786 |
|
|
|
6,713 |
|
Other
|
|
|
- |
|
|
|
(200 |
) |
Net
Cash Flows Used for Investing Activities
|
|
|
(472,029 |
) |
|
|
(570,019 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
175,000 |
|
|
|
- |
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
686,512 |
|
|
|
568,778 |
|
Change
in Advances from Affiliates, Net
|
|
|
(181,699 |
) |
|
|
(34,975 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(412,786 |
) |
|
|
(125,009 |
) |
Retirement
of Cumulative Preferred Stock
|
|
|
- |
|
|
|
(9 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(3,052 |
) |
|
|
(3,316 |
) |
Amortization
of Funds from Amended Coal Contract
|
|
|
- |
|
|
|
(32,433 |
) |
Dividends
Paid on Common Stock
|
|
|
- |
|
|
|
(25,000 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(599 |
) |
|
|
(600 |
) |
Net
Cash Flows from Financing Activities
|
|
|
263,376 |
|
|
|
347,436 |
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(208 |
) |
|
|
(1,049 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
2,195 |
|
|
|
2,318 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,987 |
|
|
$ |
1,269 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
110,349 |
|
|
$ |
86,199 |
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(26,330 |
) |
|
|
6,688 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,246 |
|
|
|
2,738 |
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
112,376 |
|
|
|
90,315 |
|
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
Results of
Operations
Third Quarter of 2008
Compared to Third Quarter of 2007
Reconciliation
of Third Quarter of 2007 to Third Quarter of 2008
Net
Income
(in
millions)
Third
Quarter of 2007
|
|
|
|
|
$ |
85 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(4 |
) |
|
|
|
|
Off-system
Sales
|
|
|
5 |
|
|
|
|
|
Transmission
Revenues
|
|
|
1 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(2 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(3 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(3 |
) |
|
|
|
|
Interest
Expense
|
|
|
(1 |
) |
|
|
|
|
Other
Income
|
|
|
2 |
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2008
|
|
|
|
|
|
$ |
82 |
|
Net
Income decreased $3 million to $82 million in 2008. The key drivers
of the decrease were a $7 million increase in Operating Expenses and Other,
partially offset by a $2 million increase in Gross Margin and a $2 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
Margins decreased $4 million primarily due to:
|
|
·
|
A
$23 million decrease in residential and commercial revenue primarily due
to a 12% decrease in cooling degree days and the outages caused by the
remnants of Hurricane Ike.
|
|
·
|
A
$20 million decrease related to increased fuel, allowance and consumables
expenses. CSPCo and OPCo have applied for an active fuel clause in
their Ohio ESP to be effective January 1, 2009.
|
|
·
|
A
$4 million increase in capacity settlement charges under the
Interconnection Agreement due to a change in relative peak
demands.
|
|
These
decreases were partially offset by a $44 million increase related to a net
increase in rates implemented.
|
·
|
Margins
from Off-system Sales increased $5 million primarily due to increased
physical sales margins driven by higher prices, 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 $2 million due
to:
|
·
|
A
$9 million increase in recoverable PJM costs.
|
·
|
A
$4 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 employee-related expenses.
|
|
These
increases were partially offset by a $15 million decrease resulting from a
settlement agreement in the third quarter 2007 related to alleged
violations of the NSR provisions of the CAA. The $15 million
represents CSPCo’s allocation of the settlement.
|
·
|
Depreciation
and Amortization increased $3 million primarily due to a greater
depreciation base related to environmental improvements placed in
service.
|
·
|
Taxes
Other Than Income Taxes increased $3 million due to property tax
adjustments.
|
·
|
Income
Tax Expense decreased $2 million primarily due to a decrease in pretax
book income.
|
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Reconciliation
of Nine Months Ended September 30, 2007 to Nine Months Ended September 30,
2008
Net
Income
(in
millions)
Nine
Months Ended September 30, 2007
|
|
|
|
|
$ |
212 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
36 |
|
|
|
|
|
Off-system
Sales
|
|
|
24 |
|
|
|
|
|
Transmission
Revenues
|
|
|
3 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
63 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(45 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
1 |
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(12 |
) |
|
|
|
|
Interest
Expense
|
|
|
(6 |
) |
|
|
|
|
Other
Income
|
|
|
5 |
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(57 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2008
|
|
|
|
|
|
$ |
214 |
|
Net
Income increased $2 million to $214 million in 2008. The key drivers
of the increase were a $63 million increase in Gross Margin primarily offset by
a $57 million increase in Operating Expenses and Other and a $4 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 $36 million primarily due to:
|
|
·
|
A
$106 million increase related to a net increase in rates
implemented.
|
|
·
|
A
$35 million decrease in capacity settlement charges related to CSPCo’s
Unit Power Agreement (UPA) for AEGCo’s Lawrenceburg Plant, which began in
May 2007, and to the April 2007 acquisition of the Darby
Plant.
|
|
·
|
A
$15 million increase in industrial revenue related to higher usage by
Ormet.
|
|
These
increases were partially offset by:
|
|
·
|
A
$59 million decrease related to increased fuel, allowance and consumables
expenses. CSPCo and OPCo have applied for an active fuel clause in
their Ohio ESP to be effective January 1, 2009.
|
|
·
|
A
$35 million decrease in residential and commercial revenue primarily due
to a 16% decrease in cooling and a 6% decrease in heating degree
days.
|
·
|
Margins
from Off-system Sales increased $24 million primarily due to increased
physical sales margins driven by higher prices, 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 $45 million primarily due
to:
|
|
·
|
A
$17 million increase in recoverable PJM expenses.
|
|
·
|
A
$13 million increase in expenses related to CSPCo’s UPA for AEGCo’s
Lawrenceburg Plant which began in May 2007.
|
|
·
|
A
$10 million increase in steam plant maintenance expenses primarily related
to work performed at the Conesville Plant.
|
|
·
|
A
$9 million increase in recoverable customer account expenses related to
the Universal Service Fund for customers who qualify for payment
assistance.
|
|
·
|
A
$4 million increase in boiler plant removal expenses primarily related to
work performed at the Conesville Plant.
|
|
These
increases were partially offset by a $15 million decrease resulting from a
settlement agreement in the third quarter 2007 related to alleged
violations of the NSR provisions of the CAA. The $15 million
represents CSPCo’s allocation of the settlement.
|
·
|
Taxes
Other Than Income Taxes increased $12 million due to property tax
adjustments.
|
·
|
Interest
Expense increased $6 million due to increased long-term
borrowings.
|
·
|
Other
Income increased $5 million primarily due to interest income on federal
tax refunds.
|
·
|
Income
Tax Expense increased $4 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” 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 $1.3 million.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
633,325 |
|
|
$ |
553,518 |
|
|
$ |
1,638,705 |
|
|
$ |
1,446,632 |
|
Sales
to AEP Affiliates
|
|
|
29,032 |
|
|
|
52,331 |
|
|
|
111,553 |
|
|
|
110,700 |
|
Other
|
|
|
1,426 |
|
|
|
1,292 |
|
|
|
4,121 |
|
|
|
3,743 |
|
TOTAL
|
|
|
663,783 |
|
|
|
607,141 |
|
|
|
1,754,379 |
|
|
|
1,561,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
112,566 |
|
|
|
103,560 |
|
|
|
283,946 |
|
|
|
255,764 |
|
Purchased
Electricity for Resale
|
|
|
63,441 |
|
|
|
49,619 |
|
|
|
150,637 |
|
|
|
113,765 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
139,017 |
|
|
|
107,386 |
|
|
|
343,699 |
|
|
|
278,715 |
|
Other
Operation
|
|
|
87,358 |
|
|
|
83,625 |
|
|
|
245,379 |
|
|
|
207,300 |
|
Maintenance
|
|
|
23,039 |
|
|
|
24,250 |
|
|
|
80,705 |
|
|
|
73,537 |
|
Depreciation
and Amortization
|
|
|
50,373 |
|
|
|
47,589 |
|
|
|
146,668 |
|
|
|
147,332 |
|
Taxes
Other Than Income Taxes
|
|
|
44,533 |
|
|
|
41,382 |
|
|
|
130,078 |
|
|
|
117,760 |
|
TOTAL
|
|
|
520,327 |
|
|
|
457,411 |
|
|
|
1,381,112 |
|
|
|
1,194,173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
143,456 |
|
|
|
149,730 |
|
|
|
373,267 |
|
|
|
366,902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
1,515 |
|
|
|
166 |
|
|
|
5,457 |
|
|
|
782 |
|
Carrying
Costs Income
|
|
|
1,566 |
|
|
|
1,261 |
|
|
|
4,870 |
|
|
|
3,492 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
745 |
|
|
|
738 |
|
|
|
2,165 |
|
|
|
2,130 |
|
Interest
Expense
|
|
|
(21,127 |
) |
|
|
(19,530 |
) |
|
|
(57,612 |
) |
|
|
(51,193 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE
|
|
|
126,155 |
|
|
|
132,365 |
|
|
|
328,147 |
|
|
|
322,113 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
44,493 |
|
|
|
46,911 |
|
|
|
113,939 |
|
|
|
109,656 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
81,662 |
|
|
|
85,454 |
|
|
|
214,208 |
|
|
|
212,457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
Stock Expense
|
|
|
39 |
|
|
|
39 |
|
|
|
118 |
|
|
|
118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
81,623 |
|
|
$ |
85,415 |
|
|
$ |
214,090 |
|
|
$ |
212,339 |
|
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 Nine Months Ended September 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
|
|
|
|
|
|
|
|
|
|
|
(90,000 |
) |
|
|
|
|
|
|
(90,000 |
) |
Capital
Stock Expense and Other
|
|
|
|
|
|
|
118 |
|
|
|
(118 |
) |
|
|
|
|
|
|
- |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
962,995 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $1,231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,285 |
) |
|
|
(2,285 |
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
212,457 |
|
|
|
|
|
|
|
212,457 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
210,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
41,026 |
|
|
$ |
580,310 |
|
|
$ |
576,104 |
|
|
$ |
(24,273 |
) |
|
$ |
1,173,167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
(87,500 |
) |
|
|
|
|
|
|
(87,500 |
) |
Capital
Stock Expense
|
|
|
|
|
|
|
118 |
|
|
|
(118 |
) |
|
|
|
|
|
|
- |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,075,366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,080 |
|
|
|
1,080 |
|
Amortization
of Pension and OPEB Deferred Costs, Net of Tax of $456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
846 |
|
|
|
846 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
214,208 |
|
|
|
|
|
|
|
214,208 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
216,134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2008
|
|
$ |
41,026 |
|
|
$ |
580,467 |
|
|
$ |
686,875 |
|
|
$ |
(16,868 |
) |
|
$ |
1,291,500 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,956 |
|
|
$ |
1,389 |
|
Other
Cash Deposits
|
|
|
31,964 |
|
|
|
53,760 |
|
Advances
to Affiliates
|
|
|
21,833 |
|
|
|
- |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
65,581 |
|
|
|
57,268 |
|
Affiliated
Companies
|
|
|
27,933 |
|
|
|
32,852 |
|
Accrued
Unbilled Revenues
|
|
|
24,078 |
|
|
|
14,815 |
|
Miscellaneous
|
|
|
11,256 |
|
|
|
9,905 |
|
Allowance
for Uncollectible Accounts
|
|
|
(2,814 |
) |
|
|
(2,563 |
) |
Total
Accounts Receivable
|
|
|
126,034 |
|
|
|
112,277 |
|
Fuel
|
|
|
30,081 |
|
|
|
35,849 |
|
Materials
and Supplies
|
|
|
34,979 |
|
|
|
36,626 |
|
Emission
Allowances
|
|
|
7,884 |
|
|
|
16,811 |
|
Risk
Management Assets
|
|
|
40,842 |
|
|
|
33,558 |
|
Prepayments
and Other
|
|
|
31,984 |
|
|
|
9,960 |
|
TOTAL
|
|
|
327,557 |
|
|
|
300,230 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
2,317,357 |
|
|
|
2,072,564 |
|
Transmission
|
|
|
568,380 |
|
|
|
510,107 |
|
Distribution
|
|
|
1,600,323 |
|
|
|
1,552,999 |
|
Other
|
|
|
211,475 |
|
|
|
198,476 |
|
Construction
Work in Progress
|
|
|
322,885 |
|
|
|
415,327 |
|
Total
|
|
|
5,020,420 |
|
|
|
4,749,473 |
|
Accumulated
Depreciation and Amortization
|
|
|
1,758,415 |
|
|
|
1,697,793 |
|
TOTAL
- NET
|
|
|
3,262,005 |
|
|
|
3,051,680 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
204,203 |
|
|
|
235,883 |
|
Long-term
Risk Management Assets
|
|
|
30,268 |
|
|
|
41,852 |
|
Deferred
Charges and Other
|
|
|
125,071 |
|
|
|
181,563 |
|
TOTAL
|
|
|
359,542 |
|
|
|
459,298 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
3,949,104 |
|
|
$ |
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
September
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
- |
|
|
$ |
95,199 |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
145,733 |
|
|
|
113,290 |
|
Affiliated
Companies
|
|
|
53,532 |
|
|
|
65,292 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
- |
|
|
|
112,000 |
|
Risk
Management Liabilities
|
|
|
37,331 |
|
|
|
28,237 |
|
Customer
Deposits
|
|
|
29,995 |
|
|
|
43,095 |
|
Accrued
Taxes
|
|
|
153,391 |
|
|
|
179,831 |
|
Other
|
|
|
84,432 |
|
|
|
96,892 |
|
TOTAL
|
|
|
504,414 |
|
|
|
733,836 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
1,343,491 |
|
|
|
1,086,224 |
|
Long-term
Debt – Affiliated
|
|
|
100,000 |
|
|
|
100,000 |
|
Long-term
Risk Management Liabilities
|
|
|
18,061 |
|
|
|
27,419 |
|
Deferred
Income Taxes
|
|
|
447,465 |
|
|
|
437,306 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
155,332 |
|
|
|
165,635 |
|
Deferred
Credits and Other
|
|
|
88,841 |
|
|
|
96,511 |
|
TOTAL
|
|
|
2,153,190 |
|
|
|
1,913,095 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,657,604 |
|
|
|
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
|
|
|
580,467 |
|
|
|
580,349 |
|
Retained
Earnings
|
|
|
686,875 |
|
|
|
561,696 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(16,868 |
) |
|
|
(18,794 |
) |
TOTAL
|
|
|
1,291,500 |
|
|
|
1,164,277 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$ |
3,949,104 |
|
|
$ |
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 Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
214,208 |
|
|
$ |
212,457 |
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
146,668 |
|
|
|
147,332 |
|
Deferred
Income Taxes
|
|
|
8,981 |
|
|
|
(13,959 |
) |
Carrying
Costs Income
|
|
|
(4,870 |
) |
|
|
(3,492 |
) |
Allowance
for Equity Funds Used During Construction
|
|
|
(2,165 |
) |
|
|
(2,130 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
5,326 |
|
|
|
1,321 |
|
Deferred
Property Taxes
|
|
|
65,763 |
|
|
|
57,890 |
|
Change
in Other Noncurrent Assets
|
|
|
(7,942 |
) |
|
|
(29,199 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
(4,081 |
) |
|
|
2,713 |
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(13,757 |
) |
|
|
(13,040 |
) |
Fuel,
Materials and Supplies
|
|
|
7,415 |
|
|
|
(2,332 |
) |
Accounts
Payable
|
|
|
(2,650 |
) |
|
|
(13,336 |
) |
Customer
Deposits
|
|
|
(13,100 |
) |
|
|
10,212 |
|
Accrued
Taxes, Net
|
|
|
(26,358 |
) |
|
|
(44,295 |
) |
Other
Current Assets
|
|
|
(13,178 |
) |
|
|
(1,490 |
) |
Other
Current Liabilities
|
|
|
(14,018 |
) |
|
|
8,817 |
|
Net
Cash Flows from Operating Activities
|
|
|
346,242 |
|
|
|
317,469 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(304,175 |
) |
|
|
(246,130 |
) |
Change
in Other Cash Deposits, Net
|
|
|
21,796 |
|
|
|
(44,360 |
) |
Change
in Advances to Affiliates, Net
|
|
|
(21,833 |
) |
|
|
- |
|
Acquisition
of Darby Plant
|
|
|
- |
|
|
|
(102,032 |
) |
Proceeds
from Sales of Assets
|
|
|
1,287 |
|
|
|
1,016 |
|
Net
Cash Flows Used for Investing Activities
|
|
|
(302,925 |
) |
|
|
(391,506 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
346,407 |
|
|
|
44,257 |
|
Change
in Advances from Affiliates, Net
|
|
|
(95,199 |
) |
|
|
122,347 |
|
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(204,245 |
) |
|
|
- |
|
Principal
Payments for Capital Lease Obligations
|
|
|
(2,213 |
) |
|
|
(2,191 |
) |
Dividends
Paid on Common Stock
|
|
|
(87,500 |
) |
|
|
(90,000 |
) |
Net
Cash Flows from (Used for) Financing Activities
|
|
|
(42,750 |
) |
|
|
74,413 |
|
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
567 |
|
|
|
376 |
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,389 |
|
|
|
1,319 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,956 |
|
|
$ |
1,695 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
57,004 |
|
|
$ |
53,464 |
|
Net
Cash Paid for Income Taxes
|
|
|
53,682 |
|
|
|
93,709 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,374 |
|
|
|
1,900 |
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
51,997 |
|
|
|
34,630 |
|
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
Third Quarter of 2008
Compared to Third Quarter of 2007
Reconciliation
of Third Quarter of 2007 to Third Quarter of 2008
Net
Income
(in
millions)
Third
Quarter of 2007
|
|
|
|
|
$ |
49 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(16 |
) |
|
|
|
|
FERC
Municipals and Cooperatives
|
|
|
(2 |
) |
|
|
|
|
Off-system
Sales
|
|
|
4 |
|
|
|
|
|
Other
|
|
|
10 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(2 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
4 |
|
|
|
|
|
Other
Income
|
|
|
(1 |
) |
|
|
|
|
Interest
Expense
|
|
|
(2 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2008
|
|
|
|
|
|
$ |
46 |
|
Net
Income decreased $3 million to $46 million in 2008. The key drivers
of the decrease were a $4 million decrease in Gross Margin and a $1 million
increase in Operating Expenses and Other, partially offset by a $2 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 $16 million primarily due to lower retail sales
reflecting weather conditions as cooling degree days decreased at
least 12% in both the Indiana and Michigan
jurisdictions.
|
·
|
Margins
from Off-system Sales increased $4 million primarily due to increased
physical sales margins driven by higher prices, 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 $2 million primarily due to
higher operation and maintenance expenses for RTD of $11 million caused by
increased barging activity and increased cost of fuel in 2008, partially
offset by a $9 million decrease in coal-fired plant operation
expenses. A settlement agreement related to alleged violations
of the NSR provisions of the CAA, of which $14 million was allocated to
I&M, increased 2007 Other Operation and Maintenance
expenses.
|
·
|
Depreciation
and Amortization expense decreased $4 million primarily due to reduced
depreciation rates reflecting longer estimated lives for Cook and Tanners
Creek Plants. Depreciation rates were reduced for the FERC and
Michigan jurisdictions in October 2007. See “Michigan
Depreciation Study Filing” section of Note 4 in the 2007 Annual
Report.
|
·
|
Income
Tax Expense decreased $2 million primarily due to a decrease in pretax
book income.
|
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Reconciliation
of Nine Months Ended September 30, 2007 to Nine Months Ended September 30,
2008
Net
Income
(in
millions)
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
$
|
109
|
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(19
|
)
|
|
|
|
|
FERC
Municipals and Cooperatives
|
|
|
4
|
|
|
|
|
|
Off-system
Sales
|
|
|
18
|
|
|
|
|
|
Transmission
Revenues
|
|
|
(2
|
)
|
|
|
|
|
Other
|
|
|
31
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(24
|
)
|
|
|
|
|
Depreciation
and Amortization
|
|
|
50
|
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(3
|
)
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2008
|
|
|
|
|
|
$
|
151
|
|
Net
Income increased $42 million to $151 million in 2008. The key drivers
of the increase were a $32 million increase in Gross Margin and a $23 million
decrease in Operating Expenses and Other, partially offset by a $13 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 $19 million primarily due to lower retail sales
reflecting weather conditions as cooling degree days decreased at
least 19% in both the Indiana and Michigan
jurisdictions.
|
·
|
Margins
from Off-system Sales increased $18 million primarily due to increased
physical sales margins driven by higher prices, partially offset by lower
trading margins.
|
·
|
Other
revenues increased $31 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 $24 million primarily due to higher
operation and maintenance expenses for RTD of $31 million caused by
increased barging activity and increased cost of fuel and an increase in
nuclear operation and maintenance expenses of $16
million. Lower coal-fired plant operation and maintenance
expenses of $18 million, including the NSR settlement, and a $5 million
decrease in accretion expense partially offset the
increases.
|
·
|
Depreciation
and Amortization expense decreased $50 million primarily due to the
reduced depreciation rates in all jurisdictions. 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 $13 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.
|
Cook Plant Unit 1 Fire and
Shutdown
Cook
Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in
Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine
vibrations likely caused by blade failure which resulted in a fire on the
electric generator. This equipment is in the turbine building and is
separate and isolated from the nuclear reactor. The steam turbines
that caused the vibration were installed in 2006 and are under warranty from the
vendor. The warranty provides for the replacement of the turbines if
the damage was caused by a defect in the design or assembly of the
turbines. I&M is also working with its insurance company, Nuclear
Electric Insurance Limited (NEIL), and turbine vendor to evaluate the
extent of the damage resulting from the incident and the costs to return the
unit to service. Management cannot estimate the ultimate costs of the
outage at this time. Management believes that I&M should recover a
significant portion of these costs through the turbine vendor’s warranty,
insurance and the regulatory process. Management's preliminary
analysis indicates that Unit 1 could resume operations as early as late first
quarter/early second quarter of 2009 or as late as the second half of
2009, depending upon whether the damaged components can be repaired or
whether they need to be replaced.
I&M
maintains property insurance through NEIL with a $1 million
deductible. I&M also maintains a separate accidental outage
policy with NEIL whereby, after a 12 week deductible period, I&M is
entitled to weekly payments of $3.5 million during the outage period for a
covered loss. If the ultimate costs of the incident are not covered
by warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.
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” 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 $5.7 million.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
513,548 |
|
|
$ |
478,907 |
|
|
$ |
1,370,158 |
|
|
$ |
1,286,223 |
|
Sales
to AEP Affiliates
|
|
|
72,295 |
|
|
|
56,262 |
|
|
|
232,734 |
|
|
|
186,653 |
|
Other
– Affiliated
|
|
|
31,792 |
|
|
|
16,250 |
|
|
|
84,268 |
|
|
|
43,488 |
|
Other
– Nonaffiliated
|
|
|
3,388 |
|
|
|
7,757 |
|
|
|
13,659 |
|
|
|
21,718 |
|
TOTAL
|
|
|
621,023 |
|
|
|
559,176 |
|
|
|
1,700,819 |
|
|
|
1,538,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
141,563 |
|
|
|
103,740 |
|
|
|
351,300 |
|
|
|
290,507 |
|
Purchased
Electricity for Resale
|
|
|
39,427 |
|
|
|
26,580 |
|
|
|
87,351 |
|
|
|
63,830 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
112,060 |
|
|
|
96,451 |
|
|
|
296,559 |
|
|
|
249,755 |
|
Other
Operation
|
|
|
136,875 |
|
|
|
129,439 |
|
|
|
381,928 |
|
|
|
367,483 |
|
Maintenance
|
|
|
52,573 |
|
|
|
58,502 |
|
|
|
156,402 |
|
|
|
146,657 |
|
Depreciation
and Amortization
|
|
|
31,822 |
|
|
|
35,604 |
|
|
|
95,301 |
|
|
|
145,801 |
|
Taxes
Other Than Income Taxes
|
|
|
19,992 |
|
|
|
19,704 |
|
|
|
60,236 |
|
|
|
56,936 |
|
TOTAL
|
|
|
534,312 |
|
|
|
470,020 |
|
|
|
1,429,077 |
|
|
|
1,320,969 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
86,711 |
|
|
|
89,156 |
|
|
|
271,742 |
|
|
|
217,113 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income
|
|
|
880 |
|
|
|
1,986 |
|
|
|
4,621 |
|
|
|
4,273 |
|
Interest
Expense
|
|
|
(20,629 |
) |
|
|
(18,312 |
) |
|
|
(56,977 |
) |
|
|
(57,744 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE
|
|
|
66,962 |
|
|
|
72,830 |
|
|
|
219,386 |
|
|
|
163,642 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
21,326 |
|
|
|
23,706 |
|
|
|
68,348 |
|
|
|
55,020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
45,636 |
|
|
|
49,124 |
|
|
|
151,038 |
|
|
|
108,622 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
85 |
|
|
|
85 |
|
|
|
255 |
|
|
|
255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
45,551 |
|
|
$ |
49,039 |
|
|
$ |
150,783 |
|
|
$ |
108,367 |
|
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 Nine Months Ended September 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
|
|
|
|
|
|
|
|
|
|
|
(30,000 |
) |
|
|
|
|
|
|
(30,000 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(255 |
) |
|
|
|
|
|
|
(255 |
) |
Gain
on Reacquired Preferred Stock
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,259,512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,747 |
) |
|
|
(1,747 |
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
108,622 |
|
|
|
|
|
|
|
108,622 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106,875 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
56,584 |
|
|
$ |
861,291 |
|
|
$ |
465,310 |
|
|
$ |
(16,798 |
) |
|
$ |
1,366,387 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
(56,250 |
) |
|
|
|
|
|
|
(56,250 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(255 |
) |
|
|
|
|
|
|
(255 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,327,796 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,795 |
|
|
|
1,795 |
|
Amortization
of Pension and OPEB Deferred Costs, Net of Tax of $178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
331 |
|
|
|
331 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
151,038 |
|
|
|
|
|
|
|
151,038 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
153,164 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2008
|
|
$ |
56,584 |
|
|
$ |
861,291 |
|
|
$ |
576,634 |
|
|
$ |
(13,549 |
) |
|
$ |
1,480,960 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,328 |
|
|
$ |
1,139 |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
82,788 |
|
|
|
70,995 |
|
Affiliated
Companies
|
|
|
77,640 |
|
|
|
92,018 |
|
Accrued
Unbilled Revenues
|
|
|
21,028 |
|
|
|
16,207 |
|
Miscellaneous
|
|
|
2,010 |
|
|
|
1,335 |
|
Allowance
for Uncollectible Accounts
|
|
|
(3,200 |
) |
|
|
(2,711 |
) |
Total
Accounts Receivable
|
|
|
180,266 |
|
|
|
177,844 |
|
Fuel
|
|
|
46,745 |
|
|
|
61,342 |
|
Materials
and Supplies
|
|
|
143,245 |
|
|
|
141,384 |
|
Risk
Management Assets
|
|
|
40,215 |
|
|
|
32,365 |
|
Accrued
Tax Benefits
|
|
|
1,004 |
|
|
|
4,438 |
|
Prepayments
and Other
|
|
|
35,829 |
|
|
|
11,091 |
|
TOTAL
|
|
|
448,632 |
|
|
|
429,603 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
3,512,424 |
|
|
|
3,529,524 |
|
Transmission
|
|
|
1,100,255 |
|
|
|
1,078,575 |
|
Distribution
|
|
|
1,262,017 |
|
|
|
1,196,397 |
|
Other
(including nuclear fuel and coal mining)
|
|
|
655,257 |
|
|
|
626,390 |
|
Construction
Work in Progress
|
|
|
173,062 |
|
|
|
122,296 |
|
Total
|
|
|
6,703,015 |
|
|
|
6,553,182 |
|
Accumulated
Depreciation, Depletion and Amortization
|
|
|
3,000,898 |
|
|
|
2,998,416 |
|
TOTAL
- NET
|
|
|
3,702,117 |
|
|
|
3,554,766 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
251,451 |
|
|
|
246,435 |
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,291,986 |
|
|
|
1,346,798 |
|
Long-term
Risk Management Assets
|
|
|
29,518 |
|
|
|
40,227 |
|
Deferred
Charges and Other
|
|
|
118,574 |
|
|
|
128,623 |
|
TOTAL
|
|
|
1,691,529 |
|
|
|
1,762,083 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
5,842,278 |
|
|
$ |
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
September
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
224,071 |
|
|
$ |
45,064 |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
177,480 |
|
|
|
184,435 |
|
Affiliated
Companies
|
|
|
64,970 |
|
|
|
61,749 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
50,000 |
|
|
|
145,000 |
|
Risk
Management Liabilities
|
|
|
36,802 |
|
|
|
27,271 |
|
Customer
Deposits
|
|
|
26,957 |
|
|
|
26,445 |
|
Accrued
Taxes
|
|
|
60,111 |
|
|
|
60,995 |
|
Obligations
Under Capital Leases
|
|
|
43,626 |
|
|
|
43,382 |
|
Other
|
|
|
133,267 |
|
|
|
130,232 |
|
TOTAL
|
|
|
817,284 |
|
|
|
724,573 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
1,377,115 |
|
|
|
1,422,427 |
|
Long-term
Risk Management Liabilities
|
|
|
17,585 |
|
|
|
26,348 |
|
Deferred
Income Taxes
|
|
|
382,374 |
|
|
|
321,716 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
693,981 |
|
|
|
789,346 |
|
Asset
Retirement Obligations
|
|
|
886,278 |
|
|
|
852,646 |
|
Deferred
Credits and Other
|
|
|
178,621 |
|
|
|
215,617 |
|
TOTAL
|
|
|
3,535,954 |
|
|
|
3,628,100 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,353,238 |
|
|
|
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
|
|
|
576,634 |
|
|
|
483,499 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(13,549 |
) |
|
|
(15,675 |
) |
TOTAL
|
|
|
1,480,960 |
|
|
|
1,385,699 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
5,842,278 |
|
|
$ |
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 Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
151,038 |
|
|
$ |
108,622 |
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
95,301 |
|
|
|
145,801 |
|
Deferred
Income Taxes
|
|
|
47,565 |
|
|
|
(9,235 |
) |
Amortization
of Incremental Nuclear Refueling Outage Expenses, Net
|
|
|
834 |
|
|
|
14,450 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
(967 |
) |
|
|
(2,726 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
4,876 |
|
|
|
3,046 |
|
Amortization
of Nuclear Fuel
|
|
|
72,453 |
|
|
|
48,360 |
|
Change
in Other Noncurrent Assets
|
|
|
5,678 |
|
|
|
17,163 |
|
Change
in Other Noncurrent Liabilities
|
|
|
38,568 |
|
|
|
33,995 |
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(2,422 |
) |
|
|
34,569 |
|
Fuel,
Materials and Supplies
|
|
|
12,736 |
|
|
|
14,584 |
|
Accounts
Payable
|
|
|
16,549 |
|
|
|
(27,015 |
) |
Accrued
Taxes, Net
|
|
|
2,550 |
|
|
|
41,243 |
|
Other
Current Assets
|
|
|
(24,736 |
) |
|
|
(4,595 |
) |
Other
Current Liabilities
|
|
|
1,393 |
|
|
|
3,150 |
|
Net
Cash Flows from Operating Activities
|
|
|
421,416 |
|
|
|
421,412 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(221,538 |
) |
|
|
(191,110 |
) |
Purchases
of Investment Securities
|
|
|
(413,538 |
) |
|
|
(561,509 |
) |
Sales
of Investment Securities
|
|
|
362,773 |
|
|
|
505,620 |
|
Acquisitions
of Nuclear Fuel
|
|
|
(99,110 |
) |
|
|
(73,112 |
) |
Proceeds
from Sales of Assets and Other
|
|
|
3,376 |
|
|
|
670 |
|
Net
Cash Flows Used for Investing Activities
|
|
|
(368,037 |
) |
|
|
(319,441 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
115,225 |
|
|
|
- |
|
Change
in Advances from Affiliates, Net
|
|
|
179,007 |
|
|
|
(66,939 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(262,000 |
) |
|
|
- |
|
Retirement
of Cumulative Preferred Stock
|
|
|
- |
|
|
|
(2 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(28,917 |
) |
|
|
(3,954 |
) |
Dividends
Paid on Common Stock
|
|
|
(56,250 |
) |
|
|
(30,000 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(255 |
) |
|
|
(255 |
) |
Net
Cash Flows Used for Financing Activities
|
|
|
(53,190 |
) |
|
|
(101,150 |
) |
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
189 |
|
|
|
821 |
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,139 |
|
|
|
1,369 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,328 |
|
|
$ |
2,190 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
57,086 |
|
|
$ |
49,628 |
|
Net
Cash Paid for Income Taxes
|
|
|
7,482 |
|
|
|
14,395 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
3,279 |
|
|
|
5,847 |
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
26,150 |
|
|
|
23,935 |
|
Acquisition
of Nuclear Fuel Included in Accounts Payable at September
30,
|
|
|
66,127 |
|
|
|
691 |
|
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
Third Quarter of 2008
Compared to Third Quarter of 2007
Reconciliation
of Third Quarter of 2007 to Third Quarter of 2008
Net
Income
(in
millions)
Third
Quarter of 2007
|
|
|
|
|
$ |
75 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(48 |
) |
|
|
|
|
Off-system
Sales
|
|
|
11 |
|
|
|
|
|
Other
|
|
|
3 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(34 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(2 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
12 |
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1 |
) |
|
|
|
|
Other
Income
|
|
|
2 |
|
|
|
|
|
Interest
Expense
|
|
|
(4 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2008
|
|
|
|
|
|
$ |
56 |
|
Net
Income decreased $19 million to $56 million in 2008. The key drivers
of the decrease were a $34 million decrease in Gross Margin, partially offset by
an $8 million decrease in Income Tax Expense and a $7 million decrease in
Operating Expenses and Other.
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 $48 million primarily due to the
following:
|
|
·
|
A
$57 million decrease related to increased fuel and consumables
expenses. CSPCo and OPCo have applied for an active fuel clause in
their Ohio ESP to be effective January 1, 2009.
|
|
·
|
An
$8 million decrease in residential revenue primarily due to an 18%
decrease in cooling degree days and the outages caused by the remnants of
Hurricane Ike.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$17 million increase related to a net increase in rates
implemented.
|
|
·
|
A
$10 million increase in capacity settlements under the Interconnection
Agreement related to an increase in an affiliate’s
peak.
|
·
|
Margins
from Off-system Sales increased $11 million primarily due to increased
physical sales margins driven by higher prices, partially offset by lower
trading margins.
|
·
|
Other
revenues increased $3 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 increased $2 million primarily due
to:
|
|
·
|
A
$6 million increase in recoverable PJM expenses.
|
|
·
|
A
$4 million increase in employee-related expenses.
|
|
·
|
A
$4 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 operation and maintenance expenses related to
service restoration expenses from the remnants of Hurricane
Ike.
|
|
·
|
A
$2 million increase in plant maintenance expenses.
|
|
These
increases were partially offset by a $17 million decrease resulting from a
settlement agreement in the third quarter 2007 related to alleged
violations of the NSR provisions of the CAA. The $17 million
represents OPCo’s allocation of the settlement.
|
·
|
Depreciation
and Amortization expense decreased $12 million primarily due to an $18
million decrease in amortization as a result of completion of amortization
of regulatory assets in December 2007, partially offset by a $5 million
increase in depreciation related to environmental improvements placed in
service at the Cardinal Plant in 2008 and the Mitchell Plant in July
2007.
|
·
|
Interest
Expense increased $4 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 $8 million primarily due to a decrease in pretax
book income.
|
Nine Months Ended
September 30,
2008 Compared
to Nine Months Ended September 30,
2007
Reconciliation
of Nine Months Ended September 30, 2007 to Nine Months Ended September 30,
2008
Net
Income
(in
millions)
Nine
Months Ended September 30, 2007
|
|
|
|
|
$ |
229 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(55 |
) |
|
|
|
|
Off-system
Sales
|
|
|
34 |
|
|
|
|
|
Other
|
|
|
12 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(9 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
8 |
|
|
|
|
|
Depreciation
and Amortization
|
|
|
42 |
|
|
|
|
|
Carrying
Costs Income
|
|
|
1 |
|
|
|
|
|
Other
Income
|
|
|
6 |
|
|
|
|
|
Interest
Expense
|
|
|
(20 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
37 |
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2008
|
|
|
|
|
|
$ |
247 |
|
Net
Income increased $18 million to $247 million in 2008. The key drivers
of the increase were a $37 million decrease in Operating Expenses and Other,
partially offset by a $10 million increase in Income Tax Expense and a $9
million decrease in Gross Margin.
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 $55 million primarily due to the
following:
|
|
·
|
A
$105 million decrease related to increased fuel and consumables
expenses. CSPCo and OPCo have applied for an active fuel clause in
their Ohio ESP to be effective January 1, 2009.
|
|
·
|
A
$9 million decrease in residential revenues primarily due to a 21%
decrease in cooling degree days.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$42 million increase related to a net increase in rates
implemented.
|
|
·
|
A
$29 million increase related to coal contract amendments in
2008.
|
|
·
|
A
$17 million increase in capacity settlements under the Interconnection
Agreement related to an increase in an affiliate’s
peak.
|
·
|
Margins
from Off-system Sales increased $34 million primarily due to increased
physical sales margins driven by higher prices and higher trading
margins.
|
·
|
Other
revenues increased $12 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 $8 million primarily due
to:
|
|
·
|
A
$20 million decrease in removal expenses related to planned outages at the
Gavin and Mitchell Plants during 2007.
|
|
·
|
A
$17 million decrease resulting from a settlement agreement in the third
quarter 2007 related to alleged violations of the NSR provisions of the
CAA. The $17 million represents OPCo’s allocation of the
settlement.
|
|
·
|
A
$7 million decrease in overhead line maintenance
expenses.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$13 million increase in recoverable PJM expenses.
|
|
·
|
An
$11 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 maintenance expenses from planned and forced
outages at various plants.
|
|
·
|
A
$4 million increase in employee-related expenses.
|
·
|
Depreciation
and Amortization decreased $42 million primarily due
to:
|
|
·
|
A
$53 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 $19 million increase in depreciation
related to environmental improvements placed in service at the Cardinal
Plant in 2008 and the Mitchell Plant in 2007.
|
·
|
Interest
Expense increased $20 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 $10 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, its borrowing costs could increase and access to
borrowed funds could be negatively affected.
Cash
Flow
Cash
flows for the nine months ended September 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
|
|
|
434,295 |
|
|
|
402,980 |
|
Investing
Activities
|
|
|
(486,678 |
) |
|
|
(743,260 |
) |
Financing
Activities
|
|
|
54,805 |
|
|
|
351,381 |
|
Net
Increase in Cash and Cash Equivalents
|
|
|
2,422 |
|
|
|
11,101 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
9,088 |
|
|
$ |
12,726 |
|
Operating
Activities
Net Cash
Flows from Operating Activities were $434 million in 2008. OPCo
produced Net Income of $247 million during the period and a noncash expense item
of $212 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 and changes in the future rights or
obligations to receive or pay cash, such as regulatory assets and
liabilities. Accounts Payable had a $45 million inflow primarily due
to increases in tonnage and prices per ton related to fuel and consumable
purchases. Fuel, Materials and Supplies had a $48 million outflow due
to price increases.
Net Cash
Flows from Operating Activities were $403 million in 2007. OPCo
produced Net Income of $229 million during the period and a noncash expense item
of $253 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
included two significant items. Accounts Payable had a $60 million
cash outflow partially due to emission allowance payments in January 2007,
reduced accruals for Mitchell Plant environmental projects that went into
service in 2007 and timing differences for payments to
affiliates. Accounts Receivable, Net had a $33 million cash outflow
partially due to the timing of collections of receivables.
Investing
Activities
Net Cash
Used for Investing Activities were $487 million and $743 million in 2008 and
2007, respectively. Construction Expenditures were $453 million and
$751 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 flue gas desulfurization projects at
the Cardinal, Amos and Mitchell Plants. In 2007, environmental
upgrades were completed for Units 1 and 2 at the Mitchell Plant. For
the remainder of 2008, OPCo expects construction expenditures to be
approximately $230 million.
Financing
Activities
Net Cash
Flows from Financing Activities were $55 million in 2008. OPCo issued
$165 million of Pollution Control Bonds and $250 million of Senior Unsecured
Notes. These increases were partially offset by the retirement of
$250 million of Pollution Control Bonds and $13 million of Notes Payable –
Nonaffiliated. OPCo also had a net decrease in borrowings of $102
million from the Utility Money Pool.
Net Cash
Flows from Financing Activities were $351 million in 2007. OPCo
issued $400 million of Senior Unsecured Notes and $65 million of Pollution
Control Bonds. OPCo reduced borrowings by $96 million from the
Utility Money Pool.
Financing
Activity
Long-term
debt issuances, retirements and principal payments made during the first nine
months of 2008 were:
Issuances
|
|
Principal
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
Amount
|
|
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
|
Senior
Unsecured Notes
|
|
|
250,000
|
|
5.75
|
|
2013
|
Retirements and Principal
Payments
|
|
Principal
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
Amount
Paid
|
|
Rate
|
|
Date
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Notes
Payable – Nonaffiliated
|
|
$
|
1,463
|
|
6.81
|
|
2008
|
Notes
Payable – Nonaffiliated
|
|
|
12,000
|
|
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
In recent
months, the financial markets have become increasingly unstable and constrained
at both a global and domestic level. This systemic marketplace
distress is impacting OPCo’s access to capital, liquidity and cost of
capital. The uncertainties in the credit markets could have
significant implications on OPCo since it relies on continuing access to capital
to fund operations and capital expenditures.
OPCo
participates in the Utility Money Pool, which provides access to AEP’s
liquidity. OPCo has $37 million of Senior Unsecured Notes that will
mature in 2008 and $82 million of Notes Payable that will mature in
2009. To the extent refinancing is unavailable due to challenging
credit markets, OPCo will rely upon cash flows from operations and access to the
Utility Money Pool to fund its maturities, current operations and capital
expenditures.
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 which were reduced by
Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12
million, respectively, following its bankruptcy. As of September 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”. Adverse results in these proceedings have the
potential to materially affect net income, financial condition and cash
flows.
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries” 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” 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 September 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 September 30, 2008
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
|
Cash
Flow &
Fair
Value Hedges
|
|
|
DETM
Assignment (a)
|
|
|
Collateral
Deposits
|
|
|
Total
|
|
Current
Assets
|
|
$ |
77,357 |
|
|
$ |
2,245 |
|
|
$ |
- |
|
|
$ |
(2,466 |
) |
|
$ |
77,136 |
|
Noncurrent
Assets
|
|
|
48,369 |
|
|
|
720 |
|
|
|
- |
|
|
|
(3,281 |
) |
|
|
45,808 |
|
Total
MTM Derivative Contract Assets
|
|
|
125,726 |
|
|
|
2,965 |
|
|
|
- |
|
|
|
(5,747 |
) |
|
|
122,944 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(67,432 |
) |
|
|
(3,170 |
) |
|
|
(2,174 |
) |
|
|
620 |
|
|
|
(72,156 |
) |
Noncurrent
Liabilities
|
|
|
(24,105 |
) |
|
|
- |
|
|
|
(2,222 |
) |
|
|
36 |
|
|
|
(26,291 |
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(91,537 |
) |
|
|
(3,170 |
) |
|
|
(4,396 |
) |
|
|
656 |
|
|
|
(98,447 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$ |
34,189 |
|
|
$ |
(205 |
) |
|
$ |
(4,396 |
) |
|
$ |
(5,091 |
) |
|
$ |
24,497 |
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 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
|
|
|
(8,565 |
) |
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
1,154 |
|
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)
|
|
|
1,026 |
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(c)
|
|
|
13,061 |
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
(2,671 |
) |
Total
MTM Risk Management Contract Net Assets
|
|
|
34,189 |
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
(205 |
) |
DETM
Assignment (e)
|
|
|
(4,396 |
) |
Collateral
Deposits
|
|
|
(5,091 |
) |
Ending
Net Risk Management Assets at September 30, 2008
|
|
$ |
24,497 |
|
(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. Inception value is only recorded if observable market
data can be obtained for valuation inputs for the entire contract
term. 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.
|
(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 September 30, 2008
(in
thousands)
|
|
Remainder
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2012
|
|
|
Total
|
|
Level
1 (a)
|
|
$ |
(695 |
) |
|
$ |
(1,596 |
) |
|
$ |
(15 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(2,306 |
) |
Level
2 (b)
|
|
|
310 |
|
|
|
16,487 |
|
|
|
12,052 |
|
|
|
724 |
|
|
|
338 |
|
|
|
- |
|
|
|
29,911 |
|
Level
3 (c)
|
|
|
(2,788 |
) |
|
|
462 |
|
|
|
(1,303 |
) |
|
|
189 |
|
|
|
107 |
|
|
|
- |
|
|
|
(3,333 |
) |
Total
|
|
|
(3,173 |
) |
|
|
15,353 |
|
|
|
10,734 |
|
|
|
913 |
|
|
|
445 |
|
|
|
- |
|
|
|
24,272 |
|
Dedesignated
Risk Management Contracts (d)
|
|
|
976 |
|
|
|
3,282 |
|
|
|
3,256 |
|
|
|
1,268 |
|
|
|
1,135 |
|
|
|
- |
|
|
|
9,917 |
|
Total
MTM Risk Management Contract Net Assets (Liabilities)
|
|
$ |
(2,197 |
) |
|
$ |
18,635 |
|
|
$ |
13,990 |
|
|
$ |
2,181 |
|
|
$ |
1,580 |
|
|
$ |
- |
|
|
$ |
34,189 |
|
(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 September 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
Nine
Months Ended September 30, 2008
(in
thousands)
|
|
|
|
|
|
|
|
Foreign
|
|
|
|
|
|
|
Power
|
|
|
Interest
Rate
|
|
|
Currency
|
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2007
|
|
$ |
(756 |
) |
|
$ |
2,167 |
|
|
$ |
(254 |
) |
|
$ |
1,157 |
|
Changes
in Fair Value
|
|
|
431 |
|
|
|
(903 |
) |
|
|
68 |
|
|
|
(404 |
) |
Reclassifications
from AOCI for Cash Flow Hedges Settled
|
|
|
859 |
|
|
|
160 |
|
|
|
10 |
|
|
|
1,029 |
|
Ending
Balance in AOCI September 30, 2008
|
|
$ |
534 |
|
|
$ |
1,424 |
|
|
$ |
(176 |
) |
|
$ |
1,782 |
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $328 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 September 30, 2008, a
near term typical change in commodity prices is not expected to have a material
effect on OPCo’s net income, 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:
Nine
Months Ended
|
|
|
|
|
Twelve
Months Ended
|
September
30, 2008
|
|
|
|
|
December
31, 2007
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$901
|
|
$1,284
|
|
$447
|
|
$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 $10.1 million.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
600,841 |
|
|
$ |
543,404 |
|
|
$ |
1,672,203 |
|
|
$ |
1,516,383 |
|
Sales
to AEP Affiliates
|
|
|
245,830 |
|
|
|
205,193 |
|
|
|
739,077 |
|
|
|
564,292 |
|
Other
- Affiliated
|
|
|
5,759 |
|
|
|
5,749 |
|
|
|
17,545 |
|
|
|
16,604 |
|
Other
- Nonaffiliated
|
|
|
4,584 |
|
|
|
3,397 |
|
|
|
12,738 |
|
|
|
10,838 |
|
TOTAL
|
|
|
857,014 |
|
|
|
757,743 |
|
|
|
2,441,563 |
|
|
|
2,108,117 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
359,341 |
|
|
|
254,310 |
|
|
|
928,465 |
|
|
|
653,941 |
|
Purchased
Electricity for Resale
|
|
|
56,142 |
|
|
|
33,178 |
|
|
|
129,874 |
|
|
|
85,900 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
48,867 |
|
|
|
43,147 |
|
|
|
116,540 |
|
|
|
92,858 |
|
Other
Operation
|
|
|
98,653 |
|
|
|
102,850 |
|
|
|
280,494 |
|
|
|
292,809 |
|
Maintenance
|
|
|
51,791 |
|
|
|
45,663 |
|
|
|
159,706 |
|
|
|
155,428 |
|
Depreciation
and Amortization
|
|
|
72,180 |
|
|
|
84,400 |
|
|
|
211,919 |
|
|
|
253,455 |
|
Taxes
Other Than Income Taxes
|
|
|
49,019 |
|
|
|
47,506 |
|
|
|
146,534 |
|
|
|
146,211 |
|
TOTAL
|
|
|
735,993 |
|
|
|
611,054 |
|
|
|
1,973,532 |
|
|
|
1,680,602 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
121,021 |
|
|
|
146,689 |
|
|
|
468,031 |
|
|
|
427,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
2,252 |
|
|
|
108 |
|
|
|
6,910 |
|
|
|
992 |
|
Carrying
Costs Income
|
|
|
3,936 |
|
|
|
3,644 |
|
|
|
12,159 |
|
|
|
10,779 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
555 |
|
|
|
590 |
|
|
|
1,801 |
|
|
|
1,607 |
|
Interest
Expense
|
|
|
(39,964 |
) |
|
|
(36,262 |
) |
|
|
(116,199 |
) |
|
|
(95,927 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE
|
|
|
87,800 |
|
|
|
114,769 |
|
|
|
372,702 |
|
|
|
344,966 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
31,601 |
|
|
|
39,507 |
|
|
|
125,782 |
|
|
|
116,103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
56,199 |
|
|
|
75,262 |
|
|
|
246,920 |
|
|
|
228,863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
183 |
|
|
|
183 |
|
|
|
549 |
|
|
|
549 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
56,016 |
|
|
$ |
75,079 |
|
|
$ |
246,371 |
|
|
$ |
228,314 |
|
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 Nine Months Ended September 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
|
|
|
|
|
|
|
|
|
|
|
(549 |
) |
|
|
|
|
|
|
(549 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,002,413 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $1,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,486 |
) |
|
|
(3,486 |
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
228,863 |
|
|
|
|
|
|
|
228,863 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
225,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
321,201 |
|
|
$ |
536,639 |
|
|
$ |
1,430,199 |
|
|
$ |
(60,249 |
) |
|
$ |
2,227,790 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
(549 |
) |
|
|
|
|
|
|
(549 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,288,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
625 |
|
|
|
625 |
|
Amortization
of Pension and OPEB Deferred Costs, Net of Tax of $1,136
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,110 |
|
|
|
2,110 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
246,920 |
|
|
|
|
|
|
|
246,920 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
249,655 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2008
|
|
$ |
321,201 |
|
|
$ |
536,640 |
|
|
$ |
1,713,942 |
|
|
$ |
(33,806 |
) |
|
$ |
2,537,977 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
9,088 |
|
|
$ |
6,666 |
|
Advances
to Affiliates
|
|
|
39,758 |
|
|
|
- |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
93,951 |
|
|
|
104,783 |
|
Affiliated
Companies
|
|
|
105,503 |
|
|
|
119,560 |
|
Accrued
Unbilled Revenues
|
|
|
24,947 |
|
|
|
26,819 |
|
Miscellaneous
|
|
|
11,551 |
|
|
|
1,578 |
|
Allowance
for Uncollectible Accounts
|
|
|
(3,555 |
) |
|
|
(3,396 |
) |
Total
Accounts Receivable
|
|
|
232,397 |
|
|
|
249,344 |
|
Fuel
|
|
|
146,332 |
|
|
|
92,874 |
|
Materials
and Supplies
|
|
|
104,924 |
|
|
|
108,447 |
|
Risk
Management Assets
|
|
|
77,136 |
|
|
|
44,236 |
|
Prepayments
and Other
|
|
|
38,372 |
|
|
|
18,300 |
|
TOTAL
|
|
|
648,007 |
|
|
|
519,867 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
5,937,723 |
|
|
|
5,641,537 |
|
Transmission
|
|
|
1,101,463 |
|
|
|
1,068,387 |
|
Distribution
|
|
|
1,442,047 |
|
|
|
1,394,988 |
|
Other
|
|
|
379,242 |
|
|
|
318,805 |
|
Construction
Work in Progress
|
|
|
683,404 |
|
|
|
716,640 |
|
Total
|
|
|
9,543,879 |
|
|
|
9,140,357 |
|
Accumulated
Depreciation and Amortization
|
|
|
3,084,683 |
|
|
|
2,967,285 |
|
TOTAL
- NET
|
|
|
6,459,196 |
|
|
|
6,173,072 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
324,260 |
|
|
|
323,105 |
|
Long-term
Risk Management Assets
|
|
|
45,808 |
|
|
|
49,586 |
|
Deferred
Charges and Other
|
|
|
207,562 |
|
|
|
272,799 |
|
TOTAL
|
|
|
577,630 |
|
|
|
645,490 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
7,684,833 |
|
|
$ |
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
September
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
- |
|
|
$ |
101,548 |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
187,803 |
|
|
|
141,196 |
|
Affiliated
Companies
|
|
|
132,195 |
|
|
|
137,389 |
|
Short-term
Debt – Nonaffiliated
|
|
|
- |
|
|
|
701 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
119,225 |
|
|
|
55,188 |
|
Risk
Management Liabilities
|
|
|
72,156 |
|
|
|
40,548 |
|
Customer
Deposits
|
|
|
24,002 |
|
|
|
30,613 |
|
Accrued
Taxes
|
|
|
130,211 |
|
|
|
185,011 |
|
Accrued
Interest
|
|
|
37,704 |
|
|
|
41,880 |
|
Other
|
|
|
151,044 |
|
|
|
149,658 |
|
TOTAL
|
|
|
854,340 |
|
|
|
883,732 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
2,682,247 |
|
|
|
2,594,410 |
|
Long-term
Debt – Affiliated
|
|
|
200,000 |
|
|
|
200,000 |
|
Long-term
Risk Management Liabilities
|
|
|
26,291 |
|
|
|
32,194 |
|
Deferred
Income Taxes
|
|
|
957,441 |
|
|
|
914,170 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
150,794 |
|
|
|
160,721 |
|
Deferred
Credits and Other
|
|
|
242,084 |
|
|
|
229,635 |
|
TOTAL
|
|
|
4,258,857 |
|
|
|
4,131,130 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
5,113,197 |
|
|
|
5,014,862 |
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
17,032 |
|
|
|
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
|
|
|
1,713,942 |
|
|
|
1,469,717 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(33,806 |
) |
|
|
(36,541 |
) |
TOTAL
|
|
|
2,537,977 |
|
|
|
2,291,017 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
7,684,833 |
|
|
$ |
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 Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
246,920 |
|
|
$ |
228,863 |
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
211,919 |
|
|
|
253,455 |
|
Deferred
Income Taxes
|
|
|
45,424 |
|
|
|
3,938 |
|
Carrying
Costs Income
|
|
|
(12,159 |
) |
|
|
(10,779 |
) |
Allowance
for Equity Funds Used During Construction
|
|
|
(1,801 |
) |
|
|
(1,607 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
(2,028 |
) |
|
|
(3,894 |
) |
Deferred
Property Taxes
|
|
|
63,867 |
|
|
|
54,036 |
|
Change
in Other Noncurrent Assets
|
|
|
(52,788 |
) |
|
|
(20,275 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
9,300 |
|
|
|
8,026 |
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
16,947 |
|
|
|
(32,723 |
) |
Fuel,
Materials and Supplies
|
|
|
(48,197 |
) |
|
|
(1,245 |
) |
Accounts
Payable
|
|
|
45,252 |
|
|
|
(59,925 |
) |
Accrued
Taxes, Net
|
|
|
(56,936 |
) |
|
|
(19,997 |
) |
Other
Current Assets
|
|
|
(14,333 |
) |
|
|
(11,784 |
) |
Other
Current Liabilities
|
|
|
(17,092 |
) |
|
|
16,891 |
|
Net
Cash Flows from Operating Activities
|
|
|
434,295 |
|
|
|
402,980 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(453,405 |
) |
|
|
(751,161 |
) |
Change
in Advances to Affiliates, Net
|
|
|
(39,758 |
) |
|
|
- |
|
Proceeds
from Sales of Assets
|
|
|
6,872 |
|
|
|
7,924 |
|
Other
|
|
|
(387 |
) |
|
|
(23 |
) |
Net
Cash Flows Used for Investing Activities
|
|
|
(486,678 |
) |
|
|
(743,260 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
412,389 |
|
|
|
461,324 |
|
Change
in Short-term Debt, Net – Nonaffiliated
|
|
|
(701 |
) |
|
|
895 |
|
Change
in Advances from Affiliates, Net
|
|
|
(101,548 |
) |
|
|
(95,940 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(263,463 |
) |
|
|
(8,927 |
) |
Retirement
of Cumulative Preferred Stock
|
|
|
- |
|
|
|
(2 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(4,636 |
) |
|
|
(5,420 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(549 |
) |
|
|
(549 |
) |
Other
|
|
|
13,313 |
|
|
|
- |
|
Net
Cash Flows from Financing Activities
|
|
|
54,805 |
|
|
|
351,381 |
|
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
2,422 |
|
|
|
11,101 |
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
6,666 |
|
|
|
1,625 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
9,088 |
|
|
$ |
12,726 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
112,321 |
|
|
$ |
85,851 |
|
Net
Cash Paid for Income Taxes
|
|
|
61,051 |
|
|
|
61,459 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
2,018 |
|
|
|
1,620 |
|
Noncash
Acquisition of Coal Land Rights
|
|
|
41,600 |
|
|
|
- |
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
25,839 |
|
|
|
42,055 |
|
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
Third Quarter of 2008
Compared to Third Quarter of 2007
Reconciliation
of Third Quarter of 2007 to Third Quarter of 2008
Net
Income
(in
millions)
Third
Quarter of 2007
|
|
|
|
|
$ |
37 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
(6 |
) |
|
|
|
|
Transmission
Revenues
|
|
|
3 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(11 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(3 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
2 |
|
|
|
|
|
Other
Income
|
|
|
(1 |
) |
|
|
|
|
Carrying
Costs Income
|
|
|
3 |
|
|
|
|
|
Interest
Expense
|
|
|
(1 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2008
|
|
|
|
|
|
$ |
28 |
|
Net
Income decreased $9 million to $28 million in 2008. The key drivers
of the decrease were an $11 million increase in Operating Expenses and Other and
a $3 million decrease in Gross Margin, offset by a $5 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
and Off-system Sales Margins decreased $6 million primarily due to a
decrease in retail sales margins mainly due to an 11% decrease in cooling
degree days, partially offset by base rate adjustments.
|
·
|
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 $11 million primarily due
to:
|
|
·
|
A
$4 million increase primarily associated with outside services and
employee-related expenses.
|
|
·
|
A
$2 million increase in overhead line expenses.
|
|
·
|
A
$1 million increase in transmission expense primarily due to higher rates
within SPP.
|
|
·
|
A
$1 million increase in expense for the June 2008
storms.
|
·
|
Depreciation
and Amortization expenses increased $3 million primarily due to an
increase in the amortization of the Lawton Settlement regulatory
assets.
|
·
|
Taxes
Other Than Income Taxes decreased $2 million primarily due to decreases in
real property tax and decreases in state sales and use
tax.
|
·
|
Carrying
Costs Income increased $3 million primarily due to the new peaking units
and to deferred ice storms costs. See “Oklahoma 2007 Ice
Storms” section of Note 3.
|
·
|
Income
Tax Expense decreased $5 million primarily due to a decrease in pretax
book income.
|
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Reconciliation
of Nine Months Ended September 30, 2007 to Nine Months Ended September 30,
2008
Net
Income
(in
millions)
Nine
Months Ended September 30, 2007
|
|
|
|
|
$ |
22 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
16 |
|
|
|
|
|
Transmission
Revenues
|
|
|
7 |
|
|
|
|
|
Other
|
|
|
11 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
34 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(24 |
) |
|
|
|
|
Deferral
of Ice Storm Costs
|
|
|
72 |
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(8 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
1 |
|
|
|
|
|
Other
Income
|
|
|
2 |
|
|
|
|
|
Carrying
Costs Income
|
|
|
7 |
|
|
|
|
|
Interest
Expense
|
|
|
(7 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(30 |
) |
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2008
|
|
|
|
|
|
$ |
69 |
|
Net
Income increased $47 million to $69 million in 2008. The key drivers
of the increase were a $43 million decrease in Operating Expenses and Other and
a $34 million increase in Gross Margin, offset by a $30 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 $16 million primarily due to an
increase in retail sales margins resulting from base rate adjustments
during the year, partially offset by a 5% decrease in cooling degree
days.
|
·
|
Transmission
Revenues increased $7 million primarily due to higher rates within
SPP.
|
·
|
Other
revenues increased $11 million primarily due to an 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 $24 million primarily due
to:
|
|
·
|
A
$12 million increase in production expenses primarily due to a $10 million
write-off of pre-construction costs related to the cancelled Red Rock
Generating Facility. See “Red Rock Generating Facility” section
of Note 3.
|
|
·
|
A
$10 million increase due to amortization of the deferred 2007 ice storm
costs.
|
|
·
|
A
$7 million increase in transmission expense primarily due to higher rates
within SPP.
|
|
·
|
A
$6 million increase in administrative and general expenses, primarily
associated with outside services and employee-related
expenses.
|
|
·
|
A
$3 million increase in expense for the June 2008
storms.
|
|
·
|
A
$2 million increase in distribution maintenance expense due to increased
vegetation management activities.
|
|
These
increases were partially offset by:
|
|
·
|
A
$12 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 $8 million primarily due to an
increase related to the amortization of the Lawton Settlement regulatory
assets.
|
·
|
Other
Income increased $2 million primarily due to an increase in the equity
component of AFUDC.
|
·
|
Carrying
Costs Income increased $7 million due to the new peaking units and
deferred ice storm costs. See “Oklahoma 2007 Ice Storms”
section of Note 3.
|
·
|
Interest
Expense increased $7 million primarily due to a $12 million increase in
interest expense from long-term borrowings, partially offset by a $4
million decrease in interest expense from short-term
borrowings.
|
·
|
Income
Tax Expense increased $30 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 nine months ended September 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
|
|
|
42,386 |
|
|
|
62,042 |
|
Investing
Activities
|
|
|
(161,523 |
) |
|
|
(231,916 |
) |
Financing
Activities
|
|
|
120,011 |
|
|
|
169,713 |
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
874 |
|
|
|
(161 |
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
2,244 |
|
|
$ |
1,490 |
|
Operating
Activities
Net Cash
Flows from Operating Activities were $42 million in 2008. PSO
produced Net Income of $69 million during the period and had noncash expense
items of $78 million for Depreciation and Amortization and $71 million for
Deferred Income Taxes. 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 relates to a number of
items. The $81 million outflow from Accounts Payable was primarily
due to a decrease in accounts payable accruals and purchased power
payable. The $47 million outflow from Fuel Over/Under-Recovery, Net
resulted from rapidly increasing natural gas costs which fuels the majority
of PSO’s generating facilities. The $36 million inflow from Accrued
Taxes, Net was the result of a refund for the 2007 overpayment of federal income
taxes and increased accruals related to property and income taxes.
Net Cash
Flows from Operating Activities were $62 million in 2007. PSO
produced Net Income of $22 million during the period and had a noncash expense
item of $70 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 $32 million outflow from Accounts Receivable, Net was
primarily due to a receivable booked on behalf of the joint owners of a
generating station related to fuel transportation costs. The $26
million inflow from Margin Deposits was primarily due to gas trading
activities. The $8 million outflow from Fuel Over/Under Recovery, Net
resulted from increasing natural gas costs which fuels the majority of PSO’s
generating facilities.
Investing
Activities
Net Cash
Flows Used for Investing Activities during 2008 and 2007 were $162 million and
$232 million, respectively. Construction Expenditures of $214 million
and $235 million in 2008 and 2007, respectively, 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 $70
million.
Financing
Activities
Net Cash
Flows from Financing Activities were $120 million during 2008. PSO
had a net increase of $125 million in borrowings from the Utility Money
Pool. PSO repurchased $34 million in Pollution Control Bonds in May
2008. PSO received capital contributions from the Parent of $30
million.
Net Cash
Flows from Financing Activities were $170 million during 2007. PSO
had a net increase of $111 million in borrowings from the Utility Money
Pool. PSO received capital contributions from the Parent of $60
million.
Financing
Activity
Long-term
debt issuances, retirements and principal payments made during the first nine
months of 2008 were:
Issuances
None
Retirements and Principal
Payments
|
|
Principal
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
Amount
Paid
|
|
Rate
|
|
Date
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$
|
33,700
|
|
Variable
|
|
2014
|
Liquidity
In recent
months, the financial markets have become increasingly unstable and constrained
at both a global and domestic level. This systemic marketplace
distress is impacting PSO’s access to capital, liquidity and cost of
capital. The uncertainties in the credit markets could have
significant implications on PSO since it relies on continuing access to capital
to fund operations and capital expenditures.
PSO
participates in the Utility Money Pool, which provides access to AEP’s
liquidity. PSO has $50 million of Senior Unsecured Notes that will
mature in 2009. To the extent refinancing is unavailable due to the
challenging credit markets, PSO will rely upon cash flows from operations and
access to the Utility Money Pool to fund its maturity, current
operations and capital expenditures.
Summary Obligation
Information
The
summary of contractual obligations for the year ended 2007 is included in the
second quarter 2008 10-Q and has not changed significantly 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”. Adverse results in these proceedings have the
potential to materially affect net income, financial condition and cash
flows.
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries” 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” 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 Balance Sheet as of September 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
Balance Sheet
As
of September 30, 2008
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MTM
Risk
|
|
|
DETM
|
|
|
|
|
|
|
|
|
|
Management
|
|
|
Assignment
|
|
|
Collateral
|
|
|
|
|
|
|
Contracts
|
|
|
(a)
|
|
|
Deposits
|
|
|
Total
|
|
Current
Assets
|
|
$ |
25,165 |
|
|
$ |
- |
|
|
$ |
(448 |
) |
|
$ |
24,717 |
|
Noncurrent
Assets
|
|
|
2,703 |
|
|
|
- |
|
|
|
(51 |
) |
|
|
2,652 |
|
Total
MTM Derivative Contract Assets
|
|
|
27,868 |
|
|
|
- |
|
|
|
(499 |
) |
|
|
27,369 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(25,508 |
) |
|
|
(110 |
) |
|
|
40 |
|
|
|
(25,578 |
) |
Noncurrent
Liabilities
|
|
|
(1,891 |
) |
|
|
(112 |
) |
|
|
7 |
|
|
|
(1,996 |
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(27,399 |
) |
|
|
(222 |
) |
|
|
47 |
|
|
|
(27,574 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$ |
469 |
|
|
$ |
(222 |
) |
|
$ |
(452 |
) |
|
$ |
(205 |
) |
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
MTM
Risk Management Contract Net Assets (Liabilities)
Nine
Months Ended September 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
|
|
|
(6,988 |
) |
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)
|
|
|
20 |
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(c)
|
|
|
(104 |
) |
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
560 |
|
Total
MTM Risk Management Contract Net Assets
|
|
|
469 |
|
DETM
Assignment (e)
|
|
|
(222 |
) |
Collateral
Deposits
|
|
|
(452 |
) |
Ending
Net Risk Management Assets (Liabilities) at September 30,
2008
|
|
$ |
(205 |
) |
(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. Inception value is only recorded if observable market
data can be obtained for valuation inputs for the entire contract
term. 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
Statements of Income. These net gains (losses) are recorded as
regulatory assets/liabilities.
|
(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 September 30, 2008
(in
thousands)
|
|
Remainder
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
After
2012
|
|
|
Total
|
|
Level
1 (a)
|
|
$ |
316 |
|
|
$ |
(250 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
66 |
|
Level
2 (b)
|
|
|
50 |
|
|
|
1,134 |
|
|
|
511 |
|
|
|
(85 |
) |
|
|
- |
|
|
|
- |
|
|
|
1,610 |
|
Level
3 (c)
|
|
|
(1,208 |
) |
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,207 |
) |
Total
|
|
$ |
(842 |
) |
|
$ |
884 |
|
|
$ |
512 |
|
|
$ |
(85 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
469 |
|
(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 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 Balance Sheets and the reasons for the
changes from December 31, 2007 to September 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
Nine
Months Ended September 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
|
|
|
137 |
|
Ending
Balance in AOCI September 30, 2008
|
|
$ |
(750 |
) |
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 September 30, 2008, a near
term typical change in commodity prices is not expected to have a material
effect on PSO’s net income, 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:
Nine
Months Ended September 30, 2008
|
|
|
|
|
Twelve
Months Ended December 31, 2007
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$69
|
|
$164
|
|
$45
|
|
$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 $3.6 million.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
518,182 |
|
|
$ |
433,737 |
|
|
$ |
1,194,737 |
|
|
$ |
1,028,637 |
|
Sales
to AEP Affiliates
|
|
|
32,286 |
|
|
|
12,737 |
|
|
|
89,988 |
|
|
|
53,605 |
|
Other
|
|
|
781 |
|
|
|
1,562 |
|
|
|
2,858 |
|
|
|
2,746 |
|
TOTAL
|
|
|
551,249 |
|
|
|
448,036 |
|
|
|
1,287,583 |
|
|
|
1,084,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
288,027 |
|
|
|
182,680 |
|
|
|
584,769 |
|
|
|
438,828 |
|
Purchased
Electricity for Resale
|
|
|
77,834 |
|
|
|
75,875 |
|
|
|
230,432 |
|
|
|
213,429 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
15,169 |
|
|
|
16,216 |
|
|
|
53,944 |
|
|
|
48,679 |
|
Other
Operation
|
|
|
51,432 |
|
|
|
44,030 |
|
|
|
152,617 |
|
|
|
127,382 |
|
Maintenance
|
|
|
27,530 |
|
|
|
24,128 |
|
|
|
87,772 |
|
|
|
89,390 |
|
Deferral
of Ice Storm Costs
|
|
|
69 |
|
|
|
- |
|
|
|
(71,610 |
) |
|
|
- |
|
Depreciation
and Amortization
|
|
|
27,192 |
|
|
|
24,430 |
|
|
|
78,079 |
|
|
|
70,128 |
|
Taxes
Other Than Income Taxes
|
|
|
7,839 |
|
|
|
10,007 |
|
|
|
29,265 |
|
|
|
30,191 |
|
TOTAL
|
|
|
495,092 |
|
|
|
377,366 |
|
|
|
1,145,268 |
|
|
|
1,018,027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
56,157 |
|
|
|
70,670 |
|
|
|
142,315 |
|
|
|
66,961 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income
|
|
|
34 |
|
|
|
1,086 |
|
|
|
4,004 |
|
|
|
2,294 |
|
Carrying
Costs Income
|
|
|
3,183 |
|
|
|
- |
|
|
|
6,945 |
|
|
|
- |
|
Interest
Expense
|
|
|
(13,713 |
) |
|
|
(12,381 |
) |
|
|
(43,179 |
) |
|
|
(36,549 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE
|
|
|
45,661 |
|
|
|
59,375 |
|
|
|
110,085 |
|
|
|
32,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
17,917 |
|
|
|
22,804 |
|
|
|
40,815 |
|
|
|
10,266 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
27,744 |
|
|
|
36,571 |
|
|
|
69,270 |
|
|
|
22,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
53 |
|
|
|
53 |
|
|
|
159 |
|
|
|
159 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
27,691 |
|
|
$ |
36,518 |
|
|
$ |
69,111 |
|
|
$ |
22,281 |
|
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 Nine Months Ended September 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
|
|
|
|
|
|
|
60,000 |
|
|
|
|
|
|
|
|
|
|
|
60,000 |
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(159 |
) |
|
|
|
|
|
|
(159 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
644,893 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
137 |
|
|
|
137 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
22,440 |
|
|
|
|
|
|
|
22,440 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,577 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
157,230 |
|
|
$ |
290,016 |
|
|
$ |
221,157 |
|
|
$ |
(933 |
) |
|
$ |
667,470 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
(159 |
) |
|
|
|
|
|
|
(159 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
669,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive
Income, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
137 |
|
|
|
137 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
69,270 |
|
|
|
|
|
|
|
69,270 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
69,407 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2008
|
|
$ |
157,230 |
|
|
$ |
340,016 |
|
|
$ |
242,543 |
|
|
$ |
(750 |
) |
|
$ |
739,039 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
BALANCE SHEETS
ASSETS
September
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
2,244 |
|
|
$ |
1,370 |
|
Advances
to Affiliates
|
|
|
- |
|
|
|
51,202 |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
42,023 |
|
|
|
74,330 |
|
Affiliated
Companies
|
|
|
72,627 |
|
|
|
59,835 |
|
Miscellaneous
|
|
|
9,716 |
|
|
|
10,315 |
|
Allowance
for Uncollectible Accounts
|
|
|
(28 |
) |
|
|
- |
|
Total
Accounts Receivable
|
|
|
124,338 |
|
|
|
144,480 |
|
Fuel
|
|
|
26,547 |
|
|
|
19,394 |
|
Materials
and Supplies
|
|
|
47,419 |
|
|
|
47,691 |
|
Risk
Management Assets
|
|
|
24,717 |
|
|
|
33,308 |
|
Accrued
Tax Benefits
|
|
|
13,040 |
|
|
|
31,756 |
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
35,495 |
|
|
|
- |
|
Margin
Deposits
|
|
|
426 |
|
|
|
8,980 |
|
Prepayments
and Other
|
|
|
18,385 |
|
|
|
18,137 |
|
TOTAL
|
|
|
292,611 |
|
|
|
356,318 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
1,252,804 |
|
|
|
1,110,657 |
|
Transmission
|
|
|
601,518 |
|
|
|
569,746 |
|
Distribution
|
|
|
1,437,156 |
|
|
|
1,337,038 |
|
Other
|
|
|
253,886 |
|
|
|
241,722 |
|
Construction
Work in Progress
|
|
|
77,392 |
|
|
|
200,018 |
|
Total
|
|
|
3,622,756 |
|
|
|
3,459,181 |
|
Accumulated
Depreciation and Amortization
|
|
|
1,191,777 |
|
|
|
1,182,171 |
|
TOTAL
- NET
|
|
|
2,430,979 |
|
|
|
2,277,010 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
186,216 |
|
|
|
158,731 |
|
Long-term
Risk Management Assets
|
|
|
2,652 |
|
|
|
3,358 |
|
Deferred
Charges and Other
|
|
|
59,369 |
|
|
|
48,454 |
|
TOTAL
|
|
|
248,237 |
|
|
|
210,543 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
2,971,827 |
|
|
$ |
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
September
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
125,029 |
|
|
$ |
- |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
98,541 |
|
|
|
189,032 |
|
Affiliated
Companies
|
|
|
74,420 |
|
|
|
80,316 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
50,000 |
|
|
|
- |
|
Risk
Management Liabilities
|
|
|
25,578 |
|
|
|
27,118 |
|
Customer
Deposits
|
|
|
39,498 |
|
|
|
41,477 |
|
Accrued
Taxes
|
|
|
35,282 |
|
|
|
18,374 |
|
Regulatory
Liability for Over-Recovered Fuel Costs
|
|
|
- |
|
|
|
11,697 |
|
Other
|
|
|
46,703 |
|
|
|
57,708 |
|
TOTAL
|
|
|
495,051 |
|
|
|
425,722 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
834,798 |
|
|
|
918,316 |
|
Long-term
Risk Management Liabilities
|
|
|
1,996 |
|
|
|
2,808 |
|
Deferred
Income Taxes
|
|
|
530,293 |
|
|
|
456,497 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
316,521 |
|
|
|
338,788 |
|
Deferred
Credits and Other
|
|
|
48,867 |
|
|
|
55,580 |
|
TOTAL
|
|
|
1,732,475 |
|
|
|
1,771,989 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,227,526 |
|
|
|
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
|
|
|
242,543 |
|
|
|
174,539 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(750 |
) |
|
|
(887 |
) |
TOTAL
|
|
|
739,039 |
|
|
|
640,898 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
2,971,827 |
|
|
$ |
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 Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
69,270 |
|
|
$ |
22,440 |
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
78,079 |
|
|
|
70,128 |
|
Deferred
Income Taxes
|
|
|
70,856 |
|
|
|
23,220 |
|
Deferral
of Ice Storm Costs
|
|
|
(71,610 |
) |
|
|
- |
|
Allowance
for Equity Funds Used During Construction
|
|
|
(1,840 |
) |
|
|
(649 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
6,973 |
|
|
|
7,120 |
|
Change
in Other Noncurrent Assets
|
|
|
9,920 |
|
|
|
(17,754 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
(34,426 |
) |
|
|
(31,165 |
) |
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
21,846 |
|
|
|
(31,617 |
) |
Fuel,
Materials and Supplies
|
|
|
(6,881 |
) |
|
|
(2,110 |
) |
Margin
Deposits
|
|
|
8,554 |
|
|
|
26,461 |
|
Accounts
Payable
|
|
|
(81,228 |
) |
|
|
10,226 |
|
Accrued
Taxes, Net
|
|
|
35,624 |
|
|
|
19,725 |
|
Fuel
Over/Under-Recovery, Net
|
|
|
(47,192 |
) |
|
|
(8,260 |
) |
Other
Current Assets
|
|
|
(1,676 |
) |
|
|
177 |
|
Other
Current Liabilities
|
|
|
(13,883 |
) |
|
|
(25,900 |
) |
Net
Cash Flows from Operating Activities
|
|
|
42,386 |
|
|
|
62,042 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(214,319 |
) |
|
|
(235,089 |
) |
Change
in Advances to Affiliates, Net
|
|
|
51,202 |
|
|
|
- |
|
Other
|
|
|
1,594 |
|
|
|
3,173 |
|
Net
Cash Flows Used for Investing Activities
|
|
|
(161,523 |
) |
|
|
(231,916 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
30,000 |
|
|
|
60,000 |
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
- |
|
|
|
12,488 |
|
Change
in Advances from Affiliates, Net
|
|
|
125,029 |
|
|
|
111,169 |
|
Retirement
of Long-term Debt – Affiliated
|
|
|
(33,700 |
) |
|
|
(12,660 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(1,159 |
) |
|
|
(1,125 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(159 |
) |
|
|
(159 |
) |
Net
Cash Flows from Financing Activities
|
|
|
120,011 |
|
|
|
169,713 |
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
874 |
|
|
|
(161 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,370 |
|
|
|
1,651 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
2,244 |
|
|
$ |
1,490 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
39,739 |
|
|
$ |
34,427 |
|
Net
Cash Received for Income Taxes
|
|
|
44,559 |
|
|
|
18,004 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
403 |
|
|
|
600 |
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
12,251 |
|
|
|
16,358 |
|
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
Third Quarter of 2008
Compared to Third Quarter of 2007
Reconciliation
of Third Quarter of 2007 to Third Quarter of 2008
Net
Income
(in
millions)
Third
Quarter of 2007
|
|
|
|
|
$ |
44 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
11 |
|
|
|
|
|
Transmission
Revenues
|
|
|
3 |
|
|
|
|
|
Other
|
|
|
3 |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(15 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(1 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
4 |
|
|
|
|
|
Other
Income
|
|
|
5 |
|
|
|
|
|
Interest
Expense
|
|
|
(7 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(14 |
) |
|
|
|
|
|
|
|
|
|
Third
Quarter of 2008
|
|
|
|
|
|
$ |
47 |
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income increased $3 million to $47 million in 2008. The key drivers
of the increase were a $17 million increase in Gross Margin, partially offset by
a $14 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 $11 million primarily due to an
increase in wholesale fuel recovery.
|
·
|
Transmission
Revenues increased $3 million due to higher rates in the SPP
region.
|
·
|
Other
revenues increased $3 million primarily due to an 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 changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $15 million primarily due to
the following:
|
|
·
|
A
$14 million increase in distribution expenses primarily due to storm
restoration expenses for Hurricanes Ike and Gustav. SWEPCo intends
to pursue the recovery of these expenses.
|
|
·
|
A
$3 million increase in expense for coal deliveries from SWEPCo’s mining
subsidiary, Dolet Hills Lignite Company, LLC. The increased
expenses for coal deliveries were offset by a corresponding increase in
revenues from mining operations as discussed above.
|
·
|
Taxes
Other Than Income Taxes decreased $4 million primarily due to a $3 million
decrease in state and local franchise tax from refunds related to prior
years.
|
·
|
Other
Income increased $5 million primarily due to higher nonaffiliated interest
income resulting from the fuel under-recovery balance, the Texas state
franchise refund and the Utility Money Pool.
|
·
|
Interest
Expense increased $7 million primarily due to a $10 million increase
related to higher long-term debt outstanding, partially offset by a $3
million increase in the debt component of AFUDC due to new generation
projects.
|
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Reconciliation
of Nine Months Ended September 30, 2007 to Nine Months Ended September 30,
2008
Net
Income
(in
millions)
Nine
Months Ended September 30, 2007
|
|
|
|
|
$ |
55 |
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
38 |
|
|
|
|
|
Transmission
Revenues
|
|
|
7 |
|
|
|
|
|
Other
|
|
|
- |
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
45 |
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(33 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(5 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
5 |
|
|
|
|
|
Other
Income
|
|
|
8 |
|
|
|
|
|
Interest
Expense
|
|
|
(8 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(33 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2008
|
|
|
|
|
|
$ |
66 |
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income increased $11 million to $66 million in 2008. The key drivers
of the increase were a $45 million increase in Gross Margin, partially offset by
a $33 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 $38 million primarily due to higher
fuel recovery resulting from an $18 million refund provision booked in
2007 pursuant to an unfavorable ALJ ruling in the Texas Fuel
Reconciliation proceeding. In addition, an increase of $10
million in wholesale revenue and lower purchase power capacity of $4
million was reflected in 2008.
|
·
|
Transmission
Revenues increased $7 million due to higher rates in the SPP
region.
|
·
|
While
Other revenues in total were unchanged, there was a $12 million decrease
in gains on sales of emission allowances. This decrease was
offset by an $11 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 changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $33 million primarily due to
the following:
|
|
·
|
A
$12 million increase in distribution expenses primarily due to storm
restoration expenses from Hurricanes Ike and Gustav. SWEPCo intends
to pursue the recovery of these expenses.
|
|
·
|
A
$14 million increase in expenses for coal deliveries from SWEPCo’s mining
subsidiary, Dolet Hills Lignite Company, LLC. The increased
expenses for coal deliveries were offset by a corresponding increase in
revenues from mining operations as discussed above.
|
·
|
Depreciation
and Amortization increased $5 million primarily due to higher depreciable
asset balances.
|
·
|
Taxes
Other Than Income Taxes decreased $5 million primarily due to a decrease
in state and local franchise tax from refunds related to prior
years.
|
·
|
Other
Income increased $8 million primarily due to higher nonaffiliated interest
income and an increase in the equity component of AFUDC as a result of new
generation projects.
|
·
|
Interest
Expense increased $8 million primarily due to a $17 million increase from
higher long-term debt outstanding, partially offset by a $7 million
increase in the debt component of AFUDC due to new generation
projects.
|
·
|
Income
Tax Expense increased $1 million primarily due to an increase in pretax
book income, partially offset by state income taxes and changes in certain
book/tax differences accounted for on a flow-through
basis.
|
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, its borrowing costs could increase and access to
borrowed funds could be negatively affected.
Cash
Flow
Cash
flows for the nine months ended September 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
|
|
|
130,250 |
|
|
|
180,146 |
|
Investing
Activities
|
|
|
(619,487 |
) |
|
|
(353,001 |
) |
Financing
Activities
|
|
|
490,247 |
|
|
|
172,089 |
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
1,010 |
|
|
|
(766 |
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
2,752 |
|
|
$ |
1,852 |
|
Operating
Activities
Net Cash
Flows from Operating Activities were $130 million in 2008. SWEPCo
produced Net Income of $66 million during the period and had a noncash expense
item of $109 million for Depreciation and Amortization and $37 million for
Deferred Income Taxes. 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 $99
million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel
costs. The $47 million inflow from Accounts Receivable, Net was
primarily due to the assignment of certain ERCOT contracts to an affiliate
company. The $35 million outflow from Accounts Payable was primarily
due to a decrease in purchased power payables. The $29 million inflow
from Accrued Taxes, Net was due to a refund for the 2007 overpayment of federal
income taxes.
Net Cash
Flows from Operating Activities were $180 million in 2007. SWEPCo
produced Net Income of $55 million during the period and had noncash expense
items of $103 million for Depreciation and Amortization and $24 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 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 $48 million inflow from Accounts Receivable, Net was
primarily due to the assignment of certain ERCOT contracts to an affiliate
company. The $30 million inflow from Margin Deposits was due to
decreased trading-related deposits resulting from normal trading
activities. The $27 million outflow from Fuel Over/Under Recovery,
Net is due to under recovery of higher fuel costs.
Investing
Activities
Net Cash
Flows Used for Investing Activities during 2008 and 2007 were $619 million and
$353 million, respectively. Construction Expenditures of $424 million
and $353 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 $196
million in loans to the Utility Money Pool. For the remainder of
2008, SWEPCo expects construction expenditures to be approximately $250
million.
Financing
Activities
Net Cash
Flows from Financing Activities were $490 million during 2008. SWEPCo
issued $400 million of Senior Unsecured Notes. SWEPCo received a
Capital Contribution from Parent of $100 million. SWEPCo retired $46
million of Nonaffiliated Long-term Debt.
Net Cash
Flows from Financing Activities were $172 million during 2007. SWEPCo
issued $250 million of Senior Unsecured Notes and retired $90 million of First
Mortgage Bonds. SWEPCo received a Capital Contribution from Parent of
$55 million. SWEPCo also reduced its borrowings from the Utility
Money Pool by $33 million.
Financing
Activity
Long-term
debt issuances, retirements and principal payments made during the first nine
months of 2008 were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Senior
Unsecured Notes
|
|
$
|
400,000
|
|
6.45
|
|
2019
|
Pollution
Control Bonds
|
|
|
41,135
|
|
4.50
|
|
2011
|
Retirements and Principal
Payments
|
|
Principal
Amount
Paid
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Notes
Payable – Nonaffiliated
|
|
$
|
1,500
|
|
Variable
|
|
2008
|
Notes
Payable – Nonaffiliated
|
|
|
3,304
|
|
4.47
|
|
2011
|
Pollution
Control Bonds
|
|
|
41,135
|
|
Variable
|
|
2011
|
In
October 2008, SWEPCo retired $113 million of 5.25% Notes Payable due in
2043.
Liquidity
In recent
months, the financial markets have become increasingly unstable and constrained
at both a global and domestic level. This systemic marketplace
distress is impacting SWEPCo’s access to capital, liquidity and cost of
capital. The uncertainties in the credit markets could have
significant implications on SWEPCo since it relies on continuing access to
capital to fund operations and capital expenditures.
SWEPCo
participates in the Utility Money Pool, which provides access to AEP’s
liquidity. SWEPCo has no debt obligations that will mature in the
remainder of 2008 or 2009. To the extent refinancing is unavailable
due to the challenging credit markets, SWEPCo will rely upon cash flows from
operations and access to the Utility Money Pool to fund its current
operations.
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”. Adverse results in these proceedings have the
potential to materially affect net income, financial condition and cash
flows.
See the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries” 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” 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 September 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 September 30, 2008
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
|
Cash
Flow &
Fair
Value Hedges
|
|
|
DETM
Assignment (a)
|
|
|
Collateral
Deposits
|
|
|
Total
|
|
Current
Assets
|
|
$ |
30,804 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(528 |
) |
|
$ |
30,276 |
|
Noncurrent
Assets
|
|
|
3,561 |
|
|
|
- |
|
|
|
- |
|
|
|
(60 |
) |
|
|
3,501 |
|
Total
MTM Derivative Contract Assets
|
|
|
34,365 |
|
|
|
- |
|
|
|
- |
|
|
|
(588 |
) |
|
|
33,777 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(31,197 |
) |
|
|
(90 |
) |
|
|
(130 |
) |
|
|
60 |
|
|
|
(31,357 |
) |
Noncurrent
Liabilities
|
|
|
(2,406 |
) |
|
|
(93 |
) |
|
|
(132 |
) |
|
|
9 |
|
|
|
(2,622 |
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(33,603 |
) |
|
|
(183 |
) |
|
|
(262 |
) |
|
|
69 |
|
|
|
(33,979 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$ |
762 |
|
|
$ |
(183 |
) |
|
$ |
(262 |
) |
|
$ |
(519 |
) |
|
$ |
(202 |
) |
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual
Report.
|
MTM
Risk Management Contract Net Assets (Liabilities)
Nine
Months Ended September 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
|
|
|
(8,169 |
) |
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)
|
|
|
103 |
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(c)
|
|
|
106 |
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
591 |
|
Total
MTM Risk Management Contract Net Assets
|
|
|
762 |
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
(183 |
) |
DETM
Assignment (e)
|
|
|
(262 |
) |
Collateral
Deposits
|
|
|
(519 |
) |
Ending
Net Risk Management Assets (Liabilities) at September 30,
2008
|
|
$ |
(202 |
) |
(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. Inception value is only recorded if observable market
data can be obtained for valuation inputs for the entire contract
term. 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.
|
(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 September 30, 2008
(in
thousands)
|
|
Remainder
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
After
2012
|
|
|
Total
|
|
Level
1 (a)
|
|
$ |
372 |
|
|
$ |
(294 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
78 |
|
Level
2 (b)
|
|
|
10 |
|
|
|
1,467 |
|
|
|
757 |
|
|
|
(122 |
) |
|
|
- |
|
|
|
- |
|
|
|
2,112 |
|
Level
3 (c)
|
|
|
(1,429 |
) |
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,428 |
) |
Total
|
|
$ |
(1,047 |
) |
|
$ |
1,173 |
|
|
$ |
758 |
|
|
$ |
(122 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
762 |
|
(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 September 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
Nine
Months Ended September 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
|
|
|
- |
|
|
|
(204 |
) |
|
|
(204 |
) |
Reclassifications
from AOCI for Cash
Flow Hedges Settled
|
|
|
621 |
|
|
|
(544 |
) |
|
|
77 |
|
Ending
Balance in AOCI September 30, 2008
|
|
$ |
(6,029 |
) |
|
$ |
(119 |
) |
|
$ |
(6,148 |
) |
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 September 30, 2008, a near
term typical change in commodity prices is not expected to have a material
effect on SWEPCo’s net income, 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:
Nine
Months Ended
September
30, 2008
|
|
|
|
|
Twelve
Months Ended
December
31, 2007
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$101
|
|
$220
|
|
$64
|
|
$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 $1.9 million.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
500,484 |
|
|
$ |
445,169 |
|
|
$ |
1,232,017 |
|
|
$ |
1,101,703 |
|
Sales
to AEP Affiliates
|
|
|
11,508 |
|
|
|
2,839 |
|
|
|
42,692 |
|
|
|
35,491 |
|
Other
|
|
|
471 |
|
|
|
502 |
|
|
|
1,164 |
|
|
|
1,437 |
|
TOTAL
|
|
|
512,463 |
|
|
|
448,510 |
|
|
|
1,275,873 |
|
|
|
1,138,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
197,474 |
|
|
|
141,837 |
|
|
|
462,282 |
|
|
|
379,818 |
|
Purchased
Electricity for Resale
|
|
|
50,449 |
|
|
|
73,438 |
|
|
|
145,097 |
|
|
|
182,806 |
|
Purchased
Electricity from AEP Affiliates
|
|
|
36,170 |
|
|
|
22,282 |
|
|
|
108,542 |
|
|
|
61,284 |
|
Other
Operation
|
|
|
64,377 |
|
|
|
59,759 |
|
|
|
186,713 |
|
|
|
163,746 |
|
Maintenance
|
|
|
33,694 |
|
|
|
23,205 |
|
|
|
88,854 |
|
|
|
79,265 |
|
Depreciation
and Amortization
|
|
|
35,842 |
|
|
|
34,605 |
|
|
|
108,875 |
|
|
|
103,395 |
|
Taxes
Other Than Income Taxes
|
|
|
12,623 |
|
|
|
16,767 |
|
|
|
45,747 |
|
|
|
50,298 |
|
TOTAL
|
|
|
430,629 |
|
|
|
371,893 |
|
|
|
1,146,110 |
|
|
|
1,020,612 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
81,834 |
|
|
|
76,617 |
|
|
|
129,763 |
|
|
|
118,019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
5,417 |
|
|
|
518 |
|
|
|
7,834 |
|
|
|
1,999 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
4,152 |
|
|
|
3,681 |
|
|
|
10,167 |
|
|
|
7,634 |
|
Interest
Expense
|
|
|
(22,659 |
) |
|
|
(15,966 |
) |
|
|
(57,071 |
) |
|
|
(48,691 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE AND MINORITY INTEREST
EXPENSE
|
|
|
68,744 |
|
|
|
64,850 |
|
|
|
90,693 |
|
|
|
78,961 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
20,353 |
|
|
|
19,811 |
|
|
|
21,717 |
|
|
|
20,879 |
|
Minority
Interest Expense
|
|
|
976 |
|
|
|
919 |
|
|
|
2,870 |
|
|
|
2,733 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
47,415 |
|
|
|
44,120 |
|
|
|
66,106 |
|
|
|
55,349 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
58 |
|
|
|
58 |
|
|
|
172 |
|
|
|
172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
47,357 |
|
|
$ |
44,062 |
|
|
$ |
65,934 |
|
|
$ |
55,177 |
|
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 Nine Months Ended September 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
|
|
|
|
|
|
|
55,000 |
|
|
|
|
|
|
|
|
|
|
|
55,000 |
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(172 |
) |
|
|
|
|
|
|
(172 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
874,388 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168 |
|
|
|
168 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
55,349 |
|
|
|
|
|
|
|
55,349 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55,517 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
135,660 |
|
|
$ |
300,003 |
|
|
$ |
512,873 |
|
|
$ |
(18,631 |
) |
|
$ |
929,905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
(172 |
) |
|
|
|
|
|
|
(172 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,071,637 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income
(Loss), Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(127 |
) |
|
|
(127 |
) |
Amortization
of Pension and OPEB Deferred Costs, Net of Tax of $380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
706 |
|
|
|
706 |
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
66,106 |
|
|
|
|
|
|
|
66,106 |
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2008
|
|
$ |
135,660 |
|
|
$ |
430,003 |
|
|
$ |
588,519 |
|
|
$ |
(15,860 |
) |
|
$ |
1,138,322 |
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2008 and December 31, 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
2,752 |
|
|
$ |
1,742 |
|
Advances
to Affiliates
|
|
|
195,628 |
|
|
|
- |
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
32,619 |
|
|
|
91,379 |
|
Affiliated
Companies
|
|
|
42,876 |
|
|
|
33,196 |
|
Miscellaneous
|
|
|
12,781 |
|
|
|
10,544 |
|
Allowance
for Uncollectible Accounts
|
|
|
(135 |
) |
|
|
(143 |
) |
Total
Accounts Receivable
|
|
|
88,141 |
|
|
|
134,976 |
|
Fuel
|
|
|
89,408 |
|
|
|
75,662 |
|
Materials
and Supplies
|
|
|
51,565 |
|
|
|
48,673 |
|
Risk
Management Assets
|
|
|
30,276 |
|
|
|
39,850 |
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
81,907 |
|
|
|
5,859 |
|
Margin
Deposits
|
|
|
600 |
|
|
|
10,650 |
|
Prepayments
and Other
|
|
|
38,406 |
|
|
|
28,147 |
|
TOTAL
|
|
|
578,683 |
|
|
|
345,559 |
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
1,756,486 |
|
|
|
1,743,198 |
|
Transmission
|
|
|
771,747 |
|
|
|
737,975 |
|
Distribution
|
|
|
1,364,596 |
|
|
|
1,312,746 |
|
Other
|
|
|
698,764 |
|
|
|
631,765 |
|
Construction
Work in Progress
|
|
|
735,226 |
|
|
|
451,228 |
|
Total
|
|
|
5,326,819 |
|
|
|
4,876,912 |
|
Accumulated
Depreciation and Amortization
|
|
|
1,996,531 |
|
|
|
1,939,044 |
|
TOTAL
- NET
|
|
|
3,330,288 |
|
|
|
2,937,868 |
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
120,858 |
|
|
|
133,617 |
|
Long-term
Risk Management Assets
|
|
|
3,501 |
|
|
|
4,073 |
|
Deferred
Charges and Other
|
|
|
93,126 |
|
|
|
67,269 |
|
TOTAL
|
|
|
217,485 |
|
|
|
204,959 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
4,126,456 |
|
|
$ |
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
September
30, 2008 and December 31, 2007
(Unaudited)
|
|
2008
|
|
|
2007
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
- |
|
|
$ |
1,565 |
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
163,540 |
|
|
|
152,305 |
|
Affiliated
Companies
|
|
|
41,010 |
|
|
|
51,767 |
|
Short-term
Debt – Nonaffiliated
|
|
|
9,519 |
|
|
|
285 |
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
117,809 |
|
|
|
5,906 |
|
Risk
Management Liabilities
|
|
|
31,357 |
|
|
|
32,629 |
|
Customer
Deposits
|
|
|
34,989 |
|
|
|
37,473 |
|
Accrued
Taxes
|
|
|
60,052 |
|
|
|
26,494 |
|
Regulatory
Liability for Over-Recovered Fuel Costs
|
|
|
- |
|
|
|
22,879 |
|
Other
|
|
|
94,559 |
|
|
|
76,554 |
|
TOTAL
|
|
|
552,835 |
|
|
|
407,857 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
1,424,395 |
|
|
|
1,141,311 |
|
Long-term
Debt – Affiliated
|
|
|
50,000 |
|
|
|
50,000 |
|
Long-term
Risk Management Liabilities
|
|
|
2,622 |
|
|
|
3,334 |
|
Deferred
Income Taxes
|
|
|
407,149 |
|
|
|
361,806 |
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
331,985 |
|
|
|
334,014 |
|
Deferred
Credits and Other
|
|
|
214,153 |
|
|
|
210,725 |
|
TOTAL
|
|
|
2,430,304 |
|
|
|
2,101,190 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,983,139 |
|
|
|
2,509,047 |
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
298 |
|
|
|
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
|
|
|
588,519 |
|
|
|
523,731 |
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(15,860 |
) |
|
|
(16,439 |
) |
TOTAL
|
|
|
1,138,322 |
|
|
|
972,955 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
4,126,456 |
|
|
$ |
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 Nine Months Ended September 30, 2008 and 2007
(in
thousands)
(Unaudited)
|
|
2008
|
|
|
2007
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
66,106 |
|
|
$ |
55,349 |
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
108,875 |
|
|
|
103,395 |
|
Deferred
Income Taxes
|
|
|
37,162 |
|
|
|
(17,863 |
) |
Provision
for Fuel Disallowance
|
|
|
- |
|
|
|
24,074 |
|
Allowance
for Equity Funds Used During Construction
|
|
|
(10,167 |
) |
|
|
(7,634 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
7,905 |
|
|
|
7,864 |
|
Deferred
Property Taxes
|
|
|
(9,315 |
) |
|
|
(9,172 |
) |
Change
in Other Noncurrent Assets
|
|
|
9,104 |
|
|
|
10,170 |
|
Change
in Other Noncurrent Liabilities
|
|
|
(17,015 |
) |
|
|
(7,134 |
) |
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
46,835 |
|
|
|
47,992 |
|
Fuel,
Materials and Supplies
|
|
|
(16,665 |
) |
|
|
(11,572 |
) |
Margin
Deposits
|
|
|
10,050 |
|
|
|
29,986 |
|
Accounts
Payable
|
|
|
(34,819 |
) |
|
|
(21,603 |
) |
Accrued
Taxes, Net
|
|
|
29,271 |
|
|
|
25,556 |
|
Fuel
Over/Under-Recovery, Net
|
|
|
(98,928 |
) |
|
|
(26,891 |
) |
Other
Current Assets
|
|
|
(3,121 |
) |
|
|
(687 |
) |
Other
Current Liabilities
|
|
|
4,972 |
|
|
|
(21,684 |
) |
Net
Cash Flows from Operating Activities
|
|
|
130,250 |
|
|
|
180,146 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(424,092 |
) |
|
|
(353,107 |
) |
Change
in Advances to Affiliates, Net
|
|
|
(195,628 |
) |
|
|
- |
|
Other
|
|
|
233 |
|
|
|
106 |
|
Net
Cash Flows Used for Investing Activities
|
|
|
(619,487 |
) |
|
|
(353,001 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
100,000 |
|
|
|
55,000 |
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
437,113 |
|
|
|
247,496 |
|
Change
in Short-term Debt, Net – Nonaffiliated
|
|
|
9,234 |
|
|
|
8,754 |
|
Change
in Advances from Affiliates, Net
|
|
|
(1,565 |
) |
|
|
(33,096 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(45,939 |
) |
|
|
(100,460 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(8,424 |
) |
|
|
(5,433 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(172 |
) |
|
|
(172 |
) |
Net
Cash Flows from Financing Activities
|
|
|
490,247 |
|
|
|
172,089 |
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
1,010 |
|
|
|
(766 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,742 |
|
|
|
2,618 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
2,752 |
|
|
$ |
1,852 |
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
44,255 |
|
|
$ |
44,662 |
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(20,835 |
) |
|
|
37,479 |
|
Noncash
Acquisitions Under Capital Leases
|
|
|
21,807 |
|
|
|
19,567 |
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
94,837 |
|
|
|
41,978 |
|
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 net income, financial position and cash flows for the interim periods for
each Registrant Subsidiary. The net income for the three and nine
months ended September 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 reclassifications had no impact
on the Registrant Subsidiaries’ previously reported net income 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).
In
October 2008, the FASB issued FSP SFAS 157-3 “Determining the Fair Value of a
Financial Asset When the Market for That Asset is Not Active” which clarifies
application of SFAS 157 in markets that are not active and provides an
illustrative example. The FSP was effective upon
issuance. The adoption of this standard had no impact on the
Registrant Subsidiaries’ financial statements.
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. Management
expects that the adoption of FSP SFAS 157-2 will have an immaterial impact on
the financial statements. 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
derivative fair values are verified using broker or dealer quotations, similar
observable market transactions in either the listed or OTC markets, or valued
using 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 September 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 September 30,
2008
APCo
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
7,275 |
|
|
$ |
553,289 |
|
|
$ |
5,005 |
|
|
$ |
(447,811 |
) |
|
$ |
117,758 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
10,120 |
|
|
|
- |
|
|
|
(4,980 |
) |
|
|
5,140 |
|
Dedesignated
Risk Management Contracts (b)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
14,259 |
|
|
|
14,259 |
|
Total
Risk Management Assets
|
|
$ |
7,275 |
|
|
$ |
563,409 |
|
|
$ |
5,005 |
|
|
$ |
(438,532 |
) |
|
$ |
137,157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
10,589 |
|
|
$ |
518,486 |
|
|
$ |
9,646 |
|
|
$ |
(440,158 |
) |
|
$ |
98,563 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
7,976 |
|
|
|
- |
|
|
|
(4,980 |
) |
|
|
2,996 |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,321 |
|
|
|
6,321 |
|
Total
Risk Management Liabilities
|
|
$ |
10,589 |
|
|
$ |
526,462 |
|
|
$ |
9,646 |
|
|
$ |
(438,817 |
) |
|
$ |
107,880 |
|
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of September 30,
2008
CSPCo
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Cash Deposits (e)
|
|
$ |
31,002 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
962 |
|
|
$ |
31,964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
4,083 |
|
|
$ |
286,118 |
|
|
$ |
2,811 |
|
|
$ |
(232,301 |
) |
|
$ |
60,711 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
5,189 |
|
|
|
- |
|
|
|
(2,795 |
) |
|
|
2,394 |
|
Dedesignated
Risk Management Contracts (b)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8,005 |
|
|
|
8,005 |
|
Total
Risk Management Assets
|
|
$ |
4,083 |
|
|
$ |
291,307 |
|
|
$ |
2,811 |
|
|
$ |
(227,091 |
) |
|
$ |
71,110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
35,085 |
|
|
$ |
291,307 |
|
|
$ |
2,811 |
|
|
$ |
(226,129 |
) |
|
$ |
103,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
5,945 |
|
|
$ |
266,791 |
|
|
$ |
5,406 |
|
|
$ |
(227,981 |
) |
|
$ |
50,161 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
4,477 |
|
|
|
- |
|
|
|
(2,795 |
) |
|
|
1,682 |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,549 |
|
|
|
3,549 |
|
Total
Risk Management Liabilities
|
|
$ |
5,945 |
|
|
$ |
271,268 |
|
|
$ |
5,406 |
|
|
$ |
(227,227 |
) |
|
$ |
55,392 |
|
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of September 30,
2008
I&M
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
3,952 |
|
|
$ |
283,053 |
|
|
$ |
2,721 |
|
|
$ |
(230,057 |
) |
|
$ |
59,669 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
5,022 |
|
|
|
- |
|
|
|
(2,705 |
) |
|
|
2,317 |
|
Dedesignated
Risk Management Contracts (b)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,747 |
|
|
|
7,747 |
|
Total
Risk Management Assets
|
|
$ |
3,952 |
|
|
$ |
288,075 |
|
|
$ |
2,721 |
|
|
$ |
(225,015 |
) |
|
$ |
69,733 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spent
Nuclear Fuel and Decommissioning Trusts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents (d)
|
|
$ |
- |
|
|
$ |
3,523 |
|
|
$ |
- |
|
|
$ |
6,328 |
|
|
$ |
9,851 |
|
Debt
Securities (f)
|
|
|
- |
|
|
|
837,141 |
|
|
|
- |
|
|
|
- |
|
|
|
837,141 |
|
Equity
Securities (g)
|
|
|
444,994 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
444,994 |
|
Total Spent Nuclear Fuel and
Decommissioning Trusts
|
|
$ |
444,994 |
|
|
$ |
840,664 |
|
|
$ |
- |
|
|
$ |
6,328 |
|
|
$ |
1,291,986 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
448,946 |
|
|
$ |
1,128,739 |
|
|
$ |
2,721 |
|
|
$ |
(218,687 |
) |
|
$ |
1,361,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
5,754 |
|
|
$ |
264,220 |
|
|
$ |
5,234 |
|
|
$ |
(225,884 |
) |
|
$ |
49,324 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
4,333 |
|
|
|
- |
|
|
|
(2,705 |
) |
|
|
1,628 |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,435 |
|
|
|
3,435 |
|
Total
Risk Management Liabilities
|
|
$ |
5,754 |
|
|
$ |
268,553 |
|
|
$ |
5,234 |
|
|
$ |
(225,154 |
) |
|
$ |
54,387 |
|
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of September 30,
2008
OPCo
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Cash Deposits (e)
|
|
$ |
3,116 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
2,164 |
|
|
$ |
5,280 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
5,059 |
|
|
$ |
582,635 |
|
|
$ |
3,476 |
|
|
$ |
(481,108 |
) |
|
$ |
110,062 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
6,428 |
|
|
|
- |
|
|
|
(3,463 |
) |
|
|
2,965 |
|
Dedesignated
Risk Management Contracts (b)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9,917 |
|
|
|
9,917 |
|
Total
Risk Management Assets
|
|
$ |
5,059 |
|
|
$ |
589,063 |
|
|
$ |
3,476 |
|
|
$ |
(474,654 |
) |
|
$ |
122,944 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
8,175 |
|
|
$ |
589,063 |
|
|
$ |
3,476 |
|
|
$ |
(472,490 |
) |
|
$ |
128,224 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
7,365 |
|
|
$ |
552,724 |
|
|
$ |
6,809 |
|
|
$ |
(476,017 |
) |
|
$ |
90,881 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
6,633 |
|
|
|
- |
|
|
|
(3,463 |
) |
|
|
3,170 |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,396 |
|
|
|
4,396 |
|
Total
Risk Management Liabilities
|
|
$ |
7,365 |
|
|
$ |
559,357 |
|
|
$ |
6,809 |
|
|
$ |
(475,084 |
) |
|
$ |
98,447 |
|
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of September 30,
2008
PSO
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
3,743 |
|
|
$ |
141,674 |
|
|
$ |
3,803 |
|
|
$ |
(121,851 |
) |
|
$ |
27,369 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
Risk Management Assets
|
|
$ |
3,743 |
|
|
$ |
141,674 |
|
|
$ |
3,803 |
|
|
$ |
(121,851 |
) |
|
$ |
27,369 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
3,677 |
|
|
$ |
140,064 |
|
|
$ |
5,010 |
|
|
$ |
(121,399 |
) |
|
$ |
27,352 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
222 |
|
|
|
222 |
|
Total
Risk Management Liabilities
|
|
$ |
3,677 |
|
|
$ |
140,064 |
|
|
$ |
5,010 |
|
|
$ |
(121,177 |
) |
|
$ |
27,574 |
|
Assets
and Liabilities Measured at Fair Value on a Recurring Basis as of September 30,
2008
SWEPCo
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Other
|
|
|
Total
|
|
Assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
4,412 |
|
|
$ |
177,218 |
|
|
$ |
4,481 |
|
|
$ |
(152,334 |
) |
|
$ |
33,777 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
44 |
|
|
|
- |
|
|
|
(44 |
) |
|
|
- |
|
Total
Risk Management Assets
|
|
$ |
4,412 |
|
|
$ |
177,262 |
|
|
$ |
4,481 |
|
|
$ |
(152,378 |
) |
|
$ |
33,777 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
Management Contracts (a)
|
|
$ |
4,334 |
|
|
$ |
175,106 |
|
|
$ |
5,909 |
|
|
$ |
(151,815 |
) |
|
$ |
33,534 |
|
Cash
Flow and Fair Value Hedges (a)
|
|
|
- |
|
|
|
227 |
|
|
|
- |
|
|
|
(44 |
) |
|
|
183 |
|
DETM
Assignment (c)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
262 |
|
|
|
262 |
|
Total
Risk Management Liabilities
|
|
$ |
4,334 |
|
|
$ |
175,333 |
|
|
$ |
5,909 |
|
|
$ |
(151,597 |
) |
|
$ |
33,979 |
|
(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.
|
(f)
|
Amounts
represent corporate, municipal and treasury bonds.
|
(g)
|
Amounts
represent publicly traded equity
securities.
|
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 September 30, 2008
|
|
APCo
|
|
|
CSPCo
|
|
|
I&M
|
|
|
OPCo
|
|
|
PSO
|
|
|
SWEPCo
|
|
|
|
(in
thousands)
|
|
Balance
as of July 1, 2008
|
|
$ |
(18,560 |
) |
|
$ |
(11,122 |
) |
|
$ |
(10,675 |
) |
|
$ |
(13,245 |
) |
|
$ |
(23 |
) |
|
$ |
(45 |
) |
Realized
(Gain) Loss Included in Earnings (or Changes in Net Assets)
(a)
|
|
|
4,466 |
|
|
|
2,670 |
|
|
|
2,561 |
|
|
|
3,287 |
|
|
|
4 |
|
|
|
13 |
|
Unrealized
Gain (Loss) Included in Earnings (or Changes in Net Assets) Relating to
Assets Still Held at the Reporting Date (a)
|
|
|
- |
|
|
|
(1,317 |
) |
|
|
- |
|
|
|
(1,574 |
) |
|
|
- |
|
|
|
26 |
|
Realized
and Unrealized Gains (Losses) Included in Other Comprehensive
Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Purchases,
Issuances and Settlements
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Transfers
in and/or out of Level 3 (b)
|
|
|
5,595 |
|
|
|
3,360 |
|
|
|
3,228 |
|
|
|
3,914 |
|
|
|
(1,249 |
) |
|
|
(1,471 |
) |
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
3,858 |
|
|
|
3,814 |
|
|
|
2,373 |
|
|
|
4,285 |
|
|
|
61 |
|
|
|
49 |
|
Balance
as of September 30, 2008
|
|
$ |
(4,641 |
) |
|
$ |
(2,595 |
) |
|
$ |
(2,513 |
) |
|
$ |
(3,333 |
) |
|
$ |
(1,207 |
) |
|
$ |
(1,428 |
) |
Nine
Months Ended September 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)
|
|
|
332 |
|
|
|
88 |
|
|
|
105 |
|
|
|
1,063 |
|
|
|
170 |
|
|
|
290 |
|
Unrealized
Gain (Loss) Included in Earnings (or Changes in Net Assets) Relating to
Assets Still Held at the Reporting Date (a)
|
|
|
- |
|
|
|
190 |
|
|
|
- |
|
|
|
126 |
|
|
|
- |
|
|
|
56 |
|
Realized
and Unrealized Gains (Losses) Included in Other Comprehensive
Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Purchases,
Issuances and Settlements
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Transfers
in and/or out of Level 3 (b)
|
|
|
(731 |
) |
|
|
(454 |
) |
|
|
(430 |
) |
|
|
(244 |
) |
|
|
(1,249 |
) |
|
|
(1,472 |
) |
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(3,545 |
) |
|
|
(2,156 |
) |
|
|
(1,908 |
) |
|
|
(2,671 |
) |
|
|
115 |
|
|
|
106 |
|
Balance
as of September 30, 2008
|
|
$ |
(4,641 |
) |
|
$ |
(2,595 |
) |
|
$ |
(2,513 |
) |
|
$ |
(3,333 |
) |
|
$ |
(1,207 |
) |
|
$ |
(1,428 |
) |
(a)
|
Included
in revenues on the Condensed Statements 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.
|
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. 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.” Management expects the adoption of this standard will
have no impact on the Registrant Subsidiaries’ 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.
EITF
Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value
with a Third-Party Credit Enhancement” (EITF
08-5)
|
In
September 2008, the FASB ratified the EITF consensus on liabilities with
third-party credit enhancements when the liability is measured and disclosed at
fair value. The consensus treats the liability and the credit
enhancement as two units of accounting. Under the consensus, the fair
value measurement of the liability does not include the effect of the
third-party credit enhancement. Consequently, changes in the issuer’s
credit standing without the support of the credit enhancement affect the fair
value measurement of the issuer’s liability. Entities will need to
provide disclosures about the existence of any third-party credit enhancements
related to their liabilities.
EITF 08-5
is effective for the first reporting period beginning after December 15,
2008. It will be applied prospectively upon adoption with the effect
of initial application included as a change in fair value of the liability in
the period of adoption. In the period of adoption, entities must
disclose the valuation method(s) used to measure the fair value of liabilities
within its scope and any change in the fair value measurement method that occurs
as a result of its initial application. Early adoption is
permitted. Although management has not completed an analysis,
management expects that the adoption of this standard will have an immaterial
impact on the financial statements. The Registrant Subsidiaries will
adopt this standard effective January 1, 2009.
FSP
SFAS 133-1 and FIN 45-4 “Disclosures about Credit Derivatives and Certain
Guarantees: An Amendment of FASB Statement No.133 and FASB Interpretation
No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (SFAS
133-1 and FIN 45-4)
In
September 2008, the FASB issued SFAS 133-1 and FIN 45-4 as amendments to
original statements SFAS 133 and FIN 45 “Guarantor’s Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others.” Under the SFAS 133 requirements, the seller of a credit derivative
shall disclose the following information for each derivative, including credit
derivatives embedded in a hybrid instrument, even if the likelihood of payment
is remote:
(a)
|
The
nature of the credit derivative.
|
(b)
|
The
maximum potential amount of future payments.
|
(c)
|
The
fair value of the credit derivative.
|
(d)
|
The
nature of any recourse provisions and any assets held as collateral or by
third parties.
|
Further,
the standard requires the disclosure of current payment status/performance risk
of all FIN 45 guarantees. In the event an entity uses internal
groupings, the entity shall disclose how those groupings are determined and used
for managing risk.
The
standard is effective for interim and annual reporting periods ending after
November 15, 2008. Upon adoption, the guidance will be prospectively
applied. Management expects that the adoption of this standard will
have an immaterial impact on the financial statements but increase
the FIN 45 guarantees disclosure requirements. The
Registrant Subsidiaries will adopt the standard effective December 31,
2008.
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.
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 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
September 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
September 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
September 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
September 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
September 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
September 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 September 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:
|
September
30, 2008
|
|
|
Cash
Collateral
|
|
Cash
Collateral
|
|
|
Received
|
|
Paid
|
|
|
Netted
Against
|
|
Netted
Against
|
|
|
Risk
Management
|
|
Risk
Management
|
|
|
Assets
|
|
Liabilities
|
|
|
(in
thousands)
|
|
APCo
|
|
$ |
8,250 |
|
|
$ |
597 |
|
CSPCo
|
|
|
4,631 |
|
|
|
311 |
|
I&M
|
|
|
4,482 |
|
|
|
309 |
|
OPCo
|
|
|
5,747 |
|
|
|
656 |
|
PSO
|
|
|
499 |
|
|
|
47 |
|
SWEPCo
|
|
|
588 |
|
|
|
69 |
|
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,
consolidation policy, 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 net income 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
net income, 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 after the PUCO approves a
MRO. The PUCO has the authority to approve or modify each utilities’
ESP request. The PUCO is required to approve an ESP if, in the
aggregate, the ESP is more favorable to ratepayers than a 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 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 and purchased power 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 an
optional MRO. 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 (which excludes off-system
sales) 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-purchased power cost recovery
mechanism would be phased-in over the three year period from 2009 through
2011. If the ESP is approved as filed, effective with January 2009
billings, CSPCo and OPCo will defer any fuel cost under-recoveries and related
carrying costs for future recovery. The under-recoveries and related
carrying costs that exist at the end of 2011 will be recovered 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 distribution reliability costs and for unexpected
non-fuel generation costs. The filings also include programs for
smart metering initiatives and economic development and mandated energy
efficiency and peak demand reduction programs. In September 2008, the
PUCO issued a finding and order tentatively adopting rules governing MRO and ESP
applications. CSPCo and OPCo filed their ESP applications based on
proposed rules and requested waivers for portions of the proposed
rules. The PUCO denied the waiver requests in September 2008 and
ordered CSPCo and OPCo to submit information consistent with the tentative
rules. In October 2008, CSPCo and OPCo submitted additional
information related to proforma financial statements and information concerning
CSPCo and OPCo’s fuel procurement process. In October 2008, CSPCo and
OPCo filed an application for rehearing with the PUCO to challenge certain
aspects of the proposed rules.
Within
the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $46
million and $38 million, respectively, for customer choice implementation and
line extension carrying costs. In addition, CSPCo and OPCo would
recover related unrecorded equity carrying costs of $30 million and $21 million,
respectively. Such costs would be recovered over an 8-year period
beginning January 2011. Hearings are scheduled for November 2008 and
an order is expected in the fourth quarter of 2008. If an order is
not received prior to January 1, 2009, CSPCo and OPCo have requested
retroactive application of the new rates back to January 1, 2009 upon
approval. Failure of the PUCO to ultimately approve the recovery of
the regulatory assets would have an adverse effect on future net income 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 during the first quarter of
2008 of $12 million and $14 million, respectively, related to the future
recovery of increased PJM billings previously expensed from June 2007 to
December 2007 for transmission line losses. 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 recoveries are under/over actual net costs, CSPCo and
OPCo will defer the difference as a regulatory asset or regulatory liability and
adjust future customer billings to reflect actual costs, including carrying
costs on the 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.
Also, 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. Upon PUCO approval of an unrelated amendment to the Ormet
contract, Ormet withdrew its rehearing application in August 2008.
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 and incurred $11 million in
pre-construction costs. As a result, CSPCo and OPCo each established
a net regulatory liability of approximately $1 million.
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 cost recoveries 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. In September 2008, the Ohio Consumers’
Counsel filed a motion with the PUCO requesting all Phase 1 costs be refunded to
Ohio ratepayers with interest because the Ohio Supreme Court invalidated the
underlying foundation for the Phase 1 recovery. CSPCo and OPCo filed
a motion with the PUCO that argued the Ohio Consumers’ Counsel’s motion was
without legal merit and contrary to past precedent. 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 net income and cash
flows.
As of
December 31, 2007, the cost of the plant was estimated at $2.7
billion. The estimated cost of the plant has continued to increase
significantly. Management continues to pursue the ultimate
construction of the IGCC plant. CSPCo and OPCo will not start
construction of the IGCC plant until sufficient assurance of regulatory cost
recovery exists.
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 $8 million of this regulatory liability to income for the
nine months ended September 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 2008 market price. If the PUCO approves a market
price for 2008 below $47.69, it could have an adverse effect on future net
income 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.
Hurricane
Ike – Affecting CSPCo and OPCo
In
September 2008, the service territories of CSPCo and OPCo were impacted by
strong winds from the remnants of Hurricane Ike. CSPCo and OPCo
incurred approximately $18 million and $13 million, respectively, in incremental
distribution operation and maintenance costs related to service restoration
efforts. Under the current RSP, CSPCo and OPCo can seek a
distribution rate adjustment to recover incremental distribution expenses
related to major storm service restoration efforts. In September
2008, CSPCo and OPCo established regulatory assets of $17 million and $10
million, respectively, for the incremental distribution operation and
maintenance costs related to major storm service restoration
efforts. The regulatory assets represent the excess above the average
of the last three years of distribution storm expenses excluding Hurricane Ike,
which was the methodology used by the PUCO to determine the recoverable amount
of storm restoration expenses in the most recent 2006 PUCO storm damage recovery
decision. Prior to December 31, 2008, which is the expiration of the
RSP, CSPCo and OPCo will file for recovery of the regulatory
assets. As a result of the past favorable treatment of storm
restoration costs and the favorable RSP provisions, management believes the
recovery of the regulatory assets is probable. If these regulatory
assets are not recoverable, it would have an adverse effect on future net income
and cash flows.
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. This 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%. Hearings began in October 2008. As permitted under
Virginia law, APCo implemented these new base rates, subject to refund,
effective October 28, 2008.
In
September 2008, the Attorney General’s office filed testimony recommending the
proposed $208 million annual increase in base rate be reduced to $133
million. The decrease is principally due to the use of a return on
equity approved in the last base rate case of 10% and various rate base and
operating income adjustments, including a $25 million proposed disallowance of
capacity equalization charges payable by APCo as a deficit member of the FERC
approved AEP Power Pool.
In
October 2008, the Virginia SCC staff filed testimony recommending the proposed
$208 million annual increase in base rate be reduced to $157
million. The decrease is principally due to the use of a recommended
return on equity of 10.1%. In October 2008, hearings were
held in which APCo filed a $168 million settlement agreement which was
accepted by all parties except one industrial customer. APCo expects
to receive a final order from the Virginia SCC in November 2008.
Virginia
E&R Costs Recovery Filing – Affecting APCo
As of
September 2008, APCo has $118 million of deferred Virginia incremental E&R
costs (excluding $25 million of unrecognized equity carrying
costs). The $118 million consists of $6 million already approved by
the Virginia SCC to be collected during the fourth quarter 2008, $54 million
relating to APCo’s May 2008 filing for recovery in 2009, and $58 million,
representing costs deferred in 2008 to date, to be included (along with the
fourth quarter 2008 E&R deferrals) in the 2009 E&R filing, to be
collected in 2010.
In
September 2008, a settlement was reached between the parties to the 2008 filing
and a stipulation agreement (stipulation) was submitted to the hearing
examiner. The stipulation provides for recovery of $61 million of
incremental E&R costs in 2009 which is an increase of $12 million over the
level of E&R surcharge revenues being collected in 2008. The
stipulation included an unfavorable $1 million adjustment related to certain
costs considered not recoverable E&R costs and recovery of $4.5 million
representing one-half of a $9 million Virginia jurisdictional portion of NSR
settlement expenses recorded in 2007. In accordance with the
stipulation, APCo will request the remaining one-half of the $9 million of NSR
settlement expenses in APCo’s 2009 E&R filing. The stipulation
also specifies that APCo will remove $3 million of the $9 million of NSR
settlement expenses requested to be recovered over 3 years in the current base
rate case from the base rate case’s revenue requirement.
In
September 2008, the hearing examiner recommended that the Virginia SCC accept
the stipulation. As a result, in September 2008, APCo deferred as a
regulatory asset $9 million of NSR settlement expenses it had expensed in 2007
that have become probable of future recovery. In October 2008, the
Virginia SCC approved the stipulation which will have a favorable effect on 2009
future cash flows of $61 million and on net income for the previously
unrecognized equity costs of approximately $11 million. If the
Virginia SCC were to disallow a material portion of APCo’s 2008 deferral, it
would have an adverse effect on future net income and 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. The adjusted factor increases annual fuel clause 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 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. In August 2008, the Virginia SCC issued an order to allow APCo
to implement the increased fuel factor on an interim basis for services rendered
after August 2008. In September 2008, the Virginia SCC staff filed
testimony recommending a lower fuel factor which will result in an annualized
increase of $117 million, which includes the PJM transmission line loss costs,
instead of APCo’s proposed $132 million. In October 2008, the
Virginia SCC ordered an annualized increase of $117 million for services
rendered on and after October 20, 2008.
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
September 30, 2008, APCo has deferred for future recovery pre-construction IGCC
costs of approximately $9 million allocated to Virginia jurisdictional
operations.
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 allocated $134
million in future tax credits to APCo for the planned IGCC plant contingent upon
the commencement of construction, qualifying expense being incurred and
certification of the IGCC plant prior to July 2010. Although
management continues to pursue the construction of the IGCC plant, APCo will not
start construction of the IGCC plant until sufficient assurance of cost recovery
exists. If the plant is cancelled, APCo plans to seek recovery of its
prudently incurred deferred pre-construction costs. If the plant is
cancelled and if the deferred costs are not recoverable, it would have an
adverse effect on future net income and cash flows.
Mountaineer
Carbon Capture Project – Affecting APCo
In
January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party,
entered into an agreement to jointly construct a CO2 capture
facility. APCo and Alstom will each own part of the CO2 capture
facility. APCo will also construct and own the necessary facilities
to store the CO2. APCo’s
estimated cost for its share of the facilities is $76
million. Through September 30, 2008, APCo incurred $13 million in
capitalized project costs which is included in Regulatory
Assets. APCo plans to seek recovery for the CO2 capture
and storage project costs in its next Virginia and West Virginia base rate
filings which are expected to be filed in 2009. APCo is presently
seeking a return on the capitalized project costs in its current Virginia base
rate filing. The Attorney General has recommended that the project
costs should be shared by all affiliated operating companies with coal-fired
generation plants. If a significant portion of the project costs are
excluded from base rates and ultimately disallowed in Virginia and/or West
Virginia, it could have an adverse effect on future net income 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 rate increases,
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 if
actual costs exceed the recoveries due to the deferral of any
over/under-recovery of ENEC costs. The construction cost and
reliability surcharges are not subject to a true-up to actual costs and could
impact future net income and cash flows.
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. Also, in March 2008, various
intervenors filed petitions with the WVPSC to reconsider the
order. No action has been taken on the requests for
rehearing. At the time of the filing, the cost of the plant was
estimated at $2.2 billion. As of September 30, 2008, the estimated
cost of the plant has continued to significantly increase. In July
2008, based on the unfavorable 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 September 30, 2008, APCo deferred for future
recovery pre-construction IGCC costs of approximately $9 million applicable to
the West Virginia jurisdiction and approximately $2 million applicable to the
FERC jurisdiction. In July 2008, the
IRS allocated $134 million in future tax credits to APCo for the planned IGCC
plant. Although management continues to pursue the ultimate
construction of the IGCC plant, APCo will not start construction of the IGCC
plant until sufficient assurance of cost recovery exists. If the plant is
cancelled, APCo plans to seek recovery of its prudently incurred deferred
pre-construction costs. If the plant is cancelled and if the deferred
costs are not recoverable, it would have an adverse effect on future net income
and cash flows.
Indiana Rate
Matters
Indiana Base
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 and will
adversely affect cash flows when tariff rates are revised to reflect the effect
of the depreciation expense reduction. The filing also 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.
In
September 2008, the Indiana Office of Utility Consumer Counselor (OUCC) and the
Industrial Customer Coalition filed testimony recommending a $14 million and $37
million decrease in revenue, respectively. Two other intervenors
filed testimony on limited issues. The OUCC and the Industrial
Customer Coalition recommended that the IURC reduce the ROE proposed by I&M,
reduce or limit the amount of off-system sales margin sharing, deny the recovery
of reliability enhancement costs and reject the proposed environmental
compliance cost recovery trackers. In October 2008, I&M filed
testimony rebutting the recommendations of the OUCC. Hearings are
scheduled for December 2008. A decision is expected from the IURC by
June 2009.
Michigan Rate
Matters
Michigan
Restructuring – Affecting I&M
Although
customer choice commenced for I&M’s Michigan customers on January 1, 2002,
I&M’s rates for generation in Michigan continued to be cost-based regulated
because none of I&M's customers elected to change suppliers and no
alternative electric suppliers were registered to compete in I&M's Michigan
service territory. In October 2008, the Governor of Michigan signed
legislation to limit customer choice load to no more than 10% of the annual
retail load for the preceding calendar year and to require the remaining 90% of
annual retail load to be phased into cost-based rates. The new legislation
also requires utilities to meet certain energy efficiency and renewable
portfolio standards and requires cost recovery of meeting those
standards. Management continues to conclude that I&M's rates for
generation in Michigan are cost-based regulated.
Oklahoma Rate
Matters
PSO
Fuel and Purchased Power – Affecting PSO
The
Oklahoma Industrial Energy Consumers appealed an ALJ recommendation in June 2008
regarding a pending fuel case involving the reallocation of $42 million of
purchased power costs among AEP West companies in 2002. The Oklahoma
Industrial Energy Consumers requested that PSO be required to refund this $42
million of reallocated purchased power costs through its fuel
clause. PSO had recovered the $42 million during the period June 2007
through May 2008. In August 2008, the OCC heard the appeal and a
decision is pending.
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 previously was determined not to be jurisdictional to the
OCC. See “Allocation of Off-system Sales Margins” section within
“FERC Rate Matters”. Consistent with the prior OCC determination, the
ALJ found that the OCC lacked authority to alter the FERC-approved allocation
methodology and that PSO’s fuel costs were prudent. The intervenors
appealed the ALJ recommendation and the OCC heard the appeal in August
2008. In August 2008, the OCC filed a complaint at the FERC alleging
that AEPSC inappropriately allocated off-system trading margins between the AEP
East companies and the AEP West companies and did not properly allocate
off-system trading margins within the AEP West companies.
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. In August 2008, the OCC issued
a final order that PSO’s calculations of fuel and purchased power costs were
accurate and are consistent with PSO’s fuel tariff.
In
September 2008, the OCC initiated a review of PSO’s generation, purchased power
and fuel procurement processes and costs for 2007. Under the OCC
minimum filing requirements, PSO is required to file testimony and supporting
data within 60 days which will occur in the fourth quarter of
2008. Management cannot predict the outcome of the pending fuel and
purchased power cost recovery filings or prudence reviews. However,
PSO believes its fuel and purchased power procurement practices and costs were
prudent and properly incurred and therefore are legally
recoverable.
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 pre-approval to construct the coal-fired Red Rock Generating
Facility (Red Rock) 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
pre-approval. The OCC stated that PSO failed to fully study other
alternatives to a coal-fired plant. Since PSO and OG&E could not
obtain pre-approval to build Red Rock, PSO and OG&E cancelled the third
party construction contract and their joint venture development
contract. In June 2008, PSO 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 $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 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. In July 2008, PSO filed a base rate case which included $11
million of deferred Red Rock costs plus carrying charges at PSO’s AFUDC rate
beginning in March 2008. See “2008 Oklahoma Base Rate Filing” section
below.
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 the December 2007 ice
storm.
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. The settlement also provided for PSO to 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 actual
costs. After the true-up, application of proceeds from to-date sales
of excess SO2 emission
allowances and carrying costs, the ice storm regulatory asset was $64
million. 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. In July 2008, as required by the settlement
agreement, PSO filed its reconciliation of the December 2007 storm restoration
costs along with a proposed tariff to recover the amounts not offset by the
sales of SO2 emission
allowances. In September 2008, the OCC staff filed testimony
supporting PSO’s filing with minor changes. In October 2008, an ALJ
recommended that PSO recover $62 million of the December 2007 storm restoration
costs before consideration of emission allowance gains and carrying
costs. In October 2008, the OCC approved the filing which allows PSO
to recover $62 million of the December 2007 storm restoration costs beginning in
November 2008.
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 costs, 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 actually $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 base rates to become effective in the
first quarter of 2009. In October 2008, the OCC staff, the Attorney
General's office, and a group of industrial customers filed testimony
recommending annual base rate increases of $86 million, $68 million and $29
million, respectively. The differences are principally due to the use of
recommended return on equity of 10.88%, 10% and 9.5% by the OCC staff, the
Attorney General's office, and a group of industrial customers. The OCC
staff and the Attorney General's office recommended $22 million and $8 million,
respectively, of costs included in the filing be recovered through the fuel
adjustment clause and riders outside of base rates.
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. Under the plan, beginning in 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 deferred 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 August 2008, the LPSC issued
an order approving the settlement.
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 accordance with the settlement, SWEPCo recorded
a $4 million regulatory liability related to the reduction in generation
depreciation rates. The amount of the unamortized regulatory
liability for the reduction in generation depreciation was $4 million as of
September 30, 2008. In August 2008, SWEPCo implemented the FRP rates,
subject to refund, as the LPSC staff reviews SWEPCo’s FRP filing and the
production depreciation study.
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 currently
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 September 2008, the LPSC approved
SWEPCo’s request for certification to construct 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 September 30, 2008, SWEPCo has capitalized
pre-construction costs of $158 million and has contractual construction
commitments of an additional $145 million. As of September 30, 2008,
if the plant had been cancelled, cancellation fees of $61 million would have
been required in order to terminate these construction
commitments. If SWEPCo cancels the plant and cannot recover its
capitalized costs, including any cancellation fees, it would have an adverse
effect on future net income, cash flows and possibly financial
condition.
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 currently
estimated to cost $1.5 billion, excluding AFUDC, with SWEPCo’s portion estimated
to cost $1.1 billion. 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 August
2008, the PUCT issued an order approving the Turk Plant with the following four
conditions: (a) the capping of capital costs for the Turk Plant at the $1.5
billion projected construction cost, excluding AFUDC, (b) capping CO2 emission
costs at $28 per ton through the year 2030, (c) holding Texas ratepayers
financially harmless from any adverse impact related to the Turk Plant not being
fully subscribed to by other utilities or wholesale customers and (d) providing
the PUCT all updates, studies, reviews, reports and analyses as previously
required under the Louisiana and Arkansas orders. An intervenor filed
a motion for rehearing seeking reversal of the PUCT’s
decision. SWEPCo filed a motion for rehearing stating that the two
cost cap restrictions are unlawful. In September 2008, the motions
for rehearing were denied. In October 2008, SWEPCo appealed the
PUCT’s order regarding the two cost cap restrictions. If the cost cap
restrictions are upheld and construction or emissions costs exceed the
restrictions, it could have a material adverse impact on future net income and
cash flows. In October 2008, an intervenor filed an appeal contending
that the PUCT’s grant of a conditional Certificate of Public Convenience and
Necessity for the Turk Plant was not necessary to serve retail
customers.
SWEPCo is
also working with the Arkansas Department of Environmental Quality for the
approval of an air permit and the U.S. Army Corps of Engineers for the
approval of a wetlands and stream impact permit. Once SWEPCo receives the
air permit, they will commence construction. 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.
In
January 2008 and July 2008, SWEPCo filed applications for authority with the
APSC to construct transmission lines necessary for service from the Turk
Plant. Several landowners filed for intervention status and one
landowner also contended he should be permitted to re-litigate Turk Plant
issues, including the need for the generation. The APSC granted their
intervention but denied the request to re-litigate the Turk Plant
issues. The landowner filed an appeal to the Arkansas State Court of
Appeals in June 2008.
The
Arkansas Governor’s Commission on Global Warming is scheduled to issue its final
report to the Governor by November 1, 2008. The Commission was
established to set a global warming pollution reduction goal together with a
strategic plan for implementation in Arkansas. If legislation is
passed as a result of the findings in the Commission’s report, it could impact
SWEPCo’s proposal to build the Turk Plant.
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 September 30, 2008, SWEPCo has capitalized
approximately $448 million of expenditures and has significant contractual
construction commitments for an additional $771 million. As of
September 30, 2008, if the plant had been cancelled, SWEPCo would have incurred
cancellation fees of $61 million. If the Turk Plant does not receive
all necessary approvals on reasonable terms and SWEPCo cannot recover its
capitalized costs, including any cancellation fees, it would have an adverse
effect on future net income, 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 retail 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, based on advice of legal
counsel, 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, based on anticipated settlements, the AEP East companies provided reserves
for net refunds for current and future SECA settlements totaling $37 million and
$5 million in 2006 and 2007, respectively, applicable to a total of $220 million
of SECA revenues. 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 |
|
AEP has
completed settlements totaling $7 million applicable to $75 million of SECA
revenues. The balance in the reserve for future settlements as of
September 2008 was $35 million. In-process settlements total $3
million applicable to $37 million of SECA revenues. Management
believes that the available $32 million of reserves for possible refunds are
sufficient to settle the remaining $108 million of contested SECA
revenues.
If the
FERC adopts the ALJ’s decision and/or AEP cannot settle all of the remaining
unsettled claims within the remaining amount reserved for refund, it will have
an adverse effect on future net income 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 $32 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 necessary.
The FERC PJM Regional
Transmission Rate Proceeding
With the
elimination of T&O rates, the expiration of SECA rates and after
considerable administrative litigation at the FERC in which AEP sought to
mitigate the effect of the 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 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, net income and cash flows.
The AEP
East companies filed for and in 2006 obtained increases in their 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 80% 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 net income and cash flows will
continue to be adversely affected in Indiana and Michigan until the remaining
20% 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 argued 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 of time due to regulatory lag until the AEP East companies 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 by $63 million
annually. 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. The remaining $54 million requested would be billed to the AEP
East companies to be recovered in retail rates. Retail rates for
jurisdictions other than Ohio are not affected until the next base rate filing
at FERC. Retail rates for CSPCo and OPCo would be adjusted through
the Transmission Cost Recovery Rider (TCRR) totaling approximately $10 million
and $12 million, respectively. The TCRR includes a true-up mechanism
so CSPCo’s and OPCo’s net income will not be adversely affected by a FERC
ordered transmission rate increase. Other jurisdictions would be
recoverable on a lag basis as base rates are changed. AEP requested
an effective date of October 1, 2008. In September 2008, the FERC
issued an order conditionally accepting AEP’s proposed formula rate, subject to
a compliance filing, suspended the effective date until March 1, 2009 and
established a settlement proceeding with an ALJ. 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 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, beginning in February
2008. If the final refund exceeds the provisions it would
adversely affect future net income and cash flows. 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 requested 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. In September 2008, the FERC issued
an order accepting AEP’s market-based rates with minor changes and rejected the
PUCO’s and the industrial retail customers’ suggestions to further investigate
AEP’s lack of market power.
In an
unrelated matter, in May 2008, the FERC issued an order in response to a
complaint from the state of Maryland’s Public Service Commission to hold a
future hearing to review the structure of the three pivotal market power
supplier tests in PJM. In September 2008, PJM filed a report on the
results of the PJM stakeholder process concerning the three pivotal supplier
market power tests which recommended the FERC not make major revisions to the
test because the test is not unjust or unreasonable.
The
FERC’s order will become final if no requests for rehearing are
filed. If a request for rehearing is filed and ultimately results in
a further investigation by the FERC which 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 and cash flows.
Allocation
of Off-system Sales Margins – Affecting APCo, CSPCo, I&M, OPCo, PSO and
SWEPCo
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 the 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 net income and cash flows for AEP
Consolidated, the AEP East companies and the AEP West 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. In June 2008, the Oklahoma Industrial
Energy Consumers appealed the ALJ recommendation to the OCC. In
August 2008, the OCC heard the appeal and a decision is pending. See
“PSO Fuel and Purchased Power” section within “Oklahoma Rate
Matters”. In August 2008, the OCC filed a complaint at the FERC
alleging that AEPSC inappropriately allocated off-system trading margins between
the AEP East companies and the AEP West companies and did not properly allocate
off-system trading margins within the AEP West companies. The PUCT,
the APSC and the Oklahoma Industrial Energy Consumers have all intervened in
this filing.
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 the final
fuel reconciliation in Texas under the restructuring
legislation. 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.
Management
cannot predict the outcome of these proceedings. However, 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. The results of these proceedings could
have an adverse effect on future net income and cash flows for AEP Consolidated,
the AEP East companies and the AEP West companies.
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 which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $46 million following its bankruptcy.
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 which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $23 million and $12 million, respectively, following its
bankruptcy. As of September 30, 2008, $372 million of letters of
credit were issued by Registrant Subsidiaries under the 3-year credit agreement
to support variable rate demand notes.
At
September 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 September 30, 2008, SWEPCo collected approximately $37
million through a rider for final mine closure costs, of which approximately $7
million is recorded in Other Current Liabilities and $30 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 September 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 Registrant Subsidiaries
have 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
September 30, 2008, the maximum potential loss by Registrant 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 $20
million for I&M and $23 million for SWEPCo as of September 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) assuming the fair
market value of the equipment is zero at the end of the current lease
term. 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. In October 2008, the court
approved a consent decree for a settlement reached with the Sierra Club in a
case involving 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. Under the terms of the settlement, the joint-owners agreed
to certain emission targets related to NOx, SO2 and
PM. They also agreed to make energy efficiency and renewable energy
commitments that are conditioned on receiving PUCO approval for recovery of
costs. The joint-owners also agreed to forfeit 5,500 SO2 allowances
and provide $300 thousand to a third party organization to establish
a solar water heater rebate program. 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.
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. In October 2008, TCEQ approved the
settlement.
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 net income, 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 U.S. 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. The defendants filed
motions to dismiss the action. The motions are pending before the
court. 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 issued a decision that would vacate the CAIR and remand
the rule to the Federal EPA. In September 2008, the Federal EPA and
other parties petitioned for rehearing. Management is unable to
predict the outcome of the rehearing petitions or 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 $9 million of
annual CAIR NOx allowances
which are included in Deferred Charges and Other as of September 30,
2008. The market value of annual CAIR NOx allowances
decreased following this court decision. However, the
weighted-average cost of these allowances is below market. If CAIR
remains vacated, management intends to seek partial recovery of the cost of
purchased allowances. Any unrecovered portion would have an adverse
effect on future net income 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 state
implementation plan (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 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. I&M recorded
approximately $4 million of expense through September 30, 2008. 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.
Cook
Plant Unit 1 Fire and Shutdown – Affecting I&M
Cook
Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in
Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine
vibrations likely caused by blade failure which resulted in a fire on the
electric generator. This equipment is in the turbine building and is
separate and isolated from the nuclear reactor. The steam turbines
that caused the vibration were installed in 2006 and are under warranty from the
vendor. The warranty provides for the replacement of the turbines if
the damage was caused by a defect in the design or assembly of the
turbines. I&M is also working with its insurance company, Nuclear
Electric Insurance Limited (NEIL), and turbine vendor to evaluate the
extent of the damage resulting from the incident and the costs to return the
unit to service. Management cannot estimate the ultimate costs of the
outage at this time. Management believes that I&M should recover a
significant portion of these costs through the turbine vendor’s warranty,
insurance and the regulatory process. Management's preliminary
analysis indicates that Unit 1 could resume operations as early as late first
quarter/early second quarter of 2009 or as late as the second half of 2009,
depending upon whether the damaged components can be repaired or whether they
need to be replaced.
I&M
maintains property insurance through NEIL with a $1 million
deductible. I&M also maintains a separate accidental outage
policy with NEIL whereby, after a 12 week deductible period, I&M is entitled
to weekly payments of $3.5 million during the outage period for a covered
loss. If the ultimate costs of the incident are not covered by
warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.
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.
Rail
Transportation Litigation – Affecting PSO
In
October 2008, the Oklahoma Municipal Power Authority and the Public Utilities
Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed
a lawsuit in United States District Court, Western District of Oklahoma against
AEP alleging breach of contract and breach of fiduciary duties related to
negotiations for rail transportation services for the plant. The
plaintiffs allege that AEP took the duty of the project manager, PSO, and
operated the plant for the project manager and is therefore responsible for the
alleged breaches. Management intends to vigorously defend against
these allegations.
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 net income 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 nine months ended September 30, 2008 and
2007:
|
|
|
Other
Postretirement
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
Three
Months Ended September 30,
|
|
Three
Months Ended September 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
25 |
|
|
$ |
24 |
|
|
$ |
10 |
|
|
$ |
11 |
|
Interest
Cost
|
|
|
62 |
|
|
|
59 |
|
|
|
28 |
|
|
|
26 |
|
Expected
Return on Plan Assets
|
|
|
(84 |
) |
|
|
(85 |
) |
|
|
(27 |
) |
|
|
(26 |
) |
Amortization
of Transition Obligation
|
|
|
- |
|
|
|
- |
|
|
|
7 |
|
|
|
6 |
|
Amortization
of Net Actuarial Loss
|
|
|
10 |
|
|
|
15 |
|
|
|
3 |
|
|
|
3 |
|
Net
Periodic Benefit Cost
|
|
$ |
13 |
|
|
$ |
13 |
|
|
$ |
21 |
|
|
$ |
20 |
|
|
|
|
Other
Postretirement
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
Nine
Months Ended September 30,
|
|
Nine
Months Ended September 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
75 |
|
|
$ |
72 |
|
|
$ |
31 |
|
|
$ |
32 |
|
Interest
Cost
|
|
|
187 |
|
|
|
176 |
|
|
|
84 |
|
|
|
78 |
|
Expected
Return on Plan Assets
|
|
|
(252 |
) |
|
|
(254 |
) |
|
|
(83 |
) |
|
|
(78 |
) |
Amortization
of Transition Obligation
|
|
|
- |
|
|
|
- |
|
|
|
21 |
|
|
|
20 |
|
Amortization
of Net Actuarial Loss
|
|
|
29 |
|
|
|
44 |
|
|
|
8 |
|
|
|
9 |
|
Net
Periodic Benefit Cost
|
|
$ |
39 |
|
|
$ |
38 |
|
|
$ |
61 |
|
|
$ |
61 |
|
The
following tables provide the Registrant Subsidiaries’ net periodic benefit cost
(credit) for the plans for the three and nine months ended September 30, 2008
and 2007:
|
|
|
Other
Postretirement
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
Three
Months Ended September 30,
|
|
Three
Months Ended September 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Company
|
(in
thousands)
|
|
APCo
|
|
$ |
834 |
|
|
$ |
841 |
|
|
$ |
3,797 |
|
|
$ |
3,560 |
|
CSPCo
|
|
|
(351 |
) |
|
|
(258 |
) |
|
|
1,545 |
|
|
|
1,491 |
|
I&M
|
|
|
1,821 |
|
|
|
1,900 |
|
|
|
2,496 |
|
|
|
2,530 |
|
OPCo
|
|
|
318 |
|
|
|
362 |
|
|
|
2,908 |
|
|
|
2,802 |
|
PSO
|
|
|
509 |
|
|
|
425 |
|
|
|
1,420 |
|
|
|
1,431 |
|
SWEPCo
|
|
|
935 |
|
|
|
747 |
|
|
|
1,411 |
|
|
|
1,420 |
|
|
|
|
Other
Postretirement
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
Nine
Months Ended September 30,
|
|
Nine
Months Ended September 30,
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Company
|
(in
thousands)
|
|
APCo
|
|
$ |
2,503 |
|
|
$ |
2,525 |
|
|
$ |
11,196 |
|
|
$ |
10,680 |
|
CSPCo
|
|
|
(1,049 |
) |
|
|
(773 |
) |
|
|
4,542 |
|
|
|
4,473 |
|
I&M
|
|
|
5,462 |
|
|
|
5,700 |
|
|
|
7,342 |
|
|
|
7,591 |
|
OPCo
|
|
|
957 |
|
|
|
1,088 |
|
|
|
8,541 |
|
|
|
8,405 |
|
PSO
|
|
|
1,525 |
|
|
|
1,273 |
|
|
|
4,194 |
|
|
|
4,292 |
|
SWEPCo
|
|
|
2,806 |
|
|
|
2,240 |
|
|
|
4,163 |
|
|
|
4,258 |
|
AEP has
significant investments in several trust funds to provide for future pension and
OPEB payments. All of the trust funds’ investments are
well-diversified and managed in compliance with all laws and
regulations. The value of the investments in these trusts has
declined due to the decreases in the equity and fixed income
markets. Although the asset values are currently lower, this decline
has not affected the funds’ ability to make their required
payments.
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 are being 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 net
income.
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 net income. 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 allocated 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 allocated the
project $134 million in credits. In September 2008, AEP entered into
a memorandum of understanding with the IRS concerning the requirements of
claiming the credits.
Federal
Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and
SWEPCo
In
October 2008, the Emergency Economic Stabilization Act of 2008 (the Act) was
signed into law. The Act extended several expiring tax provisions and
added new energy incentive provisions. The legislation impacted the availability
of research credits, accelerated depreciation of smart meters, production tax
credits and energy efficient commercial building
deductions. Management has evaluated the impact of the law change and
the application of the law change will not materially impact net income, cash
flows or financial condition.
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 net income, 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 nine months of 2008 were:
|
|
|
|
Principal
|
|
Interest
|
|
Due
|
Company
|
|
Type
of Debt
|
|
Amount
|
|
Rate
|
|
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
Pollution
Control Bonds
|
|
$
|
40,000
|
|
4.85
|
|
2019
|
APCo
|
|
Pollution
Control Bonds
|
|
|
30,000
|
|
4.85
|
|
2019
|
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
|
OPCo
|
|
Senior
Unsecured Notes
|
|
|
250,000
|
|
5.75
|
|
2013
|
SWEPCo
|
|
Pollution
Control Bonds
|
|
|
41,135
|
|
4.50
|
|
2011
|
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
|
|
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
|
|
Senior
Unsecured Notes
|
|
|
200,000
|
|
3.60
|
|
2008
|
APCo
|
|
Other
|
|
|
11
|
|
13.718
|
|
2026
|
CSPCo
|
|
Pollution
Control Bonds
|
|
|
48,550
|
|
Variable
|
|
2038
|
CSPCo
|
|
Pollution
Control Bonds
|
|
|
43,695
|
|
Variable
|
|
2038
|
CSPCo
|
|
Senior
Unsecured Notes
|
|
|
52,000
|
|
6.51
|
|
2008
|
CSPCo
|
|
Senior
Unsecured Notes
|
|
|
60,000
|
|
6.55
|
|
2008
|
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
|
|
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
|
OPCo
|
|
Notes
Payable
|
|
|
1,463
|
|
6.81
|
|
2008
|
OPCo
|
|
Notes
Payable
|
|
|
12,000
|
|
6.27
|
|
2009
|
PSO
|
|
Pollution
Control Bonds
|
|
|
33,70
|
|
Variable
|
|
2014
|
SWEPCo
|
|
Pollution
Control Bonds
|
|
|
41,135
|
|
Variable
|
|
2011
|
SWEPCo
|
|
Notes
Payable
|
|
|
1,500
|
|
Variable
|
|
2008
|
SWEPCo
|
|
Notes
Payable
|
|
|
3,304
|
|
4.47
|
|
2011
|
In
October 2008, SWEPCo retired $113 million of 5.25% Notes Payable due in
2043.
As of
September 30, 2008, OPCo and SWEPCo had $218 million and $54 million,
respectively, of tax-exempt long-term debt sold at auction rates that reset
every 35 days. These auction rates ranged from 11.117% to 13% for
OPCo. SWEPCo’s rate was 4.353%. OPCo's $218 million of
debt relates to a lease structure with JMG that OPCo is unable to refinance at
this time. In order to refinance this debt, OPCo needs the lessor's
consent. 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 had in connection
with recent developments in the subprime credit market, the credit ratings of
these insurers were downgraded or placed on negative outlook. These
market factors 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. Consequently, the Registrant Subsidiaries
chose to exit the auction-rate debt market. 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 September 30, 2008, the Registrant Subsidiaries
reduced their outstanding auction rate securities. Management plans
to continue this conversion and refunding process for the remaining $272 million
to other permitted modes, including term-put structures, variable-rate and
fixed-rate structures, as opportunities arise.
As of
September 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 6.5% to 8.25% and $333 million was issued at fixed rates ranging
from 4.5% to 5.25%. As of September 30, 2008, trustees held, on
behalf of the Registrant Subsidiaries, approximately $330 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
|
|
Variable
Rate
|
|
Auction
Rate
|
|
Held
by
|
|
|
|
|
During
the First
|
|
Fixed
Rate at
|
|
During
the First
|
|
at
|
|
at
|
|
Trustee
at
|
|
|
Retired
in
|
|
Nine
Months of
|
|
September
30,
|
|
Nine
Months of
|
|
September
30,
|
|
September
30,
|
|
September
30,
|
|
|
2008
|
|
2008
|
|
2008
|
|
2008
|
|
2008
|
|
2008
|
|
2008
|
Company
|
|
(in
thousands)
|
|
|
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
APCo
|
|
$
|
-
|
|
$
|
30,000
|
|
4.85%
|
|
$
|
75,000
|
|
|
8.00%
|
|
$
|
-
|
|
$
|
17,500
|
APCo
|
|
|
-
|
|
|
40,000
|
|
4.85%
|
|
|
50,275
|
|
|
8.05%
|
|
|
-
|
|
|
-
|
CSPCo
|
|
|
-
|
|
|
56,000
|
|
5.10%
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
92,245
|
CSPCo
|
|
|
-
|
|
|
44,500
|
|
4.85%
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
I&M
|
|
|
45,000
|
|
|
40,000
|
|
5.25%
|
|
|
52,000
|
|
|
7.75%
|
|
|
-
|
|
|
100,000
|
I&M
|
|
|
-
|
|
|
-
|
|
-
|
|
|
25,000
|
|
|
8.25%
|
|
|
-
|
|
|
-
|
OPCo
|
|
|
-
|
|
|
-
|
|
-
|
|
|
65,000
|
|
|
6.50%
|
|
|
218,000
|
|
|
85,000
|
OPCo
|
|
|
-
|
|
|
-
|
|
-
|
|
|
50,000
|
|
|
7.83%
|
|
|
-
|
|
|
-
|
OPCo
|
|
|
-
|
|
|
-
|
|
-
|
|
|
50,000
|
|
|
7.50%
|
|
|
-
|
|
|
-
|
PSO
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
33,700
|
SWEPCo
|
|
|
-
|
|
|
81,700
|
|
4.95%
|
|
|
-
|
|
|
-
|
|
|
53,500
|
|
|
-
|
SWEPCo
|
|
|
-
|
|
|
41,135
|
|
4.50%
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
45,000
|
|
$
|
333,335
|
|
|
|
$
|
367,275
|
|
|
|
|
$
|
271,500
|
|
$
|
328,445
|
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 September 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 nine months ended September 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
|
|
September
30, 2008
|
|
Limit
|
|
Company
|
|
(in
thousands)
|
|
APCo
|
|
|
$ |
307,226 |
|
|
$ |
269,987 |
|
|
$ |
188,985 |
|
|
$ |
187,192 |
|
|
$ |
(93,558 |
) |
|
$ |
600,000 |
|
CSPCo
|
|
|
|
238,172 |
|
|
|
150,358 |
|
|
|
157,569 |
|
|
|
53,962 |
|
|
|
21,833 |
|
|
|
350,000 |
|
I&M
|
|
|
|
345,064 |
|
|
|
- |
|
|
|
195,582 |
|
|
|
- |
|
|
|
(224,071 |
) |
|
|
500,000 |
|
OPCo
|
|
|
|
415,951 |
|
|
|
82,486 |
|
|
|
174,840 |
|
|
|
64,127 |
|
|
|
39,758 |
|
|
|
600,000 |
|
PSO
|
|
|
|
149,278 |
|
|
|
59,384 |
|
|
|
72,688 |
|
|
|
29,811 |
|
|
|
(125,029 |
) |
|
|
300,000 |
|
SWEPCo
|
|
|
|
168,495 |
|
|
|
300,525 |
|
|
|
87,426 |
|
|
|
219,159 |
|
|
|
195,628 |
|
|
|
350,000 |
|
The
maximum and minimum interest rates for funds either borrowed from or loaned to
the Utility Money Pool were as follows:
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
Maximum
Interest Rate
|
|
|
5.37 |
% |
|
|
5.94 |
% |
Minimum
Interest Rate
|
|
|
2.91 |
% |
|
|
5.30 |
% |
The
average interest rates for funds borrowed from and loaned to the Utility Money
Pool for the nine months ended September 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
|
|
|
|
Nine
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Company
|
|
|
|
|
|
|
|
|
|
|
|
|
APCo
|
|
|
3.62 |
% |
|
|
5.41 |
% |
|
|
3.25 |
% |
|
|
5.84 |
% |
CSPCo
|
|
|
3.66 |
% |
|
|
5.48 |
% |
|
|
2.99 |
% |
|
|
5.39 |
% |
I&M
|
|
|
3.19 |
% |
|
|
5.38 |
% |
|
|
- |
% |
|
|
5.84 |
% |
OPCo
|
|
|
3.24 |
% |
|
|
5.39 |
% |
|
|
3.62 |
% |
|
|
5.43 |
% |
PSO
|
|
|
3.04 |
% |
|
|
5.47 |
% |
|
|
4.53 |
% |
|
|
- |
% |
SWEPCo
|
|
|
3.36 |
% |
|
|
5.54 |
% |
|
|
3.01 |
% |
|
|
5.34 |
% |
Short-term
Debt
The
Registrant Subsidiaries’ outstanding short-term debt was as
follows:
|
|
|
|
September
30, 2008
|
|
December
31, 2007
|
|
|
|
|
Outstanding
|
|
Interest
|
|
Outstanding
|
|
Interest
|
|
|
Type
of Debt
|
|
Amount
|
|
Rate
(a)
|
|
Amount
|
|
Rate
(a)
|
Company
|
|
|
|
(in
thousands)
|
|
|
|
(in
thousands)
|
|
|
OPCo
|
|
Commercial
Paper – JMG (b)
|
|
$
|
-
|
|
-%
|
|
$
|
701
|
|
5.35%
|
SWEPCo
|
|
Line
of Credit – Sabine Mining Company (c)
|
|
|
9,520
|
|
7.75%
|
|
|
285
|
|
5.25%
|
(a)
|
Weighted
average rate.
|
(b)
|
This
commercial paper is specifically associated with the Gavin Scrubber and is
backed by a separate credit facility.
|
(c)
|
Sabine
Mining Company is consolidated under FIN
46R.
|
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 which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $23 million and $12 million, respectively, following its
bankruptcy. Under the facilities, letters of credit may be
issued. As of September 30, 2008, $372 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 net income 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.
Market
Impacts
In recent
months, the world and U.S. economies have experienced significant
slowdowns. These economic slowdowns have impacted and will continue
to impact the Registrant Subsidiaries’ residential, commercial and industrial
sales. Concurrently, the financial markets have become increasingly unstable and
constrained at both a global and domestic level. This systemic
marketplace distress is impacting the Registrant Subsidiaries’ access to
capital, liquidity, asset valuations in trust funds, creditworthy status of
customers, suppliers and trading partners and cost of capital. AEP’s
financial staff actively manages these factors with oversight from the risk
committee. The uncertainties in the credit markets could have
significant implications since the Registrant Subsidiaries rely on continuing
access to capital to fund operations and capital expenditures.
The
current credit markets are constraining the Registrant Subsidiaries’ ability to
issue new debt and refinance existing debt. Approximately $120
million and $300 million of AEP Consolidated’s $16 billion of long-term debt as
of September 30, 2008 will mature in the remainder of 2008 and 2009,
respectively. I&M and OPCo have $50 million and $37 million,
respectively, maturing in 2008. APCo, OPCo and PSO have $150 million,
$82 million and $50 million, respectively, maturing in 2009. Management
intends to refinance these maturities. To support its operations, AEP
has $3.9 billion in aggregate credit facility commitments. These
commitments include 27 different banks with no bank having more than 10% of the
total bank commitments. Short-term funding for the Registrant
Subsidiaries comes from AEP’s commercial paper program credit facilities which
supports the Utility Money Pool. In September 2008 and October 2008,
AEP borrowed $600 million and $1.4 billion, respectively, under the credit
facilities to enhance its cash position during this period of market
disruptions. This money can be loaned to the Registrant Subsidiaries
through the Utility Money Pool.
Management
cannot predict the length of time the current credit situation will continue or
its impact on future operations and the Registrant Subsidiaries’ ability to
issue debt at reasonable interest rates. However, when market
conditions improve, management plans to repay the amounts drawn under the credit
facilities, re-enter the commercial paper market and issue long-term
debt. If there is not an improvement in access to capital, management
believes that the Registrant Subsidiaries have adequate liquidity, through the
Utility Money Pool, to support their planned business operations and
construction programs through 2009.
AEP has
significant investments in several trust funds to provide for future payments of
pensions and OPEB. I&M has significant investments in several trust funds to
provide for future payments of nuclear decommissioning and spent nuclear fuel
disposal. All of the trust funds’ investments are well-diversified
and managed in compliance with all laws and regulations. The value of
the investments in these trusts has declined due to the decreases in the equity
and fixed income markets. Although the asset values are currently
lower, this has not affected the funds’ ability to make their required
payments. As of September 30, 2008, the decline in pension asset
values will not require a contribution to be made in 2008 or 2009.
On behalf
of the Registrant Subsidiaries, AEPSC enters into risk management contracts with
numerous counterparties. Since open risk management contracts are
valued based on changes in market prices of the related commodities, exposures
change daily. AEP’s risk management organization monitors these exposures on a
daily basis to limit the Registrant Subsidiaries’ economic and financial
statement impact on a counterparty basis.
Sources of
Funding
The
credit facilities that support the Utility Money Pool were reduced by Lehman
Brothers Holdings Inc.’s commitment amount of $46 million following its
bankruptcy. 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 which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $23 million and $12 million, respectively, following its
bankruptcy. The Registrant Subsidiaries may issue LOCs under the
credit facilities. Each subsidiary has a borrowing/LOC limit under
the credit facilities. As of September 30, 2008, a total of $372
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
|
|
|
|
|
|
|
|
Against
|
|
|
|
|
|
|
|
$650
million
|
|
|
|
Credit
Facility
|
|
|
|
Agreement
at
|
|
|
|
|
|
|
|
September
30, 2008
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
|
$ |
300 |
|
|
$ |
150 |
|
|
$ |
127 |
|
CSPCo
|
|
|
|
230 |
|
|
|
120 |
|
|
|
- |
|
I&M
|
|
|
|
230 |
|
|
|
120 |
|
|
|
78 |
|
OPCo
|
|
|
|
400 |
|
|
|
200 |
|
|
|
167 |
|
PSO
|
|
|
|
65 |
|
|
|
35 |
|
|
|
- |
|
SWEPCo
|
|
|
|
230 |
|
|
|
120 |
|
|
|
- |
|
At
September 30, 2008, there were no outstanding amounts under the $350 million
facility.
Credit
Markets
To the
extent financing is unavailable due to the challenging credit markets, the
Registrant Subsidiaries will rely upon cash flows from operations and access to
the Utility Money Pool to fund their debt maturities, continuing operations and
capital expenditures.
In the
first quarter of 2008, due to the exposure that bond insurers like Ambac
Assurance Corporation and Financial Guaranty Insurance Co. had in connection
with developments in the subprime credit market, the credit ratings of those
insurers were downgraded or placed on negative outlook. These market
factors contributed to higher interest rates in successful auctions and
increasing occurrences of failed auctions for tax-exempt long-term debt sold at
auction rates. Consequently, management chose to exit the
auction-rate debt market. As of September 30, 2008, OPCo had $218
million (rates range from 11.117% to 13%) and SWEPCo had $54 million (rate of
4.353%) outstanding of tax-exempt long-term debt sold at auction rates that
reset every 35 days. Approximately $218 million of this debt relates to a
lease structure with JMG that OPCo is unable to refinance at this time. In
order to refinance this debt, OPCo needs the lessor's consent. This
debt is insured by previously AAA-rated bond insurers. The
instruments under which the bonds are issued allow for their conversion to other
short-term variable-rate structures, term-put structures and fixed-rate
structures. Management plans to continue the conversion and refunding
process to other permitted modes, including term-put structures, variable-rate
and fixed-rate structures, as opportunities arise. Through September
30, 2008, the Registrant Subsidiaries reduced their outstanding auction rate
securities.
As of
September 30, 2008, trustees held, on behalf of the Registrant Subsidiaries,
approximately $330 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
|
|
Remains
in
|
|
Held
|
|
|
|
Retired
|
|
Variable
Rates
|
|
Auction
Rate at
|
|
by
Trustee at
|
|
|
|
in
2008
|
|
During
2008
|
|
September
30, 2008
|
|
September
30, 2008
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
|
$ |
- |
|
|
$ |
195 |
|
|
$ |
- |
|
|
$ |
18 |
|
CSPCo
|
|
|
|
- |
|
|
|
101 |
|
|
|
- |
|
|
|
92 |
|
I&M
|
|
|
|
45 |
|
|
|
117 |
|
|
|
- |
|
|
|
100 |
|
OPCo
|
|
|
|
- |
|
|
|
165 |
|
|
|
218 |
|
|
|
85 |
|
PSO
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
34 |
|
SWEPCo
|
|
|
|
- |
|
|
|
123 |
|
|
|
54 |
|
|
|
- |
|
APCo,
I&M and OPCo issued $125 million, $77 million and $165 million,
respectively, of weekly variable rate debt. As of September 30, 2008,
the variable rates ranged from 6.5% to 8.25%. APCo issued fixed rate
debt of $70 million at 4.85% until 2019. 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 and issued $41 million of fixed rate debt at 4.5% through
2011.
Sales of Receivable
Agreement
In
October 2008, AEP Credit renewed its $600 million sale of receivables agreement
through October 2009. AEP Credit purchases accounts receivable from
the Registrant Subsidiaries.
Capital
Expenditures
Due to
recent credit market instability, management is currently reviewing
projections for capital expenditures for 2009 through
2010. Management plans to identify reductions of approximately $750
million for 2009 across the AEP System. Management is evaluating
possible additional capital reductions for 2010. Management is
also reviewing projections for operation and maintenance
expense. Management's intent is to keep operation and maintenance
expense flat in 2009 as compared to 2008.
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. An 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 after the PUCO approves an
MRO. 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 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 and purchased power 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 an
optional MRO. 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 (which excludes off-system
sales) 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-purchased power cost recovery
mechanism would be phased-in over the three year period from 2009 through
2011. If the ESP is approved as filed, effective with January 2009
billings, CSPCo and OPCo will defer any fuel cost under-recoveries and related
carrying costs for future recovery. The under-recoveries and related
carrying costs that exist at the end of 2011 will be recovered 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 distribution reliability costs and for unexpected
non-fuel generation costs. The filings also include programs for
smart metering initiatives and economic development and mandated energy
efficiency and peak demand reduction programs. In September 2008, the
PUCO issued a finding and order tentatively adopting rules governing MRO and ESP
applications. CSPCo and OPCo filed their ESP applications based on
proposed rules and requested waivers for portions of the proposed
rules. The PUCO denied the waiver requests in September 2008 and
ordered CSPCo and OPCo to submit information consistent with the tentative
rules. In October 2008, CSPCo and OPCo submitted additional
information related to proforma financial statements and information concerning
CSPCo and OPCo’s fuel procurement process. In October 2008, CSPCo and
OPCo filed an application for rehearing with the PUCO to challenge certain
aspects of the proposed rules.
Within
the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $46
million and $38 million, respectively, for customer choice implementation and
line extension carrying costs. In addition, CSPCo and OPCo would
recover related unrecorded equity carrying costs of $30 million and $21 million,
respectively. Such costs would be recovered over an 8-year period
beginning January 2011. Hearings are scheduled for November 2008 and
an order is expected in the fourth quarter of 2008. Failure of the
PUCO to ultimately approve the recovery of the regulatory assets would have an
adverse effect on future net income 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)
|
|
149
|
|
Gas
|
|
Combined-cycle
|
|
580
|
|
2010(h)
|
SWEPCo
|
|
Stall
|
|
Louisiana
|
|
|
378
|
|
|
158
|
|
Gas
|
|
Combined-cycle
|
|
500
|
|
2010
|
SWEPCo
|
|
Turk
|
(f)
|
Arkansas
|
|
|
1,522
|
(f)
|
|
448
|
|
Coal
|
|
Ultra-supercritical
|
|
600
|
(f)
|
2012
|
APCo
|
|
Mountaineer
|
(g)
|
West
Virginia
|
|
|
|
(g)
|
|
|
|
Coal
|
|
IGCC
|
|
629
|
|
(g)
|
CSPCo/OPCo
|
|
Great
Bend
|
(g)
|
Ohio
|
|
|
|
(g)
|
|
|
|
Coal
|
|
IGCC
|
|
629
|
|
(g)
|
(a)
|
Amount
excludes AFUDC.
|
(b)
|
Amount
includes AFUDC.
|
(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 $1.1 billion 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)
|
Construction
of IGCC plants are pending necessary permits and regulatory
approval. See “IGCC Plants” section below.
|
(h)
|
Projected
completion date of the Dresden Plant is currently under
review. To the extent that the completion date is delayed, the
total projected cost of the Dresden Plant could
change.
|
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 August
2008, the PUCT issued an order approving the Turk Plant with the following four
conditions: (a) the capping of capital costs for the Turk Plant at the $1.5
billion projected construction cost, excluding AFUDC, (b) capping CO2 emission
costs at $28 per ton through the year 2030, (c) holding Texas ratepayers
financially harmless from any adverse impact related to the Turk Plant not being
fully subscribed to by other utilities or wholesale customers and (d) providing
the PUCT all updates, studies, reviews, reports and analyses as previously
required under the Louisiana and Arkansas orders. An intervenor filed
a motion for rehearing seeking reversal of the PUCT’s
decision. SWEPCo filed a motion for rehearing stating that the two
cost cap restrictions are unlawful. In September 2008, the motions
for rehearing were denied. In October 2008, SWEPCo appealed the
PUCT’s order regarding the two cost cap restrictions. If the cost cap
restrictions are upheld and construction or emissions costs exceed the
restrictions, it could have a material adverse impact on future net income and
cash flows. In October 2008, an intervenor filed an appeal contending
that the PUCT’s grant of a conditional Certificate of Public Convenience and
Necessity for the Turk Plant was not necessary to serve retail
customers.
SWEPCo is
also working with the Arkansas Department of Environmental Quality for the
approval of an air permit and the U.S. Army Corps of Engineers for the
approval of a wetlands and stream impact permit. Once SWEPCo receives the
air permit, they will commence construction. 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.
In
January 2008 and July 2008, SWEPCo filed applications for authority with the
APSC to construct transmission lines necessary for service from the Turk
Plant. Several landowners filed for intervention status and one
landowner also contended he should be permitted to re-litigate Turk Plant
issues, including the need for the generation. The APSC granted their
intervention but denied the request to re-litigate the Turk Plant
issues. The landowner filed an appeal to the Arkansas State Court of
Appeals in June 2008.
The
Arkansas Governor’s Commission on Global Warming is scheduled to issue its final
report to the Governor by November 1, 2008. The Commission was
established to set a global warming pollution reduction goal together with a
strategic plan for implementation in Arkansas. If legislation is
passed as a result of the findings in the Commission’s report, it could impact
SWEPCo’s proposal to build the Turk Plant.
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 September 30, 2008, SWEPCo has capitalized
approximately $448 million of expenditures and has significant contractual
construction commitments for an additional $771 million. As of
September 30, 2008, if the plant had been cancelled, cancellation fees of $61
million would have been required in order to terminate these construction
commitments. If the Turk Plant does not receive all necessary
approvals on reasonable terms and SWEPCo cannot recover its capitalized costs,
including any cancellation fees, it would have an adverse effect on future net
income, cash flows and possibly financial condition.
IGCC
Plants
The
construction of the West Virginia and Ohio IGCC plants are pending necessary
permits and regulatory approvals. 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 allocated $134 million in
future tax credits to APCo for the planned IGCC plant contingent upon the
commencement of construction, qualifying expenses being incurred and
certification of the IGCC plant prior to July 2010. Through September
30, 2008, APCo deferred for future recovery preconstruction IGCC costs of $19
million. If the West Virginia IGCC plant is cancelled, APCo plans to
seek recovery of its prudently incurred deferred pre-construction
costs. If the plant is cancelled and if the deferred costs are not
recoverable, it would have an adverse effect on future net income and cash
flows.
In Ohio,
CSPCo and OPCo continue to pursue the ultimate construction of the IGCC
plant. In September 2008, the Ohio Consumers’ Counsel filed a motion
with the PUCO requesting all Phase 1 cost recoveries be refunded to Ohio
ratepayers with interest. CSPCo and OPCo filed a response with the
PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit
and contrary to past precedent. If CSPCo and OPCo were required to
refund some or all of the $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 net
income 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, 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 gas (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.
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. The Federal EPA filed a petition for
review by the U.S. Supreme Court. Management is unable to predict the
outcome of this appeal or 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% by
2010, and by 65% by 2015. NOx emissions
will be subject to additional limits beginning in 2009, and will be reduced by a
total of 70% 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. The Federal EPA and other parties petitioned for
rehearing. Management is unable to predict the outcome of the
rehearing petitions or 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 $9 million of
annual CAIR NOx allowances. The
market value of annual CAIR NOx allowances
decreased following this court decision. However, the
weighted-average cost of these allowances is below market. If CAIR
remains vacated, management intends to seek partial recovery of the cost of
purchased allowances. Any unrecovered portion would have an adverse
effect on future net income 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 state
implementation plan (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 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 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” 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 SFAS 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). In
October 2008, the FASB issued FSP SFAS 157-3 “Determining the Fair Value of
Financial Asset When the Market for That Asset is Not Active” which clarifies
application of SFAS 157 in markets that are not active and provides an
illustrative example. 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. FSP SFAS 157-3 is effective upon
issuance. The Registrant Subsidiaries will fully adopt SFAS 157
effective January 1, 2009 for items within the scope of FSP SFAS
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 third 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
September 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 third 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%. In October 2008, intervenors filed testimony
recommending annual base rate increases ranging from $29 million to $86
million. The differences are principally due to lower recommended returns
on equity. If the OCC denies all or part of the requested rate
recovery, it could have an adverse effect on future net income, 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 an order is not received
prior to January 1, 2009, CSPCo and OPCo have requested retroactive application
of the new rates back to January 1, 2009 upon approval. If the PUCO
denies all or part of the requested rate recovery, it could have an adverse
effect on future net income, cash flows and financial condition.
Our request for rate recovery in
Virginia may not be approved. (Applies to AEP and
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 proposed revenue requirement
reflects a return on equity of 11.75%. In October 2008, the Virginia
SCC staff filed testimony recommending the proposed increase be reduced to $157
million. The decrease is principally due to the use of a recommended
return on equity of 10.1%. In October 2008, hearings were held in which
APCo filed a $168 million settlement agreement which was accepted by all parties
except one industrial customer. If the Virginia SCC denies all or
part of the requested rate recovery, it could have an adverse effect on future
net income, cash flows and financial condition.
Our request for rate recovery in
Indiana may not be approved. (Applies to AEP and
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%. In September 2008, the Indiana Office of
Utility Consumer Counselor (OUCC) and the Industrial Customer Coalition filed
testimony recommending a $14 million and $37 million decrease in revenue,
respectively. In October 2008, I&M filed testimony rebutting the
recommendations of the OUCC. Hearings are scheduled for December
2008. A decision is expected from the IURC by June
2009. If the IURC denies all or part of the requested rate recovery,
it could have an adverse effect on future net income, cash flows and financial
condition.
Risks
Related to Owning and Operating Generation Assets and Selling Power
Our financial performance may be
impaired if Cook Plant Unit 1 is not returned to service in a reasonable period
of time or in a cost-efficient manner. (Applies to AEP and
I&M)
Cook
Plant Unit 1 is a 1,055 MW nuclear generating unit located in Bridgman,
Michigan. In September 2008, I&M shut down Unit 1 due to a fire on the
electric generator which resulted from steam turbine vibrations. I&M is
working with its insurance company and turbine vendor to evaluate the extent of
the damage resulting from the incident and the costs to return the unit to
service. At this time, management is unable to determine the ultimate
costs of the incident or when the unit will return to
service. Management believes that I&M should recover a
significant portion of these costs through the turbine vendor’s warranty,
insurance, other reimbursements or the regulatory process. If any of
these costs are not covered by warranty, insurance or recovered through the
regulatory process, or if the unit is not returned to service in a reasonable
period of time, it could have an adverse impact on net income, cash flows and
financial condition.
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. In September 2008, the FERC issued an order
accepting AEP’s market-based rates with minor changes and rejected the PUCO’s
and the industrial retail customers’ suggestions for further
investigation. 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, net income 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 net income 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 net income and cash flows, and possibly financial condition.
Risks
Related to Market, Economic or Financial Volatility
If we are unable to access capital
markets on reasonable terms, it could have an adverse impact on our net income,
cash flows and financial condition. (Applies to each
registrant)
We rely
on access to capital markets as a significant source of liquidity for capital
requirements not satisfied by operating cash flows. The recent
volatility and reduced liquidity in the financial markets could affect our
ability to raise capital and fund our capital needs, including construction
costs and refinancing maturing indebtedness. In addition, if capital
is available only on less than reasonable terms, interest costs could increase
materially. Restricted access to capital markets and/or increased
borrowing costs could have an adverse impact on net income, cash flows and
financial condition.
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 net
income 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 September 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
|
07/01/08
– 07/31/08
|
|
|
-
|
|
$
|
-
|
|
|
|
-
|
|
$
|
-
|
08/01/08
– 08/31/08
|
|
|
-
|
|
|
-
|
|
|
|
-
|
|
|
-
|
09/01/08
– 09/30/08
|
|
|
-
|
|
|
-
|
|
|
|
-
|
|
|
-
|
Item
4. Submission of
Matters to a Vote of Security Holders
NONE
Item
5. Other
Information
NONE
Item
6. Exhibits
AEP
10(a)
– Second Amended and Restated $1.5 Billion Credit Agreement, dated as of
March 31, 2008, among AEP, the banks, financial institutions and other
institutional lenders listed on the signatures pages thereof, and JPMorgan
Chase Bank, N.A., as Administrative
Agent.
|
10(b)
– Second Amended and Restated $1.5 Billion Credit Agreement, dated as of
March 31, 2008, among AEP, the banks, financial institutions and other
institutional lenders listed on the signatures pages thereof, and Barclays
Bank plc, as Administrative Agent.
|
AEP,
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
10(c)
– $650 Million Credit Agreement, dated as of April 4, 2008. among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
10(d)
– Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement,
among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the
Initial Lenders named therein, the Swingline Bank party thereto, the LC
Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as
Administrative Agent.
|
10(e)
– $350 Million Credit Agreement, dated as of April 4, 2008, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
10(f)
– Amendment, dated as of April 25, 2008, to $350 Million Credit
Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO
and SWEPCo, the Initial Lenders named therein, the Swingline Bank party
thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank,
N.A., as Administrative Agent.
|
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: October
31, 2008