Unassociated Document
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE
SECURITIES EXCHANGE ACT OF 1934
For
The
Quarterly Period Ended September
30, 2006
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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|
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|
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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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0-18135
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AEP
GENERATING COMPANY (An Ohio Corporation)
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31-1033833
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0-346
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|
AEP
TEXAS CENTRAL COMPANY (A Texas Corporation)
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74-0550600
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0-340
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|
AEP
TEXAS NORTH COMPANY (A Texas Corporation)
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75-0646790
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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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1-6858
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KENTUCKY
POWER COMPANY (A Kentucky Corporation)
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61-0247775
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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
|
|
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
|
No
|
Indicate
by check mark whether American Electric Power Company, Inc. is a
large
accelerated filer, an accelerated filer, or a non-accelerated filer.
See
definition of ‘accelerated filer and large accelerated filer’ in Rule
12b-2 of the Exchange Act. (Check One)
|
Large
accelerated filer X
Accelerated filer Non-accelerated
filer
|
Indicate
by check mark whether AEP Generating Company, AEP Texas Central Company,
AEP Texas North Company, Appalachian Power Company, Columbus Southern
Power Company, Indiana Michigan Power Company, Kentucky Power Company,
Ohio Power Company, Public Service Company of Oklahoma and Southwestern
Electric Power Company, are large accelerated filers, accelerated
filers,
or non-accelerated filers. See definition of ‘accelerated filer and large
accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check
One)
|
Large
accelerated filer
Accelerated filer Non-accelerated
filer X
|
|
Indicate
by check mark whether the registrants are shell companies (as defined
in
Rule 12b-2 of the Exchange Act).
|
Yes
|
No X
|
AEP
Generating Company, AEP Texas North Company, Columbus Southern Power Company,
Kentucky Power Company and Public Service Company of Oklahoma 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
31, 2006
|
|
|
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|
AEP
Generating Company
|
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1,000
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|
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|
($1,000
par value)
|
AEP
Texas Central Company
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2,211,678
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|
($25
par value)
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AEP
Texas North Company
|
|
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5,488,560
|
|
|
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($25
par value)
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American
Electric Power Company, Inc.
|
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395,572,735
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|
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($6.50
par value)
|
Appalachian
Power Company
|
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13,499,500
|
|
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|
(no
par value)
|
Columbus
Southern Power Company
|
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16,410,426
|
|
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|
(no
par value)
|
Indiana
Michigan Power Company
|
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1,400,000
|
|
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(no
par value)
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Kentucky
Power Company
|
|
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1,009,000
|
|
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($50
par value)
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Ohio
Power Company
|
|
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27,952,473
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|
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(no
par value)
|
Public
Service Company of Oklahoma
|
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9,013,000
|
|
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($15
par value)
|
Southwestern
Electric Power Company
|
|
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7,536,640
|
|
|
|
($18
par value)
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX
TO QUARTERLY REPORTS ON FORM 10-Q
September
30, 2006
Glossary
of Terms
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|
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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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AEP
Generating Company:
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Management’s
Narrative Financial Discussion and Analysis
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Condensed
Financial Statements
|
|
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
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AEP
Texas Central Company and Subsidiaries:
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|
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Management’s
Financial Discussion and Analysis
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|
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
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Condensed
Consolidated Financial Statements
|
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
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|
AEP
Texas North Company and Subsidiary:
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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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|
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Appalachian
Power Company and Subsidiaries:
|
|
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Management’s
Financial Discussion and Analysis
|
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
|
Condensed
Consolidated Financial Statements
|
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|
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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
|
|
|
|
Condensed
Consolidated Financial Statements
|
|
|
|
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
Financial Discussion and Analysis
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|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
|
Condensed
Consolidated Financial Statements
|
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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|
|
|
|
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|
Kentucky
Power Company:
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|
Management’s
Narrative Financial Discussion and Analysis
|
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
|
Condensed
Financial Statements
|
|
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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|
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Ohio
Power Company Consolidated:
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Management’s
Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
|
Condensed
Consolidated Financial Statements
|
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|
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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|
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Public
Service Company of Oklahoma:
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Management’s
Narrative Financial Discussion and Analysis
|
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
|
Condensed
Financial Statements
|
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Southwestern
Electric Power Company Consolidated:
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|
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|
Management’s
Financial Discussion and Analysis
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|
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|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
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Condensed
Consolidated Financial Statements
|
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Condensed
Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Combined
Management’s Discussion and Analysis of Registrant
Subsidiaries
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Item
4.
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Controls
and Procedures
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Part
II. OTHER INFORMATION
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Item
1.
|
Legal
Proceedings
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Item
1A.
|
Risk
Factors
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Item
2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
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Item
5.
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Other
Information
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Item
6.
|
Exhibits:
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Exhibit
12 |
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Exhibit
31
(a) |
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Exhibit
31
(b) |
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Exhibit
31
(c) |
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Exhibit
31
(d) |
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Exhibit
32
(a) |
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Exhibit
32
(b) |
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SIGNATURE
|
|
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|
This
combined Form 10-Q is separately filed by American Electric Power
Company,
Inc., AEP Generating Company, AEP Texas Central Company, AEP Texas
North
Company, Appalachian Power Company, Columbus Southern Power Company,
Indiana Michigan Power Company, Kentucky 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.
ADFIT
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Accumulated
Deferred Federal Income Taxes.
|
ADITC
|
|
Accumulated
Deferred Investment Tax Credits.
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AEGCo
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|
AEP
Generating Company, an AEP electric generating
subsidiary.
|
AEP
or Parent
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American
Electric Power Company, Inc.
|
AEP
Consolidated
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AEP
and its majority owned consolidated subsidiaries and consolidated
entities.
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AEP
East companies
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APCo,
CSPCo, I&M, KPCo and OPCo.
|
AEPES
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AEP
Energy Services, Inc., a subsidiary of AEP Resources,
Inc.
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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.
|
AEP
System Power Pool or AEP
Power Pool
|
|
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.
|
AEPSC
|
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American
Electric Power Service Corporation, a service subsidiary providing
management and professional services to AEP and its
subsidiaries.
|
AEP
West companies
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PSO,
SWEPCo, TCC and TNC.
|
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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CAA
|
|
Clean
Air Act.
|
Cook
Plant
|
|
Donald
C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by
I&M.
|
CSPCo
|
|
Columbus
Southern Power Company, an AEP electric utility
subsidiary.
|
CSW
|
|
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.).
|
CSW
Operating Agreement
|
|
Agreement,
dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing
their generating capacity allocation. AEPSC acts as the
agent.
|
CTC
|
|
Competition
Transition Charge.
|
DETM
|
|
Duke
Energy Trading and Marketing L.L.C., a risk management
counterparty.
|
ECAR
|
|
East
Central Area Reliability Council.
|
EDFIT
|
|
Excess
Deferred Federal Income Taxes.
|
EITF
|
|
Financial
Accounting Standards Board’s Emerging Issues Task
Force.
|
EPACT
|
|
Energy
Policy Act of 2005.
|
ERCOT
|
|
Electric
Reliability Council of Texas.
|
FASB
|
|
Financial
Accounting Standards Board.
|
Federal
EPA
|
|
United
States Environmental Protection Agency.
|
FERC
|
|
Federal
Energy Regulatory Commission.
|
GAAP
|
|
Accounting
Principles Generally Accepted in the United States of
America.
|
HPL
|
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Houston
Pipe Line Company LP, a former AEP subsidiary that was sold in January
2005.
|
IGCC
|
|
Integrated
Gasification Combined Cycle, technology that turns coal into a
cleaner-burning gas.
|
I&M
|
|
Indiana
Michigan Power Company, an AEP electric utility
subsidiary.
|
IPP
|
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Independent
Power Producers.
|
IRS
|
|
Internal
Revenue Service.
|
IURC
|
|
Indiana
Utility Regulatory Commission.
|
KPCo
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Kentucky
Power Company, an AEP electric utility subsidiary.
|
KPSC
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Kentucky
Public Service Commission.
|
kV
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Kilovolt.
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KWH
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Kilowatthour.
|
MISO
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Midwest
Independent Transmission System Operator.
|
MTM
|
|
Mark-to-Market.
|
MW
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|
Megawatt.
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MWH
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Megawatthour.
|
NOx
|
|
Nitrogen
oxide.
|
Nonutility
Money Pool
|
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AEP
System’s Nonutility Money Pool.
|
NRC
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|
Nuclear
Regulatory Commission.
|
NSR
|
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New
Source Review.
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NYMEX
|
|
New
York Mercantile Exchange.
|
OATT
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Open
Access Transmission Tariff.
|
OCC
|
|
Corporation
Commission of the State of Oklahoma.
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OPCo
|
|
Ohio
Power Company, an AEP electric utility subsidiary.
|
OTC
|
|
Over
the counter.
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PJM
|
|
Pennsylvania
- New Jersey - Maryland regional transmission
organization.
|
PSO
|
|
Public
Service Company of Oklahoma, an AEP electric utility
subsidiary.
|
PTB
|
|
Price-to-Beat.
|
PUCO
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|
Public
Utilities Commission of Ohio.
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PUCT
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|
Public
Utility Commission of Texas.
|
PURPA
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Public
Utility Regulatory Policies Act of 1978.
|
Registrant
Subsidiaries
|
|
AEP
subsidiaries which are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC.
|
REP
|
|
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 or leased by AEGCo and
I&M.
|
RSP
|
|
Rate
Stabilization Plan.
|
RTO
|
|
Regional
Transmission Organization.
|
S&P
|
|
Standard
and Poor’s.
|
SEC
|
|
United
States Securities and Exchange Commission.
|
SECA
|
|
Seams
Elimination Cost Allocation.
|
SFAS
|
|
Statement
of Financial Accounting Standards issued by the FASB.
|
SFAS
133
|
|
Statement
of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities.”
|
SIA
|
|
System
Integration Agreement.
|
SO2
|
|
Sulfur
Dioxide.
|
SPP
|
|
Southwest
Power Pool.
|
STP
|
|
South
Texas Project Nuclear Generating Plant.
|
Sweeny
|
|
Sweeny
Cogeneration Limited Partnership, owner and operator of a four
unit, 480
MW gas-fired generation facility, owned 50% by AEP.
|
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.
|
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.
|
FORWARD-LOOKING
INFORMATION
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 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 when needed at acceptable
prices and terms and to recover those costs 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 for new
investments, transmission service and environmental
compliance).
|
·
|
Resolution
of litigation (including pending Clean Air Act enforcement actions
and
disputes arising from the bankruptcy of Enron Corp. and related
matters).
|
·
|
Our
ability to constrain operation and maintenance costs.
|
·
|
The
economic climate and growth in our service territory and changes
in market
demand and demographic patterns.
|
·
|
Inflationary
and interest rate trends.
|
·
|
Our
ability to develop and execute a strategy based on a view regarding
prices
of electricity, natural gas and other energy-related
commodities.
|
·
|
Changes
in the creditworthiness of the counterparties with whom we have
contractual arrangements, including participants in the energy trading
market.
|
·
|
Changes
in the financial markets, particularly those affecting the availability
of
capital and our ability to refinance existing debt at attractive
rates.
|
·
|
Actions
of rating agencies, including changes in the ratings of
debt.
|
·
|
Volatility
and changes in markets for electricity, natural gas and other
energy-related commodities.
|
·
|
Changes
in utility regulation, including implementation of EPACT and membership
in
and integration into regional transmission structures.
|
·
|
Accounting
pronouncements periodically issued by accounting standard-setting
bodies.
|
·
|
The
performance of our pension and other postretirement benefit
plans.
|
·
|
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.
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS
EXECUTIVE
OVERVIEW
Several
factors, both positive and negative, contributed to our performance in the
third quarter of 2006. We continued receiving favorable outcomes in various
regulatory activities resulting in increased revenues. We also continued
securing new power supply contracts with municipal and cooperative customers
and
our barging subsidiary produced strong results. Some of these positive factors
were offset in part by mild weather and an impairment related to our Plaquemine
Cogeneration Facility in connection with the pending sale to Dow Chemical
Company.
Regulatory
Activity
Our
significant regulatory activity progressed with the following major
developments:
·
|
In
July 2006, an ALJ rendered an initial decision to the FERC recommending
that current transmission rates in PJM are unjust and unreasonable
and
should be redesigned to replace the PJM license plate rates effective
April 1, 2006. If approved by the FERC, the new regional rates would
result in parties outside of the AEP zone in PJM contributing a
significant portion of AEP’s transmission revenue requirement, some of
which may be treated as a refund to retail customers. The favorable
impact
of the initial ALJ decision is not determinable pending the decision
of
the FERC and subject to analysis of refunds to retail customers,
if
any.
|
·
|
In
July 2006, the FERC approved our request for use of an incentive
rate
treatment for our proposed 550-mile 765 kV transmission line project.
The
approval is conditioned upon PJM including the project in its formal
Regional Transmission Expansion Plan, which should be finalized in
early
2007.
|
·
|
In
July 2006, the West Virginia Public Service Commission approved a
settlement agreement in APCo and WPCo’s base rate case, providing for a
$44 million annual increase in rates effective July 28, 2006. These
rates
include a surcharge for recovery of the cost of the Wyoming-Jacksons
Ferry
765 kV line, which was energized and placed in service in June
2006.
|
·
|
In
August 2006, an ALJ rendered an initial decision to the FERC indicating
the rate design for recovery of SECA charges was flawed and that
the SECA
rates charged were unfair, unjust and discriminatory and that refunds
should be made. We believe this decision is contrary to other FERC
rulings
and intend to defend against a SECA rates refund.
|
·
|
In
September 2006, the Virginia SCC’s chief hearing examiner issued an
opinion recommending disallowance of our $21 million environmental
and
reliability cost recovery case filed in June 2005. We subsequently
wrote
off our related assets which reduced pretax earnings by $36 million
in the
third quarter of 2006. We believe the hearing examiner’s recommendation is
contrary to the law and have urged the Virginia SCC not to adopt
that
recommendation.
|
·
|
In
September 2006, we announced our intention to file transmission and
distribution wires rate cases in Texas in late 2006. We anticipate
requesting an $83 million increase for TCC and a $25 million increase
for
TNC.
|
·
|
In
September 2006, we filed a notice of intent in Oklahoma to file a
base
rate case in November 2006.
|
·
|
In
October 2006, we filed state environmental permit applications for
clean-coal power plants in Ohio and West Virginia, representing another
step towards the commencement of construction of our IGCC
plants.
|
·
|
In
October 2006, we implemented an interim increase in Virginia retail
base
rates, subject to refund, as ordered by the Virginia SCC related
to our
$198 million net base rate case filing from May 2006. Hearings are
scheduled for December 2006.
|
·
|
In
October 2006, TCC issued $1.74 billion senior secured transition
bonds as
previously approved by the PUCT. In October 2006, TCC repaid $345
million
of intercompany notes to AEP and also paid a special dividend of
$585
million to AEP. We will use the remaining proceeds to reduce a portion
of
TCC’s debt and equity.
|
·
|
In
October 2006, the IURC denied our request to revise I&M’s book
depreciation rates without adjusting base tariff
rates.
|
Fuel
Costs
During
2006, spot market prices for coal and natural gas have declined. In contrast,
market prices for fuel oil have increased and continue to be volatile. We still
expect an approximate ten percent increase in coal costs during 2006 and a
six
to eight percent increase in 2007 even considering softening fuel markets and
favorable transportation effects during the first nine months of the year.
We
have price risk related to these commodity prices. We do not have an active
fuel
cost recovery adjustment mechanism in Ohio, which represents approximately
20%
of our fuel costs.
In
Indiana, our fuel recovery mechanism is temporarily capped, subject to
preestablished escalators, at a fixed rate through June 2007. As a consequence
of the cap, we incurred under-recoveries of $17 million for the first nine
months of 2006 and expect additional under-recoveries for the remainder of
2006.
Our Ohio companies increased their generation rates in 2006, as previously
approved by the PUCO in our Rate Stabilization Plans, which are intended to
recover increases in generation costs, including increased fuel costs. These
increased rates, along with the reinstated fuel cost adjustment rate clause
for
over- or under-recovery of fuel, off-system sales margins, certain transmission
items and related costs effective July 1, 2006 in West Virginia, will help
offset future negative impacts of fuel price increases on our gross
margins.
Barging
Operations
With
the
exception of the Plaquemine Cogeneration Facility impairment in the third
quarter of 2006, we achieved favorable 2006 results in our Investments - Other
segment primarily due to our barging operations. AEP MEMCO LLC (MEMCO) handles
the dispatching and logistics for our river operations, which consist primarily
of coal deliveries to our plants, coal movement between plants for ensuring
continued operations during market disruptions and transportation of bargeable
commodities for third parties. MEMCO continues to benefit from strong market
demand for barging services as well as a tight supply of barges, which allowed
it to negotiate favorable annual freight contracts for 2006 and beyond for
hauling a variety of commodities for third parties. The strong freight market,
enhanced operating conditions when compared with the flooding and ice
encountered during the first quarter of 2005, and the continued implementation
of programs to maximize equipment use, all contributed to an increase in tonnage
transported and a corresponding increase in earnings.
Power
Generation Facility
In
August
2006, we reached an agreement to sell our Plaquemine Cogeneration Facility
(the
Facility) to Dow Chemical Company (Dow) for $64 million. We expect the sale
to
close in the fourth quarter of 2006. We recorded a pretax impairment of $209
million ($136 million, net of tax) in the third quarter of 2006 based on
the
terms of the agreement to sell the Facility to Dow. In addition to the cash
proceeds, the sale agreement allows us to participate in gross margin sharing
on
the Facility for five years and we retain the right to any judgment paid
by TEM
for breaching the original PPA, as discussed in Note 5.
Assuming
the sale closes, our future earnings will be favorably impacted by eliminating
ongoing operating losses. These improvements will be partially offset by
interest expense associated with continuing debt service
obligations.
Dividend
Increase
In
October 2006, our Board of Directors approved a five percent increase in our
quarterly dividend to $0.39 per share from $0.37 per share.
RESULTS
OF OPERATIONS
Segments
Our
principal operating business segments and their major activities
are:
Utility
Operations
|
|
·
|
Generation
of electricity for sale to U.S. retail and wholesale
customers.
|
|
·
|
Electricity
transmission and distribution in the U.S.
|
Investments
- Other
|
|
·
|
Bulk
commodity barging operations, wind farms, IPPs and other energy
supply-related businesses.
|
Our
consolidated Income Before Discontinued Operations for the three and nine months
ended September 30, 2006 and 2005 were as follows (Earnings and Weighted Average
Number of Basic Shares Outstanding in millions):
|
|
Three
Months Ended September 30,
|
|
Nine
Months Ended September 30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
Earnings
|
|
EPS
(c)
|
|
Earnings
|
|
EPS
(c)
|
|
Earnings
|
|
EPS
(c)
|
|
Earnings
|
|
EPS
(c)
|
|
Utility
Operations
|
|
$
|
379
|
|
$
|
0.96
|
|
$
|
352
|
|
$
|
0.91
|
|
$
|
904
|
|
$
|
2.29
|
|
$
|
952
|
|
$
|
2.45
|
|
Investments
- Other
|
|
|
(109
|
)
(d)
|
|
(0.28
|
)
(d)
|
|
28
|
|
|
0.07
|
|
|
(80
|
)
(d)
|
|
(0.20
|
)
(d)
|
|
32
|
|
|
0.08
|
|
All
Other (a)
|
|
|
(2
|
)
|
|
-
|
|
|
(5
|
)
|
|
(0.01
|
)
|
|
(7
|
)
|
|
(0.02
|
)
|
|
(45
|
)
|
|
(0.12
|
)
|
Investments
- Gas Operations (b)
|
|
|
(3
|
)
|
|
(0.01
|
)
|
|
(10
|
)
|
|
(0.03
|
)
|
|
(2
|
)
|
|
-
|
|
|
(2
|
)
|
|
-
|
|
Income
Before Discontinued Operations
|
|
$
|
265
|
|
$
|
0.67
|
|
$
|
365
|
|
$
|
0.94
|
|
|
815
|
|
|
2.07
|
|
|
937
|
|
|
2.41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average Number of Basic
Shares Outstanding
|
|
|
|
|
|
394
|
|
|
|
|
|
389
|
|
|
|
|
|
394
|
|
|
|
|
|
389
|
|
(a)
|
All
Other includes the parent company’s guarantee revenues, interest income
and expense, as well as other nonallocated costs.
|
|
(b)
|
We
sold our remaining gas pipeline and storage assets in
2005.
|
|
(c)
|
The
earnings per share of any segment does not represent a direct legal
interest in the assets and liabilities allocated to any one segment
but
rather represents a direct equity interest in AEP’s assets and liabilities
as a whole.
|
|
(d) |
Loss primarily due to
an
after-tax impairment of $136 million (approximately $0.34 per share)
related to our Plaquemine Cogeneration Facility. |
|
Third
Quarter of 2006 Compared to Third Quarter of 2005
Income
Before Discontinued Operations in the third quarter of 2006 decreased $100
million compared to the third quarter of 2005 principally due to an impairment
of the Plaquemine Cogeneration Facility as a result of the pending sale and
decreases in Utility Operations earnings related to lower transmission revenues
from the loss of SECA rates and the write off of Virginia environmental and
reliability regulatory assets pursuant to a hearing examiner's recommendation,
which we have urged the Virginia SCC not to adopt. These decreases were
partially offset by an earnings increase in Utility Operations primarily related
to new retail rates implemented in Ohio and Kentucky and increased off-system
sales margins.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Income
Before Discontinued Operations for the nine months ended September 30, 2006
decreased $122 million compared to the nine months ended September 30, 2005
due
to a $48 million decrease in Utility Operations earnings from decreases in
transmission revenues from the loss of SECA rates and increases in operating
expenses, partially offset by new retail rates implemented in Ohio and Kentucky.
In addition, our Investments - Other segment earnings decreased $112 million
from an impairment of the Plaquemine Cogeneration Facility related to the
pending sale. These decreases were partially offset by a decrease of $38 million
in interest expense, net of interest income, at the parent company.
Our
results of operations are discussed below according to our operating
segments.
Utility
Operations
Our
Utility Operations include 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 margins represent utility operating revenues less the
related direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power.
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Revenues
|
|
$
|
3,441
|
|
$
|
3,237
|
|
$
|
9,209
|
|
$
|
8,623
|
|
Fuel
and Purchased Energy
|
|
|
1,384
|
|
|
1,252
|
|
|
3,637
|
|
|
3,163
|
|
Gross
Margin
|
|
|
2,057
|
|
|
1,985
|
|
|
5,572
|
|
|
5,460
|
|
Depreciation
and Amortization
|
|
|
369
|
|
|
328
|
|
|
1,041
|
|
|
963
|
|
Other
Operating Expenses
|
|
|
973
|
|
|
1,014
|
|
|
2,806
|
|
|
2,757
|
|
Operating
Income
|
|
|
715
|
|
|
643
|
|
|
1,725
|
|
|
1,740
|
|
Other
Income, Net
|
|
|
20
|
|
|
43
|
|
|
105
|
|
|
122
|
|
Interest
Expense and Preferred Stock Dividend Requirements
|
|
|
161
|
|
|
145
|
|
|
475
|
|
|
445
|
|
Income
Tax Expense
|
|
|
195
|
|
|
189
|
|
|
451
|
|
|
465
|
|
Income
Before Discontinued Operations
|
|
$
|
379
|
|
$
|
352
|
|
$
|
904
|
|
$
|
952
|
|
Summary
of Selected Sales and Weather Data
For
Utility Operations
For
the Three and Nine Months Ended September 30, 2006 and
2005
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
millions of KWH)
|
|
Energy
Summary
|
|
|
|
|
|
|
|
|
|
Retail:
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
13,482
|
|
|
14,152
|
|
|
36,010
|
|
|
37,332
|
|
Commercial
|
|
|
10,799
|
|
|
10,900
|
|
|
29,149
|
|
|
29,204
|
|
Industrial
|
|
|
13,468
|
|
|
13,380
|
|
|
40,405
|
|
|
39,633
|
|
Miscellaneous
|
|
|
677
|
|
|
682
|
|
|
1,890
|
|
|
1,968
|
|
Subtotal
|
|
|
38,426
|
|
|
39,114
|
|
|
107,454
|
|
|
108,137
|
|
Texas
Retail and Other
|
|
|
105
|
|
|
115
|
|
|
312
|
|
|
504
|
|
Total
Retail
|
|
|
38,531
|
|
|
39,229
|
|
|
107,766
|
|
|
108,641
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
|
13,465
|
|
|
13,135
|
|
|
35,131
|
|
|
37,515
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
Wires Delivery
|
|
|
7,877
|
|
|
8,093
|
|
|
20,338
|
|
|
20,348
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
KWHs
|
|
|
59,873
|
|
|
60,457
|
|
|
163,235
|
|
|
166,504
|
|
Cooling
degree days and heating degree days are metrics commonly used in the utility
industry as a measure of the impact of weather on results of operations. In
general, degree day changes in our eastern region have a larger effect on
results of operations than changes in our western region due to the relative
size of the two regions and the associated number of customers within each.
Cooling degree days and heating degree days in our service territory for the
quarter and year-to-date periods ended September 30, 2006 and 2005 were as
follows:
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
degree days)
|
|
Weather
Summary
|
|
|
|
|
|
|
|
|
|
Eastern
Region
|
|
|
|
|
|
|
|
|
|
Actual
- Heating (a)
|
|
|
10
|
|
|
1
|
|
|
1,573
|
|
|
1,940
|
|
Normal
- Heating (b)
|
|
|
7
|
|
|
7
|
|
|
1,999
|
|
|
1,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
- Cooling (c)
|
|
|
685
|
|
|
834
|
|
|
914
|
|
|
1,122
|
|
Normal
- Cooling (b)
|
|
|
688
|
|
|
674
|
|
|
970
|
|
|
955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western
Region
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
- Heating (a)
|
|
|
0
|
|
|
0
|
|
|
664
|
|
|
795
|
|
Normal
- Heating (b)
|
|
|
2
|
|
|
2
|
|
|
1,007
|
|
|
1,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
- Cooling (c)
|
|
|
1,468
|
|
|
1,523
|
|
|
2,325
|
|
|
2,225
|
|
Normal
- Cooling (b)
|
|
|
1,410
|
|
|
1,397
|
|
|
2,079
|
|
|
2,059
|
|
(a)
|
Eastern
Region and Western Region heating degree days are calculated on a
55
degree temperature base.
|
|
(b)
|
Normal
Heating/Cooling represents the 30-year average of degree
days.
|
|
(c)
|
Eastern
Region and Western Region cooling days are calculated on a 65 degree
temperature base.
|
|
(d)
|
Western
Region statistics represent PSO/SWEPCo customer base only.
|
|
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006
Income
from Utility Operations Before Discontinued Operations
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
352
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
29
|
|
|
|
|
Off-system
Sales
|
|
|
75
|
|
|
|
|
Transmission
Revenues
|
|
|
(38
|
)
|
|
|
|
Other
|
|
|
6
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
72
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Maintenance
and Other Operation
|
|
|
(15
|
)
|
|
|
|
Asset
Impairments and Other Related Charges
|
|
|
39
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(41
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
17
|
|
|
|
|
Other
Income, Net
|
|
|
(23
|
)
|
|
|
|
Interest
and Other Charges
|
|
|
(16
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(39
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
379
|
|
Income
from Utility Operations Before Discontinued Operations increased $27 million
to
$379 million in 2006. The key driver of the increase was a $72 million net
increase in Gross Margin, partially offset by a $39 million increase in
Operating Expenses and Other.
The
major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $29 million primarily due to the
following:
|
|
·
|
A
$72 million increase related to new rates implemented in our
Ohio
jurisdictions as approved by the PUCO in our Rate Stabilization
Plans
(RSPs) and a $12 million increase related to new rates implemented
in
Kentucky as approved in our base rate case;
|
|
·
|
A
$20 million increase related to increased sales to municipal,
cooperative
and other wholesale customers primarily as a result of new power
supply
contracts; and
|
|
·
|
An
$18 million increase related to the purchase of the Ohio service
territory
of Monongahela Power in December 2005; partially offset
by
|
|
·
|
A
$22 million decrease in financial transmission rights revenue,
net of
congestion, primarily due to fewer transmission constraints within
the PJM
market;
|
|
·
|
A
$33 million decrease related to increased refunds to retail customers
of a
portion of off-system sales margins due to higher off-system sales
and the
reinstatement of the off-system sales margins sharing mechanism
in West
Virginia effective July 1, 2006 in conjunction with the West Virginia
rate
case settlement;
|
|
·
|
A
$14 million increase in delivered fuel costs, which relates to
AEP East
companies with inactive, capped or frozen fuel clauses;
and
|
|
·
|
A
$30 million decrease in usage related to mild weather. As compared
to the
prior year, we experienced an 18% decrease in cooling degree days
in the
eastern region and a 4% decrease in the western region.
|
·
|
Margins
from Off-system Sales for 2006 increased $75 million primarily
due to
positive margins from hedges of plant output and strong physical
sales in
the east, where AEP’s generation availability factor was high in July and
August when wholesale prices were favorable.
|
·
|
Transmission
Revenues decreased $38 million primarily due to the elimination
of SECA
revenues as of April 1, 2006. At this time, we have a pending
proposal
with the FERC to replace SECA revenues. See the “Transmission Rate
Proceedings at the FERC” section of Note
3.
|
Utility
Operating Expenses and Other and Income Taxes changed between years as follows:
·
|
Maintenance
and Other Operation expenses increased $15 million primarily due
to
increases in generation expenses for base operations, maintenance
and an
abandonment of digital turbine control equipment at the Cook Plant,
increases in transmission and distribution expenses related to vegetation
management and storm restoration and the establishment of a regulatory
asset for PJM administrative fees in 2005 which reduced expenses
in the
prior period, offset by the establishment of a net regulatory asset
for
recovery of prior years’ Ohio ice storm damage costs and lower incentive
pay accruals.
|
·
|
Asset
Impairments and Other Related Charges were $39 million in 2005 due
to our
commitment to a plan in September 2005 to retire two units at our
Conesville Plant. We retired the two units effective December 29,
2005.
|
·
|
Depreciation
and Amortization expense increased $41 million primarily due to increased
Ohio regulatory asset amortization in conjunction with rate increases,
higher depreciable property balances and the write off of Virginia
environmental and reliability regulatory assets.
|
·
|
Taxes
Other Than Income Taxes decreased $17 million primarily due to adjustments
related to real and personal property taxes and sales and use
taxes.
|
·
|
Other
Income, Net decreased $23 million primarily related to the write
off of
carrying costs on Virginia environmental and reliability regulatory
assets.
|
·
|
Interest
and Other Charges increased $16 million primarily due to additional
debt
issued in late 2005 and early 2006 and an increase in regulatory
interest
related to Texas regulatory liabilities partially offset by an increase
in
allowance for borrowed funds used during construction.
|
·
|
Income
Tax Expense increased $6 million due to the increase in pretax
income.
|
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine Months Ended September 30, 2005 to Nine Months Ended September 30,
2006
Income
from Utility Operations Before Discontinued Operations
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
952
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
198
|
|
|
|
|
Off-system
Sales
|
|
|
2
|
|
|
|
|
Transmission
Revenues
|
|
|
(93
|
)
|
|
|
|
Other
|
|
|
5
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
112
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Maintenance
and Other Operation
|
|
|
(42
|
)
|
|
|
|
Gain
on Disposition of Assets, Net
|
|
|
(47
|
)
|
|
|
|
Asset
Impairments and Other Related Charges
|
|
|
39
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(78
|
)
|
|
|
|
Other
Income, Net
|
|
|
(16
|
)
|
|
|
|
Interest
and Other Charges
|
|
|
(30
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(174
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
904
|
|
Income
from Utility Operations Before Discontinued Operations decreased $48 million
to
$904 million in 2006. The key driver of the decrease was a $174 million increase
in Operating Expenses and Other, offset by a $112 million increase in Gross
Margin and a $14 million decrease in Income Tax Expense.
The
major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $198 million primarily due to the
following:
|
|
·
|
A
$175 million increase related to new rates implemented in our
Ohio
jurisdictions as approved by the PUCO in our RSPs, a $22 million
increase
related to new rates implemented in Kentucky as approved in our
base rate
case and a $12 million increase related to new rates implemented
in
Oklahoma in June 2005;
|
|
·
|
A
$21 million increase in financial transmission rights revenue,
net of
congestion, due to improved management of price risk related
to serving
retail load within PJM under current transmission
constraints;
|
|
·
|
A
$58 million increase related to increased usage and customer
growth in the
industrial and commercial classes of which $47 million relates
to the
purchase of the Ohio service territory of Monongahela Power in
December
2005; and
|
|
·
|
A
$50 million increase related to increased sales to municipal,
cooperative
and other wholesale customers primarily as a result of new power
supply
contracts; partially offset by
|
|
·
|
An
$84 million increase in delivered fuel cost, which relates to the
AEP East
companies with inactive, capped or frozen fuel clauses;
|
|
·
|
A
$66 million decrease in usage related to mild weather. As compared
to the
prior year, our eastern region and western region experienced 19%
and 17%
declines, respectively, in heating degree days. Also compared to
the prior
year, our eastern region experienced a 19% decrease in cooling
degree
days. These decreases were partially offset by an increase of 5%
in
cooling degree days in the western region; and
|
|
·
|
A
$15 million decrease related to increased refunds to retail customers
of a
portion of off-system sales margins due to higher off-system sales
and the
reinstatement of the off-system sales margins sharing mechanism
in West
Virginia effective July 1, 2006 in conjunction with the West Virginia
rate
case settlement.
|
·
|
Transmission
Revenues decreased $93 million primarily due to the elimination
of SECA
revenues as of April 1, 2006 and a provision of $19 million recorded
in
2006 related to potential SECA refunds pending settlement negotiations
with various intervenors. At this time, we have a pending proposal
with
the FERC to replace SECA revenues. See the “Transmission Rate Proceedings
at the FERC” section of Note
3.
|
Utility
Operating Expenses and Other and Income Taxes changed between years as follows:
·
|
Maintenance
and Other Operation expenses increased $42 million primarily due
to
increases in generation expenses related to base operations, maintenance
and planned and forced plant outages, distribution expenses related
to
vegetation management and the establishment of a regulatory asset
for PJM
administrative fees in 2005 which reduced expenses in the prior period.
These increases were partially offset by favorable variances related
to
expenses from the January 2005 ice storm in Ohio and Indiana, decreases
related to the sale of STP in May 2005 and lower incentive
accruals.
|
·
|
Asset
Impairments and Other Related Charges were $39 million in 2005 due
to our
commitment to a plan in September 2005 to retire two units at our
Conesville Plant. We retired the two units effective December 29,
2005.
|
·
|
Gain
on Disposition of Assets, Net decreased $47 million resulting from
revenues related to the earnings sharing agreement with Centrica
as
stipulated in the purchase-and-sale agreement from the sale of our
REPs in
2002. In 2005, we reached a settlement with Centrica and received
$112
million related to two years of earnings sharing whereas in 2006
we
received $70 million related to one year of earnings
sharing.
|
·
|
Depreciation
and Amortization expense increased $78 million primarily due to increased
Ohio regulatory asset amortization in conjunction with rate increases,
higher depreciable property balances and the write off of Virginia
environmental and reliability regulatory assets.
|
·
|
Other
Income, Net decreased $16 million primarily due to the write off
of
carrying costs on Virginia environmental and reliability regulatory
assets
and a decrease in Ohio carrying costs income as a result of the
implementation of the Ohio rate stabilization plans in January 2006,
partially offset by an increase in the allowance for equity funds
used
during construction.
|
·
|
Interest
and Other Charges increased $30 million from the prior period primarily
due to additional debt issued in late 2005 and early 2006 and increasing
interest rates, partially offset by an increase in allowance for
borrowed
funds used during construction.
|
·
|
Income
Tax Expense decreased $14 million due to the decrease in pretax
income.
|
Investments
- Other
Third
Quarter of 2006 Compared to Third Quarter of 2005
Loss
Before Discontinued Operations from our Investments - Other segment was $109
million in 2006 compared to income of $28 million in 2005. The change was
primarily due to a $136 million after-tax impairment of the Plaquemine
Cogeneration Facility related to the pending sale and a $32 million after-tax
gain on the sale of Pacific Hydro Limited in the third quarter of 2005,
partially offset by favorable barging activity at MEMCO due to strong demand
and
a tight supply of barges resulting in increased barge freight rates. Also,
the
third quarter 2006 operating conditions for our barging operations improved
from
2005 when Hurricane Katrina increased operating costs.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Loss
Before Discontinued Operations from our Investments - Other segment was $80
million in 2006 compared to income of $32 million in 2005. The change was
primarily due to a $136 million after-tax impairment of the Plaquemine
Cogeneration Facility related to the pending sale and a $32 million after-tax
gain on the sale of Pacific Hydro Limited in the third quarter of 2005,
partially offset by favorable barging activity at MEMCO due to strong demand
and
a tight supply of barges resulting in increased barge freight rates.
Additionally, 2006 operating conditions for our barging operations improved
from
2005 when hurricanes, severe ice and flooding caused increased operating
costs.
Other
Parent
Third
Quarter of 2006 Compared to Third Quarter of 2005
The
parent company’s Loss Before Discontinued Operations decreased $3 million from
2005 primarily due to lower interest expense as a result of the maturity of
senior unsecured notes of $396 million in the second quarter of 2006, partially
offset by higher interest expense due to the issuance of $345 million of senior
notes in June 2005.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
The
parent company’s Loss Before Discontinued Operations decreased $38 million from
2005 primarily due to lower interest expense and associated buyback costs
related to the redemption of $550 million of senior unsecured notes in April
2005 and increased affiliated interest income related to favorable results
from
the corporate borrowing program.
Investments
- Gas Operations
Third
Quarter of 2006 Compared to Third Quarter of 2005
The
Loss
Before Discontinued Operations from our Gas Operations segment improved $7
million primarily related to results from gas contracts that were not sold
with
the gas pipeline and storage assets.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
The
Loss
Before Discontinued Operations from our Gas Operations segment was essentially
flat. Prior year results included one month of HPL’s operations due to the sale
of HPL in January 2005. Current year results relate primarily to gas contracts
that were not sold with the gas pipeline and storage assets.
AEP
System Income Taxes
The
decrease in income tax expense of $63 million between the third quarter of
2006
and the third quarter of 2005 is primarily due to a decrease in pretax book
income.
The
decrease in income tax expense of $77 million between the nine months ended
September 30, 2006 and the nine months ended September 30, 2005 is primarily
due
to a decrease in pretax book income.
FINANCIAL
CONDITION
We
measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.
Debt
and Equity Capitalization
($ in millions)
|
|
September
30, 2006
|
|
December
31, 2005
|
|
Long-term
Debt, including amounts due within one year
|
|
$
|
12,763
|
|
|
57.0
|
%
|
$
|
12,226
|
|
|
57.2
|
%
|
Short-term
Debt
|
|
|
23
|
|
|
0.1
|
|
|
10
|
|
|
0.0
|
|
Total
Debt
|
|
|
12,786
|
|
|
57.1
|
|
|
12,236
|
|
|
57.2
|
|
Common
Equity
|
|
|
9,525
|
|
|
42.6
|
|
|
9,088
|
|
|
42.5
|
|
Preferred
Stock
|
|
|
61
|
|
|
0.3
|
|
|
61
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt and Equity Capitalization
|
|
$
|
22,372
|
|
|
100.0
|
%
|
$
|
21,385
|
|
|
100.0
|
%
|
The
amount of our common equity increased primarily due to earnings exceeding the
amount of dividends paid in 2006. As a result, our ratio of total debt to total
capital improved from 57.2% to 57.1%.
In
September 2006, the FASB issued SFAS 158 related to phase one of its pension
and
postretirement benefit accounting project. It could have a negative impact
on our debt to capital ratio when reported at December 31, 2006. The new
standard requires the recognition of an additional minimum liability for
fully-funded pension and postretirement benefit plans, thereby eliminating
on
the balance sheet the SFAS 87 and SFAS 106 deferral and amortization of net
actuarial gains and losses. This could require recognition of a significant
net-of-tax accumulated other comprehensive income reduction to common equity
for
those jurisdictions where a regulatory asset cannot be recorded. We estimate
regulatory assets could offset as much as two-thirds of any net-of-tax
accumulated other comprehensive income reduction. The effective date is
fiscal years ending after December 15, 2006.
Liquidity
Liquidity,
or access to cash, is an important factor in determining our financial
stability. We are committed to maintaining adequate liquidity.
Credit
Facilities
We
manage
our liquidity by maintaining adequate external financing commitments. At
September 30, 2006, our available liquidity was approximately $3.2 billion
as
illustrated in the table below:
|
|
Amount
|
|
Maturity
|
|
|
|
(in
millions)
|
|
|
|
Commercial
Paper Backup:
|
|
|
|
|
|
Revolving
Credit Facility
|
|
$
|
1,500
|
|
|
March
2010
|
|
Revolving
Credit Facility
|
|
|
1,500
|
|
|
April
2011
|
|
Total
|
|
|
3,000
|
|
|
|
|
Cash
and Cash Equivalents
|
|
|
259
|
|
|
|
|
Total
Liquidity Sources
|
|
|
3,259
|
|
|
|
|
Less:
Letter of Credit Drawn
|
|
|
34
|
|
|
|
|
Net
Available Liquidity
|
|
$
|
3,225
|
|
|
|
|
In
April
2006, we amended the terms and increased the size of our credit facilities
from
$2.7 billion to $3 billion on terms more economically favorable than the
previous agreements. The amended facilities are structured as two $1.5 billion
credit facilities, each with an option to issue up to $200 million as letters
of
credit.
Debt
Covenants and Borrowing Limitations
Our
revolving credit agreements contain covenants that 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, 2006, this contractually-defined
percentage was 54.2%. Nonperformance of these covenants could result in an
event
of default under these credit agreements. At September
30,
2006, 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 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.
The
two
amended revolving credit facilities do not contain a material adverse change
clause.
Under
a
regulatory order, our utility subsidiaries, other than TCC, cannot incur
additional indebtedness if the issuer’s common equity would constitute less than
30% of its capital. In addition, this order restricts the utility subsidiaries
from issuing long-term debt unless that debt will be rated investment grade
by
at least one nationally recognized statistical rating organization. At September
30, 2006, all utility subsidiaries were comfortably in compliance with this
order.
Utility
Money Pool borrowings and external borrowings may not exceed amounts authorized
by regulatory orders. At September 30, 2006, our utility subsidiaries had not
exceeded those authorized limits.
Credit
Ratings
AEP’s
ratings have not been adjusted by any rating agency during 2006 and AEP is
currently on a stable outlook by the rating agencies. 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,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
401
|
|
$
|
320
|
|
Net
Cash Flows From Operating Activities
|
|
|
2,213
|
|
|
1,699
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(2,474
|
)
|
|
(60
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
119
|
|
|
(1,110
|
)
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(142
|
)
|
|
529
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
259
|
|
$
|
849
|
|
Cash
from
operations, bank-sponsored receivables purchase agreement and short-term
borrowings provide working capital and allows us to meet other short-term cash
needs. 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,
2006, we had credit facilities totaling $3 billion to support our commercial
paper program without an outstanding balance. The maximum amount of commercial
paper outstanding during the nine months ended September 30, 2006 was $325
million. The weighted-average interest rate for our commercial paper during
the
first nine months of 2006 was 4.96%. We
generally use short-term borrowings to fund working capital needs, property
acquisitions and construction until long-term funding mechanisms are arranged.
Sources of long-term funding include issuance of common stock or long-term
debt
and sale-leaseback or leasing agreements. Utility Money Pool borrowings and
external borrowings may not exceed authorized limits under regulatory orders.
See the discussion below for further detail related to the components of our
cash flows.
Operating
Activities
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Net
Income
|
|
$
|
821
|
|
$
|
963
|
|
Less:
Discontinued Operations, Net of Tax
|
|
|
(6
|
)
|
|
(26
|
)
|
Income
Before Discontinued Operations
|
|
|
815
|
|
|
937
|
|
Noncash
Items Included in Earnings
|
|
|
1,164
|
|
|
987
|
|
Changes
in Assets and Liabilities
|
|
|
234
|
|
|
(225
|
)
|
Net
Cash Flows From Operating Activities
|
|
$
|
2,213
|
|
$
|
1,699
|
|
The
key
drivers of the increase in cash from operations for the first nine months of
2006 were no Pension Contributions to Qualified Plan Trusts in 2006 compared
with a $306 million contribution in 2005 and increased recovery of deferred
fuel. In
2005,
we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking
recovery of our increased fuel costs.
Net
Cash
Flows From Operating Activities were $2.2 billion in 2006 consisting primarily
of Income Before Discontinued Operations of $815 million adjusted for noncash
charges of $1.2 billion, which principally includes $1.1 billion for
Depreciation and Amortization. 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
these asset and liability accounts relates to a number of items; the most
significant is a $235 million decrease in cash related to customer deposits
held
for trading activities generally due to lower gas and power market
prices.
Net
Cash
Flows From Operating Activities were $1.7 billion in 2005 consisting primarily
of Income Before Discontinued Operations of $937 million adjusted for noncash
charges of $987 million, which principally includes $988 million for
Depreciation and Amortization. Changes
in Assets and Liabilities represent those 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 these asset and liability accounts relates to a
number of items; the most significant are a $311 million cash increase from
Customer Deposits held for trading activities and increases from Accounts
Payable and Accrued Taxes. Cash increased $173 million related to Accounts
Payable due to higher fuel and allowance acquisition costs not paid at September
30, 2005. Accrued Taxes increased due to the difference between the recording
of
the current federal income tax liability, the timing of required estimated
payments and the receipt of a prior year federal income tax refund. Our
consolidated tax group paid a total of $217 million in federal income taxes,
net
of refunds, during the first nine months of 2005. We also realized gains on
sales of assets of $172
million
and made
contributions of $306 million to our pension trust fund.
Investing
Activities
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Investment
Securities:
|
|
|
|
|
|
Purchases
of Investment Securities
|
|
$
|
(8,153
|
)
|
$
|
(4,319
|
)
|
Sales
of Investment Securities
|
|
|
8,056
|
|
|
4,378
|
|
Change
in Investment Securities, Net
|
|
|
(97
|
)
|
|
59
|
|
Construction
Expenditures
|
|
|
(2,445
|
)
|
|
(1,610
|
)
|
Acquisition
of Waterford Plant
|
|
|
-
|
|
|
(218
|
)
|
Change
in Other Temporary Cash Investments, Net
|
|
|
20
|
|
|
99
|
|
Proceeds
from Sales of Assets
|
|
|
120
|
|
|
1,599
|
|
Other
|
|
|
(72
|
)
|
|
11
|
|
Net
Cash Flows Used for Investing Activities
|
|
$
|
(2,474
|
)
|
$
|
(60
|
)
|
Net
Cash
Flows Used For Investing Activities were $2.5 billion in 2006 primarily due
to
Construction Expenditures supporting our environmental investment plan.
These
cash flows were consistent with our budgeted cash flows for investing activities
for the nine months ended September 30, 2006. We forecast $1.3 billion of
Construction Expenditures for the remainder of 2006, which will be funded
through results of operations and financing activities.
During
2006, we purchased $8.2 billion of investments and received $8.1 billion of
proceeds from the sales of securities. During 2005, we purchased $4.3 billion
of
investments and received $4.4 billion of proceeds from the sales of securities.
In our normal course of business, we purchase taxable and tax exempt securities
with cash available for short-term investments. The increased purchases and
sales in 2006 reflect our investing in expanded investment security types.
These
amounts also include purchases and sales within our nuclear trusts.
Net
Cash
Flows Used For Investing Activities were $60 million in 2005 primarily due
to
the proceeds from the sale of HPL and STP, a portion of which we used to
repurchase common stock and retire senior unsecured notes. Our Construction
Expenditures of $1.6 billion included generation, environmental, transmission
and distribution investment.
We
forecast $3.5 billion of construction expenditures for 2007, which will be
funded through results of operations and financing activities. These
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, legal reviews and
the ability to access capital.
Financing
Activities
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Issuance
of Common Stock
|
|
$
|
24
|
|
$
|
393
|
|
Repurchase
of Common Stock
|
|
|
-
|
|
|
(427
|
)
|
Issuance/Retirement
of Debt, Net
|
|
|
529
|
|
|
(562
|
)
|
Dividends
Paid on Common Stock
|
|
|
(437
|
)
|
|
(408
|
)
|
Other
|
|
|
3
|
|
|
(106
|
)
|
Net
Cash Flows From (Used for) Financing Activities
|
|
$
|
119
|
|
$
|
(1,110
|
)
|
Net
Cash
Flows From Financing Activities in 2006 were $119 million. During 2006, we
issued $115 million of new obligations relating to pollution control bonds,
issued $1 billion of senior unsecured notes and retired $396 million of senior
unsecured notes for a net increase in senior unsecured notes outstanding of
$604
million and retired $100 million of first mortgage bonds and $52 million of
securitization bonds. See Note 13 for a complete discussion of long-term debt
issuances and retirements.
Net
Cash
Flows Used For Financing Activities in 2005 were $1.1 billion. During 2005,
we
repurchased common stock and reduced outstanding long-term debt using the
proceeds from the sale of HPL and the conversion of the equity units to common
stock. In addition, our subsidiaries retired $66 million of cumulative preferred
stock, which is reflected in the Other amount in the above table. In
addition to the equity unit conversion, we had limited stock issuances related
to stock options exercised.
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 changed from year-end
as follows:
|
|
September
30,
2006
|
|
December
31,
2005
|
|
|
|
(in
millions)
|
|
AEP
Credit
|
|
$
|
548
|
|
$
|
516
|
|
Rockport
Plant Unit 2
|
|
|
2,437
|
|
|
2,511
|
|
Railcars
|
|
|
31
|
|
|
31
|
|
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 2005 Annual Report.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end other than the debt issuances and
retirements discussed in “Cash Flow” -
“Financing
Activities” above.
Other
Cook
Plant Outage
In
September 2006, Cook Plant Unit 1 began a regular scheduled refueling outage.
This outage includes the replacement of major components, including the reactor
vessel head. Installation of capital projects exceeding $100 million will be
completed during this outage and were included in our capital forecast. The
improvements and replacement of major components should increase unit capacity
and efficiency. We expect to restart Cook Plant Unit 1 in early November 2006
as
planned. We refueled Cook Plant Unit 2 during March and April 2006 and
plan to replace its vessel head during its next refueling outage in the fall
of
2007.
Texas
REPs
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 March of 2006, we received a $70 million
payment for our share in earnings for 2005. The payment for 2006 is contingent
on Centrica’s future operating results, contractually capped at $20 million and,
to the extent earned, is expected to be received and recorded in the first
quarter of 2007.
New
Generation
In
September 2005, PSO sought proposals for new peaking generation to be online
in
2008 and in December 2005 sought proposals for base load generation to be online
in 2011. PSO received proposals and evaluated those proposals meeting the
Request for Proposal criteria with oversight from neutral third parties. In
March 2006, PSO announced plans to add 170 MW of peaking generation to its
Riverside Station plant in Jenks, Oklahoma where PSO will construct and operate
two 85 MW simple-cycle natural gas combustion turbines. Also in March 2006,
PSO
announced plans to add 170 MW of peaking generation to its Southwestern Station
plant in Anadarko, Oklahoma where PSO will construct and operate two 85 MW
simple-cycle natural gas combustion turbines. Combined preliminary cost
estimates for these additions are approximately $120 million. In July 2006,
PSO
announced plans to enter a joint venture with Oklahoma Gas and Electric Company
(OG&E) where OG&E will construct and operate a new 950 MW coal-fueled
electricity generating unit near Red Rock, Oklahoma. PSO will own 50% of the
new
unit. Preliminary cost estimates for 100% of the new facility are approximately
$1.8 billion.
In
December 2005, SWEPCo sought proposals for new peaking, intermediate and base
load generation to be online between 2008 and 2011. In May 2006, SWEPCo
announced plans to construct new generation to satisfy the demands of its
customers. SWEPCo will build up to 480 MW of simple-cycle natural gas combustion
turbine peaking generation in Tontitown, Arkansas and will build a 480 MW
combined-cycle natural gas fired plant at the existing Arsenal Hill Power Plant
in Shreveport, Louisiana. SWEPCo also plans to build a new base load coal plant
by 2011 in Hempstead County, Arkansas to meet the longer-term generation needs
of its customers. Preliminary cost estimates for the new facilities are
approximately $1.4 billion (this total excludes the related transmission
investment).
The
2006
through 2008 estimated construction expenditures as disclosed in our
2005 Annual
Report on Form 10-K included cost estimates for these new facilities. All new
generation construction projects discussed above are subject to regulatory
approvals from the various states in which the subsidiaries operate.
Construction is expected to begin in 2007.
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 2005 Annual Report. The 2005 Annual Report should be read
in
conjunction with this report in order to understand significant factors without
material changes in status since the issuance of our 2005 Annual Report, but
may
have a material impact on our future results of operations, cash flows and
financial condition.
ERCOT
Transmission Project
In
October 2006, we announced our intent to form a joint venture company to
fund,
own and operate new electric transmission assets in ERCOT and we signed a
memorandum of understanding with MidAmerican Energy Holdings Co. (MidAmerican)
as our joint venture partner. We will contribute Texas transmission assets
currently under construction valued at approximately $100 million to the
joint
venture company. A MidAmerican subsidiary would make a cash contribution
to the
joint venture company. The equity ownership of the new company would be split
50-50 between AEP and MidAmerican with an anticipated utility capitalization
structure targeted at 40 percent equity and 60 percent debt. The joint venture
is anticipated to be active in 2007 and is subject to regulatory approval
from
the PUCT and the FERC.
We
believe there is a high degree of regulatory certainty for transmission
investment due to the predetermination of ERCOT’s need based on significant
Texas economic growth as well as “green generation” initiatives. In addition, a
streamlined annual interim transmission cost of service review process is
available, which will help reduce regulatory lag. The use of a joint venture
structure will allow us to reduce its up-front capital requirements for this
type of significant investment while allowing us to participate in more projects
than previously anticipated.
AEP
Interstate Project
In
January 2006, we filed a proposal with the FERC and PJM to build a new 765
kV
550-mile transmission line from West Virginia to New Jersey. The 765 kV line
is
designed to reduce PJM congestion costs by substantially improving west-east
peak transfer capability by approximately 5,000 MW and reducing transmission
line losses by up to 280 MW. It will also enhance reliability of the Eastern
transmission grid. A new subsidiary, AEP Transmission Co., LLC, will own the
line and undertake construction of the project. The projected cost for the
project is approximately $3 billion, of which ownership may be shared with
other
third party participants. The project is subject to PJM, state and federal
regulatory approvals and appropriate incentive cost recovery mechanisms. The
projected in-service date is 2014, assuming three years to site and acquire
rights-of-way and five years to construct the line. We were the first to file
with the Department of Energy (DOE) seeking to have the proposed route
designated a National Interest Electric Transmission Corridor (NIETC). The
Energy Policy Act of 2005 provides for NIETC designation for areas experiencing
electric energy transmission capacity constraints or congestion that adversely
affects consumers. In August 2006, the DOE issued the “National Electric
Transmission Congestion Study”. In this study, DOE indicated that the
mid-Atlantic Coastal area, where the AEP Interstate Project is designed to
reinforce, is one of the two most critical congestion areas in the nation.
This
finding should help AEP to obtain early National Interest Transmission Corridor
Designation as promulgated by the National Energy Policy Act of 2005. In October
2006, both AEP and PJM filed comments with the DOE encouraging corridor
designation that is consistent with the proposed line.
In
July
2006, the FERC granted conditional approval for incentive rate treatment for
the
proposed line. The approval is conditioned upon the new line being included
in
PJM’s formal Regional Transmission Expansion Plan to be finalized later this
year or in early 2007. The approved incentives include, (a) a return on equity
set at the high end of the “zone of reasonableness”; (b) the option to timely
recover the cost of capital associated with construction work in progress;
and
(c) the ability to defer expense and recover costs incurred during the
pre-construction and pre-operating period. Since the FERC approved these rate
making principles, we expect to implement the incentives in future
FERC rate filings.
Texas
Regulatory Activity
Texas
Restructuring
In
June
2006, TCC filed to implement a CTC refund of $357 million for its other true-up
items over eight years. The differences between the components of TCC’s Recorded
Net Regulatory Liabilities -
Other
True-up Items as of September 30, 2006 (including interest) and its Net CTC
Refund Proposed request are detailed below:
|
|
(in
millions)
|
|
Wholesale
Capacity Auction True-up
|
|
$
|
61
|
|
Carrying
Costs on Wholesale Capacity Auction True-up
|
|
|
31
|
|
Retail
Clawback including Carrying Costs
|
|
|
(65
|
)
|
Deferred
Over-recovered Fuel Balance
|
|
|
(184
|
)
|
Retrospective
ADFIT Benefit
|
|
|
(77
|
)
|
Other
|
|
|
(4
|
)
|
Recorded
Net Regulatory Liabilities - Other True-up Items
|
|
|
(238
|
)
|
Unrecorded
Prospective ADFIT Benefit
|
|
|
(240
|
)
|
Gross
CTC Refund Proposed
|
|
|
(478
|
)
|
FERC
Jurisdictional Fuel Refund Deferral
|
|
|
16
|
|
ADITC
and EDFIT Benefit Refund Deferral
|
|
|
98
|
|
Net
CTC Refund Proposed, After Deferrals
|
|
|
(364
|
)
|
True-up
Proceeding Expense Surcharge
|
|
|
7
|
|
Net
CTC Refund Proposed, After Deferrals and Expenses
|
|
$
|
(357
|
)
|
In
September 2006, the PUCT approved an interim CTC that was implemented on October
12, 2006, the same day that TCC began billing customers for the securitization
bonds. The interim CTC will refund the entire retail clawback of $65 million
(including carrying costs) by the end of 2006 to residential customers. The
CTC
refund to the other customer classes during the interim period will be as
proposed by TCC, with the exception of the large industrials, who will not
receive any fuel refunds during the interim period.
At
an
October 2006 open meeting, the PUCT announced oral decisions regarding the
CTC
refund. A final written order is expected in late November or early December
of
this year. In its decision, the PUCT confirmed that TCC can use securitization
bond proceeds to make the CTC refund. The PUCT’s decision was to continue the
interim CTC through December 2006 to complete the refund of the retail clawback
over three months. Beginning in January 2007, the Deferred Over-recovered Fuel
Balance will be refunded over six months with the large industrial customers
receiving their entire refund in January 2007. Starting in July 2007, the
remaining CTC items will be refunded over one year, except that the PUCT agreed
with TCC’s request to defer the refund of the ADITC and EDFIT Benefit Refund
Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above).
The
PUCT will decide those issues and related amounts in another
proceeding.
Municipal
customers and other intervenors appealed the PUCT orders seeking to further
reduce TCC’s true-up recoveries. If we determine, as a result of future PUCT
orders or appeal court rulings, that it is probable TCC cannot recover a portion
of its recorded net true-up regulatory asset and we are able to estimate the
amount of a resultant impairment, we would record a provision for such amount
which would have an adverse effect on future results of operations, cash flows
and possibly financial condition. TCC appealed the PUCT orders seeking relief
in
both state and federal court where it believes the PUCT’s rulings are contrary
to the Texas Restructuring Legislation, PUCT rulemakings and federal
law. The
significant items appealed by TCC are:
·
|
the
PUCT ruled that TCC did not comply with the statute and PUCT rules
regarding the auction of 15% of its Texas jurisdictional installed
capacity,
|
·
|
that
TCC acted in a manner that was commercially unreasonable because
it failed
to determine a minimum price at which it would reject bids for
the sale of
its nuclear generating plant and it bundled gas units with the
sale of its
coal unit,
|
·
|
and
two federal matters regarding the allocation of off-system sales
related
to fuel recoveries and the potential tax normalization
violation.
|
These
appeals could take years to resolve and could result in material effects on
future results of operations. If the PUCT rejects TCC’s deferral proposal and a
normalization violation occurs, future results of operations and cash flows
could be adversely affected by the recapture of $104 million of TCC’s ADITC and
the loss by TCC of future accelerated
tax depreciation election. The estimated future impact on earnings of the Texas
Restructuring as of September 30, 2006, exclusive of a possible normalization
violation and any effects of appeal litigation, over the 14-year securitization
net recovery period assuming the PUCT approves TCC’s CTC filing, including the
interim refund, is detailed below:
|
|
(in
millions)
|
|
ADITC
and EDFIT Benefits Reducing Securitization
|
|
$
|
98
|
|
ADFIT
Benefit Applied to Reduce 2002 Securitization of Regulatory Assets
|
|
|
(60
|
)
|
Securitization
Settlement
|
|
|
(77
|
)
|
Unrecorded
Prospective ADFIT Benefit Increasing the CTC Refund
|
|
|
(240
|
)
|
Unrecorded
Equity Carrying Costs Recognized as Collected
|
|
|
224
|
|
Future
Interest Payable on Proposed CTC Refund
|
|
|
(19
|
)
|
Deferred
Fuel - Federal Jurisdictional Issue
|
|
|
16
|
|
Net
Adverse Earnings Impact Over 14 Years
|
|
$
|
(58
|
)
|
If
the
PUCT changes its oral decision regarding the proposed CTC deferral and the
two
contingent federal matters are refunded to customers, the future adverse impact
on results of operations over the next 14 years will increase to $181 million.
This potential adverse impact on results of operations over the next 14 years
would be more than offset by the annual cost of money benefit from the $2.2
billion in net proceeds that resulted from the sale of bonds in connection
with
the initial regulatory asset securitization in 2002 of $797 million and from
the
$1.74 billion sale of securitization bonds in October 2006 less the proposed
$357 million CTC refund over the next eight years.
Litigation
In
the
ordinary course of business, we and 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 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 that have
a
probable likelihood of loss and the loss amount can be estimated. For details
on
our pending litigation and regulatory proceedings see Note 4 - Rate Matters,
Note 6 - Customer Choice and Industry Restructuring, Note 7 - Commitments and
Contingencies and the “Litigation” section of “Management’s Financial Discussion
and Analysis of Results of Operations” in the 2005 Annual Report. Additionally,
see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring
and Note 5 - Commitments and Contingencies included herein. Adverse results
in
these proceedings have the potential to materially affect the results of
operations, cash flows and financial condition of AEP and its
subsidiaries.
See
discussion of the Environmental Litigation within the “Environmental Matters”
section of “Significant Factors.”
Environmental
Matters
We
have
committed to substantial capital investments and additional operational costs
to
comply with new environmental control requirements. The sources of these
requirements include:
·
|
Requirements
under the CAA to reduce emissions of SO2,
NOx,
particulate matter and mercury from fossil fuel-fired power
plants;
|
·
|
Requirements
under the Clean Water Act to reduce the impacts of water intake structures
on aquatic species at certain of our power plants; and
|
·
|
Possible
future requirements to reduce carbon dioxide emissions to address
concerns
about global climate change.
|
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. All of these matters are discussed
in the “Environmental Matters” section of “Management’s Financial Discussion and
Analysis of Results of Operations” in the 2005 Annual Report.
Environmental
Litigation
New
Source Review (NSR) Litigation:
In 1999,
the Federal EPA and a number of states filed complaints alleging that APCo,
CSPCo, I&M, and OPCo modified certain units at coal-fired generating plants
in violation of the NSR requirements of the CAA. A separate lawsuit, initiated
by certain environmental intervenor groups, has been consolidated with the
Federal EPA case. Several similar complaints were filed in 1999 and 2000 against
other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky
Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin
Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these
cases were resolved through consent decrees. The alleged modifications at our
power plants occurred over a 20-year period. A bench trial on the liability
issues was held during July 2005. Briefing has concluded. In June 2006, the
judge stayed the liability decision pending the issuance of a decision by the
U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues,
if
necessary, is scheduled to begin four months after the U.S. Supreme Court
decision is issued.
Under
the
CAA, if a plant undertakes a major modification that directly results in an
emissions increase, permitting requirements might be triggered and the plant
may
be required to install additional pollution control technology. This requirement
does not apply to activities such as routine maintenance, replacement of
degraded equipment or failed components or other repairs needed for the
reliable, safe and efficient operation of the plant.
Courts
that considered whether the activities at issue in these cases are routine
maintenance, repair, or replacement, and therefore are excluded from NSR,
reached different conclusions. Similarly, courts that considered whether the
activities at issue increased emissions from the power plants reached different
results. Appeals on these and other issues were filed in certain appellate
courts, including a petition to appeal to the U.S. Supreme Court that was
granted in one case. The Federal EPA issued a final rule that would exclude
activities similar to those challenged in these cases from NSR as “routine
replacements.” In March 2006, the Court of Appeals for the District of Columbia
Circuit issued a decision vacating the rule. The Federal EPA filed a petition
for rehearing in that case, which the Court denied. The Federal EPA also
recently proposed a rule that would define “emissions increases” in a way that
would exclude most of the challenged activities from NSR.
We
are
unable to estimate the loss or range of loss related to any contingent liability
we might have for civil penalties under the CAA proceedings. We are also unable
to predict the timing of resolution of these matters due to the number of
alleged violations and the significant number of issues yet to be determined
by
the court. If we do not prevail, we believe we can recover any capital and
operating costs of additional pollution control equipment that may be required
through regulated rates and market prices for electricity. If we are unable
to
recover such costs or if material penalties are imposed, it would adversely
affect future results of operations, cash flows and possibly financial
condition.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Management’s Financial Discussion
and Analysis of Results of Operations” in the 2005 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
Beginning
in 2006, we adopted SFAS No. 123 (revised 2004) Share-Based Payment, on a
modified prospective basis, resulting in an insignificant favorable cumulative
effect of a change in accounting principle. Including stock-based compensation
expense related to employee stock options and other share based awards, did
not
materially affect our quarter-over-quarter and year-to-date net income and
earnings per share. We have not granted options as part of our regular
stock-based compensation program since 2003. However, we have used options
in limited circumstances totaling 149,000 options in 2004, 10,000 options in
2005 and none during 2006. As of September 30, 2006, we have $49.1
million of total unrecognized compensation cost related to unvested share-based
compensation arrangements. Our unrecognized compensation cost will be recognized
over a weighted-average period of 1.57 years. See Note 2 - New Accounting
Pronouncements in our Condensed Notes to Condensed Consolidated Financial
Statements for further discussion.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
As
a
major power producer and marketer of wholesale electricity, coal and emission
allowances, our Utility Operations segment is exposed to certain market risks.
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
Investment - Gas Operations segment holds forward gas contracts that were not
sold with the gas pipeline and storage assets. These contracts are primarily
financial derivatives, along with physical contracts, 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, exchange traded futures and options, over-the-counter options, swaps
and other derivative contracts to offset price risk where appropriate. We engage
in risk management of electricity, 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 controlled by commercial
operations, our Chief Risk Officer and risk management staff. When commercial
activities exceed predetermined limits, the positions are modified to reduce
the
risk to be within the limits unless specifically approved by the Risk Executive
Committee.
We
have
policies and procedures that allow us to identify, assess, and manage market
risk exposures in our day-to-day operations. Our risk policies have been
reviewed with our Board of Directors and approved by our Risk Executive
Committee. Our Chief Risk Officer administers our risk policies and procedures.
The Risk Executive Committee establishes risk limits, approves risk policies,
and assigns responsibilities regarding the oversight and management of risk
and
monitors risk levels. Members of this committee receive various daily, weekly
and/or monthly reports regarding compliance with policies, limits and
procedures. Our committee meets monthly and consists of the Chief Risk Officer,
senior executives, and other senior financial and operating
managers.
We
actively participate in the Committee of Chief Risk Officers (CCRO) to develop
standard disclosures for risk management activities around risk management
contracts. The CCRO is composed predominantly of chief risk officers of major
electricity and gas companies in the United States. The CCRO adopted disclosure
standards for risk management contracts to improve clarity, understanding and
consistency of information reported. Implementation of the disclosures is
voluntary. We support the work of the CCRO and have embraced the disclosure
standards applicable to our business activities. The following tables provide
information on our risk management activities.
Mark-to-Market
Risk Management Contract Net Assets (Liabilities)
The
following two tables summarize the various mark-to-market (MTM) positions
included in our condensed balance sheet as of September 30, 2006 and the reasons
for changes in our total MTM value included in our condensed balance sheet
as
compared to December 31, 2005.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
September
30, 2006
(in
millions)
|
|
Utility
Operations
|
|
Investments
- Gas Operations
|
|
Sub-Total
MTM Risk Management Contracts
|
|
PLUS:
MTM of Cash Flow and Fair Value Hedges
|
|
Total
|
|
Current
Assets
|
|
$
|
444
|
|
$
|
99
|
|
$
|
543
|
|
$
|
26
|
|
$
|
569
|
|
Noncurrent
Assets
|
|
|
337
|
|
|
130
|
|
|
467
|
|
|
4
|
|
|
471
|
|
Total
Assets
|
|
|
781
|
|
|
229
|
|
|
1,010
|
|
|
30
|
|
|
1,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(373
|
)
|
|
(99
|
)
|
|
(472
|
)
|
|
(24
|
)
|
|
(496
|
)
|
Noncurrent
Liabilities
|
|
|
(184
|
)
|
|
(137
|
)
|
|
(321
|
)
|
|
(3
|
)
|
|
(324
|
) |
Total
Liabilities
|
|
|
(557
|
)
|
|
(236
|
)
|
|
(793
|
)
|
|
(27
|
)
|
|
(820
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative
Contract Net Assets
(Liabilities)
|
|
$
|
224
|
|
$
|
(7
|
)
|
$
|
217
|
|
$
|
3
|
|
$
|
220
|
|
MTM
Risk Management Contract Net Assets (Liabilities)
Nine
Months Ended September 30, 2006
(in
millions)
|
|
Utility
Operations
|
|
Investments-Gas
Operations
|
|
Total
|
|
Total
MTM Risk Management Contract
Net Assets (Liabilities) at
December
31, 2005
|
|
$
|
215
|
|
$
|
(19
|
)
|
$
|
196
|
|
(Gain)
Loss from Contracts Realized/Settled During
the Period and Entered in a Prior Period
|
|
|
(8
|
)
|
|
10
|
|
|
2
|
|
Fair
Value of New Contracts at Inception When
Entered During the Period (a)
|
|
|
1
|
|
|
-
|
|
|
1
|
|
Net
Option Premiums Paid/(Received) for Unexercised
or Unexpired Option
Contracts
Entered During The Period
|
|
|
(1
|
)
|
|
-
|
|
|
(1
|
)
|
Changes
in Fair Value Due to Valuation Methodology
Changes on Forward Contracts
|
|
|
1
|
|
|
-
|
|
|
1
|
|
Changes
in Fair Value due to Market Fluctuations During the Period
(b)
|
|
|
19
|
|
|
2
|
|
|
21
|
|
Changes
in Fair Value Allocated to Regulated
Jurisdictions (c)
|
|
|
(3
|
)
|
|
-
|
|
|
(3
|
)
|
Total
MTM Risk Management Contract Net
Assets (Liabilities) at
September 30, 2006
|
|
$
|
224
|
|
$
|
(7
|
)
|
|
217
|
|
Net
Cash Flow and Fair Value Hedge Contracts
|
|
|
|
|
|
|
|
|
3
|
|
Ending
Net Risk Management Assets at September
30, 2006
|
|
|
|
|
|
|
|
$
|
220
|
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek 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)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
“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 Operations. These net gains (losses) are
recorded as regulatory assets/liabilities for those subsidiaries
that
operate in regulated jurisdictions. Approximately $7 million of the
regulatory deferral change is due to the change in the SIA. See the
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
(Liabilities)
The
following table presents:
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities, giving 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, 2006
(in
millions)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Utility
Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted - Exchange Traded Contracts
|
|
$
|
-
|
|
$
|
(9
|
)
|
$
|
22
|
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
12
|
|
Prices
Provided by Other External
Sources
- OTC Broker Quotes
(a)
|
|
|
(4
|
)
|
|
119
|
|
|
29
|
|
|
23
|
|
|
-
|
|
|
-
|
|
|
167
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(1
|
)
|
|
(15
|
)
|
|
5
|
|
|
19
|
|
|
28
|
|
|
9
|
|
|
45
|
|
Total
|
|
$
|
(5
|
)
|
$
|
95
|
|
$
|
56
|
|
$
|
41
|
|
$
|
28
|
|
$
|
9
|
|
$
|
224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments
-
Gas
Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted - Exchange Traded Contracts
|
|
$
|
-
|
|
$
|
7
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
7
|
|
Prices
Provided by Other External
Sources
- OTC Broker Quotes (a)
|
|
|
(2
|
)
|
|
(4
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(6
|
)
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
-
|
|
|
-
|
|
|
(2
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|
1
|
|
|
(8
|
)
|
Total
|
|
$
|
(2
|
)
|
$
|
3
|
|
$
|
(2
|
)
|
$
|
(4
|
)
|
$
|
(3
|
)
|
$
|
1
|
|
$
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted - Exchange Traded Contracts
|
|
$
|
-
|
|
$
|
(2
|
)
|
$
|
22
|
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
19
|
|
Prices
Provided by Other External
Sources
- OTC Broker Quotes (a)
|
|
|
(6
|
)
|
|
115
|
|
|
29
|
|
|
23
|
|
|
-
|
|
|
-
|
|
|
161
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(1
|
)
|
|
(15
|
)
|
|
3
|
|
|
15
|
|
|
25
|
|
|
10
|
|
|
37
|
|
Total
|
|
$
|
(7
|
)
|
$
|
98
|
|
$
|
54
|
|
$
|
37
|
|
$
|
25
|
|
$
|
10
|
|
$
|
217
|
|
(a)
|
Prices
Provided by Other External Sources - OTC Broker Quotes reflects
information obtained from over-the-counter (OTC) brokers, industry
services, or multiple-party on-line platforms.
|
(b)
|
Prices
Based on Models and Other Valuation Methods is in the absence of
pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity is limited, such valuations are classified as
modeled.
|
|
|
|
Contract
values that are measured using models or valuation methods other
than
active quotes or OTC broker quotes (because of the lack of such data
for
all delivery quantities, locations and periods) incorporate in the
model
or other valuation methods, to the extent possible, OTC broker quotes
and
active quotes for deliveries in years and at locations for which
such
quotes are available.
|
The
determination of the point at which a market is no longer liquid for placing
it
in the modeled category in the preceding table varies by market. The following
table reports an estimate of the maximum tenors (contract maturities) of the
liquid portion of each energy market.
Maximum
Tenor of the Liquid Portion of Risk Management Contracts
As
of September 30, 2006
Commodity
|
|
Transaction
Class
|
|
Market/Region
|
|
Tenor
|
|
|
|
|
|
|
(in
Months)
|
Natural
Gas
|
|
Futures
|
|
NYMEX
/ Henry Hub
|
|
60
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
Gulf
Coast, Texas
|
|
18
|
|
|
|
|
|
|
|
|
|
Swaps
|
|
Northeast,
Mid-Continent, Gulf Coast, Texas
|
|
18
|
|
|
|
|
|
|
|
|
|
Exchange
Option Volatility
|
|
NYMEX
/ Henry Hub
|
|
12
|
|
|
|
|
|
|
|
Power
|
|
Futures
|
|
AEP
East - PJM
|
|
36
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
AEP
East
|
|
39
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
AEP
West
|
|
39
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
West
Coast
|
|
39
|
|
|
|
|
|
|
|
|
|
Peak
Power Volatility (Options)
|
AEP
East - Cinergy, PJM
|
|
12
|
|
|
|
|
|
|
|
Emissions
|
|
Credits
|
|
SO2,
NOx
|
|
27
|
|
|
|
|
|
|
|
Coal
|
|
Physical
Forwards
|
|
PRB,
NYMEX, CSX
|
|
27
|
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
and remaining gas operations. We monitor these risks on our future operations
and may employ various commodity instruments and cash flow hedges to mitigate
the impact of these fluctuations on the future cash flows from assets. We do
not
hedge all commodity price risk.
We
employ
the use of 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.
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, 2005 to September 30, 2006.
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 effective 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 are included in the previous risk
management tables.
Total
Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow
Hedges
Nine
Months Ended September 30, 2006
(in
millions)
|
|
Power
and
Gas
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI, December 31, 2005
|
|
$
|
(6
|
)
|
$
|
(21
|
)
|
$
|
(27
|
)
|
Changes
in Fair Value
|
|
|
13
|
|
|
(3
|
)
|
|
10
|
|
Reclassifications
from AOCI to Net Income for Cash
Flow Hedges Settled
|
|
|
7
|
|
|
1
|
|
|
8
|
|
Ending
Balance in AOCI, September 30, 2006
|
|
$
|
14
|
|
$
|
(23
|
)
|
$
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
After-Tax
Portion Expected to be Reclassified to Earnings During Next 12
Months
|
|
$
|
15
|
|
$
|
(2
|
)
|
$
|
13
|
|
Credit
Risk
We
limit
credit risk in our 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. Only after an entity has met our internal credit rating
criteria will we extend unsecured credit. 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. We use our analysis,
in
conjunction with the rating agencies’ information, to determine appropriate risk
parameters. We also require cash deposits, letters of credit and
parental/affiliate guarantees as security from counterparties depending upon
credit quality in our normal course of business.
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. As of September 30, 2006, our credit
exposure net of credit collateral to sub investment grade counterparties was
approximately 2.56%, expressed in terms of net MTM assets and net receivables.
As of September 30, 2006, 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%
|
|
Net
Exposure
of
Counterparties
>10%
|
|
Investment
Grade
|
|
$
|
802
|
|
$
|
140
|
|
$
|
662
|
|
|
1
|
|
$
|
70
|
|
Split
Rating
|
|
|
4
|
|
|
4
|
|
|
-
|
|
|
1
|
|
|
-
|
|
Noninvestment
Grade
|
|
|
15
|
|
|
15
|
|
|
-
|
|
|
2
|
|
|
-
|
|
No
External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internal
Investment Grade
|
|
|
33
|
|
|
-
|
|
|
33
|
|
|
3
|
|
|
21
|
|
Internal
Noninvestment Grade
|
|
|
40
|
|
|
22
|
|
|
18
|
|
|
3
|
|
|
17
|
|
Total
as of September 30, 2006
|
|
$
|
894
|
|
$
|
181
|
|
$
|
713
|
|
|
10
|
|
$
|
108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of December 31, 2005
|
|
$
|
1,366
|
|
$
|
484
|
|
$
|
882
|
|
|
10
|
|
$
|
322
|
|
Generation
Plant Hedging Information
This
table provides information on operating measures regarding the proportion of
output of our generation facilities (based on economic availability projections)
economically hedged, including both contracts designated as cash flow hedges
under SFAS 133 and contracts not designated as cash flow hedges. This
information is forward-looking and provided on a prospective basis through
December 31, 2008. This table is a point-in-time estimate, subject to changes
in
market conditions and our decisions on how to manage operations and risk.
“Estimated Plant Output Hedged” represents the portion of MWHs of future
generation/production, taking into consideration scheduled plant outages, for
which we have sales commitments or estimated requirement obligations to
customers.
Generation
Plant Hedging Information
Estimated
Next Three Years
As
of September 30, 2006
|
Remainder
2006
|
|
2007
|
|
2008
|
Estimated
Plant Output Hedged
|
91%
|
|
88%
|
|
87%
|
VaR
Associated with Risk Management Contracts
Commodity
Price Risk
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, 2006, a near term typical change
in
commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
VaR
Model
Nine
Months Ended
September
30, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
millions)
|
|
|
|
|
(in
millions)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$2
|
|
$10
|
|
$3
|
|
$1
|
|
|
|
|
$3
|
|
$5
|
|
$3
|
|
$1
|
The
High
VaR for the nine months ended September 30, 2006 occurred in mid-August during
a
period of high gas and power price volatility. The following day, positions
were
flattened and the VaR was significantly reduced.
Interest
Rate Risk
We
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The volatilities and correlations were based
on
three years of daily prices. The risk of potential loss in fair value
attributable to our exposure to interest rates, primarily related to long-term
debt with fixed interest rates, was $550 million at September 30, 2006 and
$615
million at December 31, 2005. We would not expect to liquidate our entire debt
portfolio in a one-year holding period. Therefore, a near term change in
interest rates should not materially affect our results of operations, cash
flows or financial position.
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
For
the Three and Nine Months Ended September 30, 2006 and
2005
(in
millions, except per-share amounts)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
$
|
3,485
|
|
$
|
3,152
|
|
$
|
9,282
|
|
$
|
8,437
|
|
Gas
Operations
|
|
|
(47
|
)
|
|
73
|
|
|
(80
|
)
|
|
449
|
|
Other
|
|
|
156
|
|
|
103
|
|
|
436
|
|
|
326
|
|
TOTAL
|
|
|
3,594
|
|
|
3,328
|
|
|
9,638
|
|
|
9,212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
1,113
|
|
|
1,066
|
|
|
2,962
|
|
|
2,659
|
|
Purchased
Energy for Resale
|
|
|
267
|
|
|
181
|
|
|
670
|
|
|
494
|
|
Purchased
Gas for Resale
|
|
|
4
|
|
|
5
|
|
|
4
|
|
|
255
|
|
Maintenance
and Other Operation
|
|
|
904
|
|
|
873
|
|
|
2,634
|
|
|
2,588
|
|
Gain/Loss
on Disposition of Assets, Net
|
|
|
-
|
|
|
(1
|
)
|
|
(68
|
)
|
|
(116
|
)
|
Asset
Impairments and Other Related Charges
|
|
|
209
|
|
|
39
|
|
|
209
|
|
|
39
|
|
Depreciation
and Amortization
|
|
|
376
|
|
|
336
|
|
|
1,065
|
|
|
988
|
|
Taxes
Other Than Income Taxes
|
|
|
186
|
|
|
205
|
|
|
567
|
|
|
566
|
|
TOTAL
|
|
|
3,059
|
|
|
2,704
|
|
|
8,043
|
|
|
7,473
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
535
|
|
|
624
|
|
|
1,595
|
|
|
1,739
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
and Investment Income
|
|
|
22
|
|
|
18
|
|
|
41
|
|
|
43
|
|
Carrying
Costs Income
|
|
|
3
|
|
|
27
|
|
|
66
|
|
|
83
|
|
Allowance
For Equity Funds Used During Construction
|
|
|
12
|
|
|
5
|
|
|
25
|
|
|
17
|
|
Gain
on Disposition of Equity Investments, Net
|
|
|
-
|
|
|
56
|
|
|
3
|
|
|
56
|
|
Investment
Value Losses
|
|
|
-
|
|
|
(7
|
)
|
|
-
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST
AND OTHER CHARGES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
|
174
|
|
|
163
|
|
|
518
|
|
|
524
|
|
Preferred
Stock Dividend Requirements of Subsidiaries
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
6
|
|
TOTAL
|
|
|
175
|
|
|
164
|
|
|
520
|
|
|
530
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE, MINORITY INTEREST EXPENSE AND
EQUITY EARNINGS
|
|
|
397
|
|
|
559
|
|
|
1,210
|
|
|
1,401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
133
|
|
|
196
|
|
|
394
|
|
|
471
|
|
Minority
Interest Expense
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
3
|
|
Equity
Earnings of Unconsolidated Subsidiaries
|
|
|
2
|
|
|
3
|
|
|
1
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS
|
|
|
265
|
|
|
365
|
|
|
815
|
|
|
937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DISCONTINUED
OPERATIONS, Net of Tax
|
|
|
-
|
|
|
22
|
|
|
6
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
265
|
|
$
|
387
|
|
$
|
821
|
|
$
|
963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING
|
|
|
394
|
|
|
389
|
|
|
394
|
|
|
389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations
|
|
$
|
0.67
|
|
$
|
0.94
|
|
$
|
2.07
|
|
$
|
2.41
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
0.05
|
|
|
0.01
|
|
|
0.07
|
|
TOTAL
BASIC EARNINGS PER SHARE
|
|
$
|
0.67
|
|
$
|
0.99
|
|
$
|
2.08
|
|
$
|
2.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING
|
|
|
396
|
|
|
390
|
|
|
396
|
|
|
390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations
|
|
$
|
0.67
|
|
$
|
0.94
|
|
$
|
2.06
|
|
$
|
2.40
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
0.05
|
|
|
0.01
|
|
|
0.07
|
|
TOTAL
DILUTED EARNINGS PER SHARE
|
|
$
|
0.67
|
|
$
|
0.99
|
|
$
|
2.07
|
|
$
|
2.47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
DIVIDENDS PAID PER SHARE
|
|
$
|
0.37
|
|
$
|
0.35
|
|
$
|
1.11
|
|
$
|
1.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
Condensed Notes to Condensed Consolidated Financial
Statements.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(in
millions)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
259
|
|
$
|
401
|
|
Other
Temporary Cash Investments
|
|
|
198
|
|
|
127
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
751
|
|
|
826
|
|
Accrued
Unbilled Revenues
|
|
|
314
|
|
|
374
|
|
Miscellaneous
|
|
|
52
|
|
|
51
|
|
Allowance
for Uncollectible Accounts
|
|
|
(34
|
)
|
|
(31
|
)
|
Total Receivables
|
|
|
1,083
|
|
|
1,220
|
|
Fuel,
Materials and Supplies
|
|
|
810
|
|
|
726
|
|
Risk
Management Assets
|
|
|
569
|
|
|
926
|
|
Margin
Deposits
|
|
|
90
|
|
|
221
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
66
|
|
|
197
|
|
Other
|
|
|
100
|
|
|
127
|
|
TOTAL
|
|
|
3,175
|
|
|
3,945
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
16,712
|
|
|
16,653
|
|
Transmission
|
|
|
6,952
|
|
|
6,433
|
|
Distribution
|
|
|
11,179
|
|
|
10,702
|
|
Other
(including coal mining and nuclear fuel)
|
|
|
3,277
|
|
|
3,116
|
|
Construction
Work in Progress
|
|
|
2,848
|
|
|
2,217
|
|
Total
|
|
|
40,968
|
|
|
39,121
|
|
Accumulated
Depreciation and Amortization
|
|
|
15,146
|
|
|
14,837
|
|
TOTAL
- NET
|
|
|
25,822
|
|
|
24,284
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
3,196
|
|
|
3,262
|
|
Securitized
Transition Assets and Other
|
|
|
558
|
|
|
593
|
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,191
|
|
|
1,134
|
|
Investments
in Power and Distribution Projects
|
|
|
45
|
|
|
97
|
|
Goodwill
|
|
|
76
|
|
|
76
|
|
Long-term
Risk Management Assets
|
|
|
471
|
|
|
886
|
|
Employee
Benefits and Pension Assets
|
|
|
1,059
|
|
|
1,105
|
|
Other
|
|
|
682
|
|
|
746
|
|
TOTAL
|
|
|
7,278
|
|
|
7,899
|
|
|
|
|
|
|
|
|
|
Assets
Held for Sale
|
|
|
110
|
|
|
44
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
36,385
|
|
$
|
36,172
|
|
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, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
millions)
|
|
Accounts
Payable
|
$
|
1,180
|
|
$
|
1,144
|
|
Short-term
Debt
|
|
23
|
|
|
10
|
|
Long-term
Debt Due Within One Year
|
|
1,789
|
|
|
1,153
|
|
Risk
Management Liabilities
|
|
496
|
|
|
906
|
|
Accrued
Taxes
|
|
828
|
|
|
651
|
|
Accrued
Interest
|
|
192
|
|
|
183
|
|
Customer
Deposits
|
|
336
|
|
|
571
|
|
Other
|
|
752
|
|
|
842
|
|
TOTAL
|
|
5,596
|
|
|
5,460
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
Long-term
Debt
|
|
10,974
|
|
|
11,073
|
|
Long-term
Risk Management Liabilities
|
|
324
|
|
|
723
|
|
Deferred
Income Taxes
|
|
4,673
|
|
|
4,810
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
2,955
|
|
|
2,747
|
|
Asset
Retirement Obligations
|
|
975
|
|
|
936
|
|
Employee
Benefits and Pension Obligations
|
|
349
|
|
|
355
|
|
Deferred
Gain on Sale and Leaseback - Rockport Plant Unit 2
|
|
150
|
|
|
157
|
|
Deferred
Credits and Other
|
|
803
|
|
|
762
|
|
TOTAL
|
|
21,203
|
|
|
21,563
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
26,799
|
|
|
27,023
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
61
|
|
|
61
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
Common
Stock Par Value $6.50:
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
Shares
Authorized
|
|
|
600,000,000
|
|
|
600,000,000
|
|
|
|
|
|
|
|
Shares
Issued
|
|
|
415,979,691
|
|
|
415,218,830
|
|
|
|
|
|
|
|
(21,499,992
shares were held in treasury at September 30, 2006 and December
31,
2005)
|
|
2,704
|
|
|
2,699
|
|
Paid-in
Capital
|
|
4,153
|
|
|
4,131
|
|
Retained
Earnings
|
|
2,669
|
|
|
2,285
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
(1
|
)
|
|
(27
|
)
|
TOTAL
|
|
9,525
|
|
|
9,088
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
36,385
|
|
$
|
36,172
|
|
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, 2006 and 2005
(in
millions)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
821
|
|
$
|
963
|
|
Less:
Discontinued Operations, Net of Tax
|
|
|
(6
|
)
|
|
(26
|
)
|
Income
Before Discontinued Operations
|
|
|
815
|
|
|
937
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
1,065
|
|
|
988
|
|
Accretion
of Asset Retirement Obligations
|
|
|
47
|
|
|
50
|
|
Deferred
Income Taxes
|
|
|
(88
|
)
|
|
(33
|
)
|
Deferred
Investment Tax Credits
|
|
|
(20
|
)
|
|
(23
|
)
|
Asset
Impairments, Investment Value Losses and Other Related
Charges
|
|
|
209
|
|
|
46
|
|
Carrying
Costs Income
|
|
|
(66
|
)
|
|
(83
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(21
|
)
|
|
-
|
|
Amortization
of Nuclear Fuel
|
|
|
38
|
|
|
42
|
|
Deferred
Property Taxes
|
|
|
105
|
|
|
94
|
|
Pension Contributions to
Qualified Plan Trusts |
|
|
- |
|
|
(306 |
) |
Fuel
Over/Under-Recovery, Net
|
|
|
158
|
|
|
(183
|
)
|
Gain
on Sales of Assets and Equity Investments, Net
|
|
|
(71
|
)
|
|
(172
|
)
|
Change
in Other Noncurrent Assets
|
|
|
72
|
|
|
(84
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
(21
|
)
|
|
34
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
139
|
|
|
5
|
|
Fuel,
Materials and Supplies
|
|
|
(84
|
)
|
|
54
|
|
Accounts
Payable
|
|
|
(49
|
)
|
|
173
|
|
Accrued
Taxes
|
|
|
176
|
|
|
118
|
|
Customer
Deposits
|
|
|
(235
|
)
|
|
311
|
|
Other
Current Assets
|
|
|
142
|
|
|
(246
|
)
|
Other
Current Liabilities
|
|
|
(98
|
)
|
|
(23
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
2,213
|
|
|
1,699
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(2,445
|
)
|
|
(1,610
|
)
|
Acquisition
of Waterford Plant
|
|
|
-
|
|
|
(218
|
)
|
Change
in Other Temporary Cash Investments, Net
|
|
|
20
|
|
|
99
|
|
Purchases
of Investment Securities
|
|
|
(8,153
|
)
|
|
(4,319
|
)
|
Sales
of Investment Securities
|
|
|
8,056
|
|
|
4,378
|
|
Proceeds
from Sales of Assets
|
|
|
120
|
|
|
1,599
|
|
Other
|
|
|
(72
|
)
|
|
11
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(2,474
|
)
|
|
(60
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Common Stock
|
|
|
24
|
|
|
393
|
|
Repurchase
of Common Stock
|
|
|
-
|
|
|
(427
|
)
|
Change
in Short-term Debt, Net
|
|
|
11
|
|
|
(8
|
)
|
Issuance
of Long-term Debt
|
|
|
1,229
|
|
|
2,045
|
|
Retirement
of Long-term Debt
|
|
|
(711
|
)
|
|
(2,599
|
)
|
Dividends
Paid on Common Stock
|
|
|
(437
|
)
|
|
(408
|
)
|
Other
|
|
|
3
|
|
|
(106
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
119
|
|
|
(1,110
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(142
|
)
|
|
529
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
401
|
|
|
320
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
259
|
|
$
|
849
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
462
|
|
$
|
492
|
|
Net
Cash Paid for Income Taxes
|
|
|
206
|
|
|
277
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
66
|
|
|
42
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
334
|
|
|
182
|
|
Disposition
of Liabilities Related to Acquisitions/Divestitures, Net
|
|
|
-
|
|
|
20
|
|
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, 2006 and 2005
(in
millions)
(Unaudited)
|
|
Common
Stock
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
Shares
|
|
Amount
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Other
Comprehensive Income (Loss)
|
|
Total
|
|
DECEMBER
31, 2004
|
|
|
405
|
|
$
|
2,632
|
|
$
|
4,203
|
|
$
|
2,024
|
|
$
|
(344
|
)
|
$
|
8,515
|
|
Issuance
of Common Stock
|
|
|
10
|
|
|
65
|
|
|
328
|
|
|
|
|
|
|
|
|
393
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
(408
|
)
|
|
|
|
|
(408
|
)
|
Repurchase
of Common Stock
|
|
|
|
|
|
|
|
|
(427
|
)
|
|
|
|
|
|
|
|
(427
|
)
|
Other
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
17
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive
Income (Loss), Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign
Currency Translation Adjustments,
Net of Tax of $0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
|
(6
|
)
|
Cash
Flow Hedges, Net of Tax of $36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(67
|
)
|
|
(67
|
)
|
Minimum
Pension Liability, Net of Tax of $0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
4
|
|
Securities
Available for Sale, Net of Tax of $0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
1
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
963
|
|
|
|
|
|
963
|
|
TOTAL COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
895
|
|
SEPTEMBER
30, 2005
|
|
|
415
|
|
$
|
2,697
|
|
$
|
4,121
|
|
$
|
2,579
|
|
$
|
(412
|
)
|
$
|
8,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
|
415
|
|
$
|
2,699
|
|
$
|
4,131
|
|
$
|
2,285
|
|
$
|
(27
|
)
|
$
|
9,088
|
|
Issuance
of Common Stock
|
|
|
1
|
|
|
5
|
|
|
19
|
|
|
|
|
|
|
|
|
24
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
(437
|
)
|
|
|
|
|
(437
|
)
|
Other
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
3
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income, Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
|
|
|
18
|
|
Securities
Available for Sale, Net of Tax of $4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
8
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
821
|
|
|
|
|
|
821
|
|
TOTAL COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
847
|
|
SEPTEMBER
30, 2006
|
|
|
416
|
|
$
|
2,704
|
|
$
|
4,153
|
|
$
|
2,669
|
|
$
|
(1
|
)
|
$
|
9,525
|
|
See Condensed Notes to Condensed Consolidated Financial
Statements.
AMERICAN
ELECTRIC POWER, INC. AND SUBSIDIARY COMPANIES
INDEX
TO CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
|
|
|
1.
|
|
Significant
Accounting Matters
|
2.
|
|
New
Accounting Pronouncements
|
3.
|
|
Rate
Matters
|
4.
|
|
Customer
Choice and Industry Restructuring
|
5.
|
|
Commitments
and Contingencies
|
6.
|
|
Guarantees
|
7.
|
|
Company-wide
Staffing and Budget Review
|
8.
|
|
Acquisitions,
Dispositions, Discontinued Operations, Assets Held for Sale and Asset
Impairments
|
9.
|
|
Benefit
Plans
|
10.
|
|
Stock-Based
Compensation
|
11.
|
|
Income
Taxes
|
12.
|
|
Business
Segments
|
13.
|
|
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 accounting principles generally accepted in
the
United States of America (GAAP) for interim financial information and with
the
instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities
and
Exchange Commission (SEC). Accordingly, they do not include all the information
and footnotes required by GAAP for complete financial statements.
In
the
opinion of management, the unaudited interim financial statements reflect all
normal and recurring accruals and adjustments necessary for a fair presentation
of our results of operations, financial position and cash flows for the interim
periods. The results of operations for the three and nine months ended September
30, 2006 are not necessarily indicative of results that may be expected for
the
year ending December 31, 2006. The accompanying condensed consolidated financial
statements are unaudited and should be read in conjunction with the audited
2005
consolidated financial statements and notes thereto, which are included in
our
Annual Report on Form 10-K for the year ended December 31, 2005 as filed with
the SEC on March 1, 2006.
Components
of Accumulated Other Comprehensive Income (Loss)
Accumulated
Other Comprehensive Income (Loss) is included on our Condensed Consolidated
Balance Sheets in the common shareholders’ equity section. The following table
provides the components that constitute the balance sheet amount in Accumulated
Other Comprehensive Income (Loss):
|
|
September
30,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
Components
|
|
(in
millions)
|
|
Securities
Available for Sale, Net of Tax
|
|
$
|
27
|
|
$
|
19
|
|
Cash
Flow Hedges, Net of Tax
|
|
|
(9
|
)
|
|
(27
|
)
|
Minimum
Pension Liability, Net of Tax
|
|
|
(19
|
)
|
|
(19
|
)
|
Total
|
|
$
|
(1
|
)
|
$
|
(27
|
)
|
At
September 30, 2006, we expect to reclassify approximately $13 million of net
gains from cash flow hedges in Accumulated Other Comprehensive Income (Loss)
to
Net Income during the next twelve months at the time the hedged transactions
affect Net Income. The actual amounts that are reclassified from Accumulated
Other Comprehensive Income (Loss) to Net Income can differ as a result of market
fluctuations.
At
September 30, 2006, thirty-nine months
is
the maximum length of time that our exposure to variability in future cash
flows
is hedged with contracts designated as cash flow hedges.
Stock-Based
Compensation Plans
At
September 30, 2006, we have options outstanding under two stock-based employee
compensation plans: The Amended and Restated American Electric Power System
Long-Term Incentive Plan and the Central and South West Corporation Long-Term
Incentive Plan. We also grant performance share units, phantom stock units,
restricted shares and restricted stock units to employees, in accordance with
plans previously approved by shareholder votes.
On
January 1, 2006, we adopted SFAS No. 123 (revised 2004), “Share-Based Payment,”
(SFAS 123R) which requires the measurement and recognition of compensation
expense for all share-based payment awards made to employees and directors
including stock options and employee stock purchases based on estimated fair
values. See the SFAS 123 (revised 2004) “Share-Based Payment” section of Note 2
for additional discussion.
In
conjunction with the adoption of SFAS 123R, we changed our method of attributing
the value of stock-based compensation to expense from the accelerated
multiple-option approach to the straight-line single-option method. Compensation
expense for all share-based payment awards granted prior to January 1, 2006
will
continue to be recognized using the accelerated multiple-option approach while
compensation expense for all share-based payment awards granted on or after
January 1, 2006 is recognized using the straight-line single-option method.
As
stock-based compensation expense recognized in our Condensed Consolidated
Statements of Operations for the three and nine months periods ended September
30, 2006 is based on awards ultimately expected to vest, it has been reduced
for
estimated forfeitures. SFAS 123R requires forfeitures to be estimated at the
time of grant and revised, if necessary, in subsequent periods if actual
forfeitures differ from those estimates. In our pro forma information presented
below as required under SFAS 123 for the periods prior to 2006, we accounted
for
forfeitures as they occurred.
For
the
three and nine months ended September 30, 2005, no stock option expense was
reflected in Net Income as we accounted for stock options using the intrinsic
value method under Accounting Principles Board (APB) Opinion No. 25, “Accounting
For Stock Issued to Employees.” Under the intrinsic value method, no stock
option expense is recognized when the exercise price of the stock options
granted equals the fair value of the underlying stock at the date of grant.
During the first nine months of 2005 the Board of Directors granted 10,000
options. For the three and nine months ended September 30, 2006 and 2005,
compensation cost is included in Net Income for the performance share units,
phantom stock units, restricted shares, restricted stock units and the
Director’s stock units. See Note 10 for additional discussion.
Pro
Forma Information Under SFAS 123, “Accounting for Stock-Based Compensation,” for
Periods Presented Prior to January 1, 2006
The
following table shows the effect on our Net Income and Earnings Per Share as
if
we had applied fair value measurement and recognition provisions of SFAS
123 to
stock-based employee and director compensation awards for the three and nine
months ended September 30, 2005:
|
|
Three
Months
Ended
|
|
Nine
Months
Ended
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
|
|
Net
Income, As Reported
|
|
$
|
387
|
|
$
|
963
|
|
Add:
Stock-based Compensation Expense Included in Reported Net Income, Net
of Related Tax Effects
|
|
|
4
|
|
|
10
|
|
Deduct:
Stock-based Compensation Expense Determined Under Fair Value Based
Method for All Awards,
Net of Related Tax Effects
|
|
|
(5
|
)
|
|
(11
|
)
|
Pro
Forma Net Income
|
|
$
|
386
|
|
$
|
962
|
|
|
|
|
|
|
|
|
|
Earnings
Per Share:
|
|
|
|
|
|
|
|
Basic
- As Reported
|
|
$
|
0.99
|
|
$
|
2.48
|
|
Basic
- Pro Forma (a)
|
|
$
|
0.99
|
|
$
|
2.48
|
|
|
|
|
|
|
|
|
|
Diluted
- As Reported
|
|
$
|
0.99
|
|
$
|
2.47
|
|
Diluted
- Pro Forma (a)
|
|
$
|
0.99
|
|
$
|
2.47
|
|
(a)
|
The
pro forma amounts are not representative of the effects on reported
net
income for future years.
|
Earnings
Per Share (EPS)
The
following table presents our basic and diluted Earnings Per Share (EPS)
calculations included in our Condensed Consolidated Statements of
Operations:
|
|
Three
Months Ended September 30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
$/share
|
|
|
|
$/share
|
|
Earnings
applicable to common stock
|
|
$
|
265
|
|
|
|
|
$
|
387
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
number of basic shares outstanding
|
|
|
393.9
|
|
$
|
0.67
|
|
|
388.9
|
|
$
|
0.99
|
|
Average
dilutive effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
2.0
|
|
|
-
|
|
|
1.0
|
|
|
-
|
|
Stock
Options
|
|
|
0.2
|
|
|
-
|
|
|
0.5
|
|
|
-
|
|
Restricted
Stock Units
|
|
|
0.1
|
|
|
-
|
|
|
0.1
|
|
|
-
|
|
Restricted
Shares
|
|
|
0.1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Average
number of diluted shares outstanding
|
|
|
396.3
|
|
$
|
0.67
|
|
|
390.5
|
|
$
|
0.99
|
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
$/share
|
|
|
|
$/share
|
|
Earnings
applicable to common stock
|
|
$
|
821
|
|
|
|
|
$
|
963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
number of basic shares outstanding
|
|
|
393.8
|
|
$
|
2.08
|
|
|
388.7
|
|
$
|
2.48
|
|
Average
dilutive effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
1.6
|
|
|
(0.01
|
)
|
|
0.9
|
|
|
(0.01
|
)
|
Stock
Options
|
|
|
0.2
|
|
|
-
|
|
|
0.3
|
|
|
-
|
|
Restricted
Stock Units
|
|
|
0.1
|
|
|
-
|
|
|
0.1
|
|
|
-
|
|
Restricted
Shares
|
|
|
0.1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Average
number of diluted shares outstanding
|
|
|
395.8
|
|
$
|
2.07
|
|
|
390.0
|
|
$
|
2.47
|
|
Our
stock
option and other equity compensation plans are discussed in Note
10.
Related
Party Transactions
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
AEP
Consolidated Purchased Energy:
|
|
|
|
Ohio
Valley Electric Corporation (43.47% Owned)
|
|
$
|
54
|
|
$
|
49
|
|
$
|
167
|
|
$
|
140
|
|
Sweeny
Cogeneration Limited Partnership (50% Owned)
|
|
|
30
|
|
|
38
|
|
|
92
|
|
|
98
|
|
AEP
Consolidated Other Revenues - Barging and Other Transportation
Services - Ohio Valley Electric Corporation (43.47%
Owned)
|
|
|
8
|
|
|
6
|
|
|
23
|
|
|
14
|
|
Reclassifications
Certain
prior period financial statement items have been reclassified to conform to
current period presentation. These revisions had no impact on our
previously reported results of operations, financial condition or changes in
shareholders’ equity.
On
our
Condensed Consolidated Statements of Cash Flows, we included purchases and
sales
of investments within our Spent Nuclear Fuel and Decommissioning Trusts as
a
component of Investing Activities rather than Operating Activities.
2. NEW
ACCOUNTING PRONOUNCEMENTS
Upon
issuance of exposure drafts or 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 2006 that we determined relate to our operations.
SFAS
123 (revised 2004) “Share-Based Payment” (SFAS 123R)
In
December 2004, the FASB issued SFAS 123R. SFAS 123R requires entities to
recognize compensation expense in an amount equal to the fair value of
share-based payments granted to employees. The statement eliminates the
alternative to use the intrinsic value method of accounting previously available
under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock
Issued to Employees.” We recorded an insignificant cumulative effect of a change
in accounting principle in the first quarter of 2006 for the effect of initially
applying the statement primarily reflected in Maintenance and Other Operation
on
our Condensed Consolidated Statements of Operations.
In
March
2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, “Share-Based
Payment” (SAB 107), which conveys the SEC staff’s views on the interaction
between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides
the SEC staff’s views regarding the valuation of share-based payment
arrangements for public companies. Also, the FASB issued three FASB Staff
Positions (FSP) during 2005 and one in February 2006 that provided additional
implementation guidance. We applied the principles of SAB 107 and the applicable
FSPs in conjunction with our adoption of SFAS 123R.
We
adopted SFAS 123R in the first quarter of 2006 using the modified prospective
method. This method requires us to record compensation expense for all awards
granted after the time of adoption and recognize the unvested portion of
previously granted awards that remain outstanding at the time of adoption as
the
requisite service is rendered. The compensation cost is based on the grant-date
fair value of the equity award. Stock-based compensation expense recognized
during the period is based on the value of the portion of share-based payment
awards that is ultimately expected to vest during the period. Stock-based
compensation expense recognized in our Condensed Consolidated Statements of
Operations for the three and nine months ended September 30, 2006 includes
compensation expense for share-based payment awards granted prior to, but not
yet vested as of, January 1, 2006 based on the grant date fair value estimated
in accordance with the pro forma provisions of SFAS 123 and compensation expense
for the share-based payment awards granted subsequent to January 1, 2006 based
on the grant date fair value estimated in accordance with the provisions of
SFAS
123R. Our implementation of SFAS 123R did not materially affect our results
of
operations, cash flows or financial condition.
SFAS
157 “Fair Value Measurements”
In
September 2006, the FASB issued SFAS 157. SFAS 157 enhances existing guidance
for fair value measurement of assets and liabilities as well as instruments
measured at fair value that are classified in shareholders’ equity. SFAS 157
defines fair value, establishes a fair value measurement framework and expands
fair value disclosures. SFAS 157 emphasizes that fair value is market-based
with
the highest measurement hierarchy being market prices in active markets. The
standard will change current practice and requires fair value measurements
be
disclosed by hierarchy level. SFAS 157 requires an entity include its own credit
standing in the measurement of its liabilities and modifies the transaction
price presumption.
SFAS
157
is effective for interim and annual periods in fiscal years beginning after
November 15, 2007. We are currently in the process of determining the effect
this standard will have on our financial statements. Although SFAS 157 is
applied prospectively upon adoption, the effect of certain transactions is
applied retrospectively as of the beginning of the fiscal year of application,
with a cumulative effect adjustment to the appropriate balance sheet items.
SFAS
157 will be effective for us starting January 1, 2008.
SFAS
158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement
Plans”
In
September 2006, the FASB issued SFAS 158. SFAS 158 amends previous standards. It
requires employers to fully recognize the obligations associated with defined
benefit pension, retiree healthcare and other postretirement (OPEB) plans in
their balance sheets. Previous standards required an employer to disclose the
complete funded status of its plan only in the notes to the financial statements
and provided that an employer delay recognition of certain changes in plan
assets and obligations that affected the costs of providing benefits resulting
in an asset or liability that often differed from the plan’s funded status. SFAS
158 requires a defined benefit pension or postretirement plan sponsor (a)
recognize in its statement of financial position an asset for a plan’s
overfunded status or a liability for the plan’s underfunded status, (b) measure
the plan’s assets and its obligations that determine its funded status as of the
end of the employer’s fiscal year (with limited exceptions), and (c) recognize,
as a component of other comprehensive income, the changes in the funded status
of the plan that arise during the year but are not recognized as a component
of
net periodic benefit cost pursuant to SFAS 87, “Employers’ Accounting for
Pensions,” or SFAS 106, “Employer’s Accounting for Postretirement Benefits Other
Than Pensions.” It also requires an employer to disclose additional information
on how delayed recognition of certain changes in the funded status of a defined
benefit postretirement plan affects net periodic benefit costs for the next
fiscal year.
The
effect of SFAS 158 is to adjust AOCI at the end of each year, for both
underfunded and overfunded pension and OPEB plans, to an amount equal to the
remaining unrecognized SFAS 87 and SFAS 106 deferrals for unamortized actuarial
losses or gains, prior service costs, or transition obligations, such that
remaining deferred costs result in an AOCI equity reduction and deferred gains
result in an AOCI equity addition.
The
year-end AOCI measure is volatile based on fluctuating investment returns and
discount rates. Favorable changes include higher returns that increase plan
assets and higher discount rates that reduce the discounted benefit
obligation.
SFAS
158
is effective for initial recognition of a defined benefit postretirement plan
and related disclosure for fiscal years ending after December 15, 2006. We
have
not completed the process of determining the effect of this standard on our
financial statements, including whether a portion of the adjustment required
by
SFAS 158 can be deferred as a regulatory asset under SFAS 71.
EITF
Issue 06-3 “How Taxes Collected from Customers and Remitted to Governmental
Authorities Should Be Presented in the Income Statement (That Is, Gross versus
Net Presentation)” (EITF 06-3)
In
June
2006, the EITF reached a consensus on the income statement presentation of
various types of taxes. The scope of this issue includes any tax assessed by
a
governmental authority that is directly imposed on a revenue-producing
transaction between a seller and a customer and may include, but is not limited
to, sales, use, value added, and some excise taxes. The presentation of taxes
within the scope of this issue on either a gross (included in revenues and
costs) or a net (excluded from revenues) basis is an accounting policy decision
that should be disclosed pursuant to APB Opinion No. 22, “Disclosure of
Accounting Policies.” The EITF’s decision on gross/net presentation requires
that any such taxes reported on a gross basis be disclosed on an aggregate
basis
in interim and annual financial statements, for each period for which an income
statement is presented, if those amounts are significant.
EITF
06-3
is effective for fiscal years beginning after December 15, 2006. As disclosed
in
Note 1 of the 2005 Annual Report, we act as an agent for some state and local
governments and collect from customers certain excise taxes levied by those
state or local governments on our customers. Our policy is to present these
taxes on a net basis and we do not recognize these taxes as revenues or
expenses. Therefore, this issue will not have a material impact on our financial
statements.
FASB
Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN
48)
In
July
2006, the FASB issued FIN 48 which clarifies the application of SFAS 109,
“Accounting for Income Taxes.” FIN 48 clarifies the accounting for uncertainty
in income taxes recognized in an enterprise’s financial statements by
prescribing a recognition threshold (whether a tax position is more likely
than
not to be sustained) without which, the benefit of that position is not
recognized in the financial statements. It requires a measurement determination
for recognized tax positions based on the largest amount of benefit that is
greater than 50 percent likely of being realized upon ultimate settlement.
FIN
48 also provides guidance on derecognition, classification, interest and
penalties, accounting in interim periods, disclosure and
transition.
FIN
48
requires that the cumulative effect of applying this interpretation be reported
and disclosed as an adjustment to the opening balance of retained earnings
for
that fiscal year and presented separately. FIN 48 is effective for fiscal years
beginning after December 15, 2006. We have not completed the process of
determining the effect of this interpretation on our financial
statements.
SAB
No. 108 “Considering the Effects of Prior Year Misstatements When Quantifying
Misstatements in the Current Year Financial Statements” (SAB
108)
In
September 2006, the SEC staff issued SAB 108. SAB 108 addresses the diversity
in
practice when quantifying the effect of an error on financial statements. SAB
108 provides guidance on the consideration of the effects of prior year
misstatements in quantifying misstatements in current year financial statements.
We will be required to adopt the provisions of SAB 108 effective December 31,
2006. We believe that the adoption of SAB 108 will not have a material impact
on
our financial statements.
Future
Accounting Changes
The
FASB’s standard-setting process is ongoing and until new standards have been
finalized and issued by 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 business
combinations, revenue recognition, liabilities and equity, earnings per share
calculations, leases, insurance, subsequent events and related tax impacts.
We
also expect to see more FASB projects as a result of its desire to converge
International Accounting Standards with GAAP. The ultimate pronouncements
resulting from these and future projects could have an impact on our future
results of operations and financial position.
3. RATE
MATTERS
As
discussed in our 2005 Annual Report, our subsidiaries are involved in rate
and
regulatory proceedings at the FERC and state commissions. The Rate Matters
note
within our 2005 Annual Report should be read in conjunction with this report
to
gain a complete understanding of material rate matters still pending that could
impact results of operations and cash flows. Rate matters that are not believed
to be reasonably likely to affect future results of operations and cash flows
are not included in this report or the 2005 Annual Report. The following
sections discuss ratemaking developments in 2006 and update the 2005 Annual
Report.
APCo
Virginia Environmental and Reliability Costs
The
Virginia Electric Restructuring Act (the statute) includes a provision that
permits recovery, during the extended capped rate period ending December 31,
2010, of incremental environmental compliance and transmission and distribution
(T&D) system reliability (E&R) costs prudently incurred on and after
July 1, 2004. In 2005, APCo filed a request with the Virginia SCC and updated
it
through supplemental testimony seeking recovery of $21 million of incremental
E&R costs incurred from July 2004 through September 2005. Through August 31,
2006, APCo deferred as a regulatory asset $47 million of incremental E&R
costs incurred since July 1, 2004 based on a legal opinion that such costs
were
probable of recovery under the law.
In
January 2006, the Virginia SCC staff proposed that APCo be allowed to increase
its electric rates at an ongoing level of $20 million to recover current, rather
than past, incremental E&R costs. The staff proposal would effectively
disallow the recovery of costs incurred prior to the authorization and
implementation of new rates, including all incremental E&R costs that were
deferred as a regulatory asset. At the E&R hearings, which concluded in
March 2006, the staff amended its testimony to recommend a $24 million increase
in APCo’s ongoing rates. In September 2006, the Hearing Examiner issued a report
recommending adoption of the staff proposal with minor modifications, which
would result in (a) an on-going level of E&R cost recovery of $29 million
only if the Virginia SCC decides that any rate increase from the base rate
case
(described below) does not include the $29 million ongoing level of E&R
costs, and (b) the disallowance of all previously deferred incremental E&R
costs. In the third quarter of 2006, we concluded that the Virginia SCC might
not grant recovery of actual incremental E&R costs incurred during the
period from July 2004 through September 2006. Accordingly, we wrote off all
of
the E&R regulatory asset, adversely affecting pretax earnings by $36
million, net of the reinstatement of related AFUDC and capitalized interest.
We
believe that the staff’s proposal and the Hearing Examiner’s recommendation are
contrary to the statute. The Virginia SCC’s final order in this proceeding is
pending.
If
the
Virginia SCC properly implements the statute as interpreted in its October
2005
order and as supported by the Virginia Attorney General’s office in October
2006, we should be able to recover all of our incremental E&R costs
prudently incurred since July 1, 2004. If the Virginia SCC adopts the Hearing
Examiner's findings, based on advice of counsel, we will appeal the
decision.
APCo
Virginia Base Rate Case
In
May
2006, APCo filed a request with the Virginia SCC seeking an increase in base
rates of $225 million to recover increasing costs including the cost of its
investment in environmental equipment and a return on equity of 11.5%. In
addition, APCo requested to move off-system sales margins, currently credited
to
customers through base rates, to the fuel factor where they can be adjusted
annually. APCo also proposed to share the off-system sales margins with the
customers with 40% going to reduce rates and 60% being retained by APCo. This
resultant proposed off-system sales fuel rate credit, which is estimated to
be
$27 million, partially offsets the $225 million requested increase in base
rates
for a net increase in revenues of $198 million. The major components of the
$225
million rate request include $73 million for the impact of removing off-system
sales margins from the rate year ending September 30, 2007, $60 million mainly
due to projected net environmental plant additions through September 30, 2007
and $48 million for return on equity. In May 2006, the Virginia SCC issued
an
order, consistent with Virginia law, placing the net requested base rate
increase of $198 million into effect October 2, 2006, subject to refund. In
October 2006, the Virginia SCC staff filed their direct testimony recommending
a
base rate increase of $13 million. Other intervenors have recommended base
rate
increases ranging from $42 million to $112 million. APCo plans to file rebuttal
testimony in November 2006. Hearings are scheduled to begin in December 2006.
We
are unable to predict the ultimate effect of this filing on future revenues,
cash flows and financial condition.
APCo
and WPCo West Virginia Rate Case
In
July
2006, the WVPSC approved the settlement agreement APCo and WPCo reached with
the
WVPSC staff and intervenors in the West Virginia rate case filed in 2005. The
settlement agreement provided for an initial overall increase in rates of $44
million effective July 28, 2006 comprised of:
·
|
A
$56 million increase in Expanded Net Energy Cost (ENEC) for fuel,
purchased power expenses, off system sales credits and other energy
related costs;
|
·
|
A
$23 million special construction surcharge providing recovery of
the costs
of scrubbers and the new Wyoming-Jacksons Ferry 765 kV line to
date;
|
·
|
An
$18 million general base rate reduction resulting predominantly from
a
reduction in the return on equity to 10.5% and a $9 million reduction
in
depreciation expense which affects cash flows but not earnings;
and
|
·
|
A
$17 million credit to refund a portion of deferred prior over-recoveries
of ENEC of $51 million, recorded in regulatory liabilities on the
Condensed Consolidated Balance Sheets, which will impact cash flows
but
not earnings.
|
In
addition, the agreement provides a surcharge mechanism that allows APCo and
WPCo
to adjust their rates annually for the timely recovery in each of the next
three
years of the incremental cost of ongoing environmental investments in scrubbers
at APCo’s Mountaineer and John Amos power plants and the costs of the new
Wyoming-Jacksons Ferry 765 kV line. Although the amount of these annual
surcharge increases cannot be determined until the incremental costs are known
and reviewed by the WVPSC, APCo estimates that they will result in an annual
increase in revenues of $36 million effective July 1, 2007, $14 million
effective July 1, 2008 and $18 million effective July 1, 2009.
The
settlement further provides for the reinstatement of the ENEC mechanism
effective July 1, 2006 with over/under recovery deferral accounting and annual
ENEC proceedings to affect annual rate adjustments for changes in fuel and
purchased power costs beginning in 2007. The settlement provides for the return
to customers of the remaining $34 million of the prior ENEC regulatory liability
plus interest at a LIBOR rate on the unrefunded balance in future ENEC
proceedings.
I&M
Depreciation Study Filing
In
December 2005, I&M filed a petition with the IURC seeking authorization to
revise its book depreciation rates applicable to its electric utility plant
in
service effective January 1, 2006. Based on a depreciation study included in
the
filing, I&M recommended a decrease in pretax annual depreciation expense of
approximately $69 million on an Indiana jurisdictional basis reflecting an
NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2
and
an extension of the service life of the Tanners Creek coal-fired generating
units. This petition was not a request for a change in customers’ electric
service rates. A
public
hearing was held in May 2006 and the final brief was filed in June 2006.
As
proposed by I&M, the
book
depreciation expense reduction would increase earnings, but would not impact
cash flows until electric service rates are revised.
An
order
issued by the IURC on October 19, 2006 does not dispute our revised depreciation
accounting rates but, nevertheless, the IURC denied I&M's request to revise
its book depreciation rates between base rate cases. The IURC believes that
depreciation rates for an electric utility should not be changed between general
rate cases unless it was “absolutely essential” and a direct benefit to
customers was shown. I&M has twenty days in which to file for a rehearing or
reconsideration. We have not yet decided whether we will file for a rehearing
or
reconsideration or if and when we will file to adjust base rates to reflect
the
depreciation study.
KPCo
Rate Filing
In
March
2006, the KPSC approved the settlement agreement in KPCo’s 2005 base rate case.
The approved agreement provides for a $41 million annual increase in revenues
effective on March 30, 2006 and the retention of the existing environmental
surcharge tariff. No return on equity is specified by the settlement terms
except to note that KPCo will use a 10.5% return on equity to calculate the
environmental surcharge tariff and AFUDC.
PSO
Fuel and Purchased Power and its Possible Impact on AEP East companies and
AEP
West companies
In
2002,
PSO under-recovered $44 million of fuel costs resulting from a reallocation
among AEP West companies of purchased power costs for periods prior to January
1, 2002. In July 2003, PSO proposed collection of those reallocated costs over
18 months. In August 2003, the OCC staff filed testimony recommending PSO
recover $42 million of the reallocated purchased power costs over three years
and PSO reduced its regulatory asset deferral by $2 million. The OCC
subsequently expanded the case to include a full prudence review of PSO’s 2001
through 2003 fuel and purchased power practices. In January 2006, the OCC staff
and intervenors issued supplemental testimony alleging that AEP deviated from
the FERC-approved method of allocating off-system sales margins between AEP
East
companies and AEP West companies and among AEP West companies. The OCC staff
proposed that the OCC offset the $42 million of under-recovered fuel with their
proposed reallocation of off-system sales margins of $27 million to $37 million
and with $9 million attributed to wholesale customers, which they claimed had
not been refunded. In February 2006, the OCC staff filed a report concluding
that the $9 million of reallocated purchased power costs assigned to wholesale
customers had been refunded, thus removing that issue from their
recommendation.
In
2004,
an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO
deviated from the FERC-approved allocation methodology and held that any such
complaints should be addressed at the FERC. The OCC has not ruled on appeals
by
intervenors of the ALJ’s finding. The United States District Court for the
Western District of Texas issued orders in September 2005 regarding a TNC fuel
proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the
PUCT from reallocating off-system sales margins between the AEP East companies
and AEP West companies. The federal court agreed that the FERC has sole
jurisdiction over that allocation. The PUCT appealed the ruling.
PSO
does
not agree with the intervenors’ and the OCC staff’s recommendations and
proposals and will defend its position. If the OCC denies recovery of any
portion of the $42 million under-recovery of reallocated costs or offsets
under-recovered fuel deferrals with additional reallocated off-system sales
margins, our future results of operations and cash flows could be adversely
affected. However, if the position taken by the federal court in Texas applies
to PSO’s case, the OCC could be preempted from disallowing fuel recoveries for
alleged improper allocations of off-system sales margins between AEP East
companies and AEP West companies. The OCC or another party may file a complaint
at the FERC alleging the allocation of off-system sales margins adopted by
PSO
is improper which could result in an adverse effect on future results of
operations and cash flows for AEP and the AEP East companies. To date, there
has
been no claim asserted at the FERC that AEP deviated from the approved
allocation methodologies. Management is unable to predict the ultimate effect,
if any, of these Oklahoma fuel clause proceedings and any future FERC
proceedings on future results of operations, cash flows and financial
condition.
In
June
2005, the OCC issued an order directing its staff to conduct a prudence review
of PSO’s fuel and purchased power practices for the year 2003. The OCC staff
filed testimony finding no disallowances in the test year data. The Attorney
General of Oklahoma filed testimony stating that they could not determine if
PSO’s gas procurement activities were prudent, but did not include a recommended
disallowance. However, an intervenor filed testimony in June 2006 proposing
the
disallowance of $22 million in fuel costs based on a historical review of
potential hedging opportunities that existed during the year. A hearing was
held
in August 2006 and we expect a recommendation from the ALJ in the fourth quarter
of 2006.
In
February 2006, a law was enacted requiring the OCC to conduct prudence reviews
on all generation and fuel procurement processes, practices and costs on either
a two or three-year cycle depending on the number of customers served. PSO
is
subject to the required biennial reviews. The OCC staff indicated that it
expects the review process to begin in late 2006 or early 2007.
Management
cannot predict the outcome of the pending fuel and purchase power reviews or
planned future reviews, but believes that PSO’s fuel and purchased power
procurement practices and costs are prudent and properly incurred. If the OCC
disagrees and disallows fuel or purchased power costs including the unrecovered
2002 reallocation of such costs incurred by PSO, it would have an adverse effect
on future results of operations and cash flows.
PSO
Rate Filing
In
September 2006, PSO filed a notice of its intent to file in November 2006 a
plan
to modify the base rates of PSO’s Oklahoma jurisdictional customers with a
proposed effective date in the second quarter of 2007.
SWEPCo
Louisiana Fuel Inquiry
In
March
2006, the Louisiana Public Service Commission (LPSC) closed its inquiry into
SWEPCo’s fuel and purchased power procurement activities during the period
January 1, 2005 through October 31, 2005. The LPSC approved the LPSC staff’s
report, which concluded that SWEPCo’s activities were appropriate and did not
identify any disallowances or areas for improvement.
SWEPCo
PUCT Staff Review of Earnings
In
October 2005, the staff of the PUCT reported the results of its review of
SWEPCo’s year-end 2004 earnings. Based on the staff’s adjustments to the
information submitted by SWEPCo, the report indicates that SWEPCo is receiving
excess revenues of approximately $15 million. The staff engaged SWEPCo in
discussions to reconcile the earnings calculation and to consider possible
ways
to address the results. After those discussions, the PUCT staff informed SWEPCo
in April 2006 that they would not pursue the matter further.
SWEPCo
Louisiana Compliance Filing
In
October 2002, SWEPCo filed with the LPSC detailed financial information
typically utilized in a revenue requirement filing, including a jurisdictional
cost of service. This filing was required by the LPSC as a result of its order
approving the merger between AEP and CSW. In April 2004, at the request of
the
LPSC, SWEPCo filed updated financial information with a test year ending
December 31, 2003. Both filings indicated that SWEPCo’s rates should not be
reduced. Due to multiple delays, in April 2006, the LPSC and SWEPCo agreed
to
update the financial information based on a 2005 test year. SWEPCo filed updated
financial review schedules in May 2006 showing a return on equity of 9.44%
compared to the previously authorized return on equity of 11.1%.
In
July
2006, the LPSC staff’s consultants filed direct testimony recommending a base
rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana
jurisdiction customers, based on a proposed 10% return on equity. The
recommended reduction range is subject to SWEPCo validating certain ongoing
operations and maintenance expense levels and the recommended base rate
reduction does not include the impact of a proposed consolidated federal income
tax adjustment, which, if approved, would increase the proposed rate reduction.
SWEPCo filed rebuttal testimony in October 2006 strongly refuting the
consultants’ recommendations. Hearings are expected to occur late in the fourth
quarter of 2006. A decision is not expected until 2007. At this time, management
is unable to predict the outcome of this proceeding. If a rate reduction is
ultimately ordered, it would adversely impact future results of operations
and
cash flows.
TCC
and TNC Rate Filings
In
September 2006, we announced that TCC and TNC will each file transmission and
distribution wires rate cases in Texas in late 2006. We anticipate
requesting an $83 million annual increase for TCC and a $25 million annual
increase for TNC. Both requests include the impact of the expiration of
the CSW merger savings credits.
ERCOT
Price-to-Beat (PTB) Fuel Factor Appeal
Several
parties including the Office of Public Utility Counsel and cities served by
both
TCC and TNC appealed the PUCT’s December 2001 orders establishing initial PTB
fuel factors for Mutual Energy CPL and Mutual Energy WTU (TCC’s and TNC’s former
affiliated REPs, respectively). In June 2003, the District Court ruled the
PUCT
record lacked substantial evidence regarding the effect of loss of load due
to
retail competition on the generation requirements of both Mutual Energy WTU
and
Mutual Energy CPL and on the PTB rates. In an opinion issued in July 2005,
the
Texas Court of Appeals reversed the District Court. The cities appealed the
appeals court decision to the Supreme Court of Texas, which has ordered full
briefing, but has not granted review. Management cannot predict the outcome
of
further appeals, but a reversal of the favorable court of appeals decision
regarding the loss of load issue could result in the issue being returned to
the
PUCT for further consideration. If that were to happen and if the PUCT orders
refunds of PTB revenues, it could adversely impact results of operations and
cash flows for the portion of the refund applicable to the period of time that
TCC and TNC owned the REPs.
RTO
Formation/Integration Costs
In
2005,
the FERC approved the amortization of approximately $18 million of deferred
RTO
formation/integration costs not billed by PJM over 15 years and $17 million
of
deferred PJM-billed integration costs over 10 years. Total amortization related
to such costs was $1 million in both the third quarter of 2006 and 2005. In
the
first nine months of 2006 and 2005, total amortization related to such costs
was
$4 million and $3 million, respectively. As of September 30, 2006 and December
31, 2005, the AEP East companies had $30 million and $31 million, respectively,
of deferred unamortized RTO and PJM formation/integration costs.
In
a
December 2005 order, the FERC approved the inclusion of a separate rate in
the
PJM AEP zone OATT to recover the amortization of deferred RTO
formation/integration costs and related carrying costs not billed by PJM of
$2
million per year. The AEP East companies will be responsible for paying the
majority of the amortized costs assigned by the FERC to the AEP East zone since
their internal load is the bulk (about 85%) of the transmission load in the
AEP
zone. As a result, the AEP East companies will need to recover the 85% through
their retail rates.
In
May
2006, the FERC approved a settlement that provides for recovery over a ten-year
period of the PJM-billed integration costs, including related carrying charges,
of AEP, Commonwealth Edison Company (ComEd) and The Dayton Power & Light
Company (DP&L) from all present zones of the PJM region, except the Virginia
Electric & Power Company (VEPCo) zone. The net result of the settlement is
that the AEP East companies will recover approximately 50% of the deferred
PJM-billed integration costs from third parties, and will need to recover the
remaining 50% through retail rates.
As
a
result of recently approved rate increases, CSPCo, OPCo and KPCo recover the
amortization of RTO formation/integration costs billed to the AEP East companies
in Ohio and Kentucky. APCo received approval to include the amortization of
RTO
formation/integration costs in retail rates in West Virginia effective July
28,
2006. In Virginia, APCo filed a base rate case, which includes recovery of
these
costs when rates became effective October 2, 2006, subject to refund. In
Indiana, I&M is subject to a rate cap until June 30, 2007 and is precluded
from recovering its share of the deferred RTO costs until that date or until
it
can file for a rate increase in Indiana. I&M has not yet filed for recovery
in Michigan.
Until
I&M can adjust its retail rates in Indiana and Michigan to recover the
amortization of its deferred RTO formation/integration costs, results of
operations and cash flows will be adversely affected by approximately 15% of
the
amortizations. If the Virginia, Indiana or Michigan commissions disallow
recovery of any portion of the billed amortization of deferred RTO
formation/integration costs, it could result in a write off of up to 25% of
the
total remaining deferred balance, adversely impacting future results of
operations and cash flows. In the event of a disallowance, we would appeal
that decision to the appropriate state or federal courts.
Transmission
Rate Proceedings at the FERC
SECA
Revenue Subject to Refund
In
accordance with FERC orders, we collected SECA rates to mitigate lost
through-and-out transmission service (T&O) revenues from December 1, 2004
through March 31, 2006, when SECA rates expired. Intervenors objected to the
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 or surcharge. The AEP East companies also paid SECA rates to other
utilities at considerably lesser amounts than collected. If a refund is ordered,
we would also receive refunds related to the SECA rates we paid. The AEP East
companies recognized gross SECA revenues as follows:
|
|
(in
millions)
|
|
Three
Months Ended September 30, 2006
|
|
$
|
-
|
|
Three
Months Ended September 30, 2005
|
|
|
43
|
|
Nine
Months Ended September 30, 2006 (a)
|
|
|
43
|
|
Nine
Months Ended September 30, 2005
|
|
|
120
|
|
(a)
|
Represents
revenues through March 31, 2006, when SECA rates expired, and excludes
all
provisions for refund.
|
Approximately
$19 million of these recorded SECA revenues billed by PJM were never collected.
The AEP East companies filed a motion with the FERC to force payment of these
SECA billings.
A
hearing
in the SECA case was held in May 2006 to determine whether any of the SECA
revenues should be refunded. In August 2006, the 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 were not
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 unpaid SECA rates must be paid in the recommended reduced
amount.
Since
the
implementation of SECA rates in December 2004, the AEP East companies recorded
approximately $220 million of gross SECA revenues, subject to refund, and have
reached settlements with certain customers related to approximately $70 million
of such revenues. The unsettled gross SECA revenues total approximately $150
million. If the ALJ’s initial decision is upheld in its entirety, it would
disallow $126 million of the AEP East companies’ unsettled gross SECA revenues.
It would also provide refunds of SECA rates paid by the AEP East companies
in
considerably less significant amounts. Based on the completed settlements,
and
before the issuance of the ALJ’s initial decision, the AEP East companies
provided for $22 million in net refunds, of which $18 million was recorded
in
the second quarter of 2006 in Utility Operations Revenues on the Condensed
Consolidated Statements of Operations.
We,
together with Exelon and DP&L, filed an extensive brief noting exceptions to
the initial ALJ decision and asking the FERC to reverse the decision in large
part. Reply briefs were filed in October 2006. We
believe that the FERC should reject the initial ALJ decision because it is
contrary to prior related FERC decisions, which are presently subject to
rehearing. Furthermore, we believe the ALJ’s findings on key issues are largely
without merit. As a result, we have not provided for a possible refund of SECA
rates in excess of our current provisions. If the FERC does adopt the ALJ’s
recommendations, we will appeal the decision to the courts. Although we believe
we have meritorious arguments, management cannot predict the ultimate outcome
of
any future FERC proceedings or court appeals. If
the
FERC adopts the ALJ’s decision, it will have an adverse effect on future results
of operations and cash flows.
AEP
East Transmission Revenue Requirement and Rates
In
December 2005, the FERC approved an uncontested settlement which allowed
increases in our wholesale transmission OATT rates in three steps: first,
beginning retroactively on November 1, 2005, second, beginning on April 1,
2006
when the SECA revenues were eliminated and third, beginning on August 1, 2006
when the new Wyoming-Jacksons Ferry 765 kV line went into service. We estimate
that this rate increase will increase wholesale transmission revenues by $22
million in 2006 and $28 million in 2007.
The
Elimination of T&O and SECA Rates and the FERC PJM Regional Transmission
Rate Proceeding
In
a
separate proceeding, at our urging, the FERC instituted an investigation of
PJM’s zonal rate regime, indicating that the present rate regime may need to be
replaced through establishment of regional rates that would compensate AEP
and
other transmission owners for the regional transmission facilities they provide
to PJM, which provides service for the benefit of customers throughout PJM.
In
September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly
filed a regional transmission rate design proposal with the FERC. This filing
proposes and supports a new PJM rate regime generally referred to as
Highway/Byway.
Parties
to the regional rate proceeding proposed the following rate
regimes:
·
|
AEP/AP
proposed a Highway/Byway rate design in which:
|
|
·
|
The
cost of all transmission facilities in the PJM region operated
at 345 kV
or higher would be included in a “Highway” rate that all load serving
entities (LSEs) would pay based on peak demand. The AEP/AP proposal
would
produce about $125 million in additional revenues per year for
AEP from
users in other zones of PJM.
|
|
·
|
The
cost of transmission facilities operating at lower voltages would
be
collected in the zones where those costs are presently charged
under PJM’s
existing rate design.
|
·
|
Two
other utilities, Baltimore Gas & Electric Company (BG&E) and Old
Dominion Electric Cooperative (ODEC), proposed a Highway/Byway
rate that
includes transmission facilities above 200 kV, which would produce
lower
revenues than the AEP/AP proposal.
|
·
|
In
a competing Highway/Byway proposal, a group of LSEs proposed
rates that
would include existing 500 kV and higher voltage facilities and
new
facilities above 200 kV in the Highway rate, which would produce
considerably lower revenues than the AEP/AP proposal.
|
·
|
In
January 2006, the FERC staff issued testimony and exhibits supporting
a
PJM-wide flat rate or “Postage Stamp” type of rate design that would
include all transmission facilities, which would produce higher
transmission revenues than the AEP/AP
proposal.
|
All
of
these proposals were challenged by a majority of other transmission owners
in
the PJM region, who favor continuation of the PJM rate design. Hearings were
held in April 2006, and the ALJ issued an initial decision in July 2006. The
ALJ
found the existing PJM zonal rate design to be unjust and determined that it
should be replaced. The ALJ found that the Highway/Byway rates proposed by
AEP/AP and BG&E/ODEC would be just and reasonable alternatives; however, the
judge also found the Postage Stamp rate proposed by the FERC staff to be just
and reasonable, and recommended it be adopted. The ALJ also found that the
effective date of the rate change should be April 1, 2006 to coincide with
SECA
rate elimination. Because the Postage Stamp rate was found to produce greater
cost shifts than other proposals, the judge also recommended that the design
be
phased-in. Without a phase-in, the Postage Stamp method would produce somewhat
more revenue for AEP than the AEP/AP proposal, but the phase-in would delay
the
full impact of that result until about 2012.
We
filed
briefs noting exceptions to the initial decision and replies to the exceptions
of other parties. We argued that a phase-in should not be required.
Nevertheless, AEP argued that if the FERC adopts the Postage Stamp rate and
a
phase-in plan, the revenue collections curtailed by the phase-in should be
deferred and paid later, with interest. A FERC decision is likely in early
to
mid-2007.
From
the
elimination of T&O rates in December 2004 through the expiration of SECA
rates on March 31, 2006, SECA transition rates failed to fully compensate the
AEP East companies for their lost T&O revenues. Effective with the
expiration of the SECA transition rates on March 31, 2006, the increase in
the
AEP East zonal transmission rates applicable to AEP’s internal load and
wholesale transmission customers in AEP’s zone was not sufficient to replace the
prior T&O revenues or the lower temporary SECA transition rate revenues;
however, a favorable outcome in the PJM regional transmission rate proceeding,
made retroactive to April 1, 2006 could mitigate a large portion of the
shortfall. Full mitigation of the effects of eliminated T&O revenues and the
less favorable terminated SECA revenues will require cost recovery through
state
retail rate proceedings pending any resolution that may result from the above
FERC regional transmission rate proceeding. The status of such state retail
rate
proceedings is as follows:
·
|
In
Kentucky, KPCo settled a rate case, which provided for the recovery
of its
share of the transmission revenue reduction in new rates effective
March
30, 2006.
|
·
|
In
Ohio, CSPCo and OPCo recover the FERC-approved OATT which reflects
their
share of the full transmission revenue requirement retroactive to
April 1,
2006 under a May 2006 PUCO order.
|
·
|
In
West Virginia, APCo settled a rate case, which provided for the recovery
of its share of the T&O/SECA transmission revenue reduction beginning
July 28, 2006.
|
·
|
In
Virginia, APCo filed a request for revised rates, which includes
recovery
of its share of the T&O/SECA transmission revenue reduction starting
October 2, 2006, subject to refund.
|
·
|
In
Indiana, I&M is precluded by a rate cap from raising its rates until
July 1, 2007.
|
·
|
In
Michigan, I&M has not yet filed to seek recovery of the lost
transmission revenues.
|
We
presently recover from retail customers approximately 65% of the reduction
in
transmission revenues of $128 million a year. On October 2, 2006, when new
base
rates went into effect subject to refund in Virginia, that percentage increased
to 80%.
Once
approved by the FERC, the favorable impacts of the new regional PJM rate design
will flow directly to wholesale customers and to retail customers in West
Virginia through the ENEC and to retail customers in Ohio upon PUCO approval
of
a filing we would make to reflect the new rates. In Kentucky, Indiana, Virginia
and Michigan, the additional transmission revenues can be expected to reduce
retail rates in future base rate proceedings.
We
believe that the AEP/AP proposal or the Postage Stamp proposal
combined with the retail recovery discussed above would be an effective
replacement for the eliminated T&O and SECA rates.
Management
is unable to predict whether the FERC will approve either the ALJ’s decision or
another regional rate design. Future results of operations, cash flows and
financial condition would be adversely affected if the approved FERC
transmission rates are not sufficient to replace the lost T&O/SECA revenues
and the resultant increase in the AEP East companies’ unrecovered transmission
costs are not fully recovered in retail rates in Indiana and
Michigan.
Calpine
Oneta Power, L.P.’s Request at the FERC for Reactive Power Compensation From
SPP
In
April
2003, Calpine Oneta Power (Calpine), an IPP, filed at the FERC a proposed rate
schedule to charge SPP for reactive power from Calpine’s generating facility.
The FERC rate schedule included a fixed annual fee of $2 million. PSO, SWEPCO
and a small portion of TNC operate in SPP. An ALJ initially ruled against
Calpine and we concluded that the likelihood of the FERC awarding Calpine a
reactive power capacity rate was remote. In September 2006, the FERC issued
its
decision reversing the ALJ decision, granting Calpine’s request and requiring
Calpine to make a compliance filing within 30 days. Our share of this SPP
expense could be approximately 90% of the total amount billed by Calpine. Based
on this information, we recorded an expense provision, including interest,
of $8
million in September 2006 for the retroactive reactive power liability. We
will
seek rehearing at the FERC and may appeal the decision if the FERC either denies
rehearing or rules in favor of Calpine on rehearing.
Allocation
Agreement between AEP East companies and AEP West companies and CSW Operating
Agreement
The
SIA
provides, among other things, for the methodology of sharing trading and
marketing margins between the AEP East companies and AEP West companies. In
March 2006, the FERC approved our proposed methodology effective April 1, 2006
and beyond. The approved allocation methodology for the AEP East companies
and
AEP West companies is based upon the location of the specific trading and
marketing activity, with margins resulting from trading and marketing activities
originating in PJM and MISO generally accruing to the benefit of the AEP East
companies and trading and marketing activities originating in SPP and ERCOT
generally accruing to the benefit of PSO and SWEPCo. Previously, the SIA
allocation provided for a different method of sharing all such margins between
both AEP East companies and AEP West companies, which effectively allowed the
AEP West companies to share in PJM and MISO regional margins. In February 2006,
we filed with the FERC to remove TCC and TNC from the SIA and CSW Operating
Agreement because they are in the final stages of exiting the generation
business and have already ceased serving retail load. The FERC approved the
removal of TCC and TNC from the SIA and CSW Operating Agreement effective May
1,
2006.
The
impact on future results of operations and cash flows will depend upon the
level
of future margins by region and the status of expanded net energy fuel clause
recovery mechanisms and related off-system sales sharing mechanisms by state.
Our total trading and marketing margins are unaffected by the allocation
methodology.
4. CUSTOMER
CHOICE AND INDUSTRY RESTRUCTURING
We
are
affected by customer choice initiatives and industry restructuring. The Customer
Choice and Industry Restructuring note in our 2005 Annual Report should be
read
in conjunction with this report to gain a complete understanding of material
customer choice and industry restructuring matters without significant changes
since year-end. The following paragraphs discuss significant events occurring
in
2006 related to customer choice and industry restructuring and update the 2005
Annual Report.
TEXAS
RESTRUCTURING
In
February 2006, the PUCT issued an order in TCC’s $2.4 billion True-up
Proceeding, which determined that TCC’s true-up regulatory asset was $1.475
billion including carrying costs through September 2005. In December 2005,
TCC
adjusted its recorded net true-up regulatory asset to comply with the order.
The
PUCT issued an order on rehearing in April 2006, which made minor changes to,
but otherwise affirmed, the February 2006 order. We appealed, seeking additional
recovery consistent with the Texas Restructuring Legislation and related rules.
Other parties appealed the PUCT’s true-up order claiming it permits TCC to
over-recover stranded generation costs and other true-up items.
TCC
Securitization Proceeding
TCC
filed
an application in March 2006 requesting recovery through securitization of
$1.8
billion of net stranded generation plant costs and related carrying costs
through August 31, 2006. The $1.8 billion request did not include TCC’s negative
other true-up items, which total $478 million. See “CTC Proceeding for Other
True-up Items” section of this note. Intervenors and the PUCT staff filed
testimony regarding TCC’s securitization request in April 2006. In May 2006, TCC
filed a letter with the PUCT reducing its request by $6 million of current
carrying costs and reduced the recorded net recoverable regulatory asset by
the
recorded debt-related component. In May 2006, TCC and the other parties filed
a
settlement with the PUCT, which further reduced the securitizable amount by
$77
million and settled several issues that would have delayed the sale of the
securitization bonds. The PUCT approved the settlement in June 2006 authorizing
$1.697 billion including carrying costs through August 31, 2006, the assumed
securitization date, plus estimated issuance costs of $23 million, for a total
of $1.72 billion. We issued TCC securitization bonds on October 11, 2006 for
$1.74 billion, including additional issuance costs and carrying costs to October
11, 2006.
TCC
performed a probability of recovery impairment test on its net true-up
regulatory asset taking into account the treatment ordered by the PUCT. We
determined that the projected cash flows from the securitization less the
proposed CTC refund would be more than sufficient to recover TCC’s recorded net
true-up regulatory asset due to the existence of $224 million of unrecorded
equity-related carrying costs which are not recorded until collected in
regulated rates. As a result, no additional impairment was recorded for the
approved reduction in the amount to be securitized. However, the $77 million
agreed upon reduction in the securitizable amount will have a negative impact
on
future earnings.
Consistent
with certain prior securitization determinations, the PUCT issued a specific
order in the securitization proceeding that calculated a $315 million
cost-of-money benefit from true-up related ADFIT through August 2006, of which
$75 million ($77 million through September 30, 2006) relates to the recorded
benefit prior to the date of securitization and $240 million relates to the
unrecorded benefit subsequent to the date of securitization. The PUCT included
the $315 million ADFIT-related stranded cost benefit in the CTC refund of $478
million. In June 2006, we transferred the effects of the ADFIT on recorded
carrying costs from the securitizable asset to the CTC refund, thereby
increasing the carrying costs identified to the securitizable assets in the
table below.
The
differences between the securitization amount ordered by the PUCT of $1.74
billion and the Recorded Securitizable True-up Regulatory Asset of $1.57 billion
by component at September 30, 2006 are detailed in the table below:
|
|
(in
millions)
|
|
Stranded
Generation Plant Costs
|
|
$
|
974
|
|
Net
Generation-related Regulatory Asset
|
|
|
249
|
|
Excess
Earnings
|
|
|
(49
|
)
|
Recorded
Net Stranded Generation Plant Costs
|
|
|
1,174
|
|
Recorded
Debt Carrying Costs on Net Stranded Generation Plant Costs
|
|
|
400
|
|
Recorded
Securitizable True-up Regulatory Asset
|
|
|
1,574
|
|
Unrecorded
But Recoverable Equity Carrying Costs
|
|
|
224
|
|
Unrecorded
Estimated October 2006 Debt Carrying Costs
|
|
|
3
|
|
Unrecorded
Excess Earnings, Related Carrying Costs and Other
|
|
|
53
|
|
Unrecorded
Settlement Reduction
|
|
|
(77
|
)
|
Reduction
for the Present Value of ADITC and EDFIT Benefits
|
|
|
(61
|
)
|
Approved
Securitizable Amount as of October 11, 2006
|
|
|
1,716
|
|
Unrecorded
Securitization Bond Issuance Costs
|
|
|
24
|
|
Amount
Securitized on October 11, 2006
|
|
$
|
1,740
|
|
Deferred
Investment Tax Credits and Excess Deferred Federal Income
Taxes
In
TCC’s
true-up and securitization orders, the PUCT reduced net stranded generation
plant costs and the amount to be securitized by $51 million related to the
present value of ADITC and by $10 million related to EDFIT associated with
TCC’s
generating assets. (See Reduction for the Present Value of ADITC and EDFIT
Benefits of $61 million in the table above.) TCC testified that the sharing
of
these tax benefits with customers might be a violation of the Internal Revenue
Code’s normalization provisions.
TCC
filed
a request for a private letter ruling from the IRS in June 2005 to determine
whether the PUCT’s action would result in a normalization violation. The IRS
issued its private letter ruling on May 9, 2006 which stated that the PUCT’s
flow through to customers of the present value of the ADITC and EDFIT benefits
would result in a normalization violation. TCC informed the PUCT on May 10,
2006
of the adverse ruling, however, the PUCT did not change its order on rehearing.
TCC filed an appeal with the PUCT. As discussed below in the “CTC Proceeding for
Other True-up Items” section of this note, TCC proposed, and the PUCT agreed, to
defer refunding the amount of the present value of its ADITC and EDFIT benefits
through its CTC until this normalization issue is resolved upon the IRS issuance
of final normalization regulations.
If
a
normalization violation occurs, it could result in the repayment of TCC’s ADITC
on all property, including transmission and distribution property, which
approximates $104 million as of September 30, 2006 and also a loss of the right
to claim accelerated tax depreciation in future tax returns. Tax counsel advised
management that a normalization violation should not occur until all remedies
under law have been exhausted and the tax benefits are returned to ratepayers
under a nonappealable order. Management intends to continue its efforts to
avoid
a normalization violation that would adversely affect future results of
operations and cash flows through the appeal of the PUCT’s true-up order and
through a CTC deferral.
CTC
Proceeding for Other True-up Items
In
June
2006, TCC filed to implement a negative CTC to refund its other true-up items
over eight years. TCC will incur interest expense on the other true-up
regulatory liability balances until it is fully refunded. The principal
components of the CTC refund liability are an over-recovered fuel balance,
the
retail clawback and the ADFIT benefit related to TCC’s stranded generation cost,
offset by a positive wholesale capacity auction true-up regulatory asset
balance.
The
differences between the components of TCC’s Recorded Net Regulatory Liabilities
- Other True-up Items of $238 million as of September 30, 2006 (including
interest expense) and its Net CTC Refund Proposed of $357 million are detailed
below:
|
|
(in
millions)
|
|
Wholesale
Capacity Auction True-up
|
|
$
|
61
|
|
Carrying
Costs on Wholesale Capacity Auction True-up
|
|
|
31
|
|
Retail
Clawback including Carrying Costs
|
|
|
(65
|
)
|
Deferred
Over-recovered Fuel Balance
|
|
|
(184
|
)
|
Retrospective
ADFIT Benefit
|
|
|
(77
|
)
|
Other
|
|
|
(4
|
)
|
Recorded
Net Regulatory Liabilities - Other True-up Items
|
|
|
(238
|
)
|
Unrecorded
Prospective ADFIT Benefit
|
|
|
(240
|
)
|
Gross
CTC Refund Proposed
|
|
|
(478
|
)
|
FERC
Jurisdictional Fuel Refund Deferral
|
|
|
16
|
|
ADITC
and EDFIT Benefit Refund Deferral
|
|
|
98
|
|
Net
CTC Refund Proposed, After Deferrals
|
|
|
(364
|
)
|
True-up
Proceeding Expense Surcharge
|
|
|
7
|
|
Net
CTC Refund Proposed, After Deferrals and Expenses
|
|
$
|
(357
|
)
|
TCC
requested that a portion of the refund be deferred, pending the outcome of
two
contingent federal matters related to the refund of $16 million of FERC
jurisdictional fuel over-recoveries (discussed below) and $98 million (including
carrying costs) related to potential tax normalization violation matters related
to the refund of ADITC and EDFIT benefits (discussed above). Under TCC’s
proposal, (a) if the two contingent federal matters are resolved consistent
with
the PUCT’s treatment, TCC will then refund the $16 million and the $98 million
plus carrying costs or (b) if these two issues are not resolved consistent
with
the PUCT’s treatment, the deferred refunds will not be made in order to avoid a
normalization violation and the violation of a Federal court order. Management
cannot predict the final outcome of this filing.
Although
TCC proposed to refund the $357 million over eight years, certain intervenors
supported accelerated refunds. In September 2006, the PUCT approved an interim
CTC that was implemented on October 12, 2006, the same day that TCC began
billing customers for the securitization bonds. The interim CTC will refund
the
entire retail clawback of $65 million (including carrying costs) to residential
customers by the end of 2006. The CTC refund to the other customer classes
during the interim period will be as proposed by TCC, with the exception of
the
large industrials, who will not receive any fuel refunds during the interim
period.
At
an
October 2006 open meeting, the PUCT announced oral decisions regarding the
CTC
refund. A final written order is expected in late November or early December
of
this year. In its decision, the PUCT confirmed that TCC can use securitization
bond proceeds to make the CTC refund. The PUCT’s decision was to continue the
interim CTC through December 2006 to complete the refund of the retail clawback
over three months. Beginning in January 2007, the Deferred Over-recovered Fuel
Balance will be refunded over six months with the large industrial customers
receiving their entire refund in January 2007. Starting in July 2007, the
remaining CTC items will be refunded over one year, except that the PUCT agreed
with TCC’s request to defer the refund of the ADITC and EDFIT Benefit Refund
Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above).
The
PUCT will decide those issues and related amounts in another
proceeding.
Fuel
Balance Recoveries
In
September 2005, the Federal District Court, Western District of Texas, issued
an
order precluding the PUCT from enforcing its ruling in the TNC fuel proceeding
regarding the PUCT’s reallocation of off-system sales margins. In August 2006,
TCC also received an order from the Federal District Court, Western District
of
Texas precluding the PUCT from enforcing its ruling regarding the PUCT’s
reallocation of off-system sales margins in connection with TCC’s final fuel
reconciliation. The favorable Federal District Court order, if upheld on appeal,
could result in reductions to the over-recovered fuel principal balances of
$8
million for TNC and $14 million ($16 million with carrying costs) for TCC.
The
PUCT appealed the TCC and TNC Federal Court decision to the United States Court
of Appeals for the Fifth Circuit. If the PUCT is unsuccessful in the federal
court system, the PUCT may file a complaint at the FERC to address the
allocation issue. We are unable to predict if the Federal District Court’s
decision will be upheld or whether the PUCT will file a complaint at the FERC.
Pending further clarification, TCC and TNC have not reversed their related
provisions for fuel over-recovery. If the PUCT or another party were to file
a
complaint at the FERC that results in the PUCT’s decisions being reinstated, it
could result in an adverse effect on results of operations and cash flows for
the AEP East companies because an unfavorable FERC ruling may result in a
reallocation of off-system sales margins from AEP East companies to AEP West
companies under the then existing SIA allocation method. If the adjustments
were
applied retroactively, the AEP East companies may be unable to recover the
amounts from their customers due to past frozen rates, past inactive fuel
clauses and fuel clauses that do not include off-system sales
credits.
Carrying
Costs on Net True-up Regulatory Assets Impacting Securitization and CTC
Proceedings
In
TCC’s
True-up Proceeding, the PUCT allowed TCC to recover carrying costs at an 11.79%
overall pretax weighted average cost of capital rate approved in its unbundled
cost of service rate proceeding. The recorded embedded debt component of this
carrying cost rate is 8.12%. Through September 30, 2006, TCC recorded $400
million of debt-related carrying costs on stranded generation plant costs
included in the securitization proceeding. Equity carrying costs of $224 million
related to amounts securitized will be recognized in income as collected. TCC
will accrue interest expense until its net CTC refund is fully refunded. The
interest expense on the net CTC refund totals $9 million and $11 million for
the
three and nine months ended September 30, 2006, respectively, and is included
in
Interest Expense on the Condensed Consolidated Statements of Operations.
In
June
2006, the PUCT adopted a proposed rule that prospectively changes the interest
rate applied to TCC’s CTC refund balance. TCC anticipates that the rule change
will reduce the rate TCC will pay on its CTC balance from 11.79% to 7.47%.
TCC
anticipates that the change will reduce its annual refund by approximately
$8
million. The rule also provides for adjustments to the rate during subsequent
rate case proceedings.
TNC
True-up Proceeding
TNC
filed
a CTC proceeding in August 2005 to establish a rate to refund its net true-up
regulatory liability. In December 2005, that proceeding was abated, pending
a
final ruling from TNC’s appeal to the federal court regarding the fuel
proceeding (described above). In August 2006, the parties to TNC’s CTC
proceeding filed a settlement that recommended implementing an interim refund
of
the true-up regulatory liability totaling $13 million, net of the amounts at
issue in the federal court proceeding, over six months beginning in September
2006. In late August 2006, the PUCT approved the settlement and the net refund
began in September 2006. TNC accrues interest expense on the unrefunded balance
and will continue to do so until the balance is fully refunded.
Excess
Earnings
As
noted
in our 2005 Annual Report, the Texas Court of Appeals issued a decision finding
the PUCT’s prior order from the unbundled cost of service case requiring TCC to
refund excess earnings was unlawful under the Texas Restructuring Legislation.
In November 2005, the PUCT filed a petition for review with the Supreme Court
of
Texas seeking reversal of the Texas Court of Appeals’ decision. The Supreme
Court of Texas requested briefing, which has been provided, but it has not
decided whether it will hear the case. Management is unable to predict the
ultimate outcome of these proceedings.
Summary
Our
recorded securitizable true-up regulatory asset at September 30, 2006 of $1.57
billion, net of the recorded net regulatory liabilities for other true-up items
of $238 million, reflects the PUCT’s orders in TCC’s True-up Proceeding and its
securitization proceeding. Barring any future disallowances to TCC’s net
recoverable true-up regulatory asset in any subsequent proceedings or court
rulings, TCC will amortize its total securitizable true-up regulatory asset
commensurate with recovery over the 14-year term of the securitized bonds issued
in October 2006. If we determine, as a result of future PUCT orders or appeal
court rulings, that it is probable TCC cannot recover a portion of its recorded
net true-up regulatory asset and we are able to estimate the amount of a
resultant impairment, we would record a provision for such amount which would
have an adverse effect on future results of operations, cash flows and possibly
financial condition. Based on advice of Texas rate counsel, TCC appealed the
PUCT orders seeking relief in both state and federal court where TCC believes
the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT
rulemakings and federal law. Municipal customers and other intervenors also
appealed the same PUCT orders seeking to further reduce TCC’s true-up
recoveries.
Although
TCC believes it has meritorious arguments, management cannot predict the
ultimate outcome of any future proceedings or court appeals. If TCC succeeds
in
future appeals, it could have a material favorable effect on future results
of
operations, cash flows and financial condition. If municipal customers and
other
intervenors succeed in their appeals, or if the PUCT does not approve TCC’s CTC
filing as filed and, as a result, causes a normalization violation, it could
have a material adverse effect on future results of operations, cash flows
and
financial condition.
Texas
Restructuring - SPP
In
August
2006, the PUCT adopted a rule delaying customer choice in the SPP area of Texas
until no sooner than January 1, 2011. SWEPCo and a small portion of TNC’s
business operate in SPP. Approximately 3% of TNC’s operations are located in the
SPP territory, with $13 million in net assets in SPP. We filed a petition in
May
2006, requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a subsidiary
of AEP C&I Company, LLC) and TNC’s customers, facilities and certificated
service located in the SPP area to SWEPCo. If this petition is successful,
SWEPCo will be our only subsidiary affected by the delay in the SPP area.
OHIO
RESTRUCTURING
Rate
Stabilization Plans
In
January 2005, the PUCO approved Rate Stabilization Plans (RSPs) for CSPCo and
OPCo (the Ohio companies). The approved plans in each of 2006, 2007 and 2008
provide, among other things, for CSPCo and OPCo to raise their generation rates
by 3% and 7%, respectively, and provide for possible additional annual
generation rate increases of up to an average of 4% per year based on supporting
the request for additional revenues for specified costs. CSPCo’s potential for
the additional annual 4% generation rate increases is diminished by
approximately three-quarters in 2006 and to a lesser extent in 2007 and 2008
due
to the power acquisition rider approved by the PUCO in the Monongahela Power
service territory acquisition proceeding and the recovery of pre-construction
costs for its share of the jointly-owned IGCC plant (see “IGCC Plant” section of
this note below). OPCo’s potential for additional annual 4% generation rate
increases is diminished in 2006 by approximately one-quarter and to a lesser
extent in 2007 due to the recovery of pre-construction costs for its share
of
the jointly-owned IGCC plant. The RSPs also provide that the Ohio companies
can
recover in 2006, 2007 and 2008 estimated 2004 and 2005 deferred environmental
carrying costs and PJM-related administrative costs and congestion costs net
of
financial transmission rights (FTR) revenue related to their obligation as
the
Provider of Last Resort (POLR) in Ohio’s customer choice program. Pretax
earnings increased by $10 million and $26 million for CSPCo and $20 million
and
$58 million for OPCo in the third quarter and first nine months of 2006,
respectively, from the RSP rate increases net of the amortization of RSP
regulatory assets. These increases also include the recognition of equity
carrying costs. As of September 30, 2006, unrecognized equity carrying costs
from 2004 and 2005, which are recognized over the three-year RSP recovery period
totaled $32 million. As of September 30, 2006, the unamortized RSP regulatory
assets to be recovered through December 31, 2008 were $43 million.
In
the
second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio
Supreme Court that challenged the RSPs and also argued that there was no POLR
obligation in Ohio and, therefore, CSPCo and OPCo are not entitled to recover
any POLR charges. In DP&L’s proceeding, the Ohio Supreme Court concluded
that there is a POLR obligation in Ohio, supporting the Ohio companies’ position
that they can recover a POLR charge. In an appeal concerning First Energy
companies’ RSP, the Ohio Supreme Court held that the PUCO’s decision to
eliminate the offer to customers of a price determined through competitive
bids
was unlawful. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP order
for the Ohio companies, which also did not include a competitive bid process,
and remanded the case to the PUCO for further proceedings, not inconsistent
with
the decision in the appeal of the First Energy companies’ RSP. In August 2006,
the PUCO acted on the Ohio companies’ remand case ordering them to file a plan
to provide an option for customer participation in the electric market through
competitive bids or other reasonable means and also held that the RSP shall
remain effective. Accordingly, the Ohio companies continued to collect RSP
revenues. In accordance with the PUCO directive, in September 2006, CSPCo and
OPCo submitted their proposal to provide additional options for customer
participation in the electric market.
In
the
Ohio companies’ case, the Ohio Supreme Court did not address any other issues
that had been raised on appeal, stating that its decision does not preclude
the
Ohio Consumers’ Counsel from raising those issues in a future appeal. Management
believes that the RSP regulatory assets remain probable of recovery and that
the
Ohio companies will continue to collect RSP revenues.
IGCC
Plant
In
March
2005, the Ohio companies filed a joint application with the PUCO seeking
authority to recover costs related to building and operating a new 600 MW IGCC
power plant using clean-coal technology. The application proposed cost recovery
associated with the IGCC plant in three phases: Phase 1, recovery of $24 million
in pre-construction costs during 2006; Phase 2, concurrent recovery of
construction-financing costs; and Phase 3, recovery, or refund, in distribution
rates of any difference between the market-based standard service offer price
for generation and the cost of operating and maintaining the plant, including
a
return on and return of the projected $1.2 billion cost of the plant along
with
fuel, consumables and replacement power costs. The proposed recoveries in Phases
1 and 2 would be applied against the 4% limit on additional generation rate
increases the Ohio companies could request in 2006, 2007 and 2008 under their
RSPs. Through September 30, 2006, the Ohio companies deferred pre-construction
IGCC costs totaling $16 million and recovered $6 million of those costs.
We are currently recovering the remaining deferred amounts through June 30,
2007.
In
April
2006, the PUCO issued an order authorizing the Ohio companies to implement
Phase
1 of the cost recovery proposal. In June 2006, the PUCO issued another order
approving a tariff to recover Phase 1 pre-construction costs over no more than
a
twelve-month period effective July 1, 2006. In its June order, the PUCO
indicated if the Ohio companies have not commenced continuous construction
of
the IGCC plant within five years of the order, all charges collected for
pre-construction costs, which are assignable to other jurisdictions, must be
refunded to Ohio ratepayers with interest. The PUCO deferred ruling on Phases
2
and 3 cost recovery until further hearings are held. No date for a further
hearing has been set.
In
June
2006, the Industrial Energy Users - Ohio (IEU), an intervenor in the PUCO
proceeding, filed a Complaint for Writ of Prohibition at the Ohio Supreme Court
to prohibit the use of the PUCO’s authorization by the Ohio companies to enforce
the collection of the Phase 1 rates and to prohibit the PUCO from further
entertaining any increase in rates for the IGCC project. The Court subsequently
granted a PUCO motion to dismiss the Complaint for Writ of Prohibition.
In
August
2006, IEU, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group
filed four separate appeals of the PUCO’s order in the IGCC proceeding. The Ohio
companies believe that the PUCO’s authorization to begin collection of Phase 1
rates is lawful. The Ohio companies, however, cannot predict the outcome of
these appeals. If the PUCO’s order is found to be unlawful, future results of
operations and cash flows will be adversely affected.
Transmission
Rate Filing
In
accordance with the RSPs, in December 2005, the PUCO approved the recovery
of
certain RTO transmission costs through separate transmission cost recovery
riders for the Ohio companies. The transmission cost recovery riders are subject
to an annual true-up process with over/under recovery mechanisms. In February
2006, the Ohio companies filed a request with the PUCO to incorporate all
transmission costs and rates in their transmission cost recovery riders and
institute a two-step increase to reflect the increases in the FERC-approved
rates. In the filing, the first increase would be effective April 1, 2006 to
reflect the Ohio companies’ share of the loss of SECA revenues and the second
increase would be effective August 1, 2006 to recover their share of the cost
of
the new Wyoming-Jacksons Ferry 765 kV line. In May 2006, the PUCO issued an
order approving a two-step increase in the transmission cost recovery riders
with over/under recovery mechanisms, effective April 1, 2006. The new tariffs
were filed with the PUCO and implemented in June 2006.
In
October 2006, the Ohio companies filed for initial true-ups under the
transmission cost recovery riders’ over/under recovery mechanisms. The filings
reflect the refund of regulatory liabilities as of September 30, 2006 of $12
million and $16 million for CSPCo and OPCo, respectively, including carrying
charges. These over-recoveries were reflected as part of the new transmission
cost recovery rider filed to be effective January 2007. We anticipate the net
effect of the new transmission cost recovery riders will result in increased
cost recoveries over 2005 levels for CSPCo and OPCo of $27 million and $36
million, respectively, in 2006 and $15 million and $16 million, respectively,
in
2007.
Distribution
Service Reliability and Restoration Costs
In
December 2003, the Ohio companies entered into a stipulation agreement regarding
distribution service reliability. The stipulation agreement covered the years
2004 and 2005 and, among other features, established certain distribution
service reliability measures that the Ohio companies were to meet. In July
2006,
based on the staff report on service reliability and responses filed by the
Ohio
companies, the PUCO directed the Ohio companies to earmark $10 million for
future measures to improve service reliability without recovery. The PUCO
further indicated that it will determine where and how the $10 million will
best
be applied.
In
March
2006, the Ohio companies filed an application with the PUCO to implement tariff
riders to recover a portion of previously expensed incremental costs of
restoring service disrupted by severe winter storms in December 2004 and January
2005. CSPCo and OPCo each requested recovery of approximately $12 million of
such costs, which was approved by the PUCO in August 2006. Effective September
1, 2006, the Ohio companies implemented the storm cost recovery riders, which
will continue until they have collected the authorized amounts or one year,
whichever is shorter. In September 2006, the Ohio Consumers’ Counsel filed a
request for rehearing with the PUCO, which was denied in October 2006.
As
a
result of the above, in September 2006 the Ohio companies recorded regulatory
assets of $14 million, favorably affecting earnings.
Ormet
Ormet
Primary Aluminum Corporation and Ormet Primary Mill Products Corporation
(together, Ormet) was a customer of OPCo until 2000. Beginning in 2000, at
Ormet’s request, the PUCO authorized a modification of the certified service
territories of OPCo and South Central Power Company (SCP), a nonaffiliate,
so
that Ormet became a customer of SCP. SCP agreed to let Ormet access the electric
generation market for the vast majority of its 520 MW load. Ormet filed a
request with the PUCO to return to being served by OPCo at the industrial tariff
rate. OPCo opposed the request because it would likely require the purchase
of
capacity and energy from the market at prices above the industrial RSP tariff
rate in order to serve Ormet, as well as substantially reduce
our ability to sell energy into the wholesale market at the higher market
prices.
In
June
2006, the PUCO found that SCP was not providing or proposing to provide
physically adequate service to Ormet. In October 2006, the PUCO convened a
hearing to determine if an electric supplier, other than SCP, should be
authorized to serve Ormet’s significant load.
Subsequent
to the hearing, the Ohio companies together with Ormet, its employees’ union and
certain other interested parties filed a settlement agreement with the PUCO
for
approval. The settlement agreement provides for the reallocation of the service
territories of CSPCo, OPCo and SCP so that Ormet’s Hannibal, Ohio facilities are
located in a joint CSPCo/OPCo certified territory effective January 1, 2007.
The
settlement also provides for the recovery in 2007 and 2008 by CSPCo and OPCo
of
the difference between $43 per MWH paid by Ormet and a to-be-determined market
price submitted by management and reviewed by the PUCO. The recovery is
accomplished by the amortization to income of a $57 million ($15 million for
CSPCo and $42 million for OPCo) Ohio franchise tax phase-out regulatory
liability recorded in 2005 and, if that is not sufficient, an increase in RSP
generation rates under the additional 4% provision of the RSP. The $43 per
MWH
price for generation services is above the industrial RSP generation tariff
but
below current market prices.
Customer
Choice Deferrals
As
provided in stipulation agreements approved by the PUCO in 2000, the Ohio
companies defer customer choice implementation costs and related carrying costs
in excess of $20 million each. The agreements provide for the deferral of these
costs as regulatory assets until the next distribution base rate cases. Through
September 30, 2006, we incurred $97 million of such costs and deferred $48
million of such costs for probable future recovery in distribution rates. We
have not recorded $9 million of equity carrying costs, which are not recognized
until collected. Pursuant to the RSPs, recovery of these amounts is subject
to
PUCO review and is deferred until the next distribution rate filing to change
rates after the December 31, 2008 end of the RSP period. We believe that the
deferred customer choice implementation costs were prudently incurred to
implement customer choice in Ohio and should be recoverable in future
distribution rates. If the PUCO determines that any of the deferred costs are
unrecoverable, it would have an adverse impact on future results of operations
and cash flows.
5. COMMITMENTS
AND CONTINGENCIES
As
discussed in the Commitments and Contingencies note within our 2005 Annual
Report, we continue to be involved in various legal matters. The 2005 Annual
Report should be read in conjunction with this report in order to understand
the
other material nuclear and operational matters without significant changes
since
our disclosure in the 2005 Annual Report. See disclosure below for significant
matters and changes in status subsequent to the disclosure made in our 2005
Annual Report.
ENVIRONMENTAL
Federal
EPA Complaint and Notice of Violation
The
Federal EPA and a number of states alleged that APCo, CSPCo, I&M, OPCo and
other nonaffiliated utilities, including the Tennessee Valley Authority, Alabama
Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company,
Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa
Electric Company, Virginia Electric Power Company and Duke Energy, modified
certain units at coal-fired generating plants in violation of the NSR
requirements of the CAA. The Federal EPA filed its complaints against our
subsidiaries in U.S. District Court for the Southern District of Ohio. The
court
also consolidated a separate lawsuit, initiated by certain special interest
groups, with the Federal EPA case. The alleged modifications occurred at our
generating units over a 20-year period. A bench trial on the liability issues
was held during July 2005. Briefing has concluded. In June 2006, the judge
stayed the liability decision pending the issuance of a decision by the U.S.
Supreme Court in the Duke Energy case. A bench trial on remedy issues, if
necessary, is scheduled to begin four months after the U.S. Supreme Court
decision is issued.
Under
the
CAA, if a plant undertakes a major modification that directly results in an
emissions increase, permitting requirements might be triggered and the plant
may
be required to install additional pollution control technology. This requirement
does not apply to activities such as routine maintenance, replacement of
degraded equipment or failed components or other repairs needed for the
reliable, safe and efficient operation of the plant. The CAA authorizes civil
penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation
at each generating unit. In 2001, the District Court ruled claims for civil
penalties based on activities that occurred more than five years before the
filing date of the complaints cannot be imposed. There is no time limit on
claims for injunctive relief.
The
Federal EPA and eight northeastern states each filed an additional complaint
containing additional allegations against the Amos and Conesville plants. APCo
and CSPCo filed an answer to the northeastern states’ complaint and the Federal
EPA’s complaint, denying the allegations and stating their defenses. Cases are
also pending that could affect CSPCo’s share of jointly-owned units at Beckjord,
Zimmer and Stuart stations. Similar cases have been filed against other
nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric
Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric
Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases
were resolved through consent decrees.
Courts
have reached different conclusions regarding whether the activities at issue
in
these cases are routine maintenance, repair or replacement, and therefore,
are
excluded from NSR. Similarly, courts have reached different results regarding
whether the activities at issue increased emissions from the power plants.
Appeals on these and other issues were filed in certain appellate courts,
including a petition to appeal to the U.S. Supreme Court that was granted in
one
case. The Federal EPA issued a final rule that would exclude activities similar
to those challenged in these cases from NSR as “routine replacements.” In March
2006, the Court of Appeals for the District of Columbia Circuit issued a
decision vacating the rule. The Federal EPA filed a petition for rehearing
in
that case, which the Court denied. The Federal EPA also recently proposed a
rule
that would define “emissions increases” in a way that would exclude most of the
challenged activities from NSR.
We
are
unable to estimate the loss or range of loss related to any contingent liability
we might have for civil penalties under the CAA proceedings. We are also unable
to predict the timing of resolution of these matters due to the number of
alleged violations and the significant number of issues yet to be determined
by
the Court. If we do not prevail, we believe we can recover any capital and
operating costs of additional pollution control equipment that may be required
through regulated rates and market prices of electricity. If we are unable
to
recover such costs or if material penalties are imposed, it would adversely
affect future results of operations, cash flows and possibly financial
condition.
SWEPCo
Notice of Enforcement and Notice of Citizen Suit
In
July
2004, two special interest groups, Sierra Club and Public Citizen, issued a
notice of intent to commence a citizen suit under the CAA for alleged violations
of various permit conditions in permits issued to several SWEPCo generating
plants. In March 2005, the special interest groups filed a complaint in Federal
District Court for the Eastern District of Texas alleging violations of the
CAA
at the Welsh Plant. SWEPCo filed a response to the complaint in May 2005. Other
preliminary motions have been filed and are pending before the
Court.
In
July
2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice
of
Enforcement to SWEPCo relating to the Welsh Plant containing a summary of
findings resulting from a compliance investigation at the plant. In April 2005,
TCEQ issued an Executive Director’s Preliminary Report and Petition recommending
the entry of an enforcement order to undertake certain corrective actions and
assessing an administrative penalty of approximately $228 thousand against
SWEPCo based on alleged violations of certain representations regarding heat
input in SWEPCo’s permit application and the violations of certain recordkeeping
and reporting requirements. SWEPCo responded to the preliminary report and
petition in May 2005. The enforcement order contains a recommendation that
would
limit the heat input on each Welsh unit to the referenced heat input contained
within the permit application within 10 days of the issuance of a final TCEQ
order and until a permit amendment is issued. SWEPCo had previously requested
a
permit alteration to remove the reference to a specific heat input value for
each Welsh unit.
Management
is unable to predict the timing of any future action by TCEQ or the special
interest groups or the effect of such actions on results of operations,
financial condition or cash flows.
Carbon
Dioxide (CO2)
Public Nuisance Claims
In
July
2004, attorneys general from eight states and the corporation counsel for 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. That same day, the Natural Resources
Defense Council, on behalf of three special interest groups, filed a similar
complaint in the same court against the same defendants. The actions alleged
that CO2
emissions from the defendants’ power plants constitute a public nuisance under
federal common law due to impacts associated with global warming and sought
injunctive relief in the form of specific emission reduction commitments from
the defendants. In September 2004, the defendants, including AEP and AEPSC,
filed a motion to dismiss the lawsuits. In September 2005, the lawsuits were
dismissed. The trial court’s dismissal was appealed to the Second Circuit Court
of Appeals. Briefing and oral argument have been completed. We believe the
actions are without merit and intend to defend against the claims.
Ontario
Litigation
In
June
2005, we, along with nineteen nonaffiliated utilities, were named as defendants
in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. We
have
not been served with the lawsuit. The time limit for serving the defendants
expired, but the case has not been dismissed. The defendants are alleged to
own
or operate coal-fired electric generating stations in various states that,
through negligence in design, management, maintenance and operation, emitted
NOX,
SO2
and
particulate matter that harmed the residents of Ontario. The lawsuit seeks
class
action designation and damages of approximately $49 billion, with continuing
damages of $4 billion annually. The lawsuit also seeks $1 billion in punitive
damages. We believe we have meritorious defenses to this action and intend
to
defend against it.
OPERATIONAL
Power
Generation Facility and
TEM Litigation
We
have
agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed
and financed a merchant power generation facility (Facility) near Plaquemine,
Louisiana and leased the Facility to us. We subleased the Facility to the Dow
Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration
facility” for purposes of PURPA.
Juniper
is a nonaffiliated limited partnership, formed to construct or otherwise acquire
real and personal property for lease to third parties, to manage financial
assets and to undertake other activities related to asset financing. Juniper
arranged to finance the Facility. The Facility is collateral for Juniper’s debt
financing. Due to the treatment of the Facility as a financing of an owned
asset, we recognized all of Juniper’s funded obligations as a liability. Upon
expiration of the lease, our actual cash obligation could range from $0 to
$415
million based on the fair value of the assets at that time. However, if we
default under the Juniper lease, our maximum cash payment could be as much
as
$525 million. Because we report Juniper’s funded obligations totaling $525
million related to the Facility on our Condensed Consolidated Balance Sheets,
the fair value of the liability for our guarantee (the $415 million payment
discussed above) is not separately reported.
In
August
2006, we reached an agreement with Dow to sell the Facility to them. We expect
the sale to close during the fourth quarter of 2006 following receipt of federal
regulatory approvals. Upon closing, we will repay our recorded $525 million
lease financing obligation, which is included in Long-term Debt Due Within
One
Year on our Condensed Consolidated Balance Sheet at September 30, 2006. The
approved sale resulted in a third quarter pretax impairment of approximately
$209 million (see Note 8).
Dow
uses
a portion of the energy produced by the Facility and sells the excess energy.
OPCo agreed to purchase up to approximately 800 MW of such excess energy from
Dow for a 20-year term. Because the Facility is a major steam supply for Dow,
Dow is expected to operate the Facility at certain minimum levels, and OPCo
is
obligated to purchase the energy generated at those minimum operating levels
(approximately 270 MW). OPCo sells the purchased energy at market prices in
the
Entergy sub-region of the Southeastern Electric Reliability Council
market.
OPCo
agreed to sell up to approximately 800 MW of energy to TEM for a period of
20
years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA),
at a price that is currently in excess of market. Beginning May 1, 2003, OPCo
tendered replacement capacity, energy and ancillary services to TEM pursuant
to
the PPA that TEM rejected as nonconforming. Commercial operation for purposes
of
the PPA began April 2, 2004.
In
September 2003, TEM and AEP separately filed declaratory judgment actions in
the
U.S. District Court for the Southern District of New York. We alleged that
TEM
breached the PPA, and we 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 AEP’s breaches. The corporate parent of TEM
(SUEZ-TRACTEBEL S.A.) provided a limited guaranty.
In
April
2004, OPCo gave notice to TEM that OPCo (a) was suspending performance of its
obligations under the PPA; (b) would seek a declaration from the District Court
that the PPA was terminated; and (c) would pursue TEM and SUEZ-TRACTEBEL S.A.
under the guaranty, seeking damages and the full termination payment value
of
the PPA.
A
bench
trial was conducted in March and April 2005. In August 2005, a federal judge
ruled that TEM breached the contract and awarded us damages of $123 million
plus
prejudgment interest. In August 2005, both parties filed motions with the trial
court seeking reconsideration of the judgment. We asked the court to modify
the
judgment to (a) award a termination payment to us under the terms of the PPA;
(b) grant our attorneys’ fees; and (c) render judgment against SUEZ-TRACTEBEL
S.A. on the guaranty. TEM sought reduction of the damages awarded by the court
for replacement electric power products made available by OPCo under the PPA.
In
January 2006, the trial judge granted our motion for reconsideration concerning
TEM’s parent guaranty and increased our judgment against TEM to $173 million
plus prejudgment interest, and denied the remaining motions for reconsideration.
In March 2006, the trial judge amended the January 2006 order eliminating the
additional $50 million damage award.
In
September 2005, TEM posted a letter of credit for $142 million as security
pending appeal of the judgment. Both parties have filed Notices of Appeal with
the United States Court of Appeals for the Second Circuit. Oral argument is
scheduled for December 2006. If the PPA is deemed terminated or found
unenforceable by the court ultimately deciding the case, we could be adversely
affected to the extent we are unable to find other purchasers of the power
with
similar contractual terms (if our sale of the Facility to Dow does not close)
and to the extent we do not fully recover the claimed termination value damages
from TEM.
Enron
Bankruptcy
In
connection with our 2001 acquisition of HPL, we entered into an agreement with
BAM Lease Company, which granted HPL the exclusive right to use approximately
65
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, Bank of
America (BOA) and certain other banks (the BOA Syndicate) and Enron entered
into
an agreement granting HPL the exclusive use of 65 BCF of 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. In July 2002, the BOA Syndicate
filed a lawsuit against HPL in Texas state court seeking a declaratory judgment
that the BOA Syndicate has a valid and enforceable security interest in gas
purportedly in the Bammel storage reservoir. In December 2003, the Texas state
trial court granted partial summary judgment in favor of the BOA Syndicate.
HPL
appealed this decision. In August 2006, the Court of Appeals for the First
District of Texas vacated the trial court’s judgment and dismissed the BOA
Syndicate’s case. The BOA Syndicate did not seek review of this decision. In
June 2004, BOA filed an amended petition in a separate lawsuit in Texas state
court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel
storage facility or its fair value. Following an adverse decision on its motion
to obtain possession of this gas, BOA voluntarily dismissed this action. In
October 2004, BOA refiled this action. HPL filed a motion to have the case
assigned to the judge who heard the case originally and that motion was granted.
HPL intends to continue to defend against BOA’s claims.
In
October 2003, AEP filed a lawsuit against BOA in the United States District
Court for the Southern District of Texas. BOA led a lending syndicate involving
the 1997 gas monetization that Enron and its subsidiaries undertook and the
leasing of the Bammel underground gas storage reservoir to HPL. 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 Bammel storage
facility lease arrangement with Enron and 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 including that the
1997
gas monetization did not contravene or constitute a default of any federal,
state, or local statute, rule, regulation, code or any law. In February 2004,
BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004,
the
Magistrate Judge issued a Recommended Decision and Order recommending that
BOA’s
Motion to Dismiss be denied, that the five counts in the lawsuit seeking
declaratory judgments involving the Bammel reservoir and the right to use and
cushion gas consent agreements be transferred to the Southern District of New
York and that the four counts alleging breach of contract, fraud and negligent
misrepresentation proceed in the Southern District of Texas. BOA objected to
the
Magistrate Judge’s decision. In April 2005, the Judge entered an order
overruling BOA’s objections, denying BOA’s Motion to Dismiss and severing and
transferring the declaratory judgment claims to the Southern District of New
York. HPL and BOA filed motions for summary judgment in the case pending in
the
Southern District of New York.
In
February 2004, in connection with BOA’s dispute, 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
2005,
we sold our interest in HPL. We indemnified the buyer of HPL against any damages
resulting from the BOA litigation up to the purchase price. The determination
of
the gain on sale and the recognition of the gain are dependent on the ultimate
resolution of the BOA dispute and the costs, if any, associated with the
resolution of this matter (see Note 8).
In
June
and July 2006, we held mediation discussions with BOA and Enron concerning
these
gas disputes. No further discussions are scheduled at this time. Although
management is unable to predict the outcome of the remaining lawsuits, it is
possible that their resolution could have an adverse impact on our results
of
operations, cash flows and financial condition.
Shareholder
Lawsuits
In
the
fourth quarter of 2002 and the first quarter of 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 July 2006, the Court entered judgment denying
plaintiff’s motion for class certification and dismissing all claims without
prejudice. In August 2006, plaintiff filed a notice of appeal to the United
States Court of Appeals for the Sixth Circuit. Briefing of this appeal is
scheduled for completion in December 2006.
Natural
Gas Markets Lawsuits
In
November 2002, the Lieutenant Governor of California filed a lawsuit in Los
Angeles County California Superior Court against forty energy companies,
including AEP, and two publishing companies 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
filed in California. In addition, a number of other cases have been filed in
state and federal courts in several states making essentially the same
allegations under federal or state laws against the same companies. In some
of
these cases, AEP (or a subsidiary) is among the companies named as defendants.
These cases are at various pre-trial stages. Several of these cases had been
transferred to the United States District Court for the District of Nevada
but
subsequently remanded to California state court. In April 2005, the judge in
Nevada dismissed one of the remaining cases in which AEP was a defendant on
the
basis of the filed rate doctrine and in December 2005, the judge dismissed
two
additional cases on the same ground. Plaintiffs in these cases appealed the
decisions. We will continue to defend each case where an AEP company is a
defendant.
Cornerstone
Lawsuit
In
the
third quarter of 2003, Cornerstone Propane Partners filed an action in the
United States District Court for the Southern District of New York against
forty
companies, including AEP and AEPES, seeking class certification and alleging
unspecified damages from claimed price manipulation of natural gas futures
and
options on the NYMEX from January 2000 through December 2002. Thereafter, two
similar actions were filed in the same court against a number of companies,
including AEP and AEPES, making essentially the same claims as Cornerstone
Propane Partners and also seeking class certification. These cases were
consolidated. In January 2004, plaintiffs filed an amended consolidated
complaint. The defendants filed a motion to dismiss the complaint which the
Court denied. In October 2005, the Court granted the plaintiffs motion for
class
certification. We intend to continue to defend against these
claims.
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. In
December 2002, a FERC ALJ ruled in our favor and dismissed the complaint filed
by the Nevada utilities. In 2001, the
Nevada
utilities filed complaints asserting that the prices for power supplied under
those contracts should be lowered because the market for power was allegedly
dysfunctional at the time such contracts were executed. The ALJ rejected
the
Nevada
utilities’ complaint, held that the markets for future delivery were not
dysfunctional, and that the
Nevada
utilities failed to demonstrate that the public interest required changes be
made to the contracts. In June 2003, the FERC issued an order affirming the
ALJ’s decision. The
Nevada
utilities’ request for a rehearing was denied. The
Nevada
utilities’ appeal of the FERC order is pending before the U.S. Court of Appeals
for the Ninth Circuit. Management
is unable to predict the outcome of this proceeding and its impact on future
results of operations and cash flows.
6. 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, debt service reserves and credit
enhancements for issued bonds. As the parent company, we issued all of these
LOCs in our ordinary course of business on behalf of our subsidiaries. At
September 30, 2006, the maximum future payments for all the LOCs are
approximately $34 million with maturities ranging from October 2006 to July
2007.
GUARANTEES
OF THIRD-PARTY OBLIGATIONS
SWEPCo
In
connection with reducing the cost of the lignite mining contract for its Henry
W. Pirkey Power Plant, SWEPCo agreed, under certain conditions, to assume the
capital lease obligations and term loan payments of the mining contractor,
Sabine Mining Company (Sabine). If Sabine defaults under any of these
agreements, SWEPCo’s total future maximum payment exposure is approximately $68
million with maturity dates ranging from February 2007 to February
2012.
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 $85 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. This guarantee ends upon
depletion of reserves and final reclamation is completed. At September 30,
2006,
we estimate the reserves will be depleted in 2029 with final reclamation
completed by 2036. We estimate the cost for final reclamation during the period
2029 through 2036 at approximately $39 million.
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. Prior to September 30, 2006,
we entered into several sale agreements. The status of certain sales agreements
is discussed in Note 8. These sale agreements include indemnifications with
a
maximum exposure related to the collective purchase price, which is
approximately $2.1 billion (approximately $1 billion relates to the BOA
litigation, see “Enron Bankruptcy” section of Note 5). There are no material
liabilities recorded for any indemnifications.
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. At September 30, 2006, the maximum potential loss for
these
lease agreements was approximately $54 million ($35 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, we entered into an agreement with BTM Capital Corporation, as lessor,
to
lease 875 coal-transporting aluminum railcars. The lease has an initial term
of
five years.
At
the
end of each lease term, we may (a) renew for another five-year term, not to
exceed a total of twenty years, (b) purchase the railcars for the purchase
price
amount specified in the lease, projected at the lease inception to be the then
fair market value, or (c) return the railcars and arrange a third party sale
(return-and-sale option). The lease is accounted for as an operating lease.
We
intend to renew the lease for the full twenty years.
Under
the
lease agreement, the lessor is guaranteed that the sale proceeds under the
return-and-sale option discussed above will equal at least the lessee obligation
amount specified in the lease, which declines over the current lease term from
approximately 86% to 77% of the projected fair market value of the equipment.
At
September 30, 2006, the maximum potential loss was approximately $31 million
($20 million, net of tax) assuming the fair market value of the equipment is
zero at the end of the current lease term. We have other railcar lease
arrangements that do not utilize this type of structure.
7. COMPANY-WIDE
STAFFING AND BUDGET REVIEW
As
a
result of a company-wide staffing and budget review in the second quarter of
2005, we identified approximately 500 positions for elimination. Pretax
severance benefits expense of $24 million and $4 million was recorded (primarily
in Maintenance and Other Operation within the Utility Operations segment) in
the
second and third quarters of 2005, respectively.
The
following table shows the accrual as of December 31, 2005 (reflected primarily
in Current Liabilities - Other on our Condensed Consolidated Balance Sheets)
and
the activity during the first nine months of 2006, which eliminated the accrual
as of June 30, 2006:
|
|
Amount
(in
millions)
|
|
Accrual
at December 31, 2005
|
|
$
|
12
|
|
Less:
Total Payments
|
|
|
8
|
|
Less:
Accrual Adjustments
|
|
|
4
|
|
Accrual
at September 30, 2006
|
|
$
|
-
|
|
The
favorable
accrual adjustments were recorded primarily in Maintenance and Other Operation
on our Condensed Consolidated Statements of Operations.
8. ACQUISITIONS,
DISPOSITIONS, DISCONTINUED OPERATIONS, ASSETS HELD FOR SALE AND ASSET
IMPAIRMENTS
ACQUISITIONS
2005
Waterford
Plant (Utility Operations segment)
In
May
2005, CSPCo signed a purchase and sale agreement with Public Service Enterprise
Group Waterford Energy LLC for the purchase of an 821 MW plant in Waterford,
Ohio. This transaction was completed in September 2005 for $218 million and
the
assumption of liabilities of approximately $2 million.
DISPOSITIONS
2006
Compresion
Bajio S de R.L. de C.V. (Investments - Other segment)
In
January 2002, we acquired a 50% interest in Compresion Bajio S de R.L. de C.V.
(Bajio), a 600-MW power plant in Mexico. We received an indicative offer for
Bajio in September 2005, which resulted in a pretax other-than-temporary
impairment charge of approximately $7 million. The impairment amount is
classified in Investment Value Losses on our Condensed Consolidated Statements
of Operations. We completed the sale in February 2006 for approximately $29
million with no effect on our 2006 results of operations.
2005
Houston
Pipe Line Company LP (HPL) (Investments - Gas Operations
segment)
During
2005, we sold our interest in HPL, 30 billion cubic feet (BCF) of working gas
and working capital for approximately $1 billion, subject to a working capital
and inventory true-up adjustment. Although the assets were legally transferred,
it is not possible to determine all costs associated with the transfer until
the
Bank of America (BOA) litigation is resolved. Accordingly, we recorded the
excess of the sales price over the carrying cost of the net assets transferred
as a deferred gain of $379 million as of September 30, 2006 and December 31,
2005, which is reflected in Deferred Credits and Other on our Condensed
Consolidated Balance Sheets. We provided an indemnity to the purchaser in an
amount up to the purchase price for damages, if any, arising from litigation
with BOA and a potential resulting inability to use the cushion gas (see “Enron
Bankruptcy” section of Note 5). The HPL operations did not meet the criteria to
be shown as discontinued operations due to continuing involvement associated
with various contractual obligations. Significant continuing involvement
includes cash flows from long-term gas contracts with the buyer through 2008
and
the cushion gas arrangement. In addition, we continue holding forward gas
contracts, with expirations through 2011, not sold with the gas pipeline and
storage assets. We manage the commodity price risk associated with these
forward gas contracts to limit our price risk exposure principally by entering
into equal and offsetting contracts. For the nine months ended September
30, 2006, the change in the mark-to-market value of these positions was less
than $100,000.
Texas
REPs (Utility Operations segment)
In
December 2002, we sold two of our Texas REPs to Centrica, a UK-based provider
of
retail energy. The sales price was $146 million plus certain other payments
including an earnings-sharing mechanism (ESM) for AEP and Centrica to share
in
the earnings of the sold business for the years 2003 through 2006. The method
of
calculating the annual earnings-sharing amount was included in the Purchase
and
Sales Agreement and was amended through a series of agreements that AEP and
Centrica entered in March 2005. Also in March 2005, we received payments related
to the ESM of $45 million and $70 million for 2003 and 2004, respectively,
resulting in a pretax gain of $112 million in 2005. In March 2006, we received
a
payment of $70 million related to the ESM for 2005. The ESM payment for 2006
is
contingent on Centrica’s future operating results and is contractually capped at
$20 million. The payments are reflected in Gain/Loss on Disposition of Assets,
Net on our Condensed Consolidated Statements of Operations.
DISCONTINUED
OPERATIONS
Certain
of our operations were determined to be discontinued operations and have been
classified as such for all periods presented. Results of operations of these
businesses have been classified as shown in the following table (in
millions):
Three
Months ended September 30, 2006 and 2005:
|
|
|
|
SEEBOARD
(a)
|
|
U.K.
Generation (b)
|
|
Total
|
|
2006
Revenue
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
2006
Pretax Income
|
|
|
-
|
|
|
-
|
|
|
-
|
|
2006
Earnings, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
Revenue
|
|
$
|
13
|
|
$
|
-
|
|
$
|
13
|
|
2005
Pretax Income
|
|
|
13
|
|
|
-
|
|
|
13
|
|
2005
Earnings, Net of Tax
|
|
|
20
|
|
|
2
|
|
|
22
|
|
|
Nine Months
ended September 30, 2006 and 2005:
|
|
|
SEEBOARD
(a) |
|
U.K.
Generation(c)
|
|
Total
|
|
2006
Revenue
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
2006
Pretax Income
|
|
|
-
|
|
|
9
|
|
|
9
|
|
2006
Earnings, Net of Tax
|
|
|
-
|
|
|
6
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
Revenue (Expense)
|
|
$
|
13
|
|
$
|
(8
|
)
|
$
|
5
|
|
2005
Pretax Income (Loss)
|
|
|
13
|
|
|
(8
|
)
|
|
5
|
|
2005
Earnings (Loss), Net of Tax
|
|
|
29
|
|
|
(3
|
)
|
|
26
|
|
(a)
|
The
amounts relate to purchase price true-up adjustments and tax adjustments
from the sale of SEEBOARD.
|
(b)
|
The
amount relates to a tax adjustment from the sale.
|
(c)
|
The
2006 amounts relate to a release of accrued liabilities for the London
office lease and tax adjustments from the sale. Amounts in 2005 relate
to
purchase price true-up adjustments and tax adjustments from the
sale.
|
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, 2006 and 2005.
ASSETS
HELD FOR SALE AND ASSET IMPAIRMENTS
Texas
Plants - Oklaunion Power Station (Utility Operations
segment)
In
January 2004, we signed an agreement to sell TCC’s 7.81% share of Oklaunion
Power Station for approximately $43 million (subject to closing adjustments)
to
Golden Spread Electric Cooperative, Inc. (Golden Spread), subject to a right
of
first refusal by the Oklahoma Municipal Power Authority and the Public Utilities
Board of the City of Brownsville (the nonaffiliated co-owners). By May 2004,
we
received notice from the nonaffiliated co-owners announcing their decision
to
exercise their right of first refusal with terms similar to the original
agreement. In June 2004 and September 2004, we entered into sales agreements
with both of the nonaffiliated co-owners for the sale of TCC’s 7.81% ownership
of the Oklaunion Power Station. Golden Spread challenged these agreements in
State District Court in Dallas County. Golden Spread alleges that the Public
Utilities Board of the City of Brownsville exceeded its legal authority and
that
the Oklahoma Municipal Power Authority did not exercise its right of first
refusal in a timely manner. Golden Spread requested that the court declare
the
nonaffiliated co-owners’ exercise of their rights of first refusal void. The
court entered a judgment in favor of Golden Spread in October 2005. TCC and
the
nonaffiliated co-owners filed an appeal to the Court of Appeals for the Fifth
District at Dallas. In May 2006, the Court of Appeals for the Fifth District
at
Dallas reversed the trial court’s judgment in favor of Golden Spread and held
that the City of Brownsville properly exercised its right of first refusal
to
acquire TCC’s share of Oklaunion. Golden Spread requested a rehearing in the
matter, and its petition was denied. Golden Spread then appealed to the Supreme
Court of Texas and in August 2006, the court requested a response from the
Oklahoma Municipal Power Authority, the Public Utilities Board of the City
of
Brownsville and us. Responses were due October 27, 2006. We cannot predict
when
these issues will be resolved. We do not expect the sale to have a significant
effect on the terms of the future results of operations. TCC’s assets related to
the Oklaunion Power Station are classified as Assets Held for Sale on our
Condensed Consolidated Balance Sheets at September 30, 2006 and December 31,
2005. The plant does not meet the “component-of-an-entity” criteria because it
does not have cash flows that can be clearly distinguished operationally. The
plant also does not meet the “component-of-an-entity” criteria for financial
reporting purposes because it does not operate individually, but rather as
a
part of the AEP System, which includes all of the generation facilities owned
by
our Registrant Subsidiaries.
Power
Generation Facility (Investments - Other segment)
In
August
2006, we reached an agreement to sell our Plaquemine Cogeneration Facility
(the
Facility) to Dow Chemical Company (Dow) for $64 million. We expect the sale
to
close in the fourth quarter of 2006. We recorded a pretax impairment of $209
million ($136 million, net of tax) in the third quarter of 2006 based on the
terms of the agreement to sell the Facility to Dow. We recorded the impairment
in Asset Impairments and Other Related Charges on our Condensed Consolidated
Statements of Operations. We classified the Facility’s assets as Assets Held for
Sale on our Condensed Consolidated Balance Sheet at September 30, 2006. The
Facility does not meet the criteria for discontinued operations
reporting.
In
addition to the cash proceeds, the sale agreement allows us to participate
in
gross margin sharing on the Facility for five years. Dow will reduce an existing
below-current-market long-term power supply contract with us in Texas by 50
MW,
and we retain the right to any judgment paid by TEM for breaching the original
PPA, as discussed in Note 5.
Conesville
Units 1 and 2 (Utility Operations segment)
In
the
third quarter of 2005, following an extensive review of the commercial viability
of CSPCo’s Conesville Units 1 and 2, management committed to a plan to retire
these units before the end of their previously estimated useful lives. As a
result, Conesville Units 1 and 2 were considered retired as of the third quarter
of 2005.
We
recognized a pretax charge of approximately $39 million in the third quarter
of
2005 related to our decision to retire the units. We classified the impairment
amount in Asset Impairments and Other Related Charges on our Condensed
Consolidated Statements of Operations.
Assets
Held for Sale at September 30, 2006 and December 31, 2005 are as
follows:
September
30, 2006
|
|
Texas
Plants
|
|
Power
Generation Facility
|
|
Total
|
|
Assets:
|
|
(in
millions)
|
|
Other
Current Assets
|
|
$
|
2
|
|
$
|
-
|
|
$
|
2
|
|
Property,
Plant and Equipment, Net
|
|
|
44
|
|
|
64
|
|
|
108
|
|
Total
Assets Held for Sale
|
|
$
|
46
|
|
$
|
64
|
|
$
|
110
|
|
December
31, 2005
|
|
Texas
Plants
|
|
Assets:
|
|
(in
millions)
|
|
Other
Current Assets
|
|
$
|
1
|
|
Property,
Plant and Equipment, Net
|
|
|
43
|
|
Total
Assets Held for Sale
|
|
$
|
44
|
|
9.
BENEFIT
PLANS
Components
of Net Periodic Benefit Cost
The
following table provides the components of our net periodic benefit cost for
the
following plans for the three and nine months ended September 30, 2006 and
2005:
|
|
Pension
Plans
|
|
Other
Postretirement
Benefit
Plans
|
|
Three
Months Ended September 30, 2006 and 2005:
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$
|
23
|
|
$
|
23
|
|
$
|
10
|
|
$
|
10
|
|
Interest
Cost
|
|
|
57
|
|
|
57
|
|
|
26
|
|
|
26
|
|
Expected
Return on Plan Assets
|
|
|
(82
|
)
|
|
(77
|
)
|
|
(24
|
)
|
|
(23
|
)
|
Amortization
of Transition (Asset) Obligation
|
|
|
-
|
|
|
(1
|
)
|
|
7
|
|
|
6
|
|
Amortization
of Net Actuarial Loss
|
|
|
20
|
|
|
13
|
|
|
5
|
|
|
5
|
|
Net
Periodic Benefit Cost
|
|
$
|
18
|
|
$
|
15
|
|
$
|
24
|
|
$
|
24
|
|
|
|
Pension
Plans
|
|
Other
Postretirement
Benefit
Plans
|
|
Nine
Months Ended September 30, 2006 and 2005:
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$
|
71
|
|
$
|
69
|
|
$
|
30
|
|
$
|
31
|
|
Interest
Cost
|
|
|
171
|
|
|
169
|
|
|
76
|
|
|
79
|
|
Expected
Return on Plan Assets
|
|
|
(248
|
)
|
|
(232
|
)
|
|
(70
|
)
|
|
(68
|
)
|
Amortization
of Transition (Asset) Obligation
|
|
|
-
|
|
|
(1
|
)
|
|
21
|
|
|
20
|
|
Amortization
of Net Actuarial Loss
|
|
|
59
|
|
|
40
|
|
|
15
|
|
|
19
|
|
Net
Periodic Benefit Cost
|
|
$
|
53
|
|
$
|
45
|
|
$
|
72
|
|
$
|
81
|
|
10. STOCK-BASED
COMPENSATION
As
previously approved by shareholder vote, the Amended and Restated American
Electric Power System Long-Term Incentive Plan (the Plan) authorizes the use
of
19,200,000 shares of AEP common stock for various types of stock-based
compensation awards, including stock option awards, to key employees. A maximum
of 9,000,000 shares may be used under this plan for full value share awards,
which include performance units, restricted shares and restricted stock units.
The Board of Directors and shareholders both adopted the original Plan in 2000
and the amended and restated version in 2005. We have not granted options
as part of our regular stock-based compensation program since 2003.
However, we have used stock options in limited circumstances totaling 149,000
options in 2004, 10,000 options in 2005 and none during 2006. The
following sections provide further information regarding each type of
stock-based compensation award the Board of Directors has granted.
We
adopted SFAS 123R, effective January 1, 2006. See
the SFAS 123 (revised 2004) “Share-Based Payment” section of Note 2 for
additional information.
Stock
Options
For
all
stock options previously granted, the exercise price equaled or exceeded the
market price of AEP’s common stock on the date of grant. Historically the Board
of Directors has granted stock options with a ten-year term that generally
vest,
subject to the participant’s continued employment, in approximately equal 1/3
increments on January 1st
of the
year following the first, second and third anniversary of the grant date.
Compensation cost for stock options is recorded over the vesting period based
on
the fair value on the grant date. The
Plan does not specify a maximum contractual term for stock options.
CSW
maintained a stock option plan prior to the merger with AEP in 2000. Effective
with the merger, all CSW stock options outstanding were converted into AEP
stock
options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock
option. The exercise price for each CSW stock option was adjusted for the
exchange ratio. Outstanding CSW stock options will continue in effect until
all
options are exercised, cancelled, expired or forfeited. Under the CSW stock
option plan, the option price was equal to the fair market value of the stock
on
the grant date. All CSW options fully vested upon the completion of the merger
and expire 10 years after their original grant date.
The
Board
of Directors did not award any stock options during the nine months ended
September 30, 2006.
The
total
fair value of stock options vested and the total intrinsic value of options
exercised during the nine months ended September 30, 2006 was $3.7 million
and
$2.3 million, respectively. Intrinsic value is calculated as market price at
exercise date less the option exercise price.
A
summary
of AEP stock option transactions during the nine months ended September 30,
2006
is as follows:
|
|
Options
|
|
Weighted
Average Exercise Price
|
|
|
|
(in
thousands)
|
|
Outstanding
at January 1, 2006
|
|
|
6,222
|
|
$
|
34.16
|
|
Granted
|
|
|
-
|
|
|
-
|
|
Exercised/Converted
|
|
|
(369
|
)
|
|
30.17
|
|
Expired
|
|
|
-
|
|
|
-
|
|
Forfeited
|
|
|
(209
|
)
|
|
41.62
|
|
Outstanding
at September 30, 2006
|
|
|
5,644
|
|
|
34.15
|
|
|
|
|
|
|
|
|
|
Exercisable
at September 30, 2006
|
|
|
5,384
|
|
$
|
34.41
|
|
The
following table summarizes information about AEP stock options outstanding
at
September 30, 2006.
Options
Outstanding
2006
Range of
Exercise
Prices
|
|
Number
Exercisable
|
|
Weighted
Average
Remaining
Life
|
|
Weighted
Average
Exercise
Price
|
|
Aggregate
Intrinsic
Value
|
|
|
|
(in
thousands)
|
|
(in
years)
|
|
|
|
(in
thousands)
|
|
$25.73
- $27.95
|
|
|
1,359
|
|
|
5.9
|
|
$
|
27.38
|
|
$
|
12,220
|
|
$30.76
- $38.65
|
|
|
3,917
|
|
|
3.2
|
|
|
35.44
|
|
|
3,665
|
|
$43.79
- $49.00
|
|
|
368
|
|
|
4.6
|
|
|
45.43
|
|
|
-
|
|
|
|
|
5,644
|
|
|
4.0
|
|
|
34.15
|
|
$
|
15,885
|
|
The
following table summarizes information about AEP stock options exercisable
at
September 30, 2006.
Options
Exercisable
2006
Range of
Exercise
Prices
|
|
Number
Exercisable
|
|
Weighted
Average
Remaining
Life
|
|
Weighted
Average
Exercise
Price
|
|
Aggregate
Intrinsic
Value
|
|
|
|
(in
thousands)
|
|
(in
years)
|
|
|
|
(in
thousands)
|
|
$25.73
- $27.95
|
|
|
1,158
|
|
|
5.7
|
|
$
|
27.29
|
|
$
|
10,519
|
|
$30.76
- $35.63
|
|
|
3,858
|
|
|
3.2
|
|
|
35.49
|
|
|
3,386
|
|
$43.79
- $49.00
|
|
|
368
|
|
|
4.6
|
|
|
45.43
|
|
|
-
|
|
|
|
|
5,384
|
|
|
3.8
|
|
|
34.41
|
|
$
|
13,905
|
|
The
proceeds received from exercised stock options are included in common stock
and
paid-in capital. For options issued through December 31, 2005, the grant date
fair value of each option award was estimated using a Black-Scholes
option-pricing model with weighted average assumptions. Expected volatilities
are estimated using the historical monthly volatility of our common stock for
the 36-month period prior to each grant. A seven-year average expected term
is
also assumed. The risk-free rate is the yield for U.S. Treasury securities
with
a remaining life equal to the expected seven-year term of AEP stock options
on
the grant date.
Performance
Units
Our
performance units are equal in value to an equivalent number of shares of AEP
common stock. The number of performance units held is multiplied by a
performance score to determine the actual number of performance units realized.
The performance score is determined at the end of the performance period based
on performance measure(s) established for each grant at the beginning of the
performance period by the Human Resources Committee of the Board of Directors
(HR Committee) and can range from 0 percent to 200 percent. Performance units
are typically paid in cash at the end of a three-year performance and vesting
period, unless they are needed to satisfy a participant’s stock ownership
requirement, in which case they are mandatorily deferred as phantom stock units
(AEP Career Shares) until after the end of the participant’s AEP career. AEP
Career Shares have a value equivalent to the market value of an equal number
of
AEP common shares and are generally paid in cash after the participant’s
termination of employment. Amounts equivalent to cash dividends on both
performance units and AEP
Career Shares accrue as additional units. The compensation cost for performance
units is recorded over the vesting period and the liability for both the
performance units and AEP Career Shares is adjusted for changes in value. The
vesting period of all performance units is three years.
Our
Board
of Directors awarded performance units and reinvested dividends on outstanding
performance units and AEP Career Shares for the nine months ended September
30,
2006 as follows:
Performance
Units
|
|
|
|
Awarded
Units (in thousands)
|
|
864
|
|
Unit
Fair Value at Grant Date
|
|
$
|
37.36
|
|
Vesting
Period (years)
|
|
|
3
|
|
Performance
Units and AEP Career Shares
(Reinvested
Dividends Portion)
|
|
|
|
Awarded
Units (in thousands)
|
|
91
|
|
Weighted
Average Grant Date Fair Value
|
|
$
|
35.37
|
|
Vesting
Period (years) (a)
|
|
|
3
|
|
(a)
|
Vesting
Period (years) range from 0 to 3 years. The Vesting Period of the
reinvested dividends is equal to the remaining life of the related
performance units and AEP Career
Shares.
|
In
January 2006, the HR Committee certified a performance score of 49% for
performance units originally granted for the 2003 through 2005 performance
period. As a result, 108,486 performance units were earned. Of this amount
33,296 were mandatorily deferred as AEP Career Shares, 4,360 were voluntarily
deferred into the Incentive Compensation Deferral Program and the remainder
were
paid in cash.
The
cash
payouts for the nine months ended September 30, 2006 were $2.6 million for
performance units and $1.0 million for AEP Career Share
distributions.
The
performance unit scores for all open performance periods are dependent on two
equally-weighted performance measures: three-year total shareholder return
measured relative to the S&P Utilities Index and three-year cumulative
earnings per share measured relative to a board-approved target. The
value
of each performance unit earned equals the average closing price of AEP common
stock for the last 20 days of the performance period.
The
fair
value of performance unit awards is based on the estimated performance score
and
the current 20-day average closing price of AEP common stock at the date of
valuation.
Restricted
Shares and Restricted Stock Units
Our
Board
of Directors granted 300,000 restricted shares to the Chairman, President and
CEO on January 2, 2004 upon the commencement of his AEP employment. Of these
restricted shares, 50,000 vested on January 1, 2005 and 50,000 vested on January
1, 2006. The remaining 200,000 restricted shares vest, subject to his continued
employment, in approximately equal thirds on November 30, 2009, 2010 and 2011.
Compensation cost is measured at fair value on the grant date and recorded
over
the vesting period. Fair value is determined by multiplying the number of shares
granted by the grant date market price. The maximum term for these restricted
shares is eight years. The Board of Directors has not granted other restricted
shares. Dividends on our restricted shares are paid in cash.
Our
Board
of Directors may also grant restricted stock units, which generally vest,
subject to the participant’s continued employment, over at least three years in
approximately equal annual increments on the anniversaries of the grant date.
Amounts equivalent to dividends paid on AEP shares accrue as additional
restricted stock units that vest on the last vesting date associated with the
underlying units. Compensation cost is measured at fair value on the grant
date
and recorded over the vesting period. Fair value is determined by multiplying
the number of units granted by the grant date market price. The maximum
contractual term of these restricted stock units is six years.
In
January 2006, our Board of Directors also granted restricted stock units with
performance vesting conditions to certain employees who are integral to our
project to design and build an IGCC power plant. Twenty percent of these awards
vest on each of the first three anniversaries of the grant date. An additional
20% vest on the date the IGCC plant achieves commercial operations. The
remaining 20% vest one year after the IGCC plant achieves commercial operations,
subject to achievement of plant availability targets.
Our
Board
of Directors awarded 47,050 restricted stock units, including units awarded
for
dividends, with a weighted average grant date fair value of $35.58 per unit,
for
the nine months ended September 30, 2006.
The
total
fair value and total intrinsic value of restricted shares and restricted stock
units vested during the nine months ended September 30, 2006 was $3.9 million
and $4.6 million, respectively.
A
summary
of the status of our nonvested restricted shares and restricted stock units
as
of September 30, 2006, and changes during the nine months ended September 30,
2006 are as follows:
Nonvested
Restricted Shares and Restricted Stock Units
|
|
Shares/Units
|
|
Weighted
Average Grant Date Fair Value
|
|
|
|
(in
thousands)
|
|
|
|
Nonvested
at January 1, 2006
|
|
|
497
|
|
$
|
32.19
|
|
Granted
|
|
|
47
|
|
|
35.58
|
|
Vested
|
|
|
(127
|
)
|
|
30.56
|
|
Forfeited
|
|
|
(22
|
)
|
|
35.52
|
|
Nonvested
at September 30, 2006
|
|
|
395
|
|
|
32.93
|
|
The
total
aggregate intrinsic value of nonvested restricted shares and restricted stock
units as of September 30, 2006 was $14.4 million and the weighted average
remaining contractual life was 3.03 years.
Share-based
Compensation Plans
Compensation
cost, the actual tax benefit realized for the tax deductions from compensation
cost for share-based payment arrangements recognized in income and total
compensation cost capitalized in relation to the cost of an asset for the nine
months ended September 30, 2006 were as follows:
Share-based
Compensation Plans
|
|
(in
thousands)
|
|
Compensation
Cost for Share-based Payment Arrangements (a)
|
|
$
|
16,671
|
|
Actual
Tax Benefit Realized
|
|
|
5,835
|
|
Total
Compensation Cost Capitalized
|
|
|
3,746
|
|
(a)
|
Compensation
cost for share-based payment arrangements is included in Maintenance
and
Other Operation on our Condensed Consolidated Statements of
Operations.
|
During
the nine months ended September 30, 2006, there were no significant
modifications affecting any of our share-based payment arrangements.
As
of
September 30, 2006, there was $49.1 million of total unrecognized compensation
cost related to unvested share-based compensation arrangements granted under
the
Plan. Unrecognized compensation cost related to the performance units and AEP
Career Shares will change as the liability is revalued each period and
forfeitures for all award types are realized. Our unrecognized compensation
cost
will be recognized over a weighted-average period of 1.57 years.
Cash
received from stock options exercised and actual tax benefit realized for the
tax deductions from stock options exercised during the nine months ended
September 30, 2006 was $11.1 million and $0.8 million,
respectively.
Our
practice is to use authorized but unissued shares to fulfill share commitments
for stock option exercises and restricted stock unit vesting. Although we do
not
currently anticipate any changes to this practice, we could use reacquired
shares, shares acquired in the open market specifically for distribution under
the Plan or any combination thereof for this purpose. The number of new shares
issued to fulfill vesting restricted stock units is generally reduced, at the
participant’s election, to offset AEP’s tax withholding obligation.
11. INCOME
TAXES
In
the
second quarter of 2006, the Texas state legislature replaced the existing
franchise/income tax with a gross margin tax at a 1% rate for electric
utilities. Overall, the new law reduces Texas income tax rates and is effective
January 1, 2007. The new gross margin tax is income-based for purposes of the
application of SFAS 109 “Accounting for Income Taxes.” Based on the new law, we
reviewed deferred tax liabilities with consideration given to the rate changes
and changes to the allowed deductible items with temporary differences. As
a
result, in the second quarter of 2006 we recorded a net reduction to Deferred
Income Taxes on the Condensed Consolidated Balance Sheet of $48 million of
which
$2 million was credited to Income Tax Expense and $46 million credited to
Regulatory Assets based upon the related rate-making treatment.
12. BUSINESS
SEGMENTS
As
outlined in our 2005 Annual Report, our business strategy and the core of our
business are to focus on domestic electric utility operations. Our previous
decision to no longer pursue business interests outside of our domestic core
utility assets led us to divest such noncore assets. Consequently, the
significance of our three Investments segments has declined.
Our
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.
|
Investments
- Gas Operations
·
|
Gas
pipeline and storage services.
|
·
|
Gas
marketing and risk management activities.
|
·
|
We
disposed of our gas pipeline and storage assets in 2005 with the
sale of
HPL (see “Dispositions” section of Note
8).
|
Investments
- UK Operations
·
|
International
generation of electricity for sale to wholesale
customers.
|
·
|
Coal
procurement and transportation to our plants.
|
·
|
We
classified UK Operations as Discontinued Operations during 2003 and
sold
them in 2004.
|
Investments
- Other
·
|
Bulk
commodity barging operations, wind farms, IPPs and other energy
supply-related businesses.
|
The
tables below present segment income statement information for the three and
nine
months ended September 30, 2006 and 2005 and balance sheet information as of
September 30, 2006 and December 31, 2005. These amounts include certain
estimates and allocations where necessary. Prior year amounts have been
reclassified to conform to the current year’s presentation.
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
Gas
Operations
|
|
UK
Operations
|
|
Other
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Three
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
3,485
|
|
$
|
(47
|
)
|
$
|
-
|
|
$
|
156
|
|
$
|
-
|
|
$
|
-
|
|
$
|
3,594
|
|
Other
Operating Segments
|
|
|
(44
|
)
|
|
51
|
|
|
-
|
|
|
4
|
|
|
1
|
|
|
(12
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
3,441
|
|
$
|
4
|
|
$
|
-
|
|
$
|
160
|
|
$
|
1
|
|
$
|
(12
|
)
|
$
|
3,594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$
|
379
|
|
$
|
(3
|
)
|
$
|
-
|
|
$
|
(109
|
)
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
265
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
Gas
Operations
|
|
UK
Operations
|
|
Other
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Three
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
3,152
|
|
$
|
73
|
|
$
|
-
|
|
$
|
103
|
|
$
|
-
|
|
$
|
-
|
|
$
|
3,328
|
|
Other
Operating Segments
|
|
|
85
|
|
|
(77
|
)
|
|
-
|
|
|
3
|
|
|
1
|
|
|
(12
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
3,237
|
|
$
|
(4
|
)
|
$
|
-
|
|
$
|
106
|
|
$
|
1
|
|
$
|
(12
|
)
|
$
|
3,328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued
Operations
|
|
$
|
352
|
|
$
|
(10
|
)
|
$
|
-
|
|
$
|
28
|
|
$
|
(5
|
)
|
$
|
-
|
|
$
|
365
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
20
|
|
|
-
|
|
|
-
|
|
|
22
|
|
Net
Income (Loss)
|
|
$
|
352
|
|
$
|
(10
|
)
|
$
|
2
|
|
$
|
48
|
|
$
|
(5
|
)
|
$
|
-
|
|
$
|
387
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
Gas
Operations
|
|
UK
Operations
|
|
Other
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
9,282
|
|
$
|
(80
|
)
|
$
|
-
|
|
$
|
436
|
|
$
|
-
|
|
$
|
-
|
|
$
|
9,638
|
|
Other
Operating Segments
|
|
|
(73
|
)
|
|
89
|
|
|
-
|
|
|
9
|
|
|
2
|
|
|
(27
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
9,209
|
|
$
|
9
|
|
$
|
-
|
|
$
|
445
|
|
$
|
2
|
|
$
|
(27
|
)
|
$
|
9,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued
Operations
|
|
$
|
904
|
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
(80
|
)
|
$
|
(7
|
)
|
$
|
-
|
|
$
|
815
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
6
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
6
|
|
Net
Income (Loss)
|
|
$
|
904
|
|
$
|
(2
|
)
|
$
|
6
|
|
$
|
(80
|
)
|
$
|
(7
|
)
|
$
|
-
|
|
$
|
821
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
Gas
Operations
|
|
UK
Operations
|
|
Other
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
8,437
|
|
$
|
449
|
|
$
|
-
|
|
$
|
326
|
|
$
|
-
|
|
$
|
-
|
|
$
|
9,212
|
|
Other
Operating Segments
|
|
|
186
|
|
|
(167
|
)
|
|
-
|
|
|
12
|
|
|
2
|
|
|
(33
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
8,623
|
|
$
|
282
|
|
$
|
-
|
|
$
|
338
|
|
$
|
2
|
|
$
|
(33
|
)
|
$
|
9,212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued Operations
|
|
$
|
952
|
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
32
|
|
$
|
(45
|
)
|
$
|
-
|
|
$
|
937
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
(3
|
)
|
|
29
|
|
|
-
|
|
|
-
|
|
|
26
|
|
Net
Income (Loss)
|
|
$
|
952
|
|
$
|
(2
|
)
|
$
|
(3
|
)
|
$
|
61
|
|
$
|
(45
|
)
|
$
|
-
|
|
$
|
963
|
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
|
Gas
Operations
|
|
|
UK
Operations
|
|
|
Other
|
|
|
All
Other (b)
|
|
|
Reconciling
Adjustments (b)
|
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
As
of September 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Property, Plant and Equipment
|
|
$
|
40,397
|
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
567
|
|
|
$
|
3
|
|
|
$
|
-
|
|
|
$
|
40,968
|
|
Accumulated
Depreciation and Amortization
|
|
|
15,014
|
|
|
|
-
|
|
|
|
-
|
|
|
|
130
|
|
|
|
2
|
|
|
|
-
|
|
|
|
15,146
|
|
Total
Property, Plant and Equipment - Net
|
|
$
|
25,383
|
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
437
|
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
25,822
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
35,185
|
|
|
$
|
591
|
(c) |
|
$
|
639
|
(d) |
|
$
|
72
|
|
|
$
|
10,372
|
|
|
$
|
(10,474
|
)
|
|
$
|
36,385
|
|
Assets
Held for Sale
|
|
|
46
|
|
|
|
-
|
|
|
|
-
|
|
|
|
64
|
|
|
|
-
|
|
|
|
-
|
|
|
|
110
|
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
|
Gas
Operations
|
|
|
UK
Operations
|
|
|
Other
|
|
|
All
Other (b)
|
|
|
Reconciling
Adjustments (b)
|
|
|
Consolidated
|
|
|
|
|
(in
millions)
|
|
As
of December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Property, Plant and Equipment
|
|
$
|
38,283
|
|
|
$
|
2
|
|
|
$
|
-
|
|
|
$
|
833
|
|
|
$
|
3
|
|
|
$
|
-
|
|
|
$
|
39,121
|
|
Accumulated
Depreciation and Amortization
|
|
|
14,723
|
|
|
|
1
|
|
|
|
-
|
|
|
|
112
|
|
|
|
1
|
|
|
|
-
|
|
|
|
14,837
|
|
Total
Property, Plant and Equipment - Net
|
|
$
|
23,560
|
|
|
$
|
1
|
|
|
$
|
-
|
|
|
$
|
721
|
|
|
$
|
2
|
|
|
$
|
-
|
|
|
$
|
24,284
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
34,339
|
|
|
$
|
1,199
|
(e) |
|
$
|
632
|
(f) |
|
$
|
509
|
|
|
$
|
9,463
|
|
|
$
|
(9,970
|
)
|
|
$
|
36,172
|
|
Assets
Held for Sale
|
|
|
44
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
44
|
|
(a)
|
All
Other includes the parent company’s guarantee revenue, interest income and
expense, as well as other nonallocated costs.
|
(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 (included in All Other) in
subsidiary companies.
|
(c)
|
Total
Assets of $591 million for the Investments-Gas Operations segment
include
$321 million in affiliated accounts receivable related to the corporate
borrowing program and risk management contracts that are eliminated
in
consolidation. The majority of the remaining $270 million in assets
represents third party risk management contracts, margin deposits
and
accounts receivable.
|
(d)
|
Total
Assets of $639 million for the Investments-UK Operations segment
include
$625 million in affiliated accounts receivable related mainly to
federal
income taxes that are eliminated in consolidation. The majority of
the
remaining $14 million in assets represents cash
equivalents.
|
(e)
|
Total
Assets of $1.2 billion for the Investments-Gas Operations segment
include
$429 million in affiliated accounts receivable related to the corporate
borrowing program and risk management contracts that are eliminated
in
consolidation. The majority of the remaining $770 million in assets
represents third party risk management contracts, margin deposits,
and
accounts receivable.
|
(f)
|
Total
Assets of $632 million for the Investments-UK Operations segment
include
$613 million in affiliated accounts receivable related to federal
income
taxes that are eliminated in consolidation. The majority of the remaining
$19 million in assets represents cash equivalents and value-added
tax
receivables.
|
13. FINANCING
ACTIVITIES
Long-term
Debt
Our
outstanding long-term debt is as follows:
|
|
September
30,
|
|
December
31,
|
|
Type
of Debt
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
|
|
|
|
|
|
Pollution
Control Bonds
|
|
$
|
2,051
|
|
$
|
1,935
|
|
Senior
Unsecured Notes
|
|
|
8,827
|
|
|
8,226
|
|
First
Mortgage Bonds
|
|
|
96
|
|
|
196
|
|
Defeased
First Mortgage Bonds (a)
|
|
|
26
|
|
|
26
|
|
Notes
Payable
|
|
|
872
|
|
|
904
|
|
Securitization
Bonds
|
|
|
596
|
|
|
648
|
|
Notes
Payable To Trust
|
|
|
113
|
|
|
113
|
|
Other
Long-Term Debt (b)
|
|
|
247
|
|
|
236
|
|
Unamortized
Discount (net)
|
|
|
(65
|
)
|
|
(58
|
)
|
Total
Long-term Debt Outstanding
|
|
|
12,763
|
|
|
12,226
|
|
Less
Portion Due Within One Year
|
|
|
1,789
|
|
|
1,153
|
|
Long-term
Portion
|
|
$
|
10,974
|
|
$
|
11,073
|
|
(a)
|
In
May 2004, we deposited cash and treasury securities with a trustee
to
defease all of TCC’s outstanding First Mortgage Bonds. The defeased TCC
First Mortgage Bonds had a balance of $18 million at both September
30,
2006 and December 31, 2005. Trust fund assets related to this obligation
of $2 million are included in Other Temporary Cash Investments at
both
September 30, 2006 and December 31, 2005 and $21 million is included
in
Other Noncurrent Assets in the Condensed Consolidated Balance Sheets
at
both September 30, 2006 and December 31, 2005. In December 2005,
we
deposited cash and treasury securities with a trustee to defease
the
remaining TNC outstanding First Mortgage Bond. The defeased TNC First
Mortgage Bond had a balance of $8 million at both September 30, 2006
and
December 31, 2005. Trust fund assets related to this obligation of
$9
million and $1 million at September 30, 2006 and December 31, 2005,
respectively, are included in Other Temporary Cash Investments and
$0 and
$8 million are included in Other Noncurrent Assets in the Condensed
Consolidated Balance Sheets at September 30, 2006 and December 31,
2005,
respectively. Trust fund assets are restricted for exclusive use
in
funding the interest and principal due on the First Mortgage
Bonds.
|
|
|
(b)
|
Pursuant
to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has
an obligation with 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 of $270 million
and $264 million related to this obligation are included in Spent
Nuclear
Fuel and Decommissioning Trusts in the Condensed Consolidated Balance
Sheets at September 30, 2006 and December 31, 2005,
respectively.
|
Long-term
debt issued, retired and principal payments made during the first nine months
of
2006 are shown in the tables below.
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
|
(in
millions)
|
|
(%)
|
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
Pollution
Control Bonds
|
|
$
|
50
|
|
Variable
|
|
2036
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
250
|
|
5.55
|
|
2011
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
250
|
|
6.375
|
|
2036
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
50
|
|
Variable
|
|
2025
|
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
65
|
|
Variable
|
|
2036
|
|
OPCo
|
|
Senior
Unsecured Notes
|
|
|
350
|
|
6.00
|
|
2016
|
|
PSO
|
|
Senior
Unsecured Notes
|
|
|
150
|
|
6.15
|
|
2016
|
|
SWEPCo
|
|
Pollution
Control Bonds
|
|
|
82
|
|
Variable
|
|
2018
|
|
Total
Issuances
|
|
|
|
$
|
1,247
|
(a)
|
|
|
|
|
The
above
borrowing arrangements do not contain guarantees, collateral or dividend
restrictions.
(a)
|
Amount
indicated on statement of cash flows of $1,229 million is net of
issuance
costs and unamortized premium or
discount.
|
Company
|
|
Type
of Debt
|
|
Principal
Amount Paid
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
|
(in
millions)
|
|
(%)
|
|
|
|
Retirements
and Principal Payments:
|
|
|
|
|
|
|
|
|
|
AEP
|
|
Senior
Unsecured Notes
|
|
$
|
396
|
|
6.125
|
|
2006
|
|
APCo
|
|
First
Mortgage Bonds
|
|
|
100
|
|
6.80
|
|
2006
|
|
I&M
|
|
Pollution
Control Bonds
|
|
|
50
|
|
6.55
|
|
2025
|
|
OPCo
|
|
Notes
Payable
|
|
|
4
|
|
6.81
|
|
2008
|
|
OPCo
|
|
Notes
Payable
|
|
|
7
|
|
6.27
|
|
2009
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
5
|
|
4.47
|
|
2011
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
2
|
|
Variable
|
|
2008
|
|
SWEPCo
|
|
Pollution
Control Bonds
|
|
|
82
|
|
6.10
|
|
2018
|
|
TCC
|
|
Securitization
Bonds
|
|
|
52
|
|
5.01
|
|
2010
|
|
Non-Registrant:
|
|
|
|
|
|
|
|
|
|
|
AEP
subsidiaries
|
|
Notes
Payable
|
|
|
9
|
|
Variable
|
|
2017
|
|
CSW
Energy, Inc.
|
|
Notes
Payable
|
|
|
4
|
|
5.88
|
|
2011
|
|
Total
Retirements and Principal
Payments
|
|
|
|
$
|
711
|
|
|
|
|
|
In
October 2006, TCC issued $1.74 billion in securitization bonds as
follows:
Principal
|
|
Interest
|
|
Scheduled
Final
|
Amount
|
|
Rate
|
|
Payment
Date
|
|
(in
millions)
|
|
(%)
|
|
|
|
|
|
|
|
|
$
|
217
|
|
4.98
|
|
2010
|
|
341
|
|
4.98
|
|
2013
|
|
250
|
|
5.09
|
|
2015
|
|
437
|
|
5.17
|
|
2018
|
|
495
|
|
5.3063
|
|
2020
|
The
proceeds will be used to retire TCC debt and equity, which are no longer needed
to support stranded costs.
In
October 2006, I&M had a required remarketing of $65 million of 2.625%
pollution control bonds, which were converted from a three-year fixed rate
mode
to an auction rate mode.
In
November 2006, APCo had a required remarketing of $30 million of 2.80% pollution
control bonds, which were converted from a three-year fixed rate mode to an
auction rate mode.
In
November 2006, APCo issued $17.5 million of variable rate pollution control
bonds and retired $17.5 million, 2.70% pollution control bonds due in
2007.
In
November 2006, $100.6 million of pollution control bonds were put back to TCC
on
the put date of November 1, 2006. TCC intends to hold these bonds for reissuance
at a later date.
Credit
Facilities
In
April
2006, we amended the terms and increased the size of our credit facilities
from
$2.7 billion to $3 billion. The amended facilities are structured as two $1.5
billion credit facilities, with an option in each to issue up to $200 million
as
letters of credit, expiring separately in March 2010 and April 2011. We also
terminated an existing $200 million letter of credit facility.
AEP
GENERATING COMPANY
AEP
GENERATING COMPANY
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
As
co-owner of the Rockport Plant, we engage in the generation and wholesale sale
of electric power to two affiliates, I&M and KPCo, under long-term
agreements. I&M is the operator and co-owner of the Rockport
Plant.
We
derive
operating revenues from the sale of Rockport Plant energy and capacity to
I&M and KPCo pursuant to FERC approved long-term unit power agreements. The
unit power agreements provide for a FERC-approved rate of return on common
equity, a return on other capital (net of temporary cash investments) and
recovery of costs including operation and maintenance, fuel and taxes. Under
the
terms of the unit power agreements, we accumulate all expenses monthly and
prepare bills for our affiliates. In the month the expenses are incurred, we
recognize the billing revenues and establish a receivable from the affiliated
companies. We divide costs of operating the plant between the
co-owners.
Results
of Operations
Net
Income was unchanged for the third quarter of 2006 compared with the third
quarter of 2005. Net Income increased $0.6 million for the nine months ended
September 30, 2006 compared with the nine months ended September 30, 2005.
The
fluctuation in Net Income is a result of terms in the unit power agreements
which allow for a return on total capital of the Rockport Plant which is
calculated and adjusted monthly.
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006 Net
Income
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
2.2
|
|
|
|
|
|
|
|
|
|
Change
in Gross Margin:
|
|
|
|
|
|
|
|
Wholesale
Sales
|
|
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(0.7
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
0.7
|
|
|
|
|
Interest
Expense
|
|
|
(0.1
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
2.2
|
|
Gross
Margin, defined as Operating Revenues less Fuel for Electric Generation,
increased $0.2 million primarily due to recovery of higher expenses.
Other
Operation and Maintenance expenses increased primarily due to increased costs
at
the Rockport Plant for steam plant operation and maintenance of
structures.
Taxes
Other Than Income Taxes decreased primarily due to lower real and personal
property taxes as the prior year accrual was adjusted to the actual amount
paid.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine Months Ended September 30, 2005 to
Nine
Months Ended September 30, 2006 Net Income
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
6.8
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Wholesale
Sales
|
|
|
|
|
|
3.2
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(2.0
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
0.7
|
|
|
|
|
Interest
Expense
|
|
|
(0.3
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(1.6
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(1.0
|
)
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
7.4
|
|
Gross
Margin, defined as Operating Revenues less Fuel for Electric Generation,
increased $3.2 million primarily due to recovery of higher expenses and higher
returns earned on plant and capital investment.
Other
Operation and Maintenance expenses increased $2.0 million primarily due to
increased maintenance cost at the Rockport Plant during a planned outage in
2006
and credits allocated to us in February 2005 from the cancellation and
settlement of corporate owned life insurance policies.
Taxes
Other Than Income Taxes decreased $0.7 million primarily due to lower real
and
personal property taxes as the prior year accrual was adjusted to the actual
amount paid.
Income
Taxes
Income
Tax Expense increased $1.0 million primarily due to an increase in pretax book
income and changes in certain book/tax differences accounted for on a
flow-through basis.
Off-Balance
Sheet Arrangements
In
prior
years, we entered into an off-balance sheet arrangement for the lease of
Rockport Plant Unit 2. Our current guidelines restrict the use of off-balance
sheet financing entities or structures to allow only traditional operating
lease
arrangements. Our off-balance sheet arrangement has not changed significantly
since year-end. For complete information on our off-balance sheet arrangement
see “Off-balance Sheet Arrangements” in the “Management’s Narrative Financial
Discussion and Analysis” section of our 2005 Annual Report.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end.
Significant
Factors
In
July
2006, we remarketed $45 million of pollution control bonds at a rate of 4.15%
compared to a previous rate of 4.05% until July 14, 2011, the next remarketing
date.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2005 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets and the impact of new accounting
pronouncements.
AEP
GENERATING COMPANY
CONDENSED
STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2006 and
2005
(Unaudited)
(in
thousands)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
|
$
|
74,756
|
|
$
|
69,640
|
|
$
|
230,102
|
|
$
|
201,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
for Electric Generation
|
|
|
42,354
|
|
|
37,403
|
|
|
131,402
|
|
|
105,771
|
|
Rent
- Rockport Plant Unit 2
|
|
|
17,070
|
|
|
17,070
|
|
|
51,212
|
|
|
51,212
|
|
Other
Operation
|
|
|
3,381
|
|
|
2,803
|
|
|
9,598
|
|
|
8,376
|
|
Maintenance
|
|
|
2,522
|
|
|
2,421
|
|
|
7,238
|
|
|
6,411
|
|
Depreciation
and Amortization
|
|
|
5,951
|
|
|
5,956
|
|
|
17,858
|
|
|
17,901
|
|
Taxes
Other Than Income Taxes
|
|
|
368
|
|
|
1,074
|
|
|
2,466
|
|
|
3,149
|
|
TOTAL
|
|
|
71,646
|
|
|
66,727
|
|
|
219,774
|
|
|
192,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
3,110
|
|
|
2,913
|
|
|
10,328
|
|
|
8,448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
24
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
-
|
|
|
-
|
|
|
24
|
|
|
60
|
|
Interest
Expense
|
|
|
(774
|
)
|
|
(652
|
)
|
|
(2,137
|
)
|
|
(1,848
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
2,336
|
|
|
2,261
|
|
|
8,215
|
|
|
6,684
|
|
Income
Tax Expense (Credit)
|
|
|
117
|
|
|
22
|
|
|
848
|
|
|
(144
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
2,219
|
|
$
|
2,239
|
|
$
|
7,367
|
|
$
|
6,828
|
|
CONDENSED
STATEMENTS OF RETAINED EARNINGS
For
the Three and Nine Months Ended September 30, 2006 and
2005
(Unaudited)
(in
thousands)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE
AT BEGINNING OF PERIOD
|
|
$
|
27,176
|
|
$
|
26,947
|
|
$
|
26,038
|
|
$
|
24,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
|
2,219
|
|
|
2,239
|
|
|
7,367
|
|
|
6,828
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Dividends Declared
|
|
|
-
|
|
|
3,015
|
|
|
4,010
|
|
|
4,894
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE
AT END OF PERIOD
|
|
$
|
29,395
|
|
$
|
26,171
|
|
$
|
29,395
|
|
$
|
26,171
|
|
The
common stock of AEGCo is wholly-owned by AEP.
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
AEP
GENERATING COMPANY
CONDENSED
BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(Unaudited)
(in
thousands)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Accounts
Receivable - Affiliated Companies
|
|
$
|
24,356
|
|
$
|
29,671
|
|
Fuel
|
|
|
24,139
|
|
|
14,897
|
|
Materials
and Supplies
|
|
|
7,913
|
|
|
7,017
|
|
Accrued
Tax Benefits
|
|
|
2,009
|
|
|
2,074
|
|
Prepayments
and Other
|
|
|
105
|
|
|
9
|
|
TOTAL
|
|
|
58,522
|
|
|
53,668
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric
- Production
|
|
|
686,025
|
|
|
684,721
|
|
Other
|
|
|
2,385
|
|
|
2,369
|
|
Construction
Work in Progress
|
|
|
11,391
|
|
|
12,252
|
|
Total
|
|
|
699,801
|
|
|
699,342
|
|
Accumulated
Depreciation and Amortization
|
|
|
393,529
|
|
|
382,925
|
|
TOTAL
- NET
|
|
|
306,272
|
|
|
316,417
|
|
|
|
|
|
|
|
|
|
Noncurrent
Assets
|
|
|
7,738
|
|
|
6,618
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
372,532
|
|
$
|
376,703
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
GENERATING COMPANY
CONDENSED
BALANCE SHEETS
LIABILITIES
AND SHAREHOLDER’S EQUITY
September
30, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
14,938
|
|
$
|
35,131
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
1,311
|
|
|
926
|
|
Affiliated
Companies
|
|
|
21,018
|
|
|
22,161
|
|
Long-term
Debt Due Within One Year
|
|
|
-
|
|
|
44,828
|
|
Accrued
Taxes
|
|
|
5,880
|
|
|
3,055
|
|
Accrued
Rent - Rockport Plant Unit 2
|
|
|
23,427
|
|
|
4,963
|
|
Other
|
|
|
805
|
|
|
1,228
|
|
TOTAL
|
|
|
67,379
|
|
|
112,292
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt
|
|
|
44,835
|
|
|
-
|
|
Deferred
Income Taxes
|
|
|
20,852
|
|
|
23,617
|
|
Asset
Retirement Obligations
|
|
|
1,399
|
|
|
1,370
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
82,331
|
|
|
82,689
|
|
Deferred
Gain on Sale and Leaseback - Rockport Plant Unit 2
|
|
|
90,155
|
|
|
94,333
|
|
Obligations
Under Capital Leases
|
|
|
11,752
|
|
|
11,930
|
|
TOTAL
|
|
|
251,324
|
|
|
213,939
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
318,703
|
|
|
326,231
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - $1,000 Par Value Per Share
Authorized
and Outstanding - 1,000 Shares
|
|
|
1,000
|
|
|
1,000
|
|
Paid-in
Capital
|
|
|
23,434
|
|
|
23,434
|
|
Retained
Earnings
|
|
|
29,395
|
|
|
26,038
|
|
TOTAL
|
|
|
53,829
|
|
|
50,472
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$
|
372,532
|
|
$
|
376,703
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
GENERATING COMPANY
CONDENSED
STATEMENTS OF CASH FLOWS
For
the Nine Months Ended September 30, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
7,367
|
|
$
|
6,828
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
17,858
|
|
|
17,901
|
|
Deferred
Income Taxes
|
|
|
(3,468
|
)
|
|
(3,539
|
)
|
Deferred
Investment Tax Credits
|
|
|
(2,482
|
)
|
|
(2,501
|
)
|
Amortization
of Deferred Gain on Sale and Leaseback - Rockport Plant Unit
2
|
|
|
(4,178
|
)
|
|
(4,178
|
)
|
Deferred
Property Taxes
|
|
|
(893
|
)
|
|
(1,010
|
)
|
Changes
in Other Noncurrent Assets
|
|
|
(2,885
|
)
|
|
(1,736
|
)
|
Changes
in Other Noncurrent Liabilities
|
|
|
2,776
|
|
|
2,201
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
|
5,315
|
|
|
(2,469
|
)
|
Fuel,
Materials and Supplies
|
|
|
(10,138
|
)
|
|
4,278
|
|
Accounts
Payable
|
|
|
(758
|
)
|
|
(1,188
|
)
|
Accrued
Taxes, Net
|
|
|
2,890
|
|
|
(2,982
|
)
|
Rent
Accrued - Rockport Plant Unit 2
|
|
|
18,464
|
|
|
18,464
|
|
Other
Current Assets
|
|
|
(96
|
)
|
|
(17
|
)
|
Other
Current Liabilities
|
|
|
(423
|
)
|
|
(363
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
29,349
|
|
|
29,689
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(4,978
|
)
|
|
(9,041
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
(20,193
|
)
|
|
(15,601
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(168
|
)
|
|
(153
|
)
|
Dividends
Paid
|
|
|
(4,010
|
)
|
|
(4,894
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(24,371
|
)
|
|
(20,648
|
)
|
|
|
|
|
|
|
|
|
Net
Change in Cash and Cash Equivalents
|
|
|
-
|
|
|
-
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
-
|
|
|
-
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
-
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
2,413
|
|
$
|
2,104
|
|
Net
Cash Paid for Income Taxes
|
|
|
6,037
|
|
|
11,025
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
78
|
|
|
31
|
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
GENERATING COMPANY
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to AEGCo’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 AEGCo.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Allocation
Agreement between AEP East companies and AEP West
companies
Under
the
Texas Restructuring Legislation, we are completing the final stage of exiting
the generation business and have ceased serving retail load. Based on the
corporate separation and generation divestiture activities underway, the nature
of our business is no longer compatible with our participation in the CSW
Operating Agreement and the SIA since these agreements involve the coordinated
planning and operation of power supply facilities. Accordingly, on behalf of
the
AEP East companies and the AEP West companies, AEPSC filed with the FERC to
remove us from those agreements. The FERC approved the filing in March 2006.
The
SIA includes a methodology for sharing trading and marketing margins among
the
AEP East companies and the AEP West companies. Our sharing of margins ceased
effective May 1, 2006, which affects our future results of operations and cash
flows. We will continue to have margin and collateral deposits, risk management
assets and liabilities and trading gains or losses to the extent that we have
contracts dedicated specifically to us. As of September 30, 2006, we have no
dedicated contracts.
Results
of Operations
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006 Net
Income
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
40
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Texas
Supply
|
|
|
(4
|
)
|
|
|
|
Texas
Wires
|
|
|
(1
|
)
|
|
|
|
Off-system
Sales
|
|
|
(18
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(3
|
)
|
|
|
|
Other
|
|
|
(3
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(29
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
1
|
|
|
|
|
Carrying
Costs Income
|
|
|
10
|
|
|
|
|
Other
Income
|
|
|
(7
|
)
|
|
|
|
Interest
Expense
|
|
|
(11
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
17
|
|
Net
Income decreased $23 million to $17 million in 2006. The key drivers of the
decrease were a $29 million decrease in Gross Margin and a $7 million increase
in Operating Expenses and Other, partially offset by a reduction in Income
Tax
Expense of $13 million. We substantially exited the generation market with
the
sale of STP in May 2005.
The
major
components of our change in Gross Margin, defined as revenues less the related
direct cost of fuel, consumption of chemicals and emissions allowances, and
purchased power, were as follows:
·
|
Texas
Supply margins decreased $4 million primarily due to lower nonaffiliated
sales of $3 million.
|
·
|
Margins
from Off-system Sales decreased $18 million due to an $11 million
decrease
in margin sharing under the SIA (no current margin sharing under
the CSW
Operating Agreement and the SIA) and a $7 million decrease in margins
from
optimization activities. See the “Allocation Agreement between AEP East
companies and AEP West companies and CSW Operating Agreement” section of
Note 3.
|
·
|
Transmission
Revenues decreased $3 million primarily due to lower ERCOT transmission
rates and reduced affiliated transmission fees resulting from the
elimination of the affiliated OATT in 2005.
|
·
|
Other
revenues decreased $3 million primarily due to lower securitization
revenues of $3 million. Securitization revenues represent amounts
collected to recover securitization bond principal and interest payments
related to our securitized transition assets and are fully offset
by
amortization and interest expenses.
|
Operating
Expenses and Other changed between years as follows:
·
|
Carrying
Costs Income increased $10 million primarily due to a negative adjustment
of $8 million made in the third quarter of 2005 related to our True-up
Proceeding orders received from the PUCT.
|
·
|
Other
Income decreased $7 million primarily due to interest income recorded
in
the prior year related to the 2005 Texas Court of Appeals order (see
“Texas Restructuring - Excess Earnings” section of Note
4).
|
·
|
Interest
Expense increased $11 million primarily due to a $9 million increase
in
accrued interest related to the Texas competition transition charge
liability (See “Texas Restructuring - CTC Proceeding for Other True-up
Items” section of Note 4).
|
Income
Taxes
The
decrease in Income Tax Expense of $13 million is primarily due to a decrease
in
pretax book income.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine Months Ended September 30, 2005 to
Nine
Months Ended September 30, 2006 Net Income
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
70
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Texas
Supply
|
|
|
(78
|
)
|
|
|
|
Texas
Wires
|
|
|
14
|
|
|
|
|
Off-system
Sales
|
|
|
(21
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(12
|
)
|
|
|
|
Other
|
|
|
(9
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(106
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
50
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(6
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
6
|
|
|
|
|
Carrying
Costs Income
|
|
|
35
|
|
|
|
|
Other
Income
|
|
|
(13
|
)
|
|
|
|
Interest
Expense
|
|
|
(8
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
38
|
|
Net
Income decreased $32 million to $38 million in 2006. The key driver of the
decrease was a $106 million decrease in Gross Margin, partially offset by a
reduction in Other Operation and Maintenance expenses of $50 million and
increased Carrying Costs Income of $35 million. We substantially exited the
generation market with the sale of STP in May 2005.
The
major
components of our change in Gross Margin, defined as revenues less the related
direct cost of fuel, consumption of chemicals and emissions allowances, and
purchased power, were as follows:
·
|
Texas
Supply margins decreased $78 million primarily due to the sale of
STP,
which resulted in lower nonaffiliated sales of $101 million and a
$6
million provision for refund primarily due to the fuel reconciliation
adjustment in 2005. These decreases were partially offset by lower
fuel
and purchased power expenses of $30 million.
|
·
|
Texas
Wires revenues increased $14 million primarily due to favorable prices
and
a five percent increase in degree days.
|
·
|
Margins
from Off-system Sales decreased $21 million due to a $15 million
decrease
in margin sharing under the SIA and a $6 million decrease in margins
from
optimization activities. See the “Allocation Agreement between AEP East
companies and AEP West companies and CSW Operating Agreement” section of
Note 3.
|
·
|
Transmission
Revenues decreased $12 million primarily due to lower ERCOT transmission
rates and reduced affiliated transmission fees resulting from the
elimination of the affiliated OATT in 2005.
|
·
|
Other
revenues decreased $9 million primarily due to lower third party
construction project revenues of $4 million related to work performed
for
the Lower Colorado River Authority and reduced securitization revenues
of
$6 million. Securitization revenues represent amounts collected to
recover
securitization bond principal and interest payments related to our
securitized transition assets and are fully offset by amortization
and
interest expenses.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses decreased $50 million primarily
due to
a $12 million decrease in plant operations, a $14 million decrease
in
plant maintenance, a $6 million decrease in administrative and general
expenses and the absence of $7 million in accretion expense all related
to
the sale of STP. An additional $4 million decrease resulted from
lower
expenses related to construction activities performed for third parties,
primarily the Lower Colorado River Authority.
|
·
|
Depreciation
and Amortization expense increased $6 million primarily related to
the
refund and amortization of excess earnings credits in 2005 partially
offset by the recovery and amortization of securitized
assets.
|
·
|
Taxes
Other Than Income Taxes decreased $6 million primarily due to lower
property-related taxes as a result of the sale of STP in 2005 and
the
favorable settlement of a state use tax audit in 2006.
|
·
|
Carrying
Costs Income increased $35 million primarily due to negative adjustments
of $29 million and $8 million made in the first and third quarters
of
2005, respectively, related to our True-up Proceeding orders received
from
the PUCT.
|
·
|
Other
Income decreased $13 million primarily due to interest income recorded
in
the prior year related to the 2005 Texas Court of Appeals order (See
“Texas Restructuring - Excess Earnings” section of Note
4).
|
·
|
Interest
Expense increased $8 million primarily due to a $12 million increase
in
accrued interest related to the Texas CTC liability (see “Texas
Restructuring - CTC Proceeding for Other True-up Items” section of Note 4)
partially offset by a $2 million decrease in interest expense associated
with securitization revenues.
|
Income
Taxes
The
decrease in Income Tax Expense of $10 million is primarily due to a decrease
in
pretax book income, offset in part by tax reserve adjustments, a decrease in
the
amortization of investment tax credits due to the sale in May 2005 of STP and
a
decrease in consolidated tax savings from AEP.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Our current ratings are
as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
First
Mortgage Bonds
|
Baa1
|
|
BBB
|
|
A
|
Senior
Unsecured Debt
|
Baa2
|
|
BBB
|
|
A-
|
Cash
Flow
Cash
flows for the nine months ended September 30, 2006 and 2005 were as
follows:
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
-
|
|
$
|
26
|
|
Net
Cash Flows From (Used For):
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
137,471
|
|
|
(95,431
|
)
|
Investing
Activities
|
|
|
(197,269
|
)
|
|
293,461
|
|
Financing
Activities
|
|
|
59,803
|
|
|
(198,053
|
)
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
5
|
|
|
(23
|
)
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
5
|
|
$
|
3
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $137 million during the first nine months
of 2006. We produced Net Income of $38 million during the period and incurred
noncash items of $111 million for Depreciation and Amortization and $(65)
million for Carrying Costs on Stranded Cost Recovery. 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 most significant are decreases in Accounts Receivable, Net partially offset
by a decrease in Accounts Payable. Accounts Receivable, Net decreased $159
million primarily due to cash received for the retail clawback of $61 million
and 2005 storm restoration performed for nonaffiliated companies of $12 million.
In addition, our removal from the SIA and CSW Operating Agreement effective
May
1, 2006 resulted in fewer energy-related receivables. Accounts Payable decreased
$108 million primarily due to lower energy-related transactions resulting from
our removal from the SIA and CSW Operating Agreement.
Net
Cash
Flows Used For Operating Activities were $95 million during the first nine
months of 2005. We
produced income of $70 million during the period including noncash expense
items
of $105 million for Depreciation and Amortization and $(63) 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 these asset
and
liability accounts relate to a number of items; the most significant is a
decrease in Accrued Taxes, Net. Accrued Taxes, Net decreased $111 million
primarily as a result of taxes remitted to the government related to prior
year
and current year tax accruals.
Investing
Activities
Net
Cash
Flows Used For Investing Activities in 2006 were $197 million primarily due
to
$203 million of Construction Expenditures focused mainly on improved service
reliability projects for transmission and distribution systems. For the
remainder of 2006, we expect $83 million in Construction
Expenditures.
Net
Cash
Flows From Investing Activities in 2005 were $293 million primarily due to
$314
million of net proceeds from the sale of the STP nuclear plant and a reduction
in Other Cash Deposits, Net of $93 million primarily for the retirement of
defeased first mortgage bonds of $66 million. These cash inflows were partially
offset by cash used for construction expenditures of $109 million related to
projects for transmission and distribution service reliability.
Financing
Activities
Net
Cash
Flows From Financing Activities in 2006 were $60 million primarily due to the
issuance of $195 million of affiliated notes with AEP. This increase in
long-term debt was partially offset by a decrease in Advances from Affiliates,
Net of $82 million and the retirement of $52 million of securitization
bonds.
Net
Cash
Flows Used for Financing Activities in 2005 were $198 million primarily due
to
the payments of dividends of $150 million and the retirement of long-term debt
of $486 million, including $66 million of bonds that were defeased in 2004.
This
was partially offset by an issuance of new debt of $427 million, including
$150
million of affiliated long-term debt.
Financing
Activity
Long-term
debt issuances and retirements during the first nine months of 2006
were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Notes
Payable - Affiliated
|
|
$
|
125,000
|
|
5.14
|
|
2007
|
Notes
Payable - Affiliated
|
|
|
70,000
|
|
5.86
|
|
2007
|
Retirements
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Securitization
Bonds
|
|
$
|
52,265
|
|
5.01
|
|
2010
|
In
October 2006 TCC issued $1.74 billion in securitization bonds, as
follows:
Principal
|
|
Interest
|
|
Scheduled
Final
|
Amount
|
|
Rate
|
|
Payment
Date
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
$
|
217,000
|
|
4.98
|
|
2010
|
|
341,000
|
|
4.98
|
|
2013
|
|
250,000
|
|
5.09
|
|
2015
|
|
437,000
|
|
5.17
|
|
2018
|
|
494,700
|
|
5.3063
|
|
2020
|
The
proceeds will generally be used to retire TCC debt and equity, which are no
longer needed to support stranded costs.
In
October 2006, we retired $345 million in intercompany notes payable as
follows:
Principal
Amount
|
|
Interest
|
|
Due
|
|
Rate
|
|
Date
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
$
|
150,000
|
|
4.58
|
|
2007
|
|
125,000
|
|
5.14
|
|
2007
|
|
70,000
|
|
5.86
|
|
2007
|
In
November 2006, $100.6 million of pollution control bonds were put back to TCC
on
the put date of November 1, 2006. TCC intends to hold these bonds for reissuance
at a later date.
In
October 2006, we also paid a special dividend of $585 million to
AEP.
Liquidity
We
have
solid investment grade ratings, which provide us ready access to capital markets
in order to issue new debt or refinance long-term debt maturities. In addition,
we participate in the Utility Money Pool, which provides access to AEP’s
liquidity.
We
will
use proceeds received from the securitization to pay down a portion of our
equity and debt and to pay any necessary accelerated refunds related to the
CTC
(discussed below under Texas Restructuring).
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end other than the debt issuances and
retirements discussed above.
Significant
Factors
Texas
Restructuring
In
June
2006, we filed to implement a CTC refund of $357 million for our other true-up
items over eight years. The differences between the components of our Recorded
Net Regulatory Liabilities - Other True-up Items as of September 30, 2006
(including interest) and our Net CTC Refund Proposed are detailed
below:
|
|
(in
millions)
|
|
Wholesale
Capacity Auction True-up
|
|
$
|
61
|
|
Carrying
Costs on Wholesale Capacity Auction True-up
|
|
|
31
|
|
Retail
Clawback including Carrying Costs
|
|
|
(65
|
)
|
Deferred
Over-recovered Fuel Balance
|
|
|
(184
|
)
|
Retrospective
ADFIT Benefit
|
|
|
(77
|
)
|
Other
|
|
|
(4
|
)
|
Recorded
Net Regulatory Liabilities - Other True-up Items
|
|
|
(238
|
)
|
Unrecorded
Prospective ADFIT Benefit
|
|
|
(240
|
)
|
Gross
CTC Refund Proposed
|
|
|
(478
|
)
|
FERC
Jurisdictional Fuel Refund Deferral
|
|
|
16
|
|
ADITC
and EDFIT Benefit Refund Deferral
|
|
|
98
|
|
Net
CTC Refund Proposed, After Deferrals
|
|
|
(364
|
)
|
True-up
Proceeding Expense Surcharge
|
|
|
7
|
|
Net
CTC Refund Proposed, After Deferrals and Expenses
|
|
$
|
(357
|
)
|
In
September 2006, the PUCT approved an interim CTC that was implemented on October
12, 2006, the same day that we began billing customers for the securitization
bonds. The interim CTC will refund the entire retail clawback of $65 million
(including carrying costs) to residential customers by the end of 2006. The
CTC
refund to the other customer classes during the interim period will be as
proposed by us, with the exception of the large industrials, who will not
receive any fuel refunds during the interim period.
At
an
October 2006 open meeting, the PUCT announced oral decisions regarding the
CTC
refund. A final written order is expected in late November or early December
of
this year. In its decision, the PUCT confirmed that TCC can use securitization
bond proceeds to make the CTC refund. The PUCT’s decision was to continue the
interim CTC through December 2006 to complete the refund of the retail clawback
over three months. Beginning in January 2007, the Deferred Over-recovered Fuel
Balance will be refunded over six months with the large industrial customers
receiving their entire refund in January 2007. Starting in July 2007, the
remaining CTC items will be refunded over one year, except that the PUCT agreed
with our request to defer the refund of the ADITC and EDFIT Benefit Refund
Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table
above). The PUCT will decide those issues and related amounts in another
proceeding.
Municipal
customers and other intervenors appealed the PUCT orders seeking to further
reduce our true-up recoveries. If we determine, as a result of future PUCT
orders or appeal court rulings, that it is probable we cannot recover a portion
of our recorded net true-up regulatory asset and we are able to estimate the
amount of a resultant impairment, we would record a provision for such amount
which would have an adverse effect on future results of operations, cash flows
and possibly financial condition. We appealed the PUCT orders seeking relief
in
both state and federal court where we believe the PUCT’s rulings are contrary to
the Texas Restructuring Legislation, PUCT rulemakings and federal
law. The
significant items appealed by TCC are:
·
|
the
PUCT ruled that TCC did not comply with the statute and PUCT rules
regarding the auction of 15% of its Texas jurisdictional installed
capacity,
|
·
|
that
TCC acted in a manner that was commercially unreasonable because
it failed
to determine a minimum price at which it would reject bids for
the sale of
its nuclear generating plant and it bundled gas units with the
sale of its
coal unit,
|
·
|
and
two federal matters regarding the allocation of off-system sales
related
to fuel recoveries and the potential tax normalization
violation.
|
These
appeals could take years to resolve and could result in material effects on
future results of operations. If the PUCT rejects our deferral proposal and
a
normalization violation occurs, future results of operations and cash flows
could be adversely affected by the recapture of $104 million of our ADITC and
the loss of future accelerated
tax depreciation election. The estimated future impact on earnings of the Texas
Restructuring as of September 30, 2006, exclusive of a possible normalization
violation and any effects of appeal litigation, over the 14-year securitization
net recovery period assuming the PUCT approves our CTC filing, including the
interim refund, is detailed below:
|
|
(in
millions)
|
|
ADITC
and EDFIT Benefits Reducing Securitization
|
|
$
|
98
|
|
ADFIT
Benefit Applied to Reduce 2002 Securitization of Regulatory Assets
|
|
|
(60
|
)
|
Securitization
Settlement
|
|
|
(77
|
)
|
Unrecorded
Prospective ADFIT Benefit Increasing the CTC Refund
|
|
|
(240
|
)
|
Unrecorded
Equity Carrying Costs Recognized as Collected
|
|
|
224
|
|
Future
Interest Payable on Proposed CTC Refund
|
|
|
(19
|
)
|
Deferred
Fuel - Federal Jurisdictional Issue
|
|
|
16
|
|
Net
Adverse Earnings Impact Over 14 Years
|
|
$
|
(58
|
)
|
If
the
PUCT changes its oral decision regarding the proposed CTC deferral and the
two
contingent federal matters are refunded to customers, the future adverse impact
on results of operations over the next 14 years will increase to $181 million.
This potential adverse impact on results of operations over the next 14 years
would be more than offset by the annual cost of money benefit from the $2.2
billion in net proceeds that resulted from the sale of bonds in connection
with
the initial regulatory asset securitization in 2002 of $797 million and from
the
$1.74 billion sale of securitization bonds in October 2006 less the proposed
$357 million CTC refund over the next eight years.
Litigation
and Regulatory Activity
In
the
ordinary course of business, we 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 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 our
pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note
6
- Customer Choice and Industry Restructuring and Note 7 - Commitments and
Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note
4
- Customer Choice and Industry Restructuring and Note 5 - Commitments and
Contingencies in the “Condensed Notes to Condensed Financial Statements of
Registrant Subsidiaries” section. Adverse results in these proceedings have the
potential to materially affect our results of operations, financial condition
and cash flows.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2005 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.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management policies and procedures are instituted and administered at the AEP
Consolidated level. 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
us.
MTM
Risk Management Contract Net Assets
Our
MTM
Risk Management Contract Net Assets are zero as of September 30, 2006. For
further explanation, see “Allocation Agreement between AEP East companies and
AEP West companies” section of this Management’s Financial Discussion and
Analysis.
The
following table summarizes the reasons for changes in our total MTM value as
compared to December 31, 2005.
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 2006
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
|
$
|
5,426
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
(1,175
|
)
|
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
|
|
|
-
|
|
Changes
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(3,868
|
)
|
Changes
Due to SIA and CSW Operating Agreement (c)
|
|
|
(383
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
-
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
-
|
|
Net
Cash Flow Hedge Contracts
|
|
|
-
|
|
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
|
$
|
-
|
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek 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)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies”
section of this Management’s Financial Discussion and
Analysis.
|
(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 liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net
Assets
Our
MTM
Risk Management Contracts Net Assets are zero as of September 30, 2006.
Therefore, there is no maturity and source of fair value to report.
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheet
As
a
result of changes made to the Allocation Agreement between AEP East companies
and AEP West companies in the second quarter of 2006, we are no longer exposed
to market fluctuations in energy commodity prices. Therefore, we have no
contracts designated as cash flow hedges on our September 30, 2006 Condensed
Consolidated Balance Sheet.
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 the changes from December 31, 2005 to September 30, 2006. 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, 2006
(in
thousands)
|
|
Power
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(224
|
)
|
Changes
in Fair Value
|
|
|
-
|
|
Impact
Due to Changes in SIA (a)
|
|
|
218
|
|
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
|
|
6
|
|
Ending
Balance in AOCI September 30, 2006
|
|
$
|
-
|
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies”
section of this Management’s Financial Discussion and
Analysis.
|
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
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, 2006, a near term typical change
in
commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended
September
30, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$-
|
|
$11
|
|
$2
|
|
$-
|
|
|
|
|
$111
|
|
$184
|
|
$88
|
|
$32
|
VaR
Associated with Debt Outstanding
We
also
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The risk of potential loss in fair value
attributable to our exposure to interest rates primarily related to long-term
debt with fixed interest rates was $70 million and $93 million at September
30,
2006 and December 31, 2005, respectively. We would not expect to liquidate
our
entire debt portfolio in a one-year holding period; therefore, a near term
change in interest rates should not negatively affect our results of operations
or consolidated financial position.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2006 and
2005
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
162,902
|
|
$
|
192,932
|
|
$
|
435,801
|
|
$
|
559,822
|
|
Sales
to AEP Affiliates
|
|
|
1,559
|
|
|
2,528
|
|
|
4,703
|
|
|
12,794
|
|
Other
- Nonaffiliated
|
|
|
9,462
|
|
|
7,905
|
|
|
30,196
|
|
|
34,432
|
|
TOTAL
|
|
|
173,923
|
|
|
203,365
|
|
|
470,700
|
|
|
607,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
2,006
|
|
|
1,915
|
|
|
4,728
|
|
|
12,047
|
|
Purchased
Electricity for Resale
|
|
|
725
|
|
|
1,691
|
|
|
3,557
|
|
|
27,057
|
|
Other
Operation
|
|
|
61,057
|
|
|
64,408
|
|
|
183,241
|
|
|
221,741
|
|
Maintenance
|
|
|
10,679
|
|
|
8,782
|
|
|
27,255
|
|
|
38,254
|
|
Depreciation
and Amortization
|
|
|
40,298
|
|
|
40,342
|
|
|
110,848
|
|
|
105,062
|
|
Taxes
Other Than Income Taxes
|
|
|
23,387
|
|
|
22,828
|
|
|
60,421
|
|
|
66,282
|
|
TOTAL
|
|
|
138,152
|
|
|
139,966
|
|
|
390,050
|
|
|
470,443
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
35,771
|
|
|
63,399
|
|
|
80,650
|
|
|
136,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
560
|
|
|
8,295
|
|
|
1,592
|
|
|
15,722
|
|
Carrying
Costs Income
|
|
|
25,443
|
|
|
15,349
|
|
|
65,279
|
|
|
30,146
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
667
|
|
|
(59
|
)
|
|
1,671
|
|
|
641
|
|
Interest
Expense
|
|
|
(36,746
|
)
|
|
(25,374
|
)
|
|
(93,401
|
)
|
|
(85,095
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
25,695
|
|
|
61,610
|
|
|
55,791
|
|
|
98,019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
8,460
|
|
|
21,134
|
|
|
17,808
|
|
|
28,038
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
17,235
|
|
|
40,476
|
|
|
37,983
|
|
|
69,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
60
|
|
|
60
|
|
|
181
|
|
|
181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
17,175
|
|
$
|
40,416
|
|
$
|
37,802
|
|
$
|
69,800
|
|
The common stock of TCC is owned by a wholly-owned subsidiary of
AEP.
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Nine Months Ended September 30, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2004
|
|
$
|
55,292
|
|
$
|
132,606
|
|
$
|
1,084,904
|
|
$
|
(4,159
|
)
|
$
|
1,268,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(150,000
|
)
|
|
|
|
|
(150,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(181
|
)
|
|
|
|
|
(181
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,118,462
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $1,626
|
|
|
|
|
|
|
|
|
|
|
|
(3,021
|
)
|
|
(3,021
|
)
|
Minimum
Pension Liability, Net of Tax of
$0
|
|
|
|
|
|
|
|
|
|
|
|
3,810
|
|
|
3,810
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
69,981
|
|
|
|
|
|
69,981
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70,770
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2005
|
|
$
|
55,292
|
|
$
|
132,606
|
|
$
|
1,004,704
|
|
$
|
(3,370
|
)
|
$
|
1,189,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
55,292
|
|
$
|
132,606
|
|
$
|
760,884
|
|
$
|
(1,152
|
)
|
$
|
947,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(181
|
)
|
|
|
|
|
(181
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
947,449
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $121
|
|
|
|
|
|
|
|
|
|
|
|
224
|
|
|
224
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
37,983
|
|
|
|
|
|
37,983
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,207
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$
|
55,292
|
|
$
|
132,606
|
|
$
|
798,686
|
|
$
|
(928
|
)
|
$
|
985,656
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
5
|
|
$
|
-
|
|
Other
Cash Deposits
|
|
|
41,728
|
|
|
66,153
|
|
Advances
to Affiliates
|
|
|
25,304
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
65,875
|
|
|
209,957
|
|
Affiliated
Companies
|
|
|
8,633
|
|
|
23,486
|
|
Accrued
Unbilled Revenues
|
|
|
25,350
|
|
|
25,606
|
|
Allowance
for Uncollectible Accounts
|
|
|
(217
|
)
|
|
(143
|
)
|
Total Accounts Receivable
|
|
|
99,641
|
|
|
258,906
|
|
Unbilled
Construction Costs
|
|
|
6,352
|
|
|
19,440
|
|
Materials
and Supplies
|
|
|
24,995
|
|
|
13,897
|
|
Risk
Management Assets
|
|
|
-
|
|
|
14,311
|
|
Prepayments
and Other
|
|
|
5,645
|
|
|
5,231
|
|
TOTAL
|
|
|
203,670
|
|
|
377,938
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Transmission
|
|
|
900,774
|
|
|
817,351
|
|
Distribution
|
|
|
1,559,593
|
|
|
1,476,683
|
|
Other
|
|
|
232,023
|
|
|
233,361
|
|
Construction
Work in Progress
|
|
|
126,418
|
|
|
129,800
|
|
Total
|
|
|
2,818,808
|
|
|
2,657,195
|
|
Accumulated
Depreciation and Amortization
|
|
|
637,517
|
|
|
636,078
|
|
TOTAL
- NET
|
|
|
2,181,291
|
|
|
2,021,117
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
1,710,352
|
|
|
1,688,787
|
|
Securitized
Transition Assets
|
|
|
557,520
|
|
|
593,401
|
|
Long-term
Risk Management Assets
|
|
|
-
|
|
|
11,609
|
|
Employee
Benefits and Pension Assets
|
|
|
112,594
|
|
|
114,733
|
|
Deferred
Charges and Other
|
|
|
57,276
|
|
|
53,011
|
|
TOTAL
|
|
|
2,437,742
|
|
|
2,461,541
|
|
|
|
|
|
|
|
|
|
Assets
Held for Sale - Texas Generation Plants
|
|
|
45,863
|
|
|
44,316
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
4,868,566
|
|
$
|
4,904,912
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
September
30, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
-
|
|
$
|
82,080
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
20,889
|
|
|
82,666
|
|
Affiliated
Companies
|
|
|
18,160
|
|
|
65,574
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
153,364
|
|
|
152,900
|
|
Long-term
Debt Due Within One Year - Affiliated
|
|
|
345,000
|
|
|
-
|
|
Risk
Management Liabilities
|
|
|
-
|
|
|
13,024
|
|
Accrued
Taxes
|
|
|
74,887
|
|
|
54,566
|
|
Accrued
Interest
|
|
|
16,011
|
|
|
32,497
|
|
Other
|
|
|
32,500
|
|
|
45,927
|
|
TOTAL
|
|
|
660,811
|
|
|
529,234
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
1,498,031
|
|
|
1,550,596
|
|
Long-term
Debt - Affiliated
|
|
|
-
|
|
|
150,000
|
|
Long-term
Risk Management Liabilities
|
|
|
-
|
|
|
7,857
|
|
Deferred
Income Taxes
|
|
|
1,014,840
|
|
|
1,048,372
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
684,566
|
|
|
652,143
|
|
Deferred
Credits and Other
|
|
|
18,723
|
|
|
13,140
|
|
TOTAL
|
|
|
3,216,160
|
|
|
3,422,108
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
3,876,971
|
|
|
3,951,342
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
5,939
|
|
|
5,940
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - $25 Par Value Per Share:
|
|
|
|
|
|
|
|
Authorized
- 12,000,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 2,211,678 Shares
|
|
|
55,292
|
|
|
55,292
|
|
Paid-in
Capital
|
|
|
132,606
|
|
|
132,606
|
|
Retained
Earnings
|
|
|
798,686
|
|
|
760,884
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(928
|
)
|
|
(1,152
|
)
|
TOTAL
|
|
|
985,656
|
|
|
947,630
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
4,868,566
|
|
$
|
4,904,912
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Nine Months Ended September 30, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
37,983
|
|
$
|
69,981
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
110,848
|
|
|
105,062
|
|
Accretion
of Asset Retirement Obligations
|
|
|
55
|
|
|
7,549
|
|
Deferred
Income Taxes
|
|
|
5,770
|
|
|
(63,426
|
)
|
Carrying
Costs on Stranded Cost Recovery
|
|
|
(65,279
|
)
|
|
(30,146
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
5,426
|
|
|
(1,139
|
)
|
Over/Under
Fuel Recovery
|
|
|
7,225
|
|
|
(2,000
|
)
|
Deferred
Property Taxes
|
|
|
(8,296
|
)
|
|
(7,600
|
)
|
Change
in Other Noncurrent Assets
|
|
|
17,653
|
|
|
(9,777
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
(17,249
|
)
|
|
(1,390
|
)
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
159,265
|
|
|
(22,504
|
)
|
Fuel,
Materials and Supplies
|
|
|
(11,508
|
)
|
|
(1,763
|
)
|
Accounts
Payable
|
|
|
(107,505
|
)
|
|
(10,533
|
)
|
Customer
Deposits
|
|
|
(6,461
|
)
|
|
12,844
|
|
Accrued
Taxes, Net
|
|
|
16,387
|
|
|
(110,975
|
)
|
Accrued
Interest
|
|
|
(16,486
|
)
|
|
(24,495
|
)
|
Other
Current Assets
|
|
|
16,611
|
|
|
(13,709
|
)
|
Other
Current Liabilities
|
|
|
(6,968
|
)
|
|
8,590
|
|
Net
Cash Flows From (Used For) Operating Activities
|
|
|
137,471
|
|
|
(95,431
|
)
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(203,116
|
)
|
|
(109,372
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
25,068
|
|
|
93,427
|
|
Change
in Advances to Affiliates, Net
|
|
|
(25,304
|
)
|
|
-
|
|
Purchases
of Investment Securities
|
|
|
-
|
|
|
(154,364
|
)
|
Sales
of Investment Securities
|
|
|
-
|
|
|
149,804
|
|
Proceeds
from Sale of Assets
|
|
|
6,083
|
|
|
313,966
|
|
Net
Cash Flows From (Used For) Investing Activities
|
|
|
(197,269
|
)
|
|
293,461
|
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt - Nonaffiliated
|
|
|
-
|
|
|
276,663
|
|
Issuance
of Long-term Debt - Affiliated
|
|
|
195,000
|
|
|
150,000
|
|
Change
in Advances from Affiliates, Net
|
|
|
(82,080
|
)
|
|
11,814
|
|
Retirement
of Long-term Debt
|
|
|
(52,265
|
)
|
|
(486,007
|
)
|
Retirement
of Preferred Stock
|
|
|
(1
|
)
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(670
|
)
|
|
(342
|
)
|
Dividends
Paid on Common Stock
|
|
|
-
|
|
|
(150,000
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(181
|
)
|
|
(181
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
59,803
|
|
|
(198,053
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
5
|
|
|
(23
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
-
|
|
|
26
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
5
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
DISCLOSURE
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
93,165
|
|
$
|
95,066
|
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(2,764
|
)
|
|
207,079
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
3,282
|
|
|
277
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
9,351
|
|
|
8,797
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to TCC’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 TCC.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Customer
Choice and Industry Restructuring
|
Note
4
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Acquisitions,
Assets Held for Sale and Asset Impairments
|
Note
8
|
Benefit
Plans
|
Note
9
|
Income
Taxes
|
Note
10
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Allocation
Agreement between AEP East companies and AEP West
companies
Under
the
Texas Restructuring Legislation, we are completing the final stage of exiting
the generation business and have ceased serving retail load. Based on the
corporate separation and generation divestiture activities underway, the nature
of our business is no longer compatible with our participation in the CSW
Operating Agreement and the SIA since these agreements involve the coordinated
planning and operation of power supply facilities. Accordingly, on behalf of
the
AEP East companies and the AEP West companies, AEPSC filed with the FERC to
remove us from those agreements. The FERC approved the filing in March 2006.
The
SIA includes a methodology for sharing trading and marketing margins among
the
AEP East companies and the AEP West companies. Our sharing of margins ceased
effective May 1, 2006, which affects our future results of operations and cash
flows. We will continue to have margin and collateral deposits, risk management
assets and liabilities and trading gains or losses to the extent that we have
contracts dedicated specifically to us.
AEP
Texas North Generation Company, LLC
In
the
third quarter of 2006, we created a new wholly-owned subsidiary, AEP Texas
North
Generation Company, LLC (TNGC). Following the creation of this subsidiary,
we
transferred all of our mothballed generation assets and related liabilities
to
this new subsidiary, substantially completing the business separation
requirement of the Texas Restructuring Legislation. Subsequently, TNGC became
a
participant in the Nonutility Money Pool. The creation of TNGC did not have
a
significant impact on our results of operations or financial
condition.
Results
of Operations
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006 Net
Income
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
22
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Texas
Supply
|
|
|
(12
|
)
|
|
|
|
Texas
Wires
|
|
|
(1
|
)
|
|
|
|
Off-system
Sales
|
|
|
(10
|
)
|
|
|
|
Transmission
Revenues
|
|
|
1
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(22
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
8
|
|
Net
Income decreased $14 million to $8 million in 2006 primarily due to a decrease
in Gross Margin of $22 million, partially offset by a reduction in Income Tax
Expense of $7 million.
The
major
components of our change in Gross Margin, defined as revenues less the related
direct cost of fuel, consumption of chemicals and emissions allowances, and
purchased power, were as follows:
·
|
Texas
Supply margins decreased $12 million primarily due to a $28 million
decrease in dedicated energy and capacity sales, offset by $16 million
of
lower fuel and purchased power costs. This decrease in Texas Supply
margins was affected by market conditions within ERCOT.
|
·
|
Margins
from Off-system Sales decreased $10 million due to a $5 million decrease
in margin sharing under the SIA (no current margin sharing under
the CSW
Operating Agreement and the SIA) and a $5 million decrease in margins
from
optimization activities. See
the “Allocation Agreement between AEP East companies and AEP West
companies and CSW Operating Agreement” section of Note
3.
|
Income
Taxes
The
decrease in Income Tax Expense of $7 million is primarily due to a decrease
in
pretax book income.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine
Months Ended September 30, 2005
to
Nine
Months
Ended September 30, 2006
Net Income
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
42
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Texas
Supply
|
|
|
(29
|
)
|
|
|
|
Texas
Wires
|
|
|
(2
|
)
|
|
|
|
Off-system
Sales
|
|
|
(11
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(5
|
)
|
|
|
|
Other
|
|
|
(39
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(86
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
38
|
|
|
|
|
Interest
Expense
|
|
|
1
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
12
|
|
Net
Income decreased $30 million to $12 million in 2006 primarily due to a decrease
in Gross Margin of $86 million partially offset by a reduction in Other
Operation and Maintenance expenses of $38 million and a reduction in Income
Tax
Expense of $17 million.
The
major
components of our change in Gross Margin, defined as revenues less the related
direct cost of fuel, consumption of chemicals and emissions allowances, and
purchased power, were as follows:
·
|
Texas
Supply margins decreased $29 million primarily due to a $58 million
decrease in dedicated energy and capacity sales, offset by $28 million
of
lower fuel and purchased power costs. This decrease in Texas Supply
margins was affected by market conditions within ERCOT.
|
·
|
Margins
from Off-system Sales decreased $11 million due to a $6 million decrease
in margin sharing under the SIA and a $5 million decrease in margins
from
optimization activities. See
the “Allocation Agreement between AEP East companies and AEP West
companies and CSW Operating Agreement” section of Note
3.
|
·
|
Transmission
Revenues decreased $5 million primarily due to reduced affiliated
transmission fees resulting from the elimination of the affiliated
OATT in
2005.
|
·
|
Other
revenues decreased $39 million primarily resulting from the completion
of
certain third party construction projects related to work performed
for
the Lower Colorado River Authority.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses decreased $38 million primarily
due to
lower expenses related to the completion of certain third party
construction projects related to work performed for the Lower Colorado
River Authority.
|
Income
Taxes
The
decrease in Income Tax Expense of $17 million is primarily due to a decrease
in
pretax book income.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook, except for Fitch which
has
us on a negative outlook. Our current ratings are as follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
First
Mortgage Bonds
|
A3
|
|
BBB
|
|
A
|
Senior
Unsecured Debt
|
Baa1
|
|
BBB
|
|
A-
|
Financing
Activity
There
were no long-term debt issuances or retirements during the first nine months
of
2006.
Liquidity
We
have
solid investment grade ratings, which provide us ready access to capital markets
in order to issue new debt or refinance long-term debt maturities. In addition,
TNC participates in the Utility Money Pool and TNGC participates in the
Nonutility Money Pool, both of which provide access to AEP’s liquidity.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end except for Energy and Capacity Purchase
Contracts. We exited both the SIA and CSW Operating Agreement, eliminating
our
future obligation for Energy and Capacity Purchase Contracts. See “Allocation
Agreement between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
Significant
Factors
Litigation
and Regulatory Activity
In
the
ordinary course of business, we 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 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 our
pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note
6
- Customer Choice and Industry Restructuring and Note 7 - Commitments and
Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note
4
- Customer Choice and Industry Restructuring and Note 5 - Commitments and
Contingencies in the “Condensed Notes to Condensed Financial Statements of
Registrant Subsidiaries” section. Adverse results in these proceedings have the
potential to materially affect our results of operations, financial condition
and cash flows.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2005 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.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management policies and procedures are instituted and administered at the AEP
Consolidated level. 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
us.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in our condensed consolidated balance sheet as of September 30, 2006
and the reasons for changes in our total MTM value as compared to December
31,
2005.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of September 30, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
Total
|
|
Current
Assets
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
Noncurrent
Assets
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
MTM Derivative Contract Assets
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(2,138
|
)
|
|
-
|
|
|
(2,138
|
)
|
Noncurrent
Liabilities
|
|
|
-
|
|
|
(2,057
|
)
|
|
(2,057
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(2,138
|
)
|
|
(2,057
|
)
|
|
(4,195
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$
|
(2,138
|
)
|
$
|
(2,057
|
)
|
$
|
(4,195
|
)
|
MTM
Risk Management Contract Net Assets (Liabilities)
Nine
Months Ended September 30, 2006
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
|
$
|
2,698
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
(585
|
)
|
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
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(3,437
|
)
|
Changes
Due to SIA and CSW Operating Agreement (c)
|
|
|
(814
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
-
|
|
Total
MTM Risk Management Contract Net Assets
(Liabilities)
|
|
|
(2,138
|
)
|
Net
Cash Flow Hedge Contracts
|
|
|
(2,057
|
)
|
Total
MTM Risk Management Contract Net Assets (Liabilities) at September
30,
2006
|
|
$
|
(4,195
|
)
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek 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)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies”
section of this Management’s Financial Discussion and
Analysis.
|
(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 liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net
Assets
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
(2,138
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(2,138
|
)
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
|
|
$
|
(2,138
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(2,138
|
)
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheet
We
are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations
on
the future cash flows from assets. We do not hedge all commodity price
risk.
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 the changes from December 31, 2005 to September 30, 2006. 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, 2006
(in
thousands)
|
|
Power
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(111
|
)
|
Changes
in Fair Value
|
|
|
(1,337
|
)
|
Impact
Due to Change in SIA (a)
|
|
|
98
|
|
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
|
|
13
|
|
Ending
Balance in AOCI September 30, 2006
|
|
$
|
(1,337
|
)
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies”
section of this Management’s Financial Discussion and
Analysis.
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is zero.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
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, 2006, a near term typical change
in
commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended
September
30, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$-
|
|
$23
|
|
$4
|
|
$-
|
|
|
|
|
$55
|
|
$92
|
|
$44
|
|
$16
|
VaR
Associated with Debt Outstanding
We
also
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The risk of potential loss in fair value
attributable to our exposure to interest rates primarily related to long-term
debt with fixed interest rates was $11 million and $13 million at September
30,
2006 and December 31, 2005, respectively. We would not expect to liquidate
our
entire debt portfolio in a one-year holding period; therefore, a near term
change in interest rates should not negatively affect our results of operations
or financial position.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2006 and
2005
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
79,805
|
|
$
|
111,107
|
|
$
|
219,681
|
|
$
|
280,195
|
|
Sales
to AEP Affiliates
|
|
|
7,711
|
|
|
13,019
|
|
|
25,596
|
|
|
37,189
|
|
Other
|
|
|
246
|
|
|
1,971
|
|
|
149
|
|
|
42,324
|
|
TOTAL
|
|
|
87,762
|
|
|
126,097
|
|
|
245,426
|
|
|
359,708
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
14,016
|
|
|
13,433
|
|
|
33,175
|
|
|
37,772
|
|
Purchased
Electricity for Resale
|
|
|
14,606
|
|
|
34,425
|
|
|
60,343
|
|
|
88,367
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
2,436
|
|
|
1
|
|
|
3,978
|
|
|
23
|
|
Other
Operation
|
|
|
19,003
|
|
|
18,878
|
|
|
59,192
|
|
|
97,135
|
|
Maintenance
|
|
|
5,088
|
|
|
5,954
|
|
|
15,505
|
|
|
15,093
|
|
Depreciation
and Amortization
|
|
|
10,767
|
|
|
10,435
|
|
|
31,172
|
|
|
30,952
|
|
Taxes
Other Than Income Taxes
|
|
|
5,478
|
|
|
6,047
|
|
|
16,874
|
|
|
17,465
|
|
TOTAL
|
|
|
71,394
|
|
|
89,173
|
|
|
220,239
|
|
|
286,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
16,368
|
|
|
36,924
|
|
|
25,187
|
|
|
72,901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
203
|
|
|
890
|
|
|
542
|
|
|
1,688
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
146
|
|
|
137
|
|
|
636
|
|
|
366
|
|
Interest
Expense
|
|
|
(4,472
|
)
|
|
(4,931
|
)
|
|
(13,351
|
)
|
|
(14,784
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
12,245
|
|
|
33,020
|
|
|
13,014
|
|
|
60,171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
3,799
|
|
|
10,716
|
|
|
1,326
|
|
|
18,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
8,446
|
|
|
22,304
|
|
|
11,688
|
|
|
41,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
26
|
|
|
26
|
|
|
78
|
|
|
78
|
|
Gain
on Reacquired Preferred Stock
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
8,420
|
|
$
|
22,278
|
|
$
|
11,612
|
|
$
|
41,624
|
|
The common
stock of TNC is owned by a wholly-owned subsidiary of AEP.
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Nine Months Ended September 30, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
DECEMBER
31, 2004
|
|
$
|
137,214
|
|
$
|
2,351
|
|
$
|
170,984
|
|
$
|
(128
|
)
|
$
|
310,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(20,827
|
)
|
|
|
|
|
(20,827
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(78
|
)
|
|
|
|
|
(78
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
289,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $698
|
|
|
|
|
|
|
|
|
|
|
|
(1,296
|
)
|
|
(1,296
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
41,702
|
|
|
|
|
|
41,702
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2005
|
|
$
|
137,214
|
|
$
|
2,351
|
|
$
|
191,781
|
|
$
|
(1,424
|
)
|
$
|
329,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
137,214
|
|
$
|
2,351
|
|
$
|
174,858
|
|
$
|
(504
|
)
|
$
|
313,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(12,750
|
)
|
|
|
|
|
(12,750
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(78
|
)
|
|
|
|
|
(78
|
)
|
Gain
on Reacquired Preferred Stock
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
2
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
301,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $660
|
|
|
|
|
|
|
|
|
|
|
|
(1,226
|
)
|
|
(1,226
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
11,688
|
|
|
|
|
|
11,688
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,462
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$
|
137,214
|
|
$
|
2,351
|
|
$
|
173,720
|
|
$
|
(1,730
|
)
|
$
|
311,555
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
-
|
|
$
|
-
|
|
Other
Cash Deposits
|
|
|
9,087
|
|
|
1,432
|
|
Advances
to Affiliates
|
|
|
4,383
|
|
|
34,286
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
23,367
|
|
|
77,678
|
|
Affiliated
Companies
|
|
|
11,910
|
|
|
26,149
|
|
Accrued
Unbilled Revenues
|
|
|
2,567
|
|
|
5,016
|
|
Allowance
for Uncollectible Accounts
|
|
|
(24
|
)
|
|
(18
|
)
|
Total
Accounts Receivable
|
|
|
37,820
|
|
|
108,825
|
|
Fuel
|
|
|
5,528
|
|
|
2,636
|
|
Materials
and Supplies
|
|
|
8,459
|
|
|
6,858
|
|
Risk
Management Assets
|
|
|
-
|
|
|
7,114
|
|
Prepayments
and Other
|
|
|
1,537
|
|
|
3,772
|
|
TOTAL
|
|
|
66,814
|
|
|
164,923
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
290,391
|
|
|
288,934
|
|
Transmission
|
|
|
324,724
|
|
|
289,029
|
|
Distribution
|
|
|
507,307
|
|
|
492,878
|
|
Other
|
|
|
165,403
|
|
|
167,849
|
|
Construction
Work in Progress
|
|
|
31,991
|
|
|
46,424
|
|
Total
|
|
|
1,319,816
|
|
|
1,285,114
|
|
Accumulated
Depreciation and Amortization
|
|
|
486,131
|
|
|
478,519
|
|
TOTAL
- NET
|
|
|
833,685
|
|
|
806,595
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
8,920
|
|
|
9,787
|
|
Long-term
Risk Management Assets
|
|
|
-
|
|
|
5,772
|
|
Employee
Benefits and Pension Assets
|
|
|
45,409
|
|
|
46,289
|
|
Deferred
Charges and Other
|
|
|
7,153
|
|
|
10,468
|
|
TOTAL
|
|
|
61,482
|
|
|
72,316
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
961,981
|
|
$
|
1,043,834
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’
EQUITY
September
30, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
$
|
9,151
|
|
$
|
19,739
|
|
Affiliated
Companies
|
|
|
27,854
|
|
|
84,923
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
8,151
|
|
|
-
|
|
Risk
Management Liabilities
|
|
|
2,138
|
|
|
6,475
|
|
Accrued
Taxes
|
|
|
29,458
|
|
|
21,212
|
|
Other
|
|
|
11,203
|
|
|
21,050
|
|
TOTAL
|
|
|
87,955
|
|
|
153,399
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
268,762
|
|
|
276,845
|
|
Long-term
Risk Management Liabilities
|
|
|
2,057
|
|
|
3,906
|
|
Deferred
Income Taxes
|
|
|
123,991
|
|
|
132,335
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
143,506
|
|
|
139,732
|
|
Deferred
Credits and Other
|
|
|
21,806
|
|
|
21,341
|
|
TOTAL
|
|
|
560,122
|
|
|
574,159
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
648,077
|
|
|
727,558
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
2,349
|
|
|
2,357
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - $25 Par Value Per Share:
|
|
|
|
|
|
|
|
Authorized
- 7,800,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 5,488,560 Shares
|
|
|
137,214
|
|
|
137,214
|
|
Paid-in
Capital
|
|
|
2,351
|
|
|
2,351
|
|
Retained
Earnings
|
|
|
173,720
|
|
|
174,858
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(1,730
|
)
|
|
(504
|
)
|
TOTAL
|
|
|
311,555
|
|
|
313,919
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
961,981
|
|
$
|
1,043,834
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Nine Months Ended September 30, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
11,688
|
|
$
|
41,702
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
31,172
|
|
|
30,952
|
|
Deferred
Income Taxes
|
|
|
(4,667
|
)
|
|
(313
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
4,836
|
|
|
(452
|
)
|
Deferred
Property Taxes
|
|
|
(4,359
|
)
|
|
(4,072
|
)
|
Change
in Other Noncurrent Assets
|
|
|
(5,173
|
)
|
|
(1,109
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
(630
|
)
|
|
(71
|
)
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
71,005
|
|
|
9,366
|
|
Fuel,
Materials and Supplies
|
|
|
(4,493
|
)
|
|
922
|
|
Accounts
Payable
|
|
|
(66,653
|
)
|
|
16,834
|
|
Customer
Deposits
|
|
|
(3,571
|
)
|
|
5,471
|
|
Accrued
Taxes, Net
|
|
|
7,984
|
|
|
(10,097
|
)
|
Other
Current Assets
|
|
|
2,496
|
|
|
11,189
|
|
Other
Current Liabilities
|
|
|
(5,304
|
)
|
|
(551
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
34,331
|
|
|
99,771
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(52,366
|
)
|
|
(44,865
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
979
|
|
|
1,508
|
|
Change
In Advances to Affiliates, Net
|
|
|
29,903
|
|
|
(36,147
|
)
|
Proceeds
from Sale of Assets
|
|
|
250
|
|
|
1,033
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(21,234
|
)
|
|
(78,471
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Retirement
of Preferred Stock
|
|
|
(6
|
)
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(263
|
)
|
|
(180
|
)
|
Dividends
Paid on Common Stock
|
|
|
(12,750
|
)
|
|
(20,827
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(78
|
)
|
|
(78
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(13,097
|
)
|
|
(21,085
|
)
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
-
|
|
|
215
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
-
|
|
|
-
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
-
|
|
$
|
215
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
DISCLOSURE
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
13,988
|
|
$
|
15,192
|
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(252
|
)
|
|
30,486
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,178
|
|
|
193
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
2,155
|
|
|
2,289
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to TNC’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 TNC.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Customer
Choice and Industry Restructuring
|
Note
4
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Income
Taxes
|
Note
10
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
APPALACHIAN
POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006 Net
Income
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
37
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(23
|
)
|
|
|
|
Off-system
Sales
|
|
|
33
|
|
|
|
|
Transmission
Revenues
|
|
|
(10
|
)
|
|
|
|
Other
|
|
|
16
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
6
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(11
|
)
|
|
|
|
Carrying
Costs Income (Expense)
|
|
|
(29
|
)
|
|
|
|
Other
Income
|
|
|
7
|
|
|
|
|
Interest
Expense
|
|
|
(2
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(29
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
31
|
|
Net
Income decreased $6 million to $31 million in 2006. The key driver of the
decrease was a $29 million net increase in Operating Expenses and Other offset
by a net increase in Gross Margin of $16 million and a $7 million decrease
in
Income Tax Expense.
The
major
components of our 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 $23 million in comparison to 2005 primarily due
to:
|
|
·
|
a
$28 million decrease related to an increase in sharing of off-system
sales
margins with retail customers due to higher off-system sales. This
sharing
mechanism was reinstated in West Virginia effective July 1, 2006
in
conjunction with our West Virginia rate case. Retail Margins further
decreased due to;
|
|
·
|
a
$13 million decrease in revenues related to financial transmission
rights,
net of congestion, primarily due to fewer transmission constraints
in the
PJM market partially offset by;
|
|
·
|
a
$19 million increase in fuel recovery caused by the activation of
the West
Virginia fuel clause in July 2006.
|
·
|
Off-system
Sales increased $33 million primarily due to $19 million increase
in
physical sales margins and an $18 million increase from lower sharing
of
off-system sales margins under the SIA slightly offset by a $3 million
decrease in margins from optimization activities. See the “Allocation
Agreement between AEP East companies and AEP West companies and CSW
Operating Agreement” section of Note 3.
|
·
|
Transmission
Revenues decreased $10 million primarily due to the elimination of
SECA
revenues as of April 1, 2006. At this time, we have a pending proposal
with the FERC to replace SECA revenues. See the “Transmission Rate
Proceedings at the FERC” section of Note 3.
|
·
|
Other
revenue increased $16 million primarily due to a write off of previously
deferred gains on sales of allowances associated with the Virginia
Environmental and Reliability Costs (E&R) case. See “APCo Virginia
Environmental and Reliability Costs” section of Note
3.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses decreased $6 million mainly due
to a
decrease in expenses associated with the Transmission Equalization
Agreement with the addition of the Wyoming-Jacksons Ferry 765 kV
line,
which was energized and placed in service in June 2006. This decrease
was
partially offset by a write off of deferred maintenance expenses
associated with the E&R case. See “APCo Virginia Environmental and
Reliability Costs” section of Note 3.
|
·
|
Depreciation
and Amortization expenses increased $11 million primarily due to
a write
off of previously deferred depreciation expenses associated with
the
E&R case. See “APCo Virginia Environmental and Reliability Costs”
section of Note 3.
|
·
|
Carrying
Costs Income (Expense) decreased $29 million primarily due to a write
off
of previously recorded carrying costs income associated with the
E&R
case. See “APCo Virginia Environmental and Reliability Costs” section of
Note 3.
|
·
|
Other
Income increased $7 million primarily due to interest income related
to an
increase in Advances to Affiliates and an increase in allowance for
funds
during construction (AFUDC).
|
Income
Taxes
The
decrease in Income Tax Expense of $7 million is primarily due to a decrease
in
pretax book income and changes in certain book/tax differences accounted for
on
a flow-through basis, offset in part by an increase in state income
taxes.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine Months Ended September 30, 2005 to
Nine
Months Ended September 30, 2006 Net Income
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
108
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
12
|
|
|
|
|
Off-system
Sales
|
|
|
34
|
|
|
|
|
Transmission
Revenues
|
|
|
(27
|
)
|
|
|
|
Other
|
|
|
15
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
34
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
9
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(11
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
1
|
|
|
|
|
Carrying
Costs Income (Expense)
|
|
|
(19
|
)
|
|
|
|
Other
Income
|
|
|
12
|
|
|
|
|
Interest
Expense
|
|
|
(13
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(21
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
114
|
|
Net
Income increased $6 million to $114 million in 2006. The key driver of the
increase was a $34 million net increase in Gross Margin offset by a $21 million
net increase in Operating Expenses and Other and a $7 million increase in Income
Tax Expense.
The
major
components of our 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 $12 million in comparison to 2005 primarily
due
to:
|
|
·
|
a
$16 million increase in retail revenues primarily related to
two new
industrial customers;
|
|
·
|
a
$14 million reduction in capacity settlement payments under the
Interconnection Agreement due to our lower member load ratio
(MLR) share
and our increased generation capacity and;
|
|
·
|
an
$11 million increase in revenues related to financial transmission
rights,
net of congestion. The increase in financial transmission rights
revenue
is due to improved management of price risk related to serving
retail load
under current transmission constraints. Retail Margin increases
were
partially offset by;
|
|
·
|
a
$28 million decrease related to an increase in sharing of off-system
sales
margins with retail customers due to higher off-system sales. This
sharing mechanism was reinstated in West Virginia effective July
1, 2006
in conjunction with our West Virginia rate case. |
·
|
Off-system
Sales increased $34 million primarily due to $42 million increase
in
physical sales margins and a $22 million increase from lower
sharing of
off-system sales margins under the SIA offset by a $30 million
decrease in
margins from optimization activities. See the “Allocation Agreement
between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
|
·
|
Transmission
Revenues decreased $27 million primarily due to the elimination
of SECA
revenues as of April 1, 2006 and a provision of $5 million for
potential
SECA refunds pending settlement negotiations with various intervenors.
At
this time, we have a pending proposal with the FERC to replace
SECA
revenues. See the “Transmission Rate Proceedings at the FERC” section of
Note 3.
|
·
|
Other
revenue increased $15 million primarily due to a write off of
previously
deferred gains on sales of allowances associated with the E&R case and
higher gains on sales of allowances. See “APCo Virginia Environmental and
Reliability Costs” section of Note
3.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses decreased $9 million mainly due
to a
decrease in expenses associated with the Transmission Equalization
Agreement with the addition of the Wyoming-Jacksons Ferry 765 kV
line,
which was energized and placed in service in June 2006, partially
offset
by a write off of previously deferred maintenance expenses associated
with
the E&R case. See “APCo Virginia Environmental and Reliability Costs”
section of Note 3.
|
·
|
Depreciation
and Amortization expenses increased $11 million primarily due to
a write
off of previously deferred depreciation expenses associated with
the
E&R case. See “APCo Virginia Environmental and Reliability Costs”
section of Note 3.
|
·
|
Carrying
Costs Income (Expense) decreased $19 million primarily due to write
off of
previously recorded carrying costs income associated with the E&R
case. See “APCo Virginia Environmental and Reliability Costs” section of
Note 3.
|
·
|
Other
Income increased $12 million primarily due to interest income related
to
an increase in Advances to Affiliates and an increase in
AFUDC.
|
·
|
Interest
Expense increased $13 million primarily due to long-term debt issuances
in
2006, partially offset by an increase in allowance for borrowed funds
used
during construction and a write off of previously deferred AFUDC
associated with the E&R case. See “APCo Virginia Environmental and
Reliability Costs” section of Note
3.
|
Income
Taxes
The
increase in Income Tax Expense of $7 million is primarily due to an increase
in
pretax book income and state income taxes offset in part by changes in certain
book/tax differences accounted for on a flow-through basis.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Current ratings are as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
Baa2
|
|
BBB
|
|
BBB+
|
Cash
Flow
Cash
flows for the nine months ended September 30, 2006 and 2005 were as
follows:
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
1,741
|
|
$
|
1,543
|
|
Net
Cash Flows From (Used For):
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
436,795
|
|
|
180,504
|
|
Investing
Activities
|
|
|
(725,650
|
)
|
|
(479,420
|
)
|
Financing
Activities
|
|
|
288,363
|
|
|
298,938
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(492
|
)
|
|
22
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,249
|
|
$
|
1,565
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $437 million in 2006. We produced Net
Income of $114 million during the period and a noncash expense item of $158
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 had no significant items.
Net
Cash
Flows From Operating Activities were $181 million in 2005. We produced Net
Income of $108 million during the period and a noncash expense item of $147
million for Depreciation and Amortization partially offset by Pension
Contributions to Qualified Plan Trusts of $60 million. 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.
Investing
Activities
Net
Cash
Flows Used For Investing Activities during 2006 and 2005 primarily reflect
our
construction expenditures of $633 million and $422 million, respectively.
Construction expenditures are primarily for projects to improve service
reliability for transmission and distribution, as well as environmental upgrades
for both periods. In 2006 and 2005, capital projects for transmission
expenditures primarily relate to the Wyoming-Jacksons Ferry 765 kV line placed
in service in June 2006. Environmental upgrades include the flue gas
desulphurization (FGD) projects at the Amos and Mountaineer Plants. For the
remainder of 2006, we expect $300 million of construction expenditures. In
addition, we invested $94 million and $68 million into the Utility Money Pool
in
2006 and 2005, respectively.
Financing
Activities
Net
Cash
Flows From Financing Activities were $288 million in 2006. We issued $500
million in Senior Unsecured Notes and $50 million in Pollution Control Bonds.
We
also retired a First Mortgage Bond of $100 million. We repaid short-term
borrowings from the Utility Money Pool of $194 million. In addition, we received
funds of $68 million related to a long-term coal purchase contract amended
in
March 2006, partially offset by repayments of $18 million. See “Coal Contract
Amendment” within “Significant Factors” for additional information.
Net
Cash
Flows From Financing Activities were $299 million in 2005.
We
issued four Senior Unsecured Notes totaling $850 million. We also issued Notes
Payable - Affiliates of $100 million and received a capital contribution from
our parent of $150 million. We retired $450 million of Senior Unsecured Notes
and three First Mortgage Bonds totaling $125 million. In addition, we repaid
$211 million of advances from the Utility Money Pool.
Financing
Activity
Long-term
debt issuances and retirements during the first nine months of 2006
were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Senior
Unsecured Notes
|
|
$
|
250,000
|
|
5.55
|
|
2011
|
Senior
Unsecured Notes
|
|
|
250,000
|
|
6.375
|
|
2036
|
Pollution
Control Bonds
|
|
|
50,275
|
|
Variable
|
|
2036
|
Retirements
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
First
Mortgage Bonds
|
|
$
|
100,000
|
|
6.80
|
|
2006
|
Other
Debt
|
|
|
8
|
|
13.718
|
|
2026
|
In
November 2006, we issued $17.5 million of variable rate Pollution Control Bonds
and retired $17.5 million, 2.70% pollution control bonds due in
2007.
In
November 2006, we had a required remarketing of $30 million of 2.80% Pollution
Control Bonds, which were converted from a three-year fixed rate mode to an
auction rate mode.
Liquidity
We
have
solid investment grade ratings, which provide us ready access to capital markets
in order to issue new debt or refinance long-term debt maturities. In addition,
we participate in the Utility Money Pool, which provides access to AEP’s
liquidity.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end other than the debt issuances and
retirements discussed above.
Significant
Factors
Coal
Contract Amendment
We
negotiated an amendment to a nonderivative coal contract that was assigned
to a
new owner of a coal supplier to which we were contractually obligated. The
amended contract includes adjustments in the quantity related to the shortfall
of tons in prior years, escalated tonnage deliveries in 2006 and a pricing
change related to future coal deliveries. In March 2006, the new owner agreed
to
pay us $80 million for the settlement, release and amendment of the original
contract. With respect to prior years’ undelivered coal, the new owner paid us
$12 million for the shortfall tons. With respect to deliveries of coal in
2006-2007, the third party paid us the remaining $68 million for the agreed
upon
price increase.
The
receipt of funds reduces the risk that the third party will short future
deliveries. However, if they fail to deliver, we are not contractually obligated
to repay any portion of the settlement payment. Our net coal price will not
materially change from the original contract price as a result of the $68
million payment that we received for future coal deliveries through 2007.
Since
there are no further requirements related to the liquidation of the shortfall
tons, we recognized the $12 million shortfall payment in the first quarter
of
2006. We recorded a $5 million reduction in Regulatory Assets on our Condensed
Consolidated Balance Sheet and recorded the remaining $7 million as a reduction
to Fuel
and
Other Consumables for Electric Generation on our Condensed Consolidated
Statement of Income.
We
recorded the $68 million payment within Deferred Credits and Other on our
Condensed Consolidated Balance Sheet. To the extent tons are received, payment
of the higher contracted price per ton will effectively result in a repayment
of
funds to the coal supplier.
Litigation
and Regulatory Activity
In
the
ordinary course of business, we 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 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 our
pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note
6
- Customer Choice and Industry Restructuring and Note 7 - Commitments and
Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters and
Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed
Financial Statements of Registrant Subsidiaries” section. Adverse results in
these proceedings have the potential to materially affect our results of
operations, financial condition and cash flows.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2005 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.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management policies and procedures are instituted and administered at the AEP
Consolidated level. 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
us.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in our condensed consolidated balance sheet as of September 30, 2006
and the reasons for changes in our total MTM value as compared to December
31,
2005.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of September 30, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow &
Fair
Value Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
85,654
|
|
$
|
7,481
|
|
$
|
-
|
|
$
|
93,135
|
|
Noncurrent
Assets
|
|
|
107,705
|
|
|
510
|
|
|
-
|
|
|
108,215
|
|
Total
MTM Derivative Contract Assets
|
|
|
193,359
|
|
|
7,991
|
|
|
-
|
|
|
201,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(64,432
|
)
|
|
(1,979
|
)
|
|
(1,881
|
)
|
|
(68,292
|
)
|
Noncurrent
Liabilities
|
|
|
(70,002
|
)
|
|
(699
|
)
|
|
(9,138
|
)
|
|
(79,839
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(134,434
|
)
|
|
(2,678
|
)
|
|
(11,019
|
)
|
|
(148,131
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
58,925
|
|
$
|
5,313
|
|
$
|
(11,019
|
)
|
$
|
53,219
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 2006
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
|
$
|
56,407
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
(6,079
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
121
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
(315
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
316
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
6,107
|
|
Changes
due to SIA Agreement (c)
|
|
|
(6,533
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
8,901
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
58,925
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
5,313
|
|
DETM
Assignment (e)
|
|
|
(11,019
|
)
|
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
|
$
|
53,219
|
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek 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)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(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 liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net
Assets
The
following table presents:
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving 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, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
1,794
|
|
$
|
12,885
|
|
$
|
4,663
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
19,342
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
4,076
|
|
|
11,246
|
|
|
4,922
|
|
|
7,304
|
|
|
-
|
|
|
-
|
|
|
27,548
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(43
|
)
|
|
(4,690
|
)
|
|
1,149
|
|
|
4,648
|
|
|
8,331
|
|
|
2,640
|
|
|
12,035
|
|
Total
|
|
$
|
5,827
|
|
$
|
19,441
|
|
$
|
10,734
|
|
$
|
11,952
|
|
$
|
8,331
|
|
$
|
2,640
|
|
$
|
58,925
|
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheet
We
are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations
on
the future cash flows from assets. We do not hedge all commodity price
risk.
We
employ
the use of interest rate forward and swap transactions in order to manage
interest rate exposure on anticipated borrowings of fixed-rate debt. We do
not
hedge all interest rate risk.
We
employ
forward contracts as cash flow hedges to lock-in prices on certain transactions
which have been denominated in foreign currencies where deemed necessary. 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 the changes from December 31, 2005 to September 30, 2006. 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, 2006
(in
thousands)
|
|
Power
|
|
Foreign
Currency
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(1,480
|
)
|
$
|
(171
|
)
|
$
|
(14,770
|
)
|
$
|
(16,421
|
)
|
Changes
in Fair Value
|
|
|
4,482
|
|
|
-
|
|
|
4,951
|
|
|
9,433
|
|
Impact
due to Changes in SIA (a)
|
|
|
(442
|
)
|
|
-
|
|
|
-
|
|
|
(442
|
)
|
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
|
|
2,261
|
|
|
5
|
|
|
1,757
|
|
|
4,023
|
|
Ending
Balance in AOCI September 30, 2006
|
|
$
|
4,821
|
|
$
|
(166
|
)
|
$
|
(8,062
|
)
|
$
|
(3,407
|
)
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $2,919 thousand gain.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
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, 2006, a near term typical change
in
commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended
September
30, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$655
|
|
$1,915
|
|
$683
|
|
$365
|
|
|
|
|
$732
|
|
$1,216
|
|
$579
|
|
$209
|
The
High
VaR for the nine months ended September 30, 2006 occurred in the third quarter
due to volatility in the ECAR/PJM region.
VaR
Associated with Debt Outstanding
We
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The
risk
of potential loss in fair value attributable to our exposure to interest rates
primarily related to long-term debt with fixed interest rates was $141 million
and $142 million at September 30, 2006 and December 31, 2005, respectively.
We
would not expect to liquidate our entire debt portfolio in a one-year holding
period; therefore, a near term change in interest rates should not negatively
affect our results of operations or consolidated financial
position.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2006 and
2005
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
588,684
|
|
$
|
468,558
|
|
$
|
1,612,735
|
|
$
|
1,380,928
|
|
Sales
to AEP Affiliates
|
|
|
57,177
|
|
|
99,551
|
|
|
177,557
|
|
|
237,648
|
|
Other
|
|
|
2,740
|
|
|
2,013
|
|
|
7,338
|
|
|
6,343
|
|
TOTAL
|
|
|
648,601
|
|
|
570,122
|
|
|
1,797,630
|
|
|
1,624,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
184,275
|
|
|
161,154
|
|
|
506,368
|
|
|
402,057
|
|
Purchased
Electricity for Resale
|
|
|
41,027
|
|
|
24,217
|
|
|
98,622
|
|
|
79,182
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
130,826
|
|
|
108,008
|
|
|
356,682
|
|
|
341,994
|
|
Other
Operation
|
|
|
63,259
|
|
|
78,421
|
|
|
210,914
|
|
|
228,916
|
|
Maintenance
|
|
|
53,874
|
|
|
44,865
|
|
|
138,381
|
|
|
129,321
|
|
Depreciation
and Amortization
|
|
|
61,160
|
|
|
50,284
|
|
|
157,518
|
|
|
146,734
|
|
Taxes
Other Than Income Taxes
|
|
|
24,464
|
|
|
23,696
|
|
|
70,355
|
|
|
71,127
|
|
TOTAL
|
|
|
558,885
|
|
|
490,645
|
|
|
1,538,840
|
|
|
1,399,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
89,716
|
|
|
79,477
|
|
|
258,790
|
|
|
225,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
2,463
|
|
|
662
|
|
|
6,228
|
|
|
1,667
|
|
Carrying
Costs Income (Expense)
|
|
|
(27,316
|
)
|
|
1,255
|
|
|
(13,532
|
)
|
|
5,320
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
6,748
|
|
|
1,791
|
|
|
13,307
|
|
|
6,559
|
|
Interest
Expense
|
|
|
(27,103
|
)
|
|
(24,976
|
)
|
|
(89,024
|
)
|
|
(76,320
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
44,508
|
|
|
58,209
|
|
|
175,769
|
|
|
162,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
13,972
|
|
|
20,837
|
|
|
61,992
|
|
|
54,557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
30,536
|
|
|
37,372
|
|
|
113,777
|
|
|
108,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements Including Capital Stock Expense
and Other
|
|
|
238
|
|
|
238
|
|
|
714
|
|
|
1,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
30,298
|
|
$
|
37,134
|
|
$
|
113,063
|
|
$
|
106,317
|
|
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2004
|
|
$
|
260,458
|
|
$
|
722,314
|
|
$
|
508,618
|
|
$
|
(81,672
|
)
|
$
|
1,409,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
Contribution From Parent
|
|
|
|
|
|
150,000
|
|
|
|
|
|
|
|
|
150,000
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(600
|
)
|
|
|
|
|
(600
|
)
|
Capital
Stock Expense and Other
|
|
|
|
|
|
2,485
|
|
|
(1,340
|
)
|
|
|
|
|
1,145
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,560,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $8,340
|
|
|
|
|
|
|
|
|
|
|
|
(15,490
|
)
|
|
(15,490
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
108,257
|
|
|
|
|
|
108,257
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2005
|
|
$
|
260,458
|
|
$
|
874,799
|
|
$
|
614,935
|
|
$
|
(97,162
|
)
|
$
|
1,653,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
260,458
|
|
$
|
924,837
|
|
$
|
635,016
|
|
$
|
(16,610
|
)
|
$
|
1,803,701
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(7,500
|
)
|
|
|
|
|
(7,500
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(600
|
)
|
|
|
|
|
(600
|
)
|
Capital
Stock Expense and Other
|
|
|
|
|
|
118
|
|
|
(114
|
)
|
|
|
|
|
4
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,795,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of
$7,007
|
|
|
|
|
|
|
|
|
|
|
|
13,014
|
|
|
13,014
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
113,777
|
|
|
|
|
|
113,777
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
126,791
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$
|
260,458
|
|
$
|
924,955
|
|
$
|
740,579
|
|
$
|
(3,596
|
)
|
$
|
1,922,396
|
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
1,249
|
|
$
|
1,741
|
|
Advances
to Affiliates
|
|
|
93,764
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
165,193
|
|
|
141,810
|
|
Affiliated
Companies
|
|
|
126,586
|
|
|
153,453
|
|
Accrued
Unbilled Revenues
|
|
|
29,073
|
|
|
51,201
|
|
Miscellaneous
|
|
|
4,326
|
|
|
527
|
|
Allowance
for Uncollectible Accounts
|
|
|
(4,415
|
)
|
|
(1,805
|
)
|
Total Accounts Receivable
|
|
|
320,763
|
|
|
345,186
|
|
Fuel
|
|
|
61,892
|
|
|
64,657
|
|
Materials
and Supplies
|
|
|
54,286
|
|
|
54,967
|
|
Risk
Management Assets
|
|
|
93,135
|
|
|
132,247
|
|
Accrued
Tax Benefits
|
|
|
3,470
|
|
|
32,979
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
34,028
|
|
|
30,697
|
|
Prepayments
and Other
|
|
|
13,230
|
|
|
44,432
|
|
TOTAL
|
|
|
675,817
|
|
|
706,906
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
2,836,442
|
|
|
2,798,157
|
|
Transmission
|
|
|
1,595,963
|
|
|
1,266,855
|
|
Distribution
|
|
|
2,218,402
|
|
|
2,141,153
|
|
Other
|
|
|
336,999
|
|
|
323,158
|
|
Construction
Work in Progress
|
|
|
784,644
|
|
|
647,638
|
|
Total
|
|
|
7,772,450
|
|
|
7,176,961
|
|
Accumulated
Depreciation and Amortization
|
|
|
2,458,665
|
|
|
2,524,855
|
|
TOTAL
- NET
|
|
|
5,313,785
|
|
|
4,652,106
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
419,891
|
|
|
457,294
|
|
Long-term
Risk Management Assets
|
|
|
108,215
|
|
|
176,231
|
|
Deferred
Charges and Other
|
|
|
237,113
|
|
|
261,556
|
|
TOTAL
|
|
|
765,219
|
|
|
895,081
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
6,754,821
|
|
$
|
6,254,093
|
|
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, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
-
|
|
$
|
194,133
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
274,165
|
|
|
230,570
|
|
Affiliated
Companies
|
|
|
113,461
|
|
|
85,941
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
141,696
|
|
|
146,999
|
|
Risk
Management Liabilities
|
|
|
68,292
|
|
|
121,165
|
|
Customer
Deposits
|
|
|
56,263
|
|
|
79,854
|
|
Accrued
Taxes
|
|
|
63,395
|
|
|
49,833
|
|
Accrued
Interest
|
|
|
59,394
|
|
|
28,614
|
|
Other
|
|
|
86,917
|
|
|
80,132
|
|
TOTAL
|
|
|
863,583
|
|
|
1,017,241
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
2,356,175
|
|
|
1,904,379
|
|
Long-term
Debt - Affiliated
|
|
|
100,000
|
|
|
100,000
|
|
Long-term
Risk Management Liabilities
|
|
|
79,839
|
|
|
147,117
|
|
Deferred
Income Taxes
|
|
|
937,835
|
|
|
952,497
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
315,346
|
|
|
201,230
|
|
Deferred
Credits and Other
|
|
|
161,884
|
|
|
110,144
|
|
TOTAL
|
|
|
3,951,079
|
|
|
3,415,367
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,814,662
|
|
|
4,432,608
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
17,763
|
|
|
17,784
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
924,955
|
|
|
924,837
|
|
Retained
Earnings
|
|
|
740,579
|
|
|
635,016
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(3,596
|
)
|
|
(16,610
|
)
|
TOTAL
|
|
|
1,922,396
|
|
|
1,803,701
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
6,754,821
|
|
$
|
6,254,093
|
|
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
113,777
|
|
$
|
108,257
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
157,518
|
|
|
146,734
|
|
Deferred
Income Taxes
|
|
|
(7,753
|
)
|
|
25,103
|
|
Carrying
Costs (Income) Expense
|
|
|
13,532
|
|
|
(5,320
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(3,817
|
)
|
|
(21,412
|
)
|
Pension
Contributions to Qualified Plan Trusts
|
|
|
-
|
|
|
(59,812
|
)
|
Over/Under
Fuel Recovery, Net
|
|
|
830
|
|
|
(21,001
|
)
|
Change
in Other Noncurrent Assets
|
|
|
8,466
|
|
|
361
|
|
Change
in Other Noncurrent Liabilities
|
|
|
20,187
|
|
|
(10,306
|
)
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
24,423
|
|
|
2,899
|
|
Fuel,
Materials and Supplies
|
|
|
3,446
|
|
|
(7,467
|
)
|
Margin
Deposits
|
|
|
27,103
|
|
|
(38,634
|
)
|
Accounts
Payable
|
|
|
22,063
|
|
|
54,994
|
|
Customer
Deposits
|
|
|
(23,591
|
)
|
|
52,302
|
|
Accrued
Taxes, Net
|
|
|
43,071
|
|
|
(39,022
|
)
|
Accrued
Interest
|
|
|
30,780
|
|
|
15,467
|
|
Other
Current Assets
|
|
|
4,972
|
|
|
(20,482
|
)
|
Other
Current Liabilities
|
|
|
1,788
|
|
|
(2,157
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
436,795
|
|
|
180,504
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(633,164
|
)
|
|
(421,544
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
(873
|
)
|
|
(24
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
(93,764
|
)
|
|
(67,532
|
)
|
Proceeds
from Sales of Assets
|
|
|
2,151
|
|
|
9,680
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(725,650
|
)
|
|
(479,420
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Capital
Contributions from Parent
|
|
|
-
|
|
|
150,000
|
|
Issuance
of Long-term Debt - Nonaffiliated
|
|
|
544,364
|
|
|
840,469
|
|
Issuance
of Long-term Debt - Affiliated
|
|
|
-
|
|
|
100,000
|
|
Change
in Advances from Affiliates, Net
|
|
|
(194,133
|
)
|
|
(211,060
|
)
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
(100,008
|
)
|
|
(575,007
|
)
|
Retirement
of Preferred Stock
|
|
|
(16
|
)
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(4,008
|
)
|
|
(4,864
|
)
|
Funds
From Amended Coal Contract, Net
|
|
|
50,264
|
|
|
-
|
|
Dividends
Paid on Common Stock
|
|
|
(7,500
|
)
|
|
-
|
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(600
|
)
|
|
(600
|
)
|
Net
Cash Flows From Financing Activities
|
|
|
288,363
|
|
|
298,938
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(492
|
)
|
|
22
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,741
|
|
|
1,543
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,249
|
|
$
|
1,565
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
DISCLOSURE
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
51,537
|
|
$
|
56,253
|
|
Net
Cash Paid for Income Taxes
|
|
|
12,047
|
|
|
61,514
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
2,598
|
|
|
1,087
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
131,692
|
|
|
54,380
|
|
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
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
COLUMBUS
SOUTHERN POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006 Net
Income
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
34
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
36
|
|
|
|
|
Off-system
Sales
|
|
|
20
|
|
|
|
|
Transmission
Revenues
|
|
|
(6
|
)
|
|
|
|
Other
|
|
|
(2
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
48
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(2
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(14
|
)
|
|
|
|
Asset
Impairments and Other Related Charges
|
|
|
39
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
5
|
|
|
|
|
Carrying
Costs Income
|
|
|
(1
|
)
|
|
|
|
Interest
Expense
|
|
|
(2
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(23
|
)
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
84
|
|
Net
Income increased $50 million to $84 million in 2006. The key drivers of the
increase were a $48 million increase in Gross Margin and a $39 million asset
impairment of units 1 and 2 at our Conesville Plant in 2005, partially offset
by
a $23 million increase in Income Tax Expense and a $14 million increase in
Depreciation and Amortization.
The
major
components of our increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emission allowances,
and purchased power, were as follows:
·
|
Retail
Margins were $36 million higher than the prior period primarily due
to
Rate Stabilization Plan (RSP) and Transition Regulatory Asset rate
increases effective January 1, 2006 as well as the addition of Monongahela
Power’s Ohio customers on December 31, 2005, partially offset by an
increase in delivered fuel costs.
|
·
|
Off-system
Sales increased $20 million primarily due to $13 million increase
in
physical sales margins and a $10 million increase from lower sharing
of
off-system sales margins under the SIA. See the “Allocation Agreement
between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
|
·
|
Transmission
Revenues decreased $6 million primarily due to the elimination of
SECA
revenues as of April 1, 2006. At this time, we have a pending proposal
with the FERC to replace SECA revenues. See the “Transmission Rate
Proceedings at the FERC” section of Note
3.
|
Operating
Expenses and Other changed between years as follows:
·
|
Depreciation
and Amortization expense increased $14 million due to the increase
in the
amortization of regulatory assets and a greater depreciable base
resulting
primarily from the acquisitions of the Waterford Plant and Monongahela
Power’s Ohio assets in late 2005.
|
·
|
Asset
Impairments and Other Related Charges of $39 million were recorded
last
year due to the 2005 retirement of units 1 and 2 at our Conesville
Plant.
|
·
|
Taxes
Other Than Income Taxes decreased $5 million due to favorable accrual
adjustments to property taxes in 2006 and unfavorable accrual adjustments
in 2005 partially offset by the increase in property taxes associated
with
the Waterford and Monongahela asset
additions.
|
Income
Tax
The
increase of $23 million in Income Tax Expense is primarily due to an increase
in
pretax book income offset in part by a decrease in state income taxes.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine Months Ended September 30, 2005 to
Nine
Months Ended September 30, 2006 Net Income
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
116
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
93
|
|
|
|
|
Off-system
Sales
|
|
|
29
|
|
|
|
|
Transmission
Revenues
|
|
|
(13
|
)
|
|
|
|
Other
|
|
|
6
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
115
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(19
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(41
|
)
|
|
|
|
Asset
Impairments and Other Related Charges
|
|
|
39
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(7
|
)
|
|
|
|
Carrying
Costs Income
|
|
|
(6
|
)
|
|
|
|
Interest
Expense
|
|
|
(8
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(42
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(21
|
)
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
168
|
|
Net
Income increased $52 million to $168 million in 2006. The key drivers of the
increase were a $115 million increase in Gross Margin and a $39 million asset
impairment of units 1 and 2 at our Conesville Plant in 2005, partially offset
by
a $41 million increase in Depreciation and Amortization, a $19 million increase
in Other Operation and Maintenance and a $21 million increase in Income Tax
Expense.
The
major
components of our increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emission allowances,
and purchased power, were as follows:
·
|
Retail
Margins increased $93 million primarily due to the RSP and Transition
Regulatory Asset rate increases effective January 1, 2006, lower
capacity
settlement costs, and the addition of Monongahela Power’s Ohio customers
on December 31, 2005, partially offset by an increase in delivered
fuel
costs.
|
·
|
Off-system
Sales increased $29 million due to $30 million increase in physical
sales
margins and a $12 million increase from lower sharing of off-system
sales
margins under the SIA offset by a decrease in margins from optimization
activities. See the “Allocation Agreement between AEP East companies and
AEP West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Transmission
Revenues decreased $13 million primarily due to the elimination of
SECA
revenues as of April 1, 2006 and a provision of $3 million recorded
in
2006 related to potential SECA refunds pending settlement negotiations
with various intervenors. At this time, we have a pending proposal
with
the FERC to replace SECA revenues. See the “Transmission Rate Proceedings
at the FERC” section of Note 3.
|
·
|
Other
revenues increased $6 million primarily due to higher gains on sales
of
emission allowances.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance increased $19 million due to an increase
in PJM
administrative fees, an increase in transmission expenses related
to the
AEP Transmission Equalization Agreement, favorable adjustments in
the
prior year related to the corporate owned life insurance policy and
increased expenses related to factored receivables and uncollectible
accounts. The increases were partially offset by the recognition
of
a regulatory asset related to recent PUCO orders regarding
distribution service reliability and restoration
costs.
|
·
|
Depreciation
and Amortization expense increased $41 million primarily due to the
increase in the amortization of regulatory assets and a greater
depreciable base resulting primarily from the acquisitions of the
Waterford Plant and Monongahela Power’s Ohio assets. In addition, the 2005
RSP order resulted in a reversal of unused shopping credits of $18
million
offset by the establishment of a $7 million regulatory liability
to
benefit low-income customers and for economic
development.
|
·
|
Asset
Impairments and Other Related Charges in the amount of $39 million
were
recorded last year due to the 2005 retirement of units 1 and 2 at
our
Conesville Plant.
|
·
|
Taxes
Other Than Income Taxes increased $7 million due to the increase
in
property taxes associated with the Waterford and Monongahela asset
additions partially offset by accrual adjustments to property taxes
that
were favorable in 2006 and unfavorable in 2005.
|
·
|
Carrying
Costs Income decreased $6 million primarily due to the completion
of
deferrals of carrying costs on environmental capital expenditures
from
2004 and 2005 that are now recovered during 2006 through 2008 according
to
the RSP.
|
·
|
Interest
Expense increased $8 million primarily due to a new long-term debt
issuance during the fourth quarter of
2005.
|
Income
Tax
The
increase of $21 million in Income Tax Expense is primarily due to an increase
in
pretax book income offset in part by a decrease in state income taxes.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Current ratings are as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
A3
|
|
BBB
|
|
A-
|
Financing
Activity
There
were no long-term debt issuances or retirements during the first nine months
of
2006.
Liquidity
We
have
solid investment grade ratings, which provide us ready access to capital markets
in order to issue new debt or refinance long-term debt maturities. In addition,
we participate in the Utility Money Pool, which provides access to AEP’s
liquidity.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end.
Significant
Factors
Litigation
and Regulatory Activity
In
the
ordinary course of business, we 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 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 our
pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note
6
- Customer Choice and Industry Restructuring and Note 7 - Commitments and
Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note
4
- Customer Choice and Industry Restructuring and Note 5 - Commitments and
Contingencies in the “Condensed Notes to Condensed Financial Statements of
Registrant Subsidiaries” section. Adverse results in these proceedings have the
potential to materially affect our results of operations, financial condition
and cash flows.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2005 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.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management policies and procedures are instituted and administered at the AEP
Consolidated level. 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
us.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in our condensed consolidated balance sheet as of September 30, 2006
and the reasons for changes in our total MTM value as compared to December
31,
2005.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of September 30, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
53,028
|
|
$
|
4,782
|
|
$
|
-
|
|
$
|
57,810
|
|
Noncurrent
Assets
|
|
|
68,304
|
|
|
326
|
|
|
-
|
|
|
68,630
|
|
Total
MTM Derivative Contract Assets
|
|
|
121,332
|
|
|
5,108
|
|
|
-
|
|
|
126,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(39,606
|
)
|
|
(743
|
)
|
|
(1,202
|
)
|
|
(41,551
|
)
|
Noncurrent
Liabilities
|
|
|
(44,001
|
)
|
|
(8
|
)
|
|
(5,841
|
)
|
|
(49,850
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(83,607
|
)
|
|
(751
|
)
|
|
(7,043
|
)
|
|
(91,401
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
37,725
|
|
$
|
4,357
|
|
$
|
(7,043
|
)
|
$
|
35,039
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 2006
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
|
$
|
33,322
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
(5,405
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
146
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
(138
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
381
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
12,996
|
|
Changes
Due to SIA (c)
|
|
|
(3,864
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
287
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
37,725
|
|
Net
Cash Flow Hedge Contracts
|
|
|
4,357
|
|
DETM
Assignment (e)
|
|
|
(7,043
|
)
|
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
|
$
|
35,039
|
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek 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)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(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 liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net
Assets
The
following table presents:
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving 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, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
1,146
|
|
$
|
8,236
|
|
$
|
2,981
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
12,363
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes
(a)
|
|
|
2,425
|
|
|
6,394
|
|
|
3,095
|
|
|
4,669
|
|
|
-
|
|
|
-
|
|
|
16,583
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
4
|
|
|
(2,247
|
)
|
|
1,039
|
|
|
2,971
|
|
|
5,324
|
|
|
1,688
|
|
|
8,779
|
Total
|
|
$
|
3,575
|
|
$
|
12,383
|
|
$
|
7,115
|
|
$
|
7,640
|
|
$
|
5,324
|
|
$
|
1,688
|
|
$
|
37,725
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheet
We
are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations
on
the future cash flows from assets. We do not hedge all commodity price
risk.
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 the changes from December 31, 2005 to September 30, 2006. 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, 2006
(in
thousands)
|
|
Power
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(859
|
)
|
Changes
in Fair Value
|
|
|
2,853
|
|
Impact
due to Changes in SIA (a)
|
|
|
(261
|
)
|
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
|
|
1,348
|
|
Ending
Balance in AOCI September 30, 2006
|
|
$
|
3,081
|
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $2,875 thousand gain.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
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, 2006, a near term typical change
in
commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended
September
30, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$418
|
|
$1,224
|
|
$414
|
|
$233
|
|
|
|
|
$424
|
|
$705
|
|
$335
|
|
$121
|
The
High
VaR for the nine months ended September 30, 2006 occurred in the third quarter
due to volatility in the ECAR/PJM region.
VaR
Associated with Debt Outstanding
We
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The
risk
of potential loss in fair value attributable to our exposure to interest rates
primarily related to long-term debt with fixed interest rates was $64 million
and $86 million at September 30, 2006 and December 31, 2005, respectively.
We
would not expect to liquidate our entire debt portfolio in a one-year holding
period; therefore, a near term change in interest rates should not negatively
affect our consolidated results of operations or financial
position.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2006 and
2005
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
513,643
|
|
$
|
406,525
|
|
$
|
1,321,422
|
|
$
|
1,074,099
|
|
Sales
to AEP Affiliates
|
|
|
24,806
|
|
|
46,698
|
|
|
60,337
|
|
|
103,939
|
|
Other
|
|
|
1,449
|
|
|
1,345
|
|
|
4,016
|
|
|
3,653
|
|
TOTAL
|
|
|
539,898
|
|
|
454,568
|
|
|
1,385,775
|
|
|
1,181,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
90,510
|
|
|
72,550
|
|
|
231,543
|
|
|
191,188
|
|
Purchased
Electricity for Resale
|
|
|
35,449
|
|
|
9,016
|
|
|
87,902
|
|
|
26,922
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
102,669
|
|
|
109,274
|
|
|
272,334
|
|
|
284,221
|
|
Other
Operation
|
|
|
66,195
|
|
|
56,276
|
|
|
180,022
|
|
|
152,833
|
|
Maintenance
|
|
|
14,704
|
|
|
21,863
|
|
|
56,140
|
|
|
63,947
|
|
Asset
Impairments and Other Related Charges
|
|
|
-
|
|
|
39,109
|
|
|
-
|
|
|
39,109
|
|
Depreciation
and Amortization
|
|
|
51,149
|
|
|
37,454
|
|
|
143,495
|
|
|
102,985
|
|
Taxes
Other Than Income Taxes
|
|
|
38,586
|
|
|
43,422
|
|
|
119,875
|
|
|
112,657
|
|
TOTAL
|
|
|
399,262
|
|
|
388,964
|
|
|
1,091,311
|
|
|
973,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
140,636
|
|
|
65,604
|
|
|
294,464
|
|
|
207,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
989
|
|
|
1,038
|
|
|
1,919
|
|
|
2,666
|
|
Carrying
Costs Income
|
|
|
1,046
|
|
|
1,800
|
|
|
3,082
|
|
|
8,716
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
659
|
|
|
229
|
|
|
1,466
|
|
|
1,036
|
|
Interest
Expense
|
|
|
(15,813
|
)
|
|
(13,508
|
)
|
|
(50,247
|
)
|
|
(42,089
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
127,517
|
|
|
55,163
|
|
|
250,684
|
|
|
178,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
43,496
|
|
|
20,938
|
|
|
83,064
|
|
|
61,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
|
84,021 |
|
|
34,225 |
|
|
167,620 |
|
|
116,344 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
Stock Expense
|
|
|
39
|
|
|
254
|
|
|
118
|
|
|
2,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK |
|
$ |
83,982 |
|
$ |
33,971 |
|
$ |
167,502 |
|
$ |
113,978 |
|
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
DECEMBER
31, 2004
|
|
$
|
41,026
|
|
$
|
577,415
|
|
$
|
341,025
|
|
$
|
(60,816
|
)
|
$
|
898,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(85,500
|
)
|
|
|
|
|
(85,500
|
)
|
Capital
Stock Expense and Other
|
|
|
|
|
|
2,366
|
|
|
(2,366
|
)
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
813,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $3,655
|
|
|
|
|
|
|
|
|
|
|
|
(6,789
|
)
|
|
(6,789
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
116,344
|
|
|
|
|
|
116,344
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2005
|
|
$
|
41,026
|
|
$
|
579,781
|
|
$
|
369,503
|
|
$
|
(67,605
|
)
|
$
|
922,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
41,026
|
|
$
|
580,035
|
|
$
|
361,365
|
|
$
|
(880
|
)
|
$
|
981,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(67,500
|
)
|
|
|
|
|
(67,500
|
)
|
Capital
Stock Expense
|
|
|
|
|
|
118
|
|
|
(118
|
)
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
914,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,121
|
|
|
|
|
|
|
|
|
|
|
|
3,940
|
|
|
3,940
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
167,620
|
|
|
|
|
|
167,620
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
171,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$
|
41,026
|
|
$
|
580,153
|
|
$
|
461,367
|
|
$
|
3,060
|
|
$
|
1,085,606
|
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
1,251
|
|
$
|
940
|
|
Advances
to Affiliates
|
|
|
60,417
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
54,517
|
|
|
43,143
|
|
Affiliated
Companies
|
|
|
51,218
|
|
|
67,694
|
|
Accrued
Unbilled Revenues
|
|
|
15,687
|
|
|
10,086
|
|
Miscellaneous
|
|
|
5,185
|
|
|
2,012
|
|
Allowance
for Uncollectible Accounts
|
|
|
(1,380
|
)
|
|
(1,082
|
)
|
Total Accounts Receivable
|
|
|
125,227
|
|
|
121,853
|
|
Fuel
|
|
|
33,556
|
|
|
28,579
|
|
Materials
and Supplies
|
|
|
30,742
|
|
|
27,519
|
|
Emission
Allowances
|
|
|
7,070
|
|
|
20,181
|
|
Risk
Management Assets
|
|
|
57,810
|
|
|
76,507
|
|
Accrued
Tax Benefits
|
|
|
-
|
|
|
36,838
|
|
Prepayments
and Other
|
|
|
11,284
|
|
|
23,546
|
|
TOTAL
|
|
|
327,357
|
|
|
335,963
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
1,889,414
|
|
|
1,874,652
|
|
Transmission
|
|
|
478,513
|
|
|
457,937
|
|
Distribution
|
|
|
1,451,842
|
|
|
1,380,722
|
|
Other
|
|
|
191,599
|
|
|
184,096
|
|
Construction
Work in Progress
|
|
|
224,854
|
|
|
129,246
|
|
Total
|
|
|
4,236,222
|
|
|
4,026,653
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,589,465
|
|
|
1,500,858
|
|
TOTAL
- NET
|
|
|
2,646,757
|
|
|
2,525,795
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
216,339
|
|
|
231,599
|
|
Long-term
Risk Management Assets
|
|
|
68,630
|
|
|
101,512
|
|
Deferred
Charges and Other
|
|
|
187,915
|
|
|
237,925
|
|
TOTAL
|
|
|
472,884
|
|
|
571,036
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
3,446,998
|
|
$
|
3,432,794
|
|
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, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
-
|
|
$
|
17,609
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
104,090
|
|
|
59,134
|
|
Affiliated
Companies
|
|
|
57,910
|
|
|
59,399
|
|
Risk
Management Liabilities
|
|
|
41,551
|
|
|
69,036
|
|
Customer
Deposits
|
|
|
32,448
|
|
|
47,013
|
|
Accrued
Taxes
|
|
|
111,910
|
|
|
157,729
|
|
Other
|
|
|
47,351
|
|
|
50,229
|
|
TOTAL
|
|
|
395,260
|
|
|
460,149
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
1,097,222
|
|
|
1,096,920
|
|
Long-term
Debt - Affiliated
|
|
|
100,000
|
|
|
100,000
|
|
Long-term
Risk Management Liabilities
|
|
|
49,850
|
|
|
84,291
|
|
Deferred
Income Taxes
|
|
|
494,805
|
|
|
498,232
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
177,801
|
|
|
165,344
|
|
Deferred
Credits and Other
|
|
|
46,454
|
|
|
46,312
|
|
TOTAL
|
|
|
1,966,132
|
|
|
1,991,099
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,361,392
|
|
|
2,451,248
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - No Par Value Per Share:
|
|
|
|
|
|
|
|
Authorized
- 24,000,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 16,410,426 Shares
|
|
|
41,026
|
|
|
41,026
|
|
Paid-in
Capital
|
|
|
580,153
|
|
|
580,035
|
|
Retained
Earnings
|
|
|
461,367
|
|
|
361,365
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
3,060
|
|
|
(880
|
)
|
TOTAL
|
|
|
1,085,606
|
|
|
981,546
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$
|
3,446,998
|
|
$
|
3,432,794
|
|
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
167,620
|
|
$
|
116,344
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
143,495
|
|
|
102,985
|
|
Deferred
Income Taxes
|
|
|
(5,097
|
)
|
|
(9,441
|
)
|
Asset
Impairments and Other Related Charges
|
|
|
-
|
|
|
39,109
|
|
Carrying
Costs Income
|
|
|
(3,082
|
)
|
|
(8,716
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(4,502
|
)
|
|
(12,767
|
)
|
Pension
Contributions to Qualified Plan Trusts
|
|
|
-
|
|
|
(37,832
|
)
|
Deferred
Property Taxes
|
|
|
49,518
|
|
|
47,640
|
|
Change
in Other Noncurrent Assets
|
|
|
(24,297
|
)
|
|
(24,839
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
11,752
|
|
|
14,747
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(3,374
|
)
|
|
(7,748
|
)
|
Fuel,
Materials and Supplies
|
|
|
(8,200
|
)
|
|
8,611
|
|
Accounts
Payable
|
|
|
31,765
|
|
|
2,215
|
|
Customer
Deposits
|
|
|
(14,565
|
)
|
|
30,760
|
|
Accrued
Taxes, Net
|
|
|
(8,981
|
)
|
|
(94,788
|
)
|
Other
Current Assets
|
|
|
26,838
|
|
|
(14,809
|
)
|
Other
Current Liabilities
|
|
|
(2,878
|
)
|
|
(10,471
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
356,012
|
|
|
141,000
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(207,875
|
)
|
|
(118,222
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
(60,417
|
)
|
|
141,550
|
|
Purchase
of Waterford Plant
|
|
|
-
|
|
|
(218,356
|
)
|
Other
|
|
|
8
|
|
|
4,639
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(268,284
|
)
|
|
(190,389
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
(17,609
|
)
|
|
138,541
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(2,308
|
)
|
|
(2,642
|
)
|
Dividends
Paid on Common Stock
|
|
|
(67,500
|
)
|
|
(85,500
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
(87,417
|
)
|
|
50,399
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
311
|
|
|
1,010
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
940
|
|
|
58
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,251
|
|
$
|
1,068
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
52,958
|
|
$
|
50,095
|
|
Net
Cash Paid for Income Taxes
|
|
|
35,561
|
|
|
109,382
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
2,130
|
|
|
520
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
22,955
|
|
|
4,974
|
|
Assumption
of Liabilities in Connection with Waterford Plant Acquisition
|
|
|
-
|
|
|
2,295
|
|
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 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
|
Note
2
|
Rate
Matters
|
Note
3
|
Customer
Choice and Industry Restructuring
|
Note
4
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Acquisitions,
Assets Held for Sale and Asset Impairments
|
Note
8
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
INDIANA
MICHIGAN POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006 Net
Income
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
53
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(44
|
)
|
|
|
|
Off-system
Sales (a)
|
|
|
34
|
|
|
|
|
Transmission
Revenues
|
|
|
(4
|
)
|
|
|
|
Other
|
|
|
2
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(17
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(5
|
)
|
|
|
|
Other
Income (Expense)
|
|
|
3
|
|
|
|
|
Interest
Expense
|
|
|
(1
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
35
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income decreased $18 million to $35 million in 2006. The key drivers of the
decrease were a $12 million decrease in Gross Margin and a $17 million increase
in Other Operation and Maintenance expenses, partially offset by a $14 million
decrease in Income Tax Expense.
The
major
components of our 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 $44 million primarily due to lower fuel recovery
as fuel
cost increases could not be recovered due to the Indiana fuel cap
and a
reduction in capacity revenues of $22 million under the Interconnection
Agreement. Capacity revenues declined due to our new peak demand
in July
2006 and our affiliates’ addition of generating capacity in
2005.
|
·
|
Off-system
Sales increased $34 million primarily due to the addition of new
municipal
contracts including new rates and increased demand beginning January
2006,
a $13 million increase in physical sales margins and a $10 million
increase from lower sharing of off-system sales margins under the
SIA. See
the “Allocation Agreement between AEP East companies and AEP West
companies and CSW Operating Agreement” section of Note
3.
|
·
|
Transmission
Revenues decreased $4 million primarily due to the elimination of
SECA
revenues as of April 1, 2006. At this time, we have a pending proposal
with the FERC to replace SECA revenues. See the “Transmission
Rate Proceedings at the FERC” section of Note
3.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other Operation
and Maintenance expenses increased $17 million primarily due to the
abandonment of digital turbine control equipment at the Cook
Plant.
|
·
|
Depreciation
and Amortization increased $5 million primarily due to higher expense
related to capital additions.
|
Income
Taxes
Income
Tax Expense decreased $14 million primarily due to a decrease in pretax book
income and changes in certain book/tax differences accounted for on a
flow-through basis.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine Months Ended September 30, 2005 to
Nine
Months Ended September 30, 2006 Net Income
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
128
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(55
|
)
|
|
|
|
Off-system
Sales (a)
|
|
|
63
|
|
|
|
|
Transmission
Revenues
|
|
|
(11
|
)
|
|
|
|
Other
|
|
|
11
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(12
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(9
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(3
|
)
|
|
|
|
Other
Income (Expense)
|
|
|
4
|
|
|
|
|
Interest
Expense
|
|
|
(4
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
121
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income decreased $7 million to $121 million in 2006. The key driver of the
decrease was a $12 million increase in Other Operation and Maintenance expenses,
partially offset by a $9 million decrease in Income Tax Expense.
The
major
components of our 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 $55 million primarily due to lower fuel recovery
as fuel
cost increases could not be recovered due to the Indiana fuel cap
and a
reduction in capacity settlement revenues of $27 million under the
Interconnection Agreement. Capacity revenues declined due to our
new peak
demand in July 2006 and our affiliates’ addition of generating capacity in
2005.
|
·
|
Off-system
Sales increased $63 million primarily due to the addition of new
municipal
contracts including new rates and increased demand beginning January
2006,
a $33 million increase in physical sales margins and a $12 million
increase from lower sharing of off-system sales margins under the
SIA,
offset by a $12 million decrease in margins from reduced optimization
activities. See the “Allocation Agreement between AEP East companies and
AEP West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Transmission
Revenues decreased $11 million primarily due to the elimination of
SECA
revenues as of April 1, 2006 and a $3 million provision for potential
SECA
refunds pending settlement negotiations with various intervenors.
At this
time, we have a pending proposal with the FERC to replace SECA
revenues. See the “Transmission Rate Proceedings at the FERC” section of
Note 3.
|
·
|
Other
revenues increased
$11 million primarily due to increased River Transportation Division
(RTD)
revenues for barging coal and gains on sales of emission allowances.
Related expenses which offset the RTD revenue increase are included
in
Other Operation on the Condensed Consolidated Statements of Income
resulting in our earning only a return approved under regulatory
order.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other Operation
and Maintenance expenses increased $12 million primarily due to the
abandonment of digital turbine control equipment at the Cook Plant
and an
increase in RTD expenses.
|
·
|
Depreciation
and Amortization increased $9 million primarily due to higher expense
related to capital additions.
|
Income
Taxes
Income
Tax Expense decreased $9 million primarily due to a decrease in pretax book
income and changes in certain book/tax differences accounted for on a
flow-through basis.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Current ratings, unchanged
since the first quarter of 2003, are as follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
Baa2
|
|
BBB
|
|
BBB
|
Cash
Flow
Cash
flows for the nine months ended September 30, 2006 and 2005 were as
follows:
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
854
|
|
$
|
511
|
|
Net
Cash Flows From (Used For):
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
456,313
|
|
|
276,523
|
|
Investing
Activities
|
|
|
(355,252
|
)
|
|
(238,875
|
)
|
Financing
Activities
|
|
|
(101,209
|
)
|
|
(37,428
|
)
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(148
|
)
|
|
220
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
706
|
|
$
|
731
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $456 million in 2006. We produced Net
Income of $121 million during the period and a noncash expense item of $137
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 current period activity in working capital relates to a number of items;
the
most significant are increases related to accounts receivable, accounts payable
and accrued taxes. We collected receivables from our affiliates related to
power
sales, settled litigation and emission allowances. Accounts payable and accrued
taxes increased related to timing of payments.
Net
Cash
Flows From Operating Activities were $277 million in 2005. We produced Net
Income of $128 million during the period and a noncash expense item of $128
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 most
significant relates to a $86 million change in accrued taxes reflecting taxes
paid during 2005. We also contributed $46 million to our pension
trust.
Investing
Activities
Net
Cash
Flows Used For Investing Activities during 2006 and 2005 primarily reflect
our
construction expenditures of $241 million and $190 million and acquisition
of
nuclear fuel of $73 million and $28 million, respectively. Construction
expenditures for the nuclear plant and transmission and distribution assets
are
to upgrade or replace equipment and improve reliability. We also invested in
capital projects to improve air quality and water intake systems. For the
remainder of 2006, we expect Construction Expenditures of approximately $90
million.
Financing
Activities
Net
Cash
Flows Used For Financing Activities were $101 million in 2006. We used cash
from
operations to repay $66 million of Advances from Affiliates and pay $30 million
of common stock dividends. We also refinanced a series of pollution control
bonds.
Net
Cash
Flows Used For Financing Activities were $37 million in 2005. We retired $61
million of preferred stock and paid $52 million of common stock dividends,
partially offset by the increase in Advances from Affiliates of $81
million.
Financing
Activity
Long-term
debt issuances and retirements during the first nine months of 2006
were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Pollution
Control Bonds
|
|
$
|
50,000
|
|
Variable
|
|
2025
|
Retirements
|
|
Principal
Amount
Paid
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Pollution
Control Bonds
|
|
$
|
50,000
|
|
6.55
|
|
2025
|
In
October 2006, we had a required remarketing of $65 million of 2.625% pollution
control bonds, which were converted from a three-year fixed rate mode to an
auction rate mode.
Liquidity
We
have
solid investment grade ratings, which provide us ready access to capital markets
in order to issue new debt or refinance long-term debt maturities. In addition,
we participate in the Utility Money Pool, which provides access to AEP’s
liquidity.
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 allow only traditional operating lease
arrangements and sales of customer accounts receivable that are entered in
the
normal course of business. Our off-balance sheet arrangements have not changed
significantly since year-end. For complete information on our off-balance sheet
arrangements including the lease of Rockport Plant Unit 2 see “Off-balance Sheet
Arrangements” in the “Management’s Financial Discussion and Analysis” section of
our 2005 Annual Report.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end.
Significant
Factors
Cook
Plant Outage
In
September 2006, Cook Plant Unit 1 began a regular refueling outage. This
outage includes the replacement of major components, including the reactor
vessel head. Installation of capital projects exceeding $100 million will be
completed during this outage and were included in our capital forecast. The
improvements and replacement of major components should increase unit capacity
and efficiency. We expect to restart Cook Plant Unit 1 during early
November 2006 as planned. We refueled Cook Plant Unit 2 during March and April
2006 and plan to replace its vessel head during its next refueling outage in
the
fall of 2007.
Litigation
and Regulatory Activity
In
the
ordinary course of business, we 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 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 our
pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note
6
- Customer Choice and Industry Restructuring and Note 7 - Commitments and
Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters and
Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed
Financial Statements of Registrant Subsidiaries” section. Adverse results in
these proceedings have the potential to materially affect our results of
operations, financial condition and cash flows.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2005 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.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management policies and procedures are instituted and administered at the AEP
Consolidated level. 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
us.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in our Condensed Consolidated Balance Sheet as of September 30, 2006
and the reasons for changes in our total MTM value as compared to December
31,
2005.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of September 30, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow &
Fair
Value Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
55,747
|
|
$
|
5,010
|
|
$
|
-
|
|
$
|
60,757
|
|
Noncurrent
Assets
|
|
|
71,650
|
|
|
342
|
|
|
-
|
|
|
71,992
|
|
Total
MTM Derivative Contract Assets
|
|
|
127,397
|
|
|
5,352
|
|
|
-
|
|
|
132,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(42,116
|
)
|
|
(15,586
|
)
|
|
(1,259
|
)
|
|
(58,961
|
)
|
Noncurrent
Liabilities
|
|
|
(46,349
|
)
|
|
(8
|
)
|
|
(6,120
|
)
|
|
(52,477
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(88,465
|
)
|
|
(15,594
|
)
|
|
(7,379
|
)
|
|
(111,438
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
38,932
|
|
$
|
(10,242
|
)
|
$
|
(7,379
|
)
|
$
|
21,311
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 2006
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
|
$
|
33,932
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
(538
|
)
|
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
|
|
|
(137
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(310
|
)
|
Changes
Due to SIA (c)
|
|
|
(3,940
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
9,925
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
38,932
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
(10,242
|
)
|
DETM
Assignment (e)
|
|
|
(7,379
|
)
|
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
|
$
|
21,311
|
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek 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)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(d)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected in our Condensed
Consolidated Statements of Income. These net gains (losses) are recorded
as regulatory liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net
Assets
The
following table presents:
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving 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, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
1,202
|
|
$
|
8,629
|
|
$
|
3,123
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
12,954
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes
(a)
|
|
|
2,395
|
|
|
6,585
|
|
|
3,260
|
|
|
4,892
|
|
|
-
|
|
|
-
|
|
|
17,132
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
-
|
|
|
(2,602
|
)
|
|
988
|
|
|
3,113
|
|
|
5,579
|
|
|
1,768
|
|
|
8,846
|
|
Total
|
|
$
|
3,597
|
|
$
|
12,612
|
|
$
|
7,371
|
|
$
|
8,005
|
|
$
|
5,579
|
|
$
|
1,768
|
|
$
|
38,932
|
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheet
We
are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations
on
the future cash flows from assets. We do not hedge all commodity price
risk.
We
employ
the use of 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
risk.
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 the changes from December 31, 2005 to September 30, 2006. 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, 2006
(in
thousands)
|
|
Power
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(877
|
)
|
$
|
(2,590
|
)
|
$
|
(3,467
|
)
|
Changes
in Fair Value
|
|
|
2,978
|
|
|
(9,382
|
)
|
|
(6,404
|
)
|
Impact
due to Changes in SIA (a)
|
|
|
(267
|
)
|
|
-
|
|
|
(267
|
)
|
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
|
|
1,394
|
|
|
241
|
|
|
1,635
|
|
Ending
Balance in AOCI September 30, 2006
|
|
$
|
3,228
|
|
$
|
(11,731
|
)
|
$
|
(8,503
|
)
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $2,120 thousand gain.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
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, 2006, a near term typical change
in
commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended
September
30, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$438
|
|
$1,283
|
|
$427
|
|
$242
|
|
|
|
|
$433
|
|
$720
|
|
$343
|
|
$124
|
The
High
VaR for the nine months ended September 30, 2006 occurred in the third quarter
due to volatility in the ECAR/PJM region.
VaR
Associated with Debt Outstanding
We
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The
risk
of potential loss in fair value attributable to our exposure to interest rates
primarily related to long-term debt with fixed interest rates was $69 million
and $55 million at September 30, 2006 and December 31, 2005, respectively.
We
would not expect to liquidate our entire debt portfolio in a one-year holding
period; therefore, a near term change in interest rates should not negatively
affect our results of operations or consolidated financial
position.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2006 and
2005
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
449,259
|
|
$
|
391,361
|
|
$
|
1,224,609
|
|
$
|
1,095,621
|
|
Sales
to AEP Affiliates
|
|
|
54,793
|
|
|
103,141
|
|
|
223,728
|
|
|
277,223
|
|
Other
- Affiliated
|
|
|
12,903
|
|
|
11,745
|
|
|
37,838
|
|
|
34,215
|
|
Other
- Nonaffiliated
|
|
|
8,580
|
|
|
8,832
|
|
|
24,593
|
|
|
23,139
|
|
TOTAL
|
|
|
525,535
|
|
|
515,079
|
|
|
1,510,768
|
|
|
1,430,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
98,135
|
|
|
93,557
|
|
|
283,734
|
|
|
253,255
|
|
Purchased
Electricity for Resale
|
|
|
20,450
|
|
|
11,784
|
|
|
46,993
|
|
|
35,786
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
92,052
|
|
|
82,763
|
|
|
259,304
|
|
|
228,756
|
|
Other
Operation
|
|
|
125,170
|
|
|
122,927
|
|
|
357,882
|
|
|
343,239
|
|
Maintenance
|
|
|
56,960
|
|
|
42,300
|
|
|
142,531
|
|
|
144,988
|
|
Depreciation
and Amortization
|
|
|
47,895
|
|
|
42,726
|
|
|
136,681
|
|
|
127,695
|
|
Taxes
Other Than Income Taxes
|
|
|
18,472
|
|
|
18,268
|
|
|
56,343
|
|
|
53,246
|
|
TOTAL
|
|
|
459,134
|
|
|
414,325
|
|
|
1,283,468
|
|
|
1,186,965
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
66,401
|
|
|
100,754
|
|
|
227,300
|
|
|
243,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
1,102
|
|
|
586
|
|
|
2,459
|
|
|
1,437
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
2,517
|
|
|
563
|
|
|
5,881
|
|
|
3,252
|
|
Interest
Expense
|
|
|
(17,228
|
)
|
|
(16,343
|
)
|
|
(52,663
|
)
|
|
(48,427
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
52,792
|
|
|
85,560
|
|
|
182,977
|
|
|
199,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
18,231
|
|
|
32,548
|
|
|
62,013
|
|
|
71,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
34,561
|
|
|
53,012
|
|
|
120,964
|
|
|
128,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements including Capital Stock Expense
|
|
|
85
|
|
|
86
|
|
|
255
|
|
|
311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
34,476
|
|
$
|
52,926
|
|
$
|
120,709
|
|
$
|
127,963
|
|
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
DECEMBER
31, 2004
|
|
$
|
56,584
|
|
$
|
858,835
|
|
$
|
221,330
|
|
$
|
(45,251
|
)
|
$
|
1,091,498
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(52,000
|
)
|
|
|
|
|
(52,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(255
|
)
|
|
|
|
|
(255
|
)
|
Capital
Stock Expense and Other
|
|
|
|
|
|
2,455
|
|
|
(56
|
)
|
|
|
|
|
2,399
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,041,642
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,900
|
|
|
|
|
|
|
|
|
|
|
|
(5,385
|
)
|
|
(5,385
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
128,274
|
|
|
|
|
|
128,274
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122,889
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2005
|
|
$
|
56,584
|
|
$
|
861,290
|
|
$
|
297,293
|
|
$
|
(50,636
|
)
|
$
|
1,164,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
56,584
|
|
$
|
861,290
|
|
$
|
305,787
|
|
$
|
(3,569
|
)
|
$
|
1,220,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(30,000
|
)
|
|
|
|
|
(30,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(255
|
)
|
|
|
|
|
(255
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,189,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,712
|
|
|
|
|
|
|
|
|
|
|
|
(5,036
|
)
|
|
(5,036
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
120,964
|
|
|
|
|
|
120,964
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
115,928
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$
|
56,584
|
|
$
|
861,290
|
|
$
|
396,496
|
|
$
|
(8,605
|
)
|
$
|
1,305,765
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
706
|
|
$
|
854
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
72,718
|
|
|
62,614
|
|
Affiliated
Companies
|
|
|
80,334
|
|
|
127,981
|
|
Miscellaneous
|
|
|
2,463
|
|
|
1,982
|
|
Allowance
for Uncollectible Accounts
|
|
|
(1,204
|
)
|
|
(898
|
)
|
Total
Accounts Receivable
|
|
|
154,311
|
|
|
191,679
|
|
Fuel
|
|
|
38,531
|
|
|
25,894
|
|
Materials
and Supplies
|
|
|
126,067
|
|
|
118,039
|
|
Risk
Management Assets
|
|
|
60,757
|
|
|
78,134
|
|
Accrued
Tax Benefits
|
|
|
16,951
|
|
|
51,846
|
|
Margin
Deposits
|
|
|
1,258
|
|
|
17,115
|
|
Prepayments
and Other
|
|
|
9,072
|
|
|
14,188
|
|
TOTAL
|
|
|
407,653
|
|
|
497,749
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
3,217,437
|
|
|
3,128,078
|
|
Transmission
|
|
|
1,041,725
|
|
|
1,028,496
|
|
Distribution
|
|
|
1,084,530
|
|
|
1,029,498
|
|
Other
(including nuclear fuel and coal mining)
|
|
|
523,502
|
|
|
465,130
|
|
Construction
Work in Progress
|
|
|
283,714
|
|
|
311,080
|
|
Total
|
|
|
6,150,908
|
|
|
5,962,282
|
|
Accumulated
Depreciation, Depletion and Amortization
|
|
|
2,909,705
|
|
|
2,822,558
|
|
TOTAL
- NET
|
|
|
3,241,203
|
|
|
3,139,724
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
217,070
|
|
|
222,686
|
|
Nuclear
Decommissioning and Spent Nuclear Fuel Disposal Trust
Funds
|
|
|
1,191,142
|
|
|
1,133,567
|
|
Long-term
Risk Management Assets
|
|
|
71,992
|
|
|
103,645
|
|
Deferred
Charges and Other
|
|
|
144,890
|
|
|
164,938
|
|
TOTAL
|
|
|
1,625,094
|
|
|
1,624,836
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
5,273,950
|
|
$
|
5,262,309
|
|
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, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
27,616
|
|
$
|
93,702
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
137,157
|
|
|
139,334
|
|
Affiliated
Companies
|
|
|
59,163
|
|
|
60,324
|
|
Long-term
Debt Due Within One Year
|
|
|
349,627
|
|
|
364,469
|
|
Risk
Management Liabilities
|
|
|
58,961
|
|
|
71,032
|
|
Customer
Deposits
|
|
|
34,943
|
|
|
49,258
|
|
Accrued
Taxes
|
|
|
49,964
|
|
|
56,567
|
|
Other
|
|
|
138,352
|
|
|
112,839
|
|
TOTAL
|
|
|
855,783
|
|
|
947,525
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt
|
|
|
1,104,274
|
|
|
1,080,471
|
|
Long-term
Risk Management Liabilities
|
|
|
52,477
|
|
|
86,159
|
|
Deferred
Income Taxes
|
|
|
336,194
|
|
|
335,264
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
714,663
|
|
|
710,015
|
|
Asset
Retirement Obligations
|
|
|
774,061
|
|
|
737,959
|
|
Deferred
Credits and Other
|
|
|
122,651
|
|
|
136,740
|
|
TOTAL
|
|
|
3,104,320
|
|
|
3,086,608
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
3,960,103
|
|
|
4,034,133
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
8,082
|
|
|
8,084
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
861,290
|
|
|
861,290
|
|
Retained
Earnings
|
|
|
396,496
|
|
|
305,787
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(8,605
|
)
|
|
(3,569
|
)
|
TOTAL
|
|
|
1,305,765
|
|
|
1,220,092
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
5,273,950
|
|
$
|
5,262,309
|
|
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
120,964
|
|
$
|
128,274
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
136,681
|
|
|
127,695
|
|
Accretion
of Asset Retirement Obligations
|
|
|
36,309
|
|
|
35,742
|
|
Deferred
Income Taxes
|
|
|
7,734
|
|
|
2,269
|
|
Deferred
Investment Tax Credits
|
|
|
(5,460
|
)
|
|
(5,496
|
)
|
Amortization
(Deferral) of Incremental Nuclear Refueling Outage Expenses,
Net
|
|
|
(20,673
|
)
|
|
10,506
|
|
Amortization
of Nuclear Fuel
|
|
|
37,839
|
|
|
41,613
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(4,915
|
)
|
|
(11,275
|
)
|
Pension
Contributions to Qualified Plan Trusts
|
|
|
-
|
|
|
(46,051
|
)
|
Deferred
Property Taxes
|
|
|
10,854
|
|
|
9,814
|
|
Change
in Other Noncurrent Assets
|
|
|
25,260
|
|
|
11,650
|
|
Change
in Other Noncurrent Liabilities
|
|
|
5,071
|
|
|
13,961
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
37,368
|
|
|
14,441
|
|
Fuel,
Materials and Supplies
|
|
|
(20,665
|
)
|
|
4,303
|
|
Accounts
Payable
|
|
|
29,483
|
|
|
4,065
|
|
Accrued
Taxes, Net
|
|
|
28,292
|
|
|
(85,750
|
)
|
Customer
Deposits
|
|
|
(14,315
|
)
|
|
28,233
|
|
Accrued
Interest
|
|
|
11,534
|
|
|
10,358
|
|
Rent
Accrued - Rockport Plant Unit 2
|
|
|
18,464
|
|
|
18,464
|
|
Other
Current Assets
|
|
|
20,997
|
|
|
(36,068
|
)
|
Other
Current Liabilities
|
|
|
(4,509
|
)
|
|
(225
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
456,313
|
|
|
276,523
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(240,806
|
)
|
|
(190,171
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
5,093
|
|
Purchases
of Investment Securities
|
|
|
(559,803
|
)
|
|
(473,802
|
)
|
Sales
of Investment Securities
|
|
|
517,017
|
|
|
434,639
|
|
Acquisitions
of Nuclear Fuel
|
|
|
(72,614
|
)
|
|
(28,188
|
)
|
Proceeds
from Sales of Assets
|
|
|
954
|
|
|
13,554
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(355,252
|
)
|
|
(238,875
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt
|
|
|
49,745
|
|
|
-
|
|
Change
in Advances from Affiliates, Net
|
|
|
(66,086
|
)
|
|
81,101
|
|
Retirement
of Long-term Debt
|
|
|
(50,000
|
)
|
|
-
|
|
Retirement
of Cumulative Preferred Stock
|
|
|
(1
|
)
|
|
(61,445
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(4,612
|
)
|
|
(4,829
|
)
|
Dividends
Paid on Common Stock
|
|
|
(30,000
|
)
|
|
(52,000
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(255
|
)
|
|
(255
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(101,209
|
)
|
|
(37,428
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(148
|
)
|
|
220
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
854
|
|
|
511
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
706
|
|
$
|
731
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
DISCLOSURE
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
37,708
|
|
$
|
34,999
|
|
Net
Cash Paid for Income Taxes
|
|
|
20,180
|
|
|
149,058
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
4,359
|
|
|
1,465
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
29,755
|
|
|
25,008
|
|
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
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
|
|
KENTUCKY
POWER COMPANY
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006 Net
Income
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
8
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
1
|
|
|
|
|
Off-system
Sales
|
|
|
8
|
|
|
|
|
Transmission
Revenues
|
|
|
(3
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(3
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
1
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
10
|
|
Net
Income increased $2 million to $10 million in 2006. The key driver of the
increase was a $6 million increase in Gross Margin.
The
major
components of our 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 $1 million primarily due to $12 million of
rate relief
from the March 2006 approval of the settlement agreement in our
base rate
case. The rate increase was partially offset by the effect
of:
|
|
·
|
a
23% decrease in cooling degree days as a result of mild weather
on
residential and commercial sales,
|
|
·
|
a
decrease in financial transmission rights revenue, net of congestion,
primarily due to fewer transmission constraints in the PJM market
and
|
|
·
|
increased
capacity charges due to changes in the relative peak demands
and
generating capacity of the AEP Power Pool
members.
|
·
|
Off-system
Sales increased $8 million due to $4 million increase in physical
sales
margins and a $4 million increase from lower sharing of off-system
sales
margins under the SIA. See the “Allocation Agreement between AEP East
companies and AEP West companies and CSW Operating Agreement” section of
Note 3.
|
·
|
Transmission
Revenues decreased $3 million primarily due to the elimination
of SECA
revenues as of April 1, 2006. At this time, we have a pending
proposal
with the FERC to replace SECA revenues. See the “Transmission Rate
Proceedings at the FERC” section of Note
3.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $3 million primarily
due to
maintenance of overhead lines.
|
Income
Taxes
The
increase in Income Tax Expense of $2 million is primarily due to an increase
in
pretax book income and changes in certain book/tax differences accounted for
on
a flow-through basis.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine Months Ended September 30, 2005 to
Nine
Months Ended September 30, 2006 Net Income
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
20
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
8
|
|
|
|
|
Off-system
Sales
|
|
|
9
|
|
|
|
|
Transmission
Revenues
|
|
|
(6
|
)
|
|
|
|
Other
|
|
|
3
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(4
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(1
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
25
|
|
|
|
|
|
|
|
|
|
Net
Income increased $5 million to $25 million in 2006. The key driver of the
increase was a $14 million increase in Gross Margin, partially offset by a
$5
million increase in Operating Expenses and Other.
The
major
components of our 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 $8 million primarily due to rate relief from the
March
2006 approval of the settlement agreement in our base rate case as
well as
favorable financial transmission rights revenue, net of congestion.
The
above was partially offset by increased capacity charges due to changes
in
the relative peak demands and generating capacity of the AEP Power
Pool
members.
|
·
|
Off-system
Sales increased $9 million primarily due to $10 million increase
in
physical sales margins and a $5 million increase from lower sharing
of
off-system sales margins under the SIA offset by a $5 million decrease
in
margins from optimization activities. See the “Allocation Agreement
between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
|
·
|
Transmission
Revenues decreased $6 million primarily due to the elimination of
SECA
revenues as of April 1, 2006 and a provision of $1 million recorded
in
2006 related to potential SECA refunds pending settlement negotiations
with various intervenors. At this time, we have a pending proposal
with
the FERC to replace SECA revenues. See the “Transmission Rate Proceedings
at the FERC” section of Note 3.
|
·
|
Other
revenues increased
$3 million primarily due to a $3 million unfavorable adjustment of
the
Demand Side Management Program regulatory asset in March
2005.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $4 million primarily
due to
maintenance of overhead lines.
|
Income
Taxes
The
increase in Income Tax Expense of $4 million is primarily due to an increase
in
pretax book income and changes in certain book/tax differences accounted for
on
a flow-through basis.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Current ratings are as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
Baa2
|
|
BBB
|
|
BBB
|
Financing
Activities
Long-term
debt issuances and retirements during the first nine months of 2006
were:
Issuances
None
Retirements
|
|
Principal
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
Amount
|
|
Rate
|
|
Date
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Notes
Payable-Affiliated
|
|
$
|
40,000
|
|
6.501
|
|
2006
|
Liquidity
We
have
solid investment grade ratings, which provide us ready access to capital markets
in order to issue new debt or refinance long-term debt maturities. In addition,
we participate in the Utility Money Pool, which provides access to AEP’s
liquidity.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end.
Significant
Factors
Big
Sandy Plant Scrubber
Completion
of construction of a scrubber at our Big Sandy Plant was previously scheduled
for 2010. We suspended the project in the second quarter of 2006 after a
generation engineering evaluation determined that there was a substantially
higher estimated capital cost due to increases in labor and material costs,
refinements of preliminary costs estimates and an increase in cost per ton
of
removed SO2.
We
currently estimate the project to have an in-service date of 2020.
Management continues to review its emission compliance plans given changing
market conditions and the evolving legistative and regulatory environment.
We
transferred the total project expenditures of $16 million during the second
quarter of 2006 from Construction Work in Progress to Deferred Charges and
Other
on our Condensed Balance Sheet. If management does not resume the project,
the
balance of incurred expenditures would negatively impact future earnings unless
a regulatory asset could be established due to probable recovery through rates.
Our
2006
estimated construction expenditures of $100 million, as reported in Note 7
-
Commitments and Contingencies in our 2005 Annual Report, has been revised to
$54
million due to the delay of the project.
Litigation
and Regulatory Activity
In
the
ordinary course of business, we 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 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 our
pending litigation and regulatory proceedings, see Note 4 - Rate Matters and
Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see
Note
3 - Rate Matters and Note 5 - Commitments and Contingencies in the “Condensed
Notes to Condensed Financial Statements of Registrant Subsidiaries” section.
Adverse results in these proceedings have the potential to materially affect
our
results of operations, financial condition and cash flows.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2005 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.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management policies and procedures are instituted and administered at the AEP
Consolidated level. 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
us.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in our condensed balance sheet as of September 30, 2006 and the reasons
for changes in our total MTM value as compared to December 31, 2005.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Balance Sheet
As
of September 30, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow &
Fair
Value Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
19,926
|
|
$
|
1,916
|
|
$
|
-
|
|
$
|
21,842
|
|
Noncurrent
Assets
|
|
|
25,640
|
|
|
122
|
|
|
-
|
|
|
25,762
|
|
Total
MTM Derivative Contract Assets
|
|
|
45,566
|
|
|
2,038
|
|
|
-
|
|
|
47,604
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(14,945
|
)
|
|
(1,156
|
)
|
|
(451
|
)
|
|
(16,552
|
)
|
Noncurrent
Liabilities
|
|
|
(16,550
|
)
|
|
(2
|
)
|
|
(2,192
|
)
|
|
(18,744
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(31,495
|
)
|
|
(1,158
|
)
|
|
(2,643
|
)
|
|
(35,296
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
14,071
|
|
$
|
880
|
|
$
|
(2,643
|
)
|
$
|
12,308
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 2006
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
|
$
|
13,518
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
32
|
|
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
|
|
|
(70
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(462
|
)
|
Changes
Due to SIA (c)
|
|
|
(1,565
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
2,618
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
14,071
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
880
|
|
DETM
Assignment (e)
|
|
|
(2,643
|
)
|
Total
MTM Risk Management Contract Net Assets at September 30, 2006
|
|
$
|
12,308
|
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek 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)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(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
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net
Assets
The
following table presents:
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving 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, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
430
|
|
$
|
3,090
|
|
$
|
1,118
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
4,638
|
|
Prices
Provided by Other External Sources
- OTC Broker Quotes
(a)
|
|
|
905
|
|
|
2,379
|
|
|
1,164
|
|
|
1,752
|
|
|
-
|
|
|
-
|
|
|
6,200
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
1
|
|
|
(885
|
)
|
|
372
|
|
|
1,114
|
|
|
1,998
|
|
|
633
|
|
|
3,233
|
|
Total
|
|
$
|
1,336
|
|
$
|
4,584
|
|
$
|
2,654
|
|
$
|
2,866
|
|
$
|
1,998
|
|
$
|
633
|
|
$
|
14,071
|
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Balance Sheet
We
are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations
on
the future cash flows from assets. We do not hedge all commodity price
risk.
We
employ
the use of interest rate derivative transactions in order to manage interest
rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge
all
interest rate risk.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on our Condensed Balance Sheets and the reasons for the changes
from December 31, 2005 to September 30, 2006. 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, 2006
(in
thousands)
|
|
Power
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(352
|
)
|
$
|
158
|
|
$
|
(194
|
)
|
Changes
in Fair Value
|
|
|
1,072
|
|
|
-
|
|
|
1,072
|
|
Impact
Due to Changes in SIA (a)
|
|
|
(106
|
)
|
|
-
|
|
|
(106
|
)
|
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
|
|
543
|
|
|
(66
|
)
|
|
477
|
|
Ending
Balance in AOCI September 30, 2006
|
|
$
|
1,157
|
|
$
|
92
|
|
$
|
1,249
|
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,164 thousand gain.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
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, 2006, a near term typical change
in
commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended
September
30, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$157
|
|
$459
|
|
$164
|
|
$87
|
|
|
|
|
$174
|
|
$289
|
|
$138
|
|
$50
|
The
High
VaR for the nine months ended September 30, 2006 occurred in the third quarter
due to volatility in the ECAR/PJM region.
VaR
Associated with Debt Outstanding
We
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The
risk
of potential loss in fair value attributable to our exposure to interest rates
primarily related to long-term debt with fixed interest rates was $11 million
and $13 million at September 30, 2006 and December 31, 2005, respectively.
We
would not expect to liquidate our entire debt portfolio in a one-year holding
period; therefore, a near term change in interest rates should not negatively
affect our results of operations or financial position.
KENTUCKY
POWER COMPANY
CONDENSED
STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2006 and
2005
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
138,554
|
|
$
|
120,321
|
|
$
|
397,248
|
|
$
|
337,912
|
|
Sales
to AEP Affiliates
|
|
|
13,466
|
|
|
23,341
|
|
|
41,543
|
|
|
55,598
|
|
Other
|
|
|
299
|
|
|
334
|
|
|
678
|
|
|
1,255
|
|
TOTAL
|
|
|
152,319
|
|
|
143,996
|
|
|
439,469
|
|
|
394,765
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
39,580
|
|
|
43,603
|
|
|
115,336
|
|
|
104,271
|
|
Purchased
Electricity for Resale
|
|
|
3,974
|
|
|
1,563
|
|
|
6,938
|
|
|
5,473
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
48,755
|
|
|
45,300
|
|
|
149,204
|
|
|
131,049
|
|
Other
Operation
|
|
|
15,176
|
|
|
14,352
|
|
|
42,662
|
|
|
42,549
|
|
Maintenance
|
|
|
9,607
|
|
|
7,180
|
|
|
26,041
|
|
|
21,578
|
|
Depreciation
and Amortization
|
|
|
11,574
|
|
|
11,318
|
|
|
34,603
|
|
|
33,695
|
|
Taxes
Other Than Income Taxes
|
|
|
1,807
|
|
|
2,457
|
|
|
6,761
|
|
|
7,101
|
|
TOTAL
|
|
|
130,473
|
|
|
125,773
|
|
|
381,545
|
|
|
345,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
21,846
|
|
|
18,223
|
|
|
57,924
|
|
|
49,049
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
159
|
|
|
189
|
|
|
518
|
|
|
456
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
236
|
|
|
37
|
|
|
249
|
|
|
209
|
|
Interest
Expense
|
|
|
(6,581
|
)
|
|
(7,227
|
)
|
|
(21,317
|
)
|
|
(21,665
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
15,660
|
|
|
11,222
|
|
|
37,374
|
|
|
28,049
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
5,791
|
|
|
3,495
|
|
|
12,624
|
|
|
7,991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
9,869
|
|
$
|
7,727
|
|
$
|
24,750
|
|
$
|
20,058
|
|
The
common stock of KPCo is wholly-owned by AEP.
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
KENTUCKY
POWER COMPANY
CONDENSED
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Nine Months Ended September 30, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Total
|
|
DECEMBER
31, 2004
|
|
$
|
50,450
|
|
$
|
208,750
|
|
$
|
70,555
|
|
$
|
(8,775
|
)
|
$
|
320,980
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $1,534
|
|
|
|
|
|
|
|
|
|
|
|
(2,848
|
)
|
|
(2,848
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
20,058
|
|
|
|
|
|
20,058
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2005
|
|
$
|
50,450
|
|
$
|
208,750
|
|
$
|
90,613
|
|
$
|
(11,623
|
)
|
$
|
338,190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
50,450
|
|
$
|
208,750
|
|
$
|
88,864
|
|
$
|
(223
|
)
|
$
|
347,841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(10,000
|
)
|
|
|
|
|
(10,000
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
337,841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $777
|
|
|
|
|
|
|
|
|
|
|
|
1,443
|
|
|
1,443
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
24,750
|
|
|
|
|
|
24,750
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$
|
50,450
|
|
$
|
208,750
|
|
$
|
103,614
|
|
$
|
1,220
|
|
$
|
364,034
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
KENTUCKY
POWER COMPANY
CONDENSED
BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
479
|
|
$
|
526
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
23,776
|
|
|
26,533
|
|
Affiliated
Companies
|
|
|
14,337
|
|
|
23,525
|
|
Accrued
Unbilled Revenues
|
|
|
1,004
|
|
|
6,311
|
|
Miscellaneous
|
|
|
554
|
|
|
35
|
|
Allowance
for Uncollectible Accounts
|
|
|
(253
|
)
|
|
(147
|
)
|
Total
Accounts Receivable
|
|
|
39,418
|
|
|
56,257
|
|
Fuel
|
|
|
10,780
|
|
|
8,490
|
|
Materials
and Supplies
|
|
|
8,854
|
|
|
10,181
|
|
Risk
Management Assets
|
|
|
21,842
|
|
|
31,437
|
|
Accrued
Tax Benefits
|
|
|
2,535
|
|
|
6,598
|
|
Margin
Deposits
|
|
|
453
|
|
|
6,895
|
|
Prepayments
and Other
|
|
|
1,955
|
|
|
6,324
|
|
TOTAL
|
|
|
86,316
|
|
|
126,708
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
477,777
|
|
|
472,575
|
|
Transmission
|
|
|
391,671
|
|
|
386,945
|
|
Distribution
|
|
|
470,606
|
|
|
456,063
|
|
Other
|
|
|
60,607
|
|
|
63,382
|
|
Construction
Work in Progress
|
|
|
30,436
|
|
|
35,461
|
|
Total
|
|
|
1,431,097
|
|
|
1,414,426
|
|
Accumulated
Depreciation and Amortization
|
|
|
438,023
|
|
|
425,817
|
|
TOTAL
- NET
|
|
|
993,074
|
|
|
988,609
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
111,089
|
|
|
117,432
|
|
Long-term
Risk Management Assets
|
|
|
25,762
|
|
|
41,810
|
|
Deferred
Charges and Other
|
|
|
54,607
|
|
|
45,467
|
|
TOTAL
|
|
|
191,458
|
|
|
204,709
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
1,270,848
|
|
$
|
1,320,026
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
KENTUCKY
POWER COMPANY
CONDENSED
BALANCE SHEETS
LIABILITIES
AND SHAREHOLDER’S EQUITY
September
30, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
24,507
|
|
$
|
6,040
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
31,118
|
|
|
32,454
|
|
Affiliated
Companies
|
|
|
18,045
|
|
|
29,326
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
124,123
|
|
|
-
|
|
Long-term
Debt Due Within One Year - Affiliated
|
|
|
-
|
|
|
39,771
|
|
Risk
Management Liabilities
|
|
|
16,552
|
|
|
28,770
|
|
Customer
Deposits
|
|
|
15,849
|
|
|
21,643
|
|
Accrued
Taxes
|
|
|
9,322
|
|
|
8,805
|
|
Accrued
Interest
|
|
|
9,897
|
|
|
7,428
|
|
Other
|
|
|
15,967
|
|
|
14,096
|
|
TOTAL
|
|
|
265,380
|
|
|
188,333
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
302,861
|
|
|
427,219
|
|
Long-term
Debt - Affiliated
|
|
|
20,000
|
|
|
20,000
|
|
Long-term
Risk Management Liabilities
|
|
|
18,744
|
|
|
35,302
|
|
Deferred
Income Taxes
|
|
|
240,423
|
|
|
234,719
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
50,500
|
|
|
56,794
|
|
Deferred
Credits and Other
|
|
|
8,906
|
|
|
9,818
|
|
TOTAL
|
|
|
641,434
|
|
|
783,852
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
906,814
|
|
|
972,185
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - $50 Par Value Per Share:
|
|
|
|
|
|
|
|
Authorized
- 2,000,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 1,009,000 Shares
|
|
|
50,450
|
|
|
50,450
|
|
Paid-in
Capital
|
|
|
208,750
|
|
|
208,750
|
|
Retained
Earnings
|
|
|
103,614
|
|
|
88,864
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
1,220
|
|
|
(223
|
)
|
TOTAL
|
|
|
364,034
|
|
|
347,841
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$
|
1,270,848
|
|
$
|
1,320,026
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
KENTUCKY
POWER COMPANY
CONDENSED
STATEMENTS OF CASH FLOWS
For
the Nine Months Ended September 30, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
24,750
|
|
$
|
20,058
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
34,603
|
|
|
33,695
|
|
Deferred
Income Taxes
|
|
|
2,742
|
|
|
1,836
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(842
|
)
|
|
(5,204
|
)
|
Pension
Contributions to Qualified Plan Trusts
|
|
|
-
|
|
|
(9,137
|
)
|
Over/Under
Fuel Recovery
|
|
|
3,608
|
|
|
(4,453
|
)
|
Change
in Other Noncurrent Assets
|
|
|
5,666
|
|
|
(4
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
2,629
|
|
|
10,333
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
16,839
|
|
|
(2,592
|
)
|
Fuel,
Materials and Supplies
|
|
|
(963
|
)
|
|
(4,200
|
)
|
Accounts
Payable
|
|
|
(8,149
|
)
|
|
12,876
|
|
Customer
Deposits
|
|
|
(5,794
|
)
|
|
12,776
|
|
Accrued
Taxes, Net
|
|
|
4,580
|
|
|
(553
|
)
|
Other
Current Assets
|
|
|
7,726
|
|
|
(14,231
|
)
|
Other
Current Liabilities
|
|
|
3,819
|
|
|
2,297
|
|
Net
Cash Flows From Operating Activities
|
|
|
91,214
|
|
|
53,497
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(59,264
|
)
|
|
(38,837
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
6,486
|
|
Other
|
|
|
465
|
|
|
191
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(58,799
|
)
|
|
(32,160
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
18,467
|
|
|
-
|
|
Retirement
of Long-term Debt - Affiliated
|
|
|
(40,000
|
)
|
|
(20,000
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(929
|
)
|
|
(1,122
|
)
|
Dividends
Paid on Common Stock
|
|
|
(10,000
|
)
|
|
-
|
|
Net
Cash Flows Used For Financing Activities
|
|
|
(32,462
|
)
|
|
(21,122
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(47
|
)
|
|
215
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
526
|
|
|
132
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
479
|
|
$
|
347
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
18,242
|
|
$
|
17,250
|
|
Net
Cash Paid for Income Taxes
|
|
|
4,573
|
|
|
7,466
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
551
|
|
|
273
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
2,085
|
|
|
1,386
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
KENTUCKY
POWER COMPANY
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to KPCo’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 KPCo.
|
Footnote
Reference
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
OHIO
POWER COMPANY CONSOLIDATED
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006 Net
Income
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
56
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
47
|
|
|
|
|
Off-system
Sales
|
|
|
23
|
|
|
|
|
Transmission
Revenues
|
|
|
(9
|
)
|
|
|
|
Other
|
|
|
(7
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(5
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(9
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
6
|
|
|
|
|
Other
Income
|
|
|
(1
|
)
|
|
|
|
Carrying
Costs Income
|
|
|
(6
|
)
|
|
|
|
Interest
Expense
|
|
|
4
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(11
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
83
|
|
Net
Income increased $27 million to $83 million in 2006. The key driver of the
increase was a $54 million increase in Gross Margin offset by a $16 million
increase in Income Tax Expense and an $11 million increase in Operating Expenses
and Other.
The
major
components of our increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emission allowances,
and purchased power, were as follows:
·
|
Retail
Margins were $47 million higher than the prior period primarily due
to the
Rate Stabilization Plan (RSP) rate increase effective January 1,
2006,
favorable capacity settlements, and lower consumable expenses. These
increases were partially offset by lower residential revenue due
to mild
weather and lower industrial revenue due to the transfer of a significant
customer to an affiliate.
|
·
|
Off-system
Sales increased $23 million primarily due to $19 million increase
in
physical sales margins and a $14 million increase from lower sharing
of
off-system sales margins under the SIA offset by a $10 million decrease
in
margins from optimization activities. See the “Allocation Agreement
between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
|
·
|
Transmission
Revenues decreased $9 million primarily due to the elimination of
SECA
revenues as of April 1, 2006. At this time, we have a pending proposal
with the FERC to replace SECA revenues. See the “Transmission Rate
Proceedings at the FERC” section of Note 3.
|
·
|
Other
revenue decreased $7 million primarily due to the expiration of a
contract
to sell supplemental demand to Buckeye Power and a decrease in rental
revenue.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expense increased $5 million partially
due to an
increase in maintenance from planned and forced outages at the Muskingum
and Sporn plants related to major turbine overhaul and boiler tube
inspections and repairs. The increase was partially offset by the
recognition of a regulatory asset related to recent PUCO orders
regarding distribution service reliability and restoration costs.
|
·
|
Depreciation
and Amortization increased $9 million due to increased amortization
of
regulatory assets and a greater depreciable base in electric utility
plant.
|
·
|
Taxes
Other Than Income Taxes decreased $6 million primarily due an adjustment
in 2005 to true-up 2004 and 2005 property taxes.
|
·
|
Carrying
Costs Income decreased $6 million primarily due to the completion
of
deferrals of the environmental carrying costs from 2004 and 2005
that are
now being recovered during 2006 through 2008 according to the
RSP.
|
Income
Taxes
The
increase in Income Tax Expense of $16 million is primarily due to an increase
in
pretax book income.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine Months Ended September 30, 2005 to
Nine
Months Ended September 30, 2006 Net Income
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
227
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
42
|
|
|
|
|
Off-system
Sales
|
|
|
29
|
|
|
|
|
Transmission
Revenues
|
|
|
(19
|
)
|
|
|
|
Other
|
|
|
4
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
56
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(65
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(12
|
)
|
|
|
|
Taxes
Other than Income Taxes
|
|
|
1
|
|
|
|
|
Carrying
Costs Income
|
|
|
(28
|
)
|
|
|
|
Interest
Expense
|
|
|
8
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(96
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
202
|
|
Net
Income decreased $25 million to $202 million in 2006. The key driver of the
decrease was a $96 million increase of Operating Expenses and Other offset
by a
$56 million increase in Gross Margin and a $15 million decrease in Income Tax
Expense.
The
major
components of our increase in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emission allowances,
and purchased power, were as follows:
·
|
Retail
Margins increased $42 million primarily due to the RSP rate increase
effective January 1, 2006, favorable capacity settlements, and lower
consumable expenses. The increase is partially offset by lower fuel
margins, a decrease in residential revenue due to mild weather and
lower
industrial revenue due to the transfer of a significant customer
to an
affiliate.
|
·
|
Off-System
Sales increased $29 million primarily due to $48 million increase
in
physical sales margins and a $17 million increase from lower sharing
of
off-system sales margins under the SIA offset by a $35 million decrease
in
margins related to optimization activities. See the “Allocation Agreement
between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
|
·
|
Transmission
Revenues decreased $19 million primarily due to the elimination of
SECA
revenues as of April 1, 2006 and a provision of $4 million recorded
in
2006 related to potential SECA refunds pending settlement negotiations
with various intervenors. At this time, we have a pending proposal
with
the FERC to replace SECA revenues. See the “Transmission Rate Proceedings
at the FERC” section of Note 3.
|
·
|
Other
revenue increased $4 million partially due to an increase in gains
on
sales of emission allowances.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expense increased $65 million primarily
due to
an increase in maintenance from planned and forced outages at the
Gavin,
Muskingum River, Kammer, and Sporn plants related to major boiler
and
turbine overhauls and boiler tube inspections and related removal
costs
and PJM administrative fees. The increase was partially offset by
the
recognition of a regulatory asset related to recent PUCO orders
regarding distribution service reliabiltiy and restoration costs
and major
ice storm expenses in the prior year.
|
·
|
Depreciation
and Amortization increased $12 million primarily due to increased
amortization of regulatory assets and a greater depreciable base
in
electric utility plant.
|
·
|
Carrying
Costs Income decreased $28 million primarily due to the completion
of
deferrals of the environmental carrying costs from 2004 and 2005
that are
now being recovered during 2006 through 2008 according to the
RSP.
|
·
|
Interest
Expense decreased $8 million primarily due to an increase in allowance
for
borrowed funds used during construction partially offset by interest
on
long-term debt issuances subsequent to September
2005.
|
Income
Taxes
The
decrease in Income Tax Expense of $15 million is primarily due to a decrease
in
pretax book income and state income taxes, offset in part by changes in certain
book/tax differences accounted for on a flow-through basis.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Current ratings are as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
A3
|
|
BBB
|
|
BBB+
|
Cash
Flow
Cash
flows for the nine months ended September 30, 2006 and 2005 were as
follows:
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
1,240
|
|
$
|
9,337
|
|
Net
Cash Flows From (Used For):
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
476,382
|
|
|
319,579
|
|
Investing
Activities
|
|
|
(709,752
|
)
|
|
(325,415
|
)
|
Financing
Activities
|
|
|
233,455
|
|
|
(2,121
|
)
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
85
|
|
|
(7,957
|
)
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,325
|
|
$
|
1,380
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $476 million in 2006. We produced Net
Income of $202 million during the period and a noncash expense item of $239
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 primarily relates to two items, Accounts
Receivable, Net and Accounts Payable. Accounts Receivable, Net decreased $78
million due to the collection of receivables related to power sales to
affiliates. Accounts Payable decreased $45 million primarily due to timing
differences for payments to affiliates related to emission allowances and the
AEP Power Pool.
Net
Cash
Flows From Operating Activities were $320 million in 2005. We produced Net
Income of $227 million during the period and a noncash expense item of $228
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 primarily relates two items, Accrued Taxes
and
Accounts Payable. Accrued Taxes decreased $115 million due primarily to the
payment of 2004 federal income tax liability during 2005 and personal property
tax. Accounts Payable increased $58 million, due to higher fuel and allowance
acquisition costs not paid at September 30, 2005.
Investing
Activities
Net
Cash
Flows Used For Investing Activities during 2006 and 2005 primarily reflect
our
Construction Expenditures of $715 million and $460 million, respectively.
Construction expenditures are primarily for environmental upgrades, as well
as
projects to improve service reliability for transmission and distribution for
both periods. In 2005, Construction Expenditures of $460 million were partially
offset by an increase in Advances to Affiliates, Net. For the remainder of
2006,
we expect our Construction Expenditures to be approximately $350
million.
Financing
Activities
Net
Cash
Flows From Financing Activities were $233 million for 2006. We issued $350
million of Senior Unsecured Notes and $65 million of Pollution Control Bonds.
We
retired Notes Payable-Affiliated of $200 million. We received a capital
contribution from our Parent of $70 million.
Net
Cash
Flows Used For Financing Activities were $2 million for 2005. We issued
Pollution Control Bonds of $353 million. We retired Pollution Control Bonds
of
$353 million.
Financing
Activity
Long-term
debt issuances and retirements during the first nine months of 2006
were:
Issuances
|
|
|
Principal
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Amount
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$
|
65,000
|
|
Variable
|
|
2036
|
Senior
Unsecured Notes
|
|
|
350,000
|
|
6.00
|
|
2016
|
Retirements
and Principal Payments
|
|
|
Principal
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Amount
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Notes
Payable - Nonaffiliated
|
|
$
|
4,390
|
|
6.81
|
|
2008
|
Notes
Payable - Nonaffiliated
|
|
|
6,500
|
|
6.27
|
|
2009
|
Notes
Payable - Affiliated
|
|
|
200,000
|
|
3.32
|
|
2006
|
Liquidity
We
have
solid investment grade ratings, which provide us ready access to capital markets
in order to issue new debt, refinance short-term debt or refinance long-term
debt maturities. In addition, we participate in the Utility Money Pool, which
provides access to AEP’s liquidity.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end, other than the debt issuances, retirements
and principal payments discussed above.
Significant
Factors
Litigation
and Regulatory Activity
In
the
ordinary course of business, we 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 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 our
pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note
6
- Customer Choice and Industry Restructuring and Note 7 - Commitments and
Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note
4
- Customer Choice and Industry Restructuring and Note 5 - Commitments and
Contingencies in the “Condensed Notes to Condensed Financial Statements of
Registrant Subsidiaries” section. Adverse results in these proceedings have the
potential to materially affect our results of operations, financial condition
and cash flows.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Muskingum
River Project Deferral
Completion
of construction of the Muskingum River Unit 5 flue gas desulphurization (FGD)
project was previously scheduled for 2008. We suspended the project in the
third
quarter of 2006 following a review of a new SO2
and
mercury compliance plan evaluation, updated coal market information reflecting
the contraction of the low sulfur versus high sulfur price differentials and
the
latest project costs. We currently estimate the project to have an in-service
date of 2015. Management continues to review its emission compliance plans
given changing market conditions and the evolving legislative and regulatory
environment.
We
transferred the total project expenditures of $35 million from Construction
Work
in Progress to Deferred Charges and Other on our Condensed Consolidated Balance
Sheet. If management does not resume the project, the balance of incurred
expenditures would negatively impact future earnings unless a regulatory asset
could be established due to probable recovery through rates.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of Combined Management’s Discussion and
Analysis of Registrant Subsidiaries in the 2005 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.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management policies and procedures are instituted and administered at the AEP
Consolidated level. 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
us.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in our condensed consolidated balance sheet as of September 30, 2006
and the reasons for changes in our total MTM value as compared to December
31,
2005.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of September 30, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
66,808
|
|
$
|
5,639
|
|
$
|
-
|
|
$
|
72,447
|
|
Noncurrent
Assets
|
|
|
82,034
|
|
|
386
|
|
|
-
|
|
|
82,420
|
|
Total
MTM Derivative Contract Assets
|
|
|
148,842
|
|
|
6,025
|
|
|
-
|
|
|
154,867
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(55,074
|
)
|
|
(881
|
)
|
|
(1,425
|
)
|
|
(57,380
|
)
|
Noncurrent
Liabilities
|
|
|
(55,004
|
)
|
|
(9
|
)
|
|
(6,923
|
)
|
|
(61,936
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(110,078
|
)
|
|
(890
|
)
|
|
(8,348
|
)
|
|
(119,316
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
38,764
|
|
$
|
5,135
|
|
$
|
(8,348
|
)
|
$
|
35,551
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 in the 2005 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 2006
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
|
$
|
40,894
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
(2,331
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
173
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
(427
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
451
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
4,664
|
|
Changes
Due to SIA (c)
|
|
|
(4,984
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
324
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
38,764
|
|
Net
Cash Flow Hedge Contracts
|
|
|
5,135
|
|
DETM
Assignment (e)
|
|
|
(8,348
|
)
|
Total
MTM Risk Management Contract Net Assets at September 30, 2006
|
|
$
|
35,551
|
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek 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)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(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 liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net
Assets
The
following table presents:
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving 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, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
1,359
|
|
$
|
9,761
|
|
$
|
3,533
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
14,653
|
|
Prices
Provided by Other External Sources
- OTC Broker Quotes
(a)
|
|
|
1,850
|
|
|
6,345
|
|
|
3,856
|
|
|
5,534
|
|
|
-
|
|
|
-
|
|
|
17,585
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(38
|
)
|
|
(5,390
|
)
|
|
119
|
|
|
3,521
|
|
|
6,314
|
|
|
2,000
|
|
|
6,526
|
|
Total
|
|
$
|
3,171
|
|
$
|
10,716
|
|
$
|
7,508
|
|
$
|
9,055
|
|
$
|
6,314
|
|
$
|
2,000
|
|
$
|
38,764
|
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheet
We
are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations
on
the future cash flows from assets. We do not hedge all commodity price
risk.
We
employ
the use of 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
risk.
We
employ
forward contracts as cash flow hedges to lock-in prices on certain transactions
which have been denominated in foreign currencies where deemed necessary. 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 the changes from December 31, 2005 to September 30, 2006. 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, 2006
(in
thousands)
|
|
Power
|
|
Foreign
Currency
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(392
|
)
|
$
|
(344
|
)
|
$
|
1,491
|
|
$
|
755
|
|
Changes
in Fair Value
|
|
|
3,413
|
|
|
-
|
|
|
2,761
|
|
|
6,174
|
|
Impact
due to Change in SIA (a)
|
|
|
(337
|
)
|
|
-
|
|
|
-
|
|
|
(337
|
)
|
Reclassifications
from AOCI to Net Income for Cash Flow Hedges
Settled
|
|
|
950
|
|
|
10
|
|
|
(497
|
)
|
|
463
|
|
Ending
Balance in AOCI September 30, 2006
|
|
$
|
3,634
|
|
$
|
(334
|
)
|
$
|
3,755
|
|
$
|
7,055
|
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $4,189 thousand gain.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
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, 2006, a near term typical change
in
commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended
September
30, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$496
|
|
$1,451
|
|
$519
|
|
$276
|
|
|
|
|
$583
|
|
$968
|
|
$461
|
|
$166
|
The
High
VaR for the nine months ended September 30, 2006 occurred in the third quarter
due to volatility in the ECAR/PJM region.
VaR
Associated with Debt Outstanding
We
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The
risk
of potential loss in fair value attributable to our exposure to interest rates
primarily related to long-term debt with fixed interest rates was $103 million
and $111 million at September 30, 2006 and December 31, 2005, respectively.
We
would not expect to liquidate our entire debt portfolio in a one-year holding
period; therefore, a near term change in interest rates should not negatively
affect our results of operations or consolidated financial
position.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2006 and
2005
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
558,490
|
|
$
|
468,795
|
|
$
|
1,556,193
|
|
$
|
1,413,796
|
|
Sales
to AEP Affiliates
|
|
|
198,640
|
|
|
204,063
|
|
|
502,547
|
|
|
544,016
|
|
Other
- Affiliated
|
|
|
4,400
|
|
|
5,333
|
|
|
11,975
|
|
|
12,534
|
|
Other
- Nonaffiliated
|
|
|
3,378
|
|
|
8,949
|
|
|
12,806
|
|
|
22,947
|
|
TOTAL
|
|
|
764,908
|
|
|
687,140
|
|
|
2,083,521
|
|
|
1,993,293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
280,593
|
|
|
272,468
|
|
|
727,261
|
|
|
721,559
|
|
Purchased
Electricity for Resale
|
|
|
28,324
|
|
|
12,345
|
|
|
76,351
|
|
|
53,530
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
35,423
|
|
|
36,012
|
|
|
92,086
|
|
|
86,723
|
|
Other
Operation
|
|
|
100,274
|
|
|
93,067
|
|
|
286,107
|
|
|
238,916
|
|
Maintenance
|
|
|
44,503
|
|
|
46,481
|
|
|
163,443
|
|
|
145,435
|
|
Depreciation
and Amortization
|
|
|
82,746
|
|
|
73,799
|
|
|
239,407
|
|
|
227,687
|
|
Taxes
Other Than Income Taxes
|
|
|
47,945
|
|
|
53,531
|
|
|
143,634
|
|
|
144,671
|
|
TOTAL
|
|
|
619,808
|
|
|
587,703
|
|
|
1,728,289
|
|
|
1,618,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
145,100
|
|
|
99,437
|
|
|
355,232
|
|
|
374,772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
840
|
|
|
930
|
|
|
2,072
|
|
|
2,402
|
|
Carrying
Costs Income
|
|
|
3,502
|
|
|
8,882
|
|
|
10,336
|
|
|
38,431
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
755
|
|
|
1,952
|
|
|
1,891
|
|
|
2,684
|
|
Interest
Expense
|
|
|
(24,610
|
)
|
|
(28,416
|
)
|
|
(72,461
|
)
|
|
(80,418
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
125,587
|
|
|
82,785
|
|
|
297,070
|
|
|
337,871
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
42,245
|
|
|
26,377
|
|
|
95,297
|
|
|
110,499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
83,342
|
|
|
56,408
|
|
|
201,773
|
|
|
227,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements including Capital Stock
Expense and Other Expense
|
|
|
183
|
|
|
183
|
|
|
549
|
|
|
723
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
83,159
|
|
$
|
56,225
|
|
$
|
201,224
|
|
$
|
226,649
|
|
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
DECEMBER
31, 2004
|
|
$
|
321,201
|
|
$
|
462,485
|
|
$
|
764,416
|
|
$
|
(74,264
|
)
|
$
|
1,473,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(22,499
|
)
|
|
|
|
|
(22,499
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(549
|
)
|
|
|
|
|
(549
|
)
|
Other
|
|
|
|
|
|
4,151
|
|
|
(174
|
)
|
|
|
|
|
3,977
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,454,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $4,739
|
|
|
|
|
|
|
|
|
|
|
|
(8,802
|
)
|
|
(8,802
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
227,372
|
|
|
|
|
|
227,372
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
218,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2005
|
|
$
|
321,201
|
|
$
|
466,636
|
|
$
|
968,566
|
|
$
|
(83,066
|
)
|
$
|
1,673,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
321,201
|
|
$
|
466,637
|
|
$
|
979,354
|
|
$
|
755
|
|
$
|
1,767,947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
Contribution From Parent
|
|
|
|
|
|
70,000
|
|
|
|
|
|
|
|
|
70,000
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(549
|
)
|
|
|
|
|
(549
|
)
|
Gain
on Reacquired Preferred Stock
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
2
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,837,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $3,393
|
|
|
|
|
|
|
|
|
|
|
|
6,300
|
|
|
6,300
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
201,773
|
|
|
|
|
|
201,773
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
208,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$
|
321,201
|
|
$
|
536,639
|
|
$
|
1,180,578
|
|
$
|
7,055
|
|
$
|
2,045,473
|
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
1,325
|
|
$
|
1,240
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
107,329
|
|
|
125,404
|
|
Affiliated
Companies
|
|
|
122,993
|
|
|
167,579
|
|
Accrued
Unbilled Revenues
|
|
|
13,771
|
|
|
14,817
|
|
Miscellaneous
|
|
|
2,313
|
|
|
15,644
|
|
Allowance
for Uncollectible Accounts
|
|
|
(2,786
|
)
|
|
(1,517
|
)
|
Total Accounts Receivable
|
|
|
243,620
|
|
|
321,927
|
|
Fuel
|
|
|
115,992
|
|
|
97,600
|
|
Materials
and Supplies
|
|
|
67,920
|
|
|
60,937
|
|
Emission
Allowances
|
|
|
12,738
|
|
|
39,251
|
|
Risk
Management Assets
|
|
|
72,447
|
|
|
115,020
|
|
Accrued
Tax Benefits
|
|
|
1,463
|
|
|
39,965
|
|
Prepayments
and Other
|
|
|
19,271
|
|
|
27,439
|
|
TOTAL
|
|
|
534,776
|
|
|
703,379
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
4,388,325
|
|
|
4,278,553
|
|
Transmission
|
|
|
1,016,000
|
|
|
1,002,255
|
|
Distribution
|
|
|
1,308,532
|
|
|
1,258,518
|
|
Other
|
|
|
296,005
|
|
|
293,794
|
|
Construction
Work in Progress
|
|
|
1,121,259
|
|
|
690,168
|
|
Total
|
|
|
8,130,121
|
|
|
7,523,288
|
|
Accumulated
Depreciation and Amortization
|
|
|
2,805,417
|
|
|
2,738,899
|
|
TOTAL
- NET
|
|
|
5,324,704
|
|
|
4,784,389
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
347,457
|
|
|
398,007
|
|
Long-term
Risk Management Assets
|
|
|
82,420
|
|
|
144,015
|
|
Deferred
Charges and Other
|
|
|
276,752
|
|
|
300,880
|
|
TOTAL
|
|
|
706,629
|
|
|
842,902
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
6,566,109
|
|
$
|
6,330,670
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
September
30, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
48,163
|
|
$
|
70,071
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
250,280
|
|
|
210,752
|
|
Affiliated
Companies
|
|
|
105,916
|
|
|
147,470
|
|
Short-term
Debt - Nonaffiliated
|
|
|
7,103
|
|
|
10,366
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
12,354
|
|
|
12,354
|
|
Long-term
Debt Due Within One Year - Affiliated
|
|
|
-
|
|
|
200,000
|
|
Risk
Management Liabilities
|
|
|
57,380
|
|
|
108,797
|
|
Customer
Deposits
|
|
|
28,811
|
|
|
51,209
|
|
Accrued
Taxes
|
|
|
92,539
|
|
|
158,774
|
|
Other
|
|
|
138,777
|
|
|
147,778
|
|
TOTAL
|
|
|
741,323
|
|
|
1,117,571
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
2,186,023
|
|
|
1,787,316
|
|
Long-term
Debt - Affiliated
|
|
|
200,000
|
|
|
200,000
|
|
Long-term
Risk Management Liabilities
|
|
|
61,936
|
|
|
119,247
|
|
Deferred
Income Taxes
|
|
|
972,867
|
|
|
987,386
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
182,647
|
|
|
168,492
|
|
Deferred
Credits and Other
|
|
|
142,616
|
|
|
154,770
|
|
TOTAL
|
|
|
3,746,089
|
|
|
3,417,211
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,487,412
|
|
|
4,534,782
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
16,593
|
|
|
11,302
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
16,631
|
|
|
16,639
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - No Par Value Per Share:
|
|
|
|
|
|
|
|
Authorized
- 40,000,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 27,952,473 Shares
|
|
|
321,201
|
|
|
321,201
|
|
Paid-in
Capital
|
|
|
536,639
|
|
|
466,637
|
|
Retained
Earnings
|
|
|
1,180,578
|
|
|
979,354
|
|
Accumulated
Other Comprehensive Income
|
|
|
7,055
|
|
|
755
|
|
TOTAL
|
|
|
2,045,473
|
|
|
1,767,947
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
6,566,109
|
|
$
|
6,330,670
|
|
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
201,773
|
|
$
|
227,372
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
239,407
|
|
|
227,687
|
|
Deferred
Income Taxes
|
|
|
(18,399
|
)
|
|
11,492
|
|
Carrying
Costs Income
|
|
|
(10,336
|
)
|
|
(38,431
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
668
|
|
|
(10,841
|
)
|
Pension
Contributions to Qualified Plan Trusts
|
|
|
-
|
|
|
(60,020
|
)
|
Deferred
Property Taxes
|
|
|
54,073
|
|
|
47,803
|
|
Change
in Other Noncurrent Assets
|
|
|
7,958
|
|
|
(12,979
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
15,923
|
|
|
6,746
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
78,307
|
|
|
(54,418
|
)
|
Fuel,
Materials and Supplies
|
|
|
(25,375
|
)
|
|
(25,840
|
)
|
Accounts
Payable
|
|
|
(44,817
|
)
|
|
57,644
|
|
Accrued
Taxes, Net
|
|
|
(27,733
|
)
|
|
(114,998
|
)
|
Other
Current Assets
|
|
|
36,333
|
|
|
28,559
|
|
Other
Current Liabilities
|
|
|
(31,400
|
)
|
|
29,803
|
|
Net
Cash Flows From Operating Activities
|
|
|
476,382
|
|
|
319,579
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(715,200
|
)
|
|
(460,282
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
125,971
|
|
Other
|
|
|
5,448
|
|
|
8,896
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(709,752
|
)
|
|
(325,415
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Capital
Contributions from Parent Company
|
|
|
70,000
|
|
|
-
|
|
Issuance
of Long-term Debt - Nonaffiliated
|
|
|
405,841
|
|
|
348,237
|
|
Change
in Short-term Debt, Net - Nonaffiliated
|
|
|
(3,264
|
)
|
|
(8,133
|
)
|
Change
in Advances from Affiliates, Net
|
|
|
(21,908
|
)
|
|
55,508
|
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
(10,890
|
)
|
|
(363,890
|
)
|
Retirement
of Long-term Debt - Affiliated
|
|
|
(200,000
|
)
|
|
-
|
|
Retirement
of Preferred Stock
|
|
|
(7
|
)
|
|
(5,000
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(5,768
|
)
|
|
(5,795
|
)
|
Dividends
Paid on Common Stock
|
|
|
-
|
|
|
(22,499
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(549
|
)
|
|
(549
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
233,455
|
|
|
(2,121
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
85
|
|
|
(7,957
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,240
|
|
|
9,337
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,325
|
|
$
|
1,380
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
71,666
|
|
$
|
92,073
|
|
Net
Cash Paid for Income Taxes
|
|
|
72,175
|
|
|
158,627
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
2,529
|
|
|
7,591
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
117,638
|
|
|
73,895
|
|
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 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
|
Note
2
|
Rate
Matters
|
Note
3
|
Customer
Choice and Industry Restructuring
|
Note
4
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Allocation
Agreement between AEP East companies and AEP West
companies
The
SIA
provides, among other things, for the methodology of sharing trading and
marketing margins between the AEP East companies and AEP West companies. In
March 2006, the FERC approved AEP’s proposed methodology to be used effective
April 1, 2006 and beyond. The approved allocation methodology is based upon
the
location of the specific trading and marketing activity, with margins resulting
from trading and marketing activities originating in PJM and MISO generally
accruing to the benefit of the AEP East companies and trading and marketing
activities originating in SPP and ERCOT generally accruing to the benefit of
SWEPCo and us. Previously, the SIA allocation provided for a different method
of
sharing all such margins between both AEP East companies and AEP West companies.
The impact on future results of operations, financial condition and cash flows
will depend upon the level of future margins and risk management activity by
region.
Results
of Operations
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006 Net
Income
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
49
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
(2
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(3
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(8
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(1
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
6
|
|
|
|
|
Interest
Expense
|
|
|
(2
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
42
|
|
Net
Income decreased $7 million to $42 million in 2006. The key drivers of the
decrease were a $5 million decrease in Gross Margin and a $5 million increase
in
Operating Expenses and Other, partially offset by a $3 million decrease in
Income Tax Expense.
The
major
components of our 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 $2 million primarily due to
a $4
million decrease in retail margins resulting from lower sales to
industrial customers due to the price mix and an increase in
non-recoverable fuel items including an accrual for an unfavorable
FERC
ruling on an SPP Reactive Power dispute with Calpine, partially offset
by
an increase in Distribution Vegetation Management (DVM) recovery.
The
decrease in retail margins was partially offset by a $2 million increase
in off-system sales margins, comprised of a $16 million increase
in
margins from optimization activities partially offset by a $14 million
decrease primarily related to lower sharing of off-system sales margins
under the SIA. See the “Allocation Agreement between AEP East companies
and AEP West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Transmission
Revenues decreased $3 million due to lower point-to-point transmission
services within SPP.
|
Operating
Expenses and Other increased between years as follows:
·
|
Other
Operation and Maintenance expenses increased $8 million due to a
$6
million increase in distribution maintenance primarily related to
increased DVM expenses.
|
·
|
Taxes
Other Than Income Taxes decreased $6 million due to an adjustment
to the
provision for state sales and use
tax.
|
Income
Taxes
The
$3
million decrease in Income Tax Expense is primarily due to the decrease in
pretax book income.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine Months Ended September 30, 2005 to
Nine
Months Ended September 30, 2006 Net Income
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
68
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
12
|
|
|
|
|
Transmission
Revenues
|
|
|
(1
|
)
|
|
|
|
Other
|
|
|
3
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(35
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
1
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
2
|
|
|
|
|
Interest
Expense
|
|
|
(5
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
51
|
|
Net
Income decreased $17 million to $51 million in 2006. The key driver of the
decrease was a $37 million increase in Operating Expenses and Other, partially
offset by a $14 million increase in Gross Margin and a $6 million decrease
in
Income Tax Expense.
The
major
components of our 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 $12 million primarily due
to a $20
million increase in retail margins resulting from a 29% increase
in
cooling degree days and an increase in DVM recovery, partially offset
by
an increase in non-recoverable fuel items including an accrual for
an
unfavorable FERC ruling on an SPP Reactive Power dispute with Calpine.
The
increase in retail margins was partially offset by an $8 million
decrease
in off-system sales margins comprised of a $17 million decrease primarily
related to lower sharing of off-system sales margins under the SIA,
partially offset by a $9 million increase in margins from optimization
activities. See the “Allocation Agreement between AEP East companies and
AEP West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Other
revenue increased $3 million partially due to a 2006 settlement received
from an electric cooperative.
|
Operating
Expenses and Other increased between years as follows:
·
|
Other
Operation and Maintenance expenses increased $35 million due to a
$15
million increase in distribution maintenance primarily related to
increased DVM expenses, a $7 million increase in forced and scheduled
power plant maintenance, a $6 million increase in administration
and
general expenses, mostly related to increased pension and other
postemployment benefits expense, a $5 million increase in expenses
related
to the factoring of accounts receivable and a $4 million increase
in
expenses related to power plant operations.
|
·
|
Interest
Expense increased $5 million primarily due to increased affiliated
short-term borrowings during the period and the issuance of long-term
debt
in 2006.
|
Income
Taxes
The
$6
million decrease in Income Tax Expense is primarily due to the decrease in
pretax book income, offset in part by tax reserve adjustments.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Current ratings are as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
Baa1
|
|
BBB
|
|
A-
|
Financing
Activity
Long-term
debt issuances and retirements during the first nine months of 2006
were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Senior
Unsecured Notes
|
|
$
|
150,000
|
|
6.15
|
|
2016
|
Retirements
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Notes
Payable - Affiliated
|
|
$
|
50,000
|
|
3.35
|
|
2006
|
Liquidity
We
have
solid investment grade ratings, which provide us ready access to capital markets
in order to issue new debt or refinance long-term debt maturities. In addition,
we participate in the Utility Money Pool, which provides access to AEP’s
liquidity.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end except for Energy and Capacity Purchase
Contracts. We increased our future obligation in Energy and Capacity Purchase
Contracts applicable to our optimization and off-system sales activities by
approximately $10 million annually due to changes within the SIA and CSW
Operating Agreement. See “Allocation Agreement between AEP East companies and
AEP West companies and CSW Operating Agreement” section of Note 3.
Significant
Factors
Litigation
and Regulatory Activity
In
the
ordinary course of business, we 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 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 our
pending litigation and regulatory proceedings, see Note 4 - Rate Matters and
Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see
Note
3 - Rate Matters and Note 5 - Commitments and Contingencies in the “Condensed
Notes to Condensed Financial Statements of Registrant Subsidiaries” section.
Adverse results in these proceedings have the potential to materially affect
our
results of operations, financial condition and cash flows.
New
Generation
In
September 2005, we sought proposals for new peaking generation to be online
in
2008 and in December 2005 we sought proposals for base load generation to
be
online in 2011. We received proposals and evaluated those proposals meeting
the
Request for Proposal criteria with oversight from neutral third parties.
In
March 2006, we announced plans to add 170 MW of peaking generation to our
Riverside Station plant in Jenks, Oklahoma where we will construct and operate
two 85 MW simple-cycle natural gas combustion turbines. Also in March 2006,
we
announced plans to add 170 MW of peaking generation to our Southwestern Station
plant in Anadarko, Oklahoma where we will construct and operate two 85 MW
simple-cycle natural gas combustion turbines. Combined preliminary cost
estimates for these additions are approximately $120 million. In July 2006,
we
announced plans to enter a joint venture with Oklahoma Gas and Electric Company
(OG&E) where OG&E will construct and operate a new 950 MW coal-fueled
electricity generating unit near Red Rock, Oklahoma. We will own 50% of the
new
unit. Preliminary cost estimates for 100% of the new facility are approximately
$1.8 billion. The 2006 through 2008 estimated construction expenditures as
disclosed in our 2005 Form 10-K included cost estimates for the peaking
additions and the base load facility. These new facilities are subject to
regulatory approval from the OCC. We expect to begin construction on all
of
these additions in 2007.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2005 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension benefits and the impact
of new accounting pronouncements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management policies and procedures are instituted and administered at the AEP
Consolidated level. 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
us.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in our condensed balance sheet as of September 30, 2006 and the reasons
for changes in our total MTM value as compared to December 31,
2005.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Balance Sheet
As
of September 30, 2006
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
DETM
Assignment
(a)
|
|
Total
|
|
Current
Assets
|
|
$
|
71,635
|
|
$
|
-
|
|
$
|
-
|
|
$
|
71,635
|
|
Noncurrent
Assets
|
|
|
32,354
|
|
|
-
|
|
|
-
|
|
|
32,354
|
|
Total
MTM Derivative Contract Assets
|
|
|
103,989
|
|
|
-
|
|
|
-
|
|
|
103,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(75,244
|
)
|
|
-
|
|
|
(96
|
)
|
|
(75,340
|
)
|
Noncurrent
Liabilities
|
|
|
(22,869
|
)
|
|
-
|
|
|
(467
|
)
|
|
(23,336
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(98,113
|
)
|
|
-
|
|
|
(563
|
)
|
|
(98,676
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
|
|
$
|
5,876
|
|
$
|
-
|
|
$
|
(563
|
)
|
$
|
5,313
|
|
(a)
|
Starting
in the third quarter of 2006, we were allocated a portion of the
DETM
assignment based on the FERC- approved methodology of AEP recording
trading and marketing margins shared between the AEP East and AEP
West
companies. See “Natural Gas Contracts with DETM” section of Note 17 of the
2005 Annual Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 2006
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
|
$
|
14,214
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
817
|
|
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
|
|
|
(386
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
148
|
|
Changes
Due to SIA and CSW Operating Agreement (c)
|
|
|
10,185
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
(19,102
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
5,876
|
|
Net
Cash Flow Hedge Contracts
|
|
|
-
|
|
DETM
Assignment (e)
|
|
|
(563
|
)
|
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
|
$
|
5,313
|
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek 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)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(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 Operations. These net gains (losses) are recorded as
regulatory liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
(e)
|
Starting
in the third quarter of 2006, we were allocated a portion of the
DETM
assignment based on the FERC- approved methodology of AEP recording
trading margins shared between the AEP East and AEP West companies.
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net
Assets
The
following table presents:
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving 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, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
(3,194
|
)
|
$
|
(21,390
|
)
|
$
|
3,101
|
|
$
|
(383
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
(21,866
|
)
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
(6,056
|
)
|
|
27,924
|
|
|
5,533
|
|
|
(490
|
)
|
|
-
|
|
|
-
|
|
|
26,911
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(143
|
)
|
|
(216
|
)
|
|
(131
|
)
|
|
1,313
|
|
|
42
|
|
|
(34
|
)
|
|
831
|
|
Total
|
|
$
|
(9,393
|
)
|
$
|
6,318
|
|
$
|
8,503
|
|
$
|
440
|
|
$
|
42
|
|
$
|
(34
|
)
|
$
|
5,876
|
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Balance Sheet
We
are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations
on
the future cash flows from assets. We do not hedge all commodity price
risk.
We
employ
the use of 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
risk.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on our Condensed Balance Sheets and the reasons for the changes
from December 31, 2005 to September 30, 2006. 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, 2006
(in
thousands)
|
|
Power
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(629
|
)
|
$
|
(483
|
)
|
$
|
(1,112
|
)
|
Changes
in Fair Value
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Impact
Due to Change in SIA (a)
|
|
|
506
|
|
|
-
|
|
|
506
|
|
Reclassifications
from AOCI to Net Income for Cash
Flow Hedges Settled
|
|
|
123
|
|
|
(633
|
)
|
|
(510
|
)
|
Ending
Balance in AOCI September 30, 2006
|
|
$
|
-
|
|
$
|
(1,116
|
)
|
$
|
(1,116
|
)
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $183 thousand loss.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
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, 2006, a near term typical change
in
commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended
September
30, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$1,175
|
|
$1,786
|
|
$647
|
|
$58
|
|
|
|
|
$311
|
|
$517
|
|
$246
|
|
$89
|
The
High
VaR for the nine months ended September 30, 2006 occurred in the third quarter
due to volatility in the ERCOT region.
VaR
Associated with Debt Outstanding
We
also
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The risk of potential loss in fair value
attributable to our exposure to interest rates primarily related to long-term
debt with fixed interest rates was $36 million and $34 million at September
30,
2006 and December 31, 2005, respectively. We would not expect to liquidate
our
entire debt portfolio in a one-year holding period; therefore, a near term
change in interest rates should not negatively affect our results of operations
or financial position.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2006 and
2005
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
443,593
|
|
$
|
415,558
|
|
$
|
1,116,507
|
|
$
|
937,985
|
|
Sales
to AEP Affiliates
|
|
|
14,034
|
|
|
16,032
|
|
|
40,647
|
|
|
32,314
|
|
Other
|
|
|
814
|
|
|
1,043
|
|
|
3,062
|
|
|
2,018
|
|
TOTAL
|
|
|
458,441
|
|
|
432,633
|
|
|
1,160,216
|
|
|
972,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
202,836
|
|
|
192,968
|
|
|
566,985
|
|
|
456,690
|
|
Purchased
Electricity for Resale
|
|
|
68,547
|
|
|
39,186
|
|
|
158,122
|
|
|
84,111
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
17,706
|
|
|
26,643
|
|
|
54,817
|
|
|
64,877
|
|
Other
Operation
|
|
|
40,756
|
|
|
40,029
|
|
|
117,721
|
|
|
107,168
|
|
Maintenance
|
|
|
25,072
|
|
|
17,809
|
|
|
67,412
|
|
|
43,321
|
|
Depreciation
and Amortization
|
|
|
22,103
|
|
|
20,842
|
|
|
64,724
|
|
|
65,708
|
|
Taxes
Other Than Income Taxes
|
|
|
3,844
|
|
|
9,769
|
|
|
23,997
|
|
|
25,507
|
|
TOTAL
|
|
|
380,864
|
|
|
347,246
|
|
|
1,053,778
|
|
|
847,382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
77,577
|
|
|
85,387
|
|
|
106,438
|
|
|
124,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
828
|
|
|
658
|
|
|
1,734
|
|
|
729
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
222
|
|
|
206
|
|
|
96
|
|
|
542
|
|
Interest
Expense
|
|
|
(10,954
|
)
|
|
(8,677
|
)
|
|
(29,723
|
)
|
|
(25,173
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
67,673
|
|
|
77,574
|
|
|
78,545
|
|
|
101,033
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
25,650
|
|
|
28,920
|
|
|
27,241
|
|
|
33,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
42,023
|
|
|
48,654
|
|
|
51,304
|
|
|
67,729
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
53
|
|
|
53
|
|
|
159
|
|
|
159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
41,970
|
|
$
|
48,601
|
|
$
|
51,145
|
|
$
|
67,570
|
|
The common stock of PSO is owned by a wholly-owned subsidiary of
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
DECEMBER
31, 2004
|
|
$
|
157,230
|
|
$
|
230,016
|
|
$
|
141,935
|
|
$
|
75
|
|
$
|
529,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(27,000
|
)
|
|
|
|
|
(27,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(159
|
)
|
|
|
|
|
(159
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
502,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,581
|
|
|
|
|
|
|
|
|
|
|
|
(4,794
|
)
|
|
(4,794
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
67,729
|
|
|
|
|
|
67,729
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2005
|
|
$
|
157,230
|
|
$
|
230,016
|
|
$
|
182,505
|
|
$
|
(4,719
|
)
|
$
|
565,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
157,230
|
|
$
|
230,016
|
|
$
|
162,615
|
|
$
|
(1,264
|
)
|
$
|
548,597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(159
|
)
|
|
|
|
|
(159
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
548,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
(4
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
51,304
|
|
|
|
|
|
51,304
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$
|
157,230
|
|
$
|
230,016
|
|
$
|
213,760
|
|
$
|
(1,268
|
)
|
$
|
599,738
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
2,277
|
|
$
|
1,520
|
|
Advances
to Affiliates
|
|
|
43,538
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
59,153
|
|
|
37,740
|
|
Affiliated
Companies
|
|
|
54,535
|
|
|
73,321
|
|
Miscellaneous
|
|
|
10,105
|
|
|
10,501
|
|
Allowance
for Uncollectible Accounts
|
|
|
(82
|
)
|
|
(240
|
)
|
Total Accounts Receivable
|
|
|
123,711
|
|
|
121,322
|
|
Fuel
|
|
|
15,301
|
|
|
16,431
|
|
Materials
and Supplies
|
|
|
46,665
|
|
|
38,545
|
|
Risk
Management Assets
|
|
|
71,635
|
|
|
40,383
|
|
Accrued
Tax Benefits
|
|
|
61
|
|
|
11,972
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
31,794
|
|
|
108,732
|
|
Margin
Deposits
|
|
|
35,862
|
|
|
10,051
|
|
Prepayments
and Other
|
|
|
8,058
|
|
|
4,236
|
|
TOTAL
|
|
|
378,902
|
|
|
353,192
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
1,083,390
|
|
|
1,072,928
|
|
Transmission
|
|
|
499,175
|
|
|
479,272
|
|
Distribution
|
|
|
1,196,071
|
|
|
1,140,535
|
|
Other
|
|
|
239,625
|
|
|
211,805
|
|
Construction
Work in Progress
|
|
|
82,724
|
|
|
90,455
|
|
Total
|
|
|
3,100,985
|
|
|
2,994,995
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,192,825
|
|
|
1,175,858
|
|
TOTAL
- NET
|
|
|
1,908,160
|
|
|
1,819,137
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
76,543
|
|
|
50,723
|
|
Long-term
Risk Management Assets
|
|
|
32,354
|
|
|
33,566
|
|
Employee
Benefits and Pension Assets
|
|
|
79,701
|
|
|
82,559
|
|
Deferred
Charges and Other
|
|
|
22,372
|
|
|
16,287
|
|
TOTAL
|
|
|
210,970
|
|
|
183,135
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
2,498,032
|
|
$
|
2,355,464
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
September
30, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
-
|
|
$
|
75,883
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
130,260
|
|
|
130,627
|
|
Affiliated
Companies
|
|
|
89,834
|
|
|
89,786
|
|
Long-term
Debt Due Within One Year - Affiliated
|
|
|
-
|
|
|
50,000
|
|
Risk
Management Liabilities
|
|
|
75,340
|
|
|
38,243
|
|
Customer
Deposits
|
|
|
51,107
|
|
|
53,844
|
|
Accrued
Taxes
|
|
|
59,354
|
|
|
22,420
|
|
Other
|
|
|
37,793
|
|
|
51,548
|
|
TOTAL
|
|
|
443,688
|
|
|
512,351
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
669,953
|
|
|
521,071
|
|
Long-term
Risk Management Liabilities
|
|
|
23,336
|
|
|
22,582
|
|
Deferred
Income Taxes
|
|
|
418,846
|
|
|
436,382
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
309,818
|
|
|
284,640
|
|
Deferred
Credits and Other
|
|
|
27,391
|
|
|
24,579
|
|
TOTAL
|
|
|
1,449,344
|
|
|
1,289,254
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
1,893,032
|
|
|
1,801,605
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
5,262
|
|
|
5,262
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
230,016
|
|
|
230,016
|
|
Retained
Earnings
|
|
|
213,760
|
|
|
162,615
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(1,268
|
)
|
|
(1,264
|
)
|
TOTAL
|
|
|
599,738
|
|
|
548,597
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
2,498,032
|
|
$
|
2,355,464
|
|
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
51,304
|
|
$
|
67,729
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
64,724
|
|
|
65,708
|
|
Deferred
Income Taxes
|
|
|
(18,661
|
)
|
|
32,661
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
8,901
|
|
|
(2,954
|
)
|
Deferred
Property Taxes
|
|
|
(8,098
|
)
|
|
(8,123
|
)
|
Change
in Other Noncurrent Assets
|
|
|
18,186
|
|
|
(34,576
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
(24,838
|
)
|
|
26,798
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(2,389
|
)
|
|
(1,687
|
)
|
Fuel,
Materials and Supplies
|
|
|
(6,990
|
)
|
|
(3,873
|
)
|
Margin
Deposits
|
|
|
(25,811
|
)
|
|
(16,121
|
)
|
Accounts
Payable
|
|
|
1,585
|
|
|
69,794
|
|
Customer
Deposits
|
|
|
(2,737
|
)
|
|
24,404
|
|
Accrued
Taxes, Net
|
|
|
48,845
|
|
|
480
|
|
Over/Under
Fuel Recovery
|
|
|
76,938
|
|
|
(81,808
|
)
|
Other
Current Assets
|
|
|
(3,828
|
)
|
|
(7,253
|
)
|
Other
Current Liabilities
|
|
|
(13,755
|
)
|
|
(6,099
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
163,376
|
|
|
125,080
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(140,998
|
)
|
|
(87,804
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
6
|
|
|
(6
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
(43,538
|
)
|
|
-
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(184,530
|
)
|
|
(87,810
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt - Nonaffiliated
|
|
|
148,747
|
|
|
74,405
|
|
Change
in Advances from Affiliates, Net
|
|
|
(75,883
|
)
|
|
(32,401
|
)
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
-
|
|
|
(50,000
|
)
|
Retirement
of Long-term Debt - Affiliated
|
|
|
(50,000
|
)
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(794
|
)
|
|
(483
|
)
|
Dividends
Paid on Common Stock
|
|
|
-
|
|
|
(27,000
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(159
|
)
|
|
(159
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
21,911
|
|
|
(35,638
|
)
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
757
|
|
|
1,632
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,520
|
|
|
279
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
2,277
|
|
$
|
1,911
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
25,491
|
|
$
|
21,954
|
|
Net
Cash Paid for Income Taxes
|
|
|
7,471
|
|
|
14,241
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
2,639
|
|
|
798
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
6,591
|
|
|
3,482
|
|
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
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Income
Taxes
|
Note
10
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Allocation
Agreement between AEP East companies and AEP West
companies
The
SIA
provides, among other things, for the methodology of sharing trading and
marketing margins between the AEP East companies and AEP West companies. In
March 2006, the FERC approved AEP’s proposed methodology to be used effective
April 1, 2006 and beyond. The approved allocation methodology is based upon
the
location of the specific trading and marketing activity, with margins resulting
from trading and marketing activities originating in PJM and MISO generally
accruing to the benefit of the AEP East companies and trading and marketing
activities originating in SPP and ERCOT generally accruing to the benefit of
PSO
and us. Previously, the SIA allocation provided for a different method of
sharing all such margins between both AEP East companies and AEP West companies.
The impact on future results of operations, financial condition and cash flows
will depend upon the level of future margins and risk management activities
by
region and the status of cost recovery mechanisms by state.
Results
of Operations
Third
Quarter of 2006 Compared to Third Quarter of 2005
Reconciliation
of Third Quarter of 2005 to Third Quarter of 2006 Net
Income
(in
millions)
Third
Quarter of 2005
|
|
|
|
|
$
|
50
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
(9
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(1
|
)
|
|
|
|
Other
|
|
|
6
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
6
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
1
|
|
|
|
|
Interest
Expense
|
|
|
(1
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
Third
Quarter of 2006
|
|
|
|
|
$
|
50
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income remained flat in the third quarter of 2006 compared to the third quarter
of 2005.
The
major
components of our 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 $9 million primarily due to
a $4
million non-recoverable accrual for an unfavorable FERC ruling on
an SPP
Reactive Power Contract with Calpine as well as an $8 million decrease
in
off-system sales margins primarily due to lower sharing of off-system
sales margins under the SIA. Partially offsetting these decreases
was a $3
million increase in wholesale revenues due to higher usage and favorable
prices. See the “Allocation Agreement between AEP East companies and AEP
West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Other
revenues increased $6 million primarily due to gains on sales of
emission
allowances.
|
Operating
Expenses and Other decreased between years as follows:
·
|
Other
Operation and Maintenance decreased $6 million primarily due to a
$3
million decrease in transmission operation expense resulting from
favorable changes to the SPP fee structure as well as a $3 million
decrease in overhead line maintenance expense primarily related to
the
absence of 2005 hurricane-related
expenses.
|
Income
Taxes
The
$2
million increase in Income Tax Expense is primarily due to the increase in
pretax book income and state income taxes.
Nine
Months Ended September 30, 2006 Compared to Nine Months Ended September 30,
2005
Reconciliation
of Nine Months Ended September 30, 2005 to
Nine
Months Ended September 30, 2006 Net Income
(in
millions)
Nine
Months Ended September 30, 2005
|
|
|
|
|
$
|
81
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
15
|
|
|
|
|
Transmission
Revenues
|
|
|
1
|
|
|
|
|
Other
|
|
|
22
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
38
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(8
|
)
|
|
|
|
Interest
Expense
|
|
|
(2
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
$
|
96
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income increased $15 million to $96 million in 2006. The key driver of the
increase was a $38 million increase in Gross Margin, partially offset by a
$10
million increase in Operating Expenses and Other and a $13 million increase
in
Income Tax Expense.
The
major
components of our 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 $15 million primarily due
to a $17
million increase in wholesale margins resulting from higher prices,
increased usage and new wholesale contracts, as well as a $15 million
increase primarily due to increased wholesale fuel recovery. These
increases were partially offset by a $17 million decrease in off-system
sales margins primarily due to lower sharing of off-system sales
margins
under the SIA. See the “Allocation Agreement between AEP East companies
and AEP West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Other
revenues increased $22 million primarily due to gains on sales of
emission
allowances.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $8 million primarily
due to a
$5 million increase in employee-related expenses, a $3 million increase
in
mining operations expense resulting from increased production and
a $2
million increase in expenses related to the factoring of customer
accounts
receivable, offset by the absence of $4 million of 2005 hurricane-related
expenses.
|
Income
Taxes
The
$13
million increase in Income Tax Expense is primarily due to the increase in
pretax book income and state income taxes.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Current ratings are as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
First
Mortgage Bonds
|
A3
|
|
A-
|
|
A
|
Senior
Unsecured Debt
|
Baa1
|
|
BBB
|
|
A-
|
Cash
Flow
Cash
flows for the nine months ended September 30, 2006 and 2005 were as
follows:
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
3,049
|
|
$
|
3,715
|
|
Net
Cash Flows From (Used For):
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
242,721
|
|
|
163,705
|
|
Investing
Activities
|
|
|
(186,631
|
)
|
|
(67,857
|
)
|
Financing
Activities
|
|
|
(56,343
|
)
|
|
(95,759
|
)
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(253
|
)
|
|
89
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
2,796
|
|
$
|
3,804
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $243 million in 2006. We produced Net
Income of $96 million during the period and noncash expense items of $98 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 $54 million inflow from
Accounts Payable was the result of higher energy purchases. The
$28
million outflow for Margin Deposits was due to increased trading-related
deposits resulting from the amended SIA. In
addition, our $64 million inflow related to Over/Under Fuel Recovery was
primarily due to the new fuel surcharges effective December 2005 in our Arkansas
service territory and in January 2006 in our Texas service territory.
The
$27
million outflow from Fuel, Materials and Supplies was the result of increased
fuel purchases.
Net
Cash
Flows From Operating Activities were $164 million in 2005. We produced Net
Income of $81 million during the period and noncash expense items of $99 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 $42 million
inflow from Accounts Payable was due to higher vendor-related payables and
increased energy transactions. The $66 million outflow related to Over/Under
Fuel Recovery was due to our increasing cumulative under-recovery of rising
fuel
costs.
Investing
Activities
Cash
Flows Used For Investing Activities during 2006 and 2005 were $187 million
and
$68 million, respectively. The cash flows during 2006 were comprised primarily
of Construction Expenditures related to projects for improved transmission
and
distribution service reliability as well as projects related to generation
facilities. For the remainder of 2006, we expect $140 million in Construction
Expenditures. During 2005, Construction Expenditures were $110 million, also
comprised primarily of spending for transmission and distribution service
reliability. Additionally, we decreased our Advances to Affiliates by $39
million.
Financing
Activities
Cash
Flows Used For Financing Activities were $56 million during 2006. We refinanced
$82 million of Pollution Control Bonds. Long-term debt retirements were $89
million. In addition, we repaid $28 million to the Utility Money Pool. We also
paid $30 million in Common Stock Dividends.
Cash
Flows Used For Financing Activities were $96 million during 2005. We issued
$150
million of Senior Unsecured Notes for the purpose of funding the July 2005
maturity of our $200 million of Senior Unsecured Notes. We paid $40 million
in
Common Stock Dividends.
Financing
Activity
Long-term
debt issuances, retirements and principal payments during the first nine months
of 2006 were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Pollution
Control Bonds
|
|
$
|
81,700
|
|
Variable
|
|
2018
|
Retirements
and Principal Payments
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Notes
Payable
|
|
$
|
5,039
|
|
4.47
|
|
2011
|
Notes
Payable
|
|
|
2,250
|
|
Variable
|
|
2008
|
Pollution
Control Bonds
|
|
|
81,700
|
|
6.10
|
|
2018
|
Liquidity
We
have
solid investment grade ratings, which provide us ready access to capital markets
in order to issue new debt and refinance short-term or long-term debt
maturities. In addition, we participate in the Utility Money Pool, which
provides access to AEP’s liquidity.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2005 Annual Report and has
not
changed significantly from year-end except for Energy and Capacity Purchase
Contracts. We increased our future obligation in Energy and Capacity Purchase
Contracts applicable to our optimization and off-system sales activities by
approximately $10 million annually due to changes within the SIA and CSW
Operating Agreement. See “Allocation Agreement between AEP East companies and
AEP West companies and CSW Operating Agreement” section of Note 3.
Significant
Factors
Litigation
and Regulatory Activity
In
the
ordinary course of business, we 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 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 our
pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note
6
- Customer Choice and Industry Restructuring and Note 7 - Commitments and
Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note
4
- Customer Choice and Industry Restructuring and Note 5 - Commitments and
Contingencies in the “Condensed Notes to Condensed Financial Statements of
Registrant Subsidiaries” section. Adverse results in these proceedings have the
potential to materially affect our results of operations, financial condition
and cash flows.
New
Generation
In
December 2005, we sought proposals for new peaking, intermediate and base load
generation to be online between 2008 and 2011. In May 2006, we announced plans
to construct new generation to satisfy the demands of our customers. We will
build up to 480 MW of simple-cycle natural gas combustion turbine peaking
generation in Tontitown, Arkansas and will build a 480 MW combined-cycle natural
gas fired plant at our existing Arsenal Hill Power Plant in Shreveport,
Louisiana. We also plan to build a new 600 MW base load coal plant in Hempstead
County, Arkansas by 2011 to meet the longer-term generation needs of our
customers. Preliminary cost estimates for the new facilities are approximately
$1.4 billion (this total excludes the related transmission investment). The
2006
through 2008 estimated construction expenditures as disclosed in our 2005 Form
10-K included cost estimates for these new facilities. These new facilities
are
subject to regulatory approvals from our three state commissions. Construction
is expected to begin in 2007.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2005 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.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management policies and procedures are instituted and administered at the AEP
Consolidated level. 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
us.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in our condensed consolidated balance sheet as of September 30, 2006
and the reasons for changes in our total MTM value as compared to December
31,
2005.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of September 30, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
DETM
Assignment
(a)
|
|
Total
|
|
Current
Assets
|
|
$
|
84,685
|
|
$
|
-
|
|
$
|
-
|
|
$
|
84,685
|
|
Noncurrent
Assets
|
|
|
38,252
|
|
|
-
|
|
|
-
|
|
|
38,252
|
|
Total
MTM Derivative Contract Assets
|
|
|
122,937
|
|
|
-
|
|
|
-
|
|
|
122,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(89,430
|
)
|
|
(4,097
|
)
|
|
(114
|
)
|
|
(93,641
|
)
|
Noncurrent
Liabilities
|
|
|
(27,326
|
)
|
|
(28
|
)
|
|
(550
|
)
|
|
(27,904
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(116,756
|
)
|
|
(4,125
|
)
|
|
(664
|
)
|
|
(121,545
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$
|
6,181
|
|
$
|
(4,125
|
)
|
|
(664
|
)
|
$
|
1,392
|
|
(a)
|
Starting
in the third quarter of 2006, we were allocated a portion of the
DETM
assignment based on the FERC- approved methodology of AEP recording
trading and marketing margins shared between the AEP East and AEP
West
companies. See “Natural Gas Contracts with DETM” section of Note 17 of the
2005 Annual Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 2006
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
|
$
|
16,387
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
655
|
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
52
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
(452
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
139
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(7,302
|
)
|
Changes
Due to SIA and CSW Operating Agreement (c)
|
|
|
11,900
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
|
|
(15,198
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
6,181
|
|
Net
Cash Flow Hedge Contracts
|
|
|
(4,125
|
)
|
DETM
Assignment (e)
|
|
|
(664
|
)
|
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
|
$
|
1,392
|
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek 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)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(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 liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
(e)
|
Starting
in the third quarter of 2006, we were allocated a portion of the
DETM
assignment based on the FERC- approved methodology of AEP recording
trading and marketing margins shared between the AEP East and AEP
West
companies. See “Natural Gas Contracts with DETM” section of Note 17 of the
2005 Annual Report.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net
Assets
The
following table presents:
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving 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, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
(3,762
|
)
|
$
|
(25,203
|
)
|
$
|
3,654
|
|
$
|
(451
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
(25,762
|
)
|
Prices
Provided by Other External Sources
- OTC Broker Quotes
(a)
|
|
|
(7,187
|
)
|
|
32,724
|
|
|
6,546
|
|
|
(577
|
)
|
|
-
|
|
|
-
|
|
|
31,506
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(173
|
)
|
|
(636
|
)
|
|
(310
|
)
|
|
1,546
|
|
|
50
|
|
|
(40
|
)
|
|
437
|
|
Total
|
|
$
|
(11,122
|
)
|
$
|
6,885
|
|
$
|
9,890
|
|
$
|
518
|
|
$
|
50
|
|
$
|
(40
|
)
|
$
|
6,181
|
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheet
We
are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may employ
various commodity instruments to mitigate the impact of these fluctuations
on
the future cash flows from assets. We do not hedge all commodity price
risk.
We
employ
the use of 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
risk.
We
employ
forward contracts and collars as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. 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 the changes from December 31, 2005 to September 30, 2006. 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, 2006
(in
thousands)
|
|
Power
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(736
|
)
|
$
|
(5,116
|
)
|
$
|
(5,852
|
)
|
Changes
in Fair Value
|
|
|
-
|
|
|
(2,655
|
)
|
|
(2,655
|
)
|
Impact
due to Change in SIA (a)
|
|
|
591
|
|
|
-
|
|
|
591
|
|
Reclassifications
from AOCI to Net Income for Cash
Flow Hedges Settled
|
|
|
145
|
|
|
403
|
|
|
548
|
|
Ending
Balance in AOCI September 30, 2006
|
|
$
|
-
|
|
$
|
(7,368
|
)
|
$
|
(7,368
|
)
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $727 thousand loss.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
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, 2006, a near term typical change
in
commodity prices is not expected to have a material effect on our results of
operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended
September
30, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$1,385
|
|
$2,104
|
|
$758
|
|
$68
|
|
|
|
|
$363
|
|
$604
|
|
$287
|
|
$104
|
The
High
VaR for the nine months ended September 30, 2006 occurred in the third quarter
due to volatility in the ERCOT region.
VaR
Associated with Debt Outstanding
We
also
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The risk of potential loss in fair value
attributable to our exposure to interest rates primarily related to long-term
debt with fixed interest rates was $21 million and $31 million at September
30,
2006 and December 31, 2005, respectively. We would not expect to liquidate
our
entire debt portfolio in a one-year holding period; therefore, a near term
change in interest rates should not negatively affect our results of operations
or consolidated financial position.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2006 and
2005
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
440,542
|
|
$
|
459,220
|
|
$
|
1,084,185
|
|
$
|
1,015,074
|
|
Sales
to AEP Affiliates
|
|
|
14,692
|
|
|
14,614
|
|
|
34,871
|
|
|
38,573
|
|
Other
|
|
|
1,466
|
|
|
449
|
|
|
2,260
|
|
|
698
|
|
TOTAL
|
|
|
456,700
|
|
|
474,283
|
|
|
1,121,316
|
|
|
1,054,345
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
158,992
|
|
|
179,904
|
|
|
367,924
|
|
|
386,719
|
|
Purchased
Electricity for Resale
|
|
|
61,816
|
|
|
45,194
|
|
|
135,918
|
|
|
91,377
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
18,140
|
|
|
27,363
|
|
|
58,303
|
|
|
55,230
|
|
Other
Operation
|
|
|
55,256
|
|
|
60,229
|
|
|
158,338
|
|
|
152,340
|
|
Maintenance
|
|
|
21,120
|
|
|
22,353
|
|
|
68,008
|
|
|
65,713
|
|
Depreciation
and Amortization
|
|
|
32,996
|
|
|
32,930
|
|
|
98,406
|
|
|
98,580
|
|
Taxes
Other Than Income Taxes
|
|
|
17,107
|
|
|
18,175
|
|
|
49,254
|
|
|
49,725
|
|
TOTAL
|
|
|
365,427
|
|
|
386,148
|
|
|
936,151
|
|
|
899,684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
91,273
|
|
|
88,135
|
|
|
185,165
|
|
|
154,661
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
822
|
|
|
250
|
|
|
2,277
|
|
|
1,167
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
287
|
|
|
516
|
|
|
400
|
|
|
1,849
|
|
Interest
Expense
|
|
|
(13,844
|
)
|
|
(12,346
|
)
|
|
(40,688
|
)
|
|
(38,027
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES AND MINORITY
INTEREST
EXPENSE
|
|
|
78,538
|
|
|
76,555
|
|
|
147,154
|
|
|
119,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
27,873
|
|
|
25,789
|
|
|
49,187
|
|
|
35,675
|
|
Minority
Interest Expense
|
|
|
959
|
|
|
1,035
|
|
|
2,077
|
|
|
2,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
49,706
|
|
|
49,731
|
|
|
95,890
|
|
|
81,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
57
|
|
|
57
|
|
|
172
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
49,649
|
|
$
|
49,674
|
|
$
|
95,718
|
|
$
|
81,068
|
|
The
common stock of SWEPCo is owned by a wholly-owned subsidiary of
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
DECEMBER
31, 2004
|
|
$
|
135,660
|
|
$
|
245,003
|
|
$
|
389,135
|
|
$
|
(1,180
|
)
|
$
|
768,618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(40,000
|
)
|
|
|
|
|
(40,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(172
|
)
|
|
|
|
|
(172
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
728,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $4,827
|
|
|
|
|
|
|
|
|
|
|
|
(8,965
|
)
|
|
(8,965
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
81,240
|
|
|
|
|
|
81,240
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2005
|
|
$
|
135,660
|
|
$
|
245,003
|
|
$
|
430,203
|
|
$
|
(10,145
|
)
|
$
|
800,721
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
135,660
|
|
$
|
245,003
|
|
$
|
407,844
|
|
$
|
(6,129
|
)
|
$
|
782,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(30,000
|
)
|
|
|
|
|
(30,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(172
|
)
|
|
|
|
|
(172
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
752,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $817
|
|
|
|
|
|
|
|
|
|
|
|
(1,516
|
)
|
|
(1,516
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
95,890
|
|
|
|
|
|
95,890
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$
|
135,660
|
|
$
|
245,003
|
|
$
|
473,562
|
|
$
|
(7,645
|
)
|
$
|
846,580
|
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
2,796
|
|
$
|
3,049
|
|
Advances
to Affiliates
|
|
|
7,018
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
65,274
|
|
|
47,515
|
|
Affiliated
Companies
|
|
|
40,779
|
|
|
49,226
|
|
Miscellaneous
|
|
|
8,260
|
|
|
7,984
|
|
Allowance
for Uncollectible Accounts
|
|
|
(264
|
)
|
|
(548
|
)
|
Total Accounts Receivable
|
|
|
114,049
|
|
|
104,177
|
|
Fuel
|
|
|
58,785
|
|
|
40,333
|
|
Materials
and Supplies
|
|
|
43,108
|
|
|
34,821
|
|
Risk
Management Assets
|
|
|
84,685
|
|
|
47,319
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
-
|
|
|
51,387
|
|
Margin
Deposits
|
|
|
42,232
|
|
|
13,740
|
|
Prepayments
and Other
|
|
|
19,129
|
|
|
20,270
|
|
TOTAL
|
|
|
371,802
|
|
|
315,096
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
1,697,764
|
|
|
1,660,392
|
|
Transmission
|
|
|
662,009
|
|
|
645,297
|
|
Distribution
|
|
|
1,200,577
|
|
|
1,153,026
|
|
Other
|
|
|
458,905
|
|
|
443,749
|
|
Construction
Work in Progress
|
|
|
137,128
|
|
|
104,175
|
|
Total
|
|
|
4,156,383
|
|
|
4,006,639
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,825,110
|
|
|
1,776,216
|
|
TOTAL
- NET
|
|
|
2,331,273
|
|
|
2,230,423
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
101,273
|
|
|
81,776
|
|
Long-term
Risk Management Assets
|
|
|
38,252
|
|
|
39,796
|
|
Employee
Benefits and Pension Assets
|
|
|
79,770
|
|
|
83,330
|
|
Deferred
Charges and Other
|
|
|
54,333
|
|
|
46,926
|
|
TOTAL
|
|
|
273,628
|
|
|
251,828
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
2,976,703
|
|
$
|
2,797,347
|
|
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, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
-
|
|
$
|
28,210
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
94,188
|
|
|
71,138
|
|
Affiliated
Companies
|
|
|
82,937
|
|
|
53,019
|
|
Short-term
Debt - Nonaffiliated
|
|
|
15,676
|
|
|
1,394
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
108,926
|
|
|
15,755
|
|
Risk
Management Liabilities
|
|
|
93,641
|
|
|
45,098
|
|
Customer
Deposits
|
|
|
48,931
|
|
|
50,848
|
|
Accrued
Taxes
|
|
|
89,311
|
|
|
42,799
|
|
Other
|
|
|
79,223
|
|
|
82,699
|
|
TOTAL
|
|
|
612,833
|
|
|
390,960
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
578,575
|
|
|
678,886
|
|
Long-term
Debt - Affiliated
|
|
|
50,000
|
|
|
50,000
|
|
Long-term
Risk Management Liabilities
|
|
|
27,904
|
|
|
27,083
|
|
Deferred
Income Taxes
|
|
|
379,470
|
|
|
409,513
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
343,954
|
|
|
320,066
|
|
Deferred
Credits and Other
|
|
|
131,017
|
|
|
131,477
|
|
TOTAL
|
|
|
1,510,920
|
|
|
1,617,025
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,123,753
|
|
|
2,007,985
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
1,672
|
|
|
2,284
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
4,698
|
|
|
4,700
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - $18 Par Value Per Share:
|
|
|
|
|
|
|
|
Authorized
- 7,600,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 7,536,640 Shares
|
|
|
135,660
|
|
|
135,660
|
|
Paid-in
Capital
|
|
|
245,003
|
|
|
245,003
|
|
Retained
Earnings
|
|
|
473,562
|
|
|
407,844
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(7,645
|
)
|
|
(6,129
|
)
|
TOTAL
|
|
|
846,580
|
|
|
782,378
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
2,976,703
|
|
$
|
2,797,347
|
|
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, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
95,890
|
|
$
|
81,240
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
98,406
|
|
|
98,580
|
|
Deferred
Income Taxes
|
|
|
(24,642
|
)
|
|
11,552
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
10,870
|
|
|
(3,141
|
)
|
Deferred
Property Taxes
|
|
|
(9,438
|
)
|
|
(9,579
|
)
|
Change
in Other Noncurrent Assets
|
|
|
20,982
|
|
|
(16,262
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
(33,256
|
)
|
|
10,149
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(9,872
|
)
|
|
(3,337
|
)
|
Fuel,
Materials and Supplies
|
|
|
(26,739
|
)
|
|
6,254
|
|
Margin
Deposits
|
|
|
(28,492
|
)
|
|
(18,766
|
)
|
Accounts
Payable
|
|
|
54,264
|
|
|
41,775
|
|
Customer Deposits |
|
|
(1,917 |
) |
|
26,571 |
|
Accrued
Taxes, Net
|
|
|
45,514
|
|
|
4,655
|
|
Over/Under Fuel
Recovery, Net |
|
|
63,862 |
|
|
(66,173 |
) |
Other
Current Assets
|
|
|
2,635
|
|
|
(3,859
|
)
|
Other
Current Liabilities
|
|
|
(15,346
|
)
|
|
4,046
|
|
Net
Cash Flows From Operating Activities
|
|
|
242,721
|
|
|
163,705
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(179,117
|
)
|
|
(110,209
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
(7,018
|
)
|
|
39,106
|
|
Other
|
|
|
(496
|
)
|
|
3,246
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(186,631
|
)
|
|
(67,857
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt - Nonaffiliated
|
|
|
80,593
|
|
|
154,642
|
|
Change
in Short-term Debt, Net - Nonaffiliated
|
|
|
14,282
|
|
|
-
|
|
Change
in Advances from Affiliates, Net
|
|
|
(28,210
|
)
|
|
605
|
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
(88,989
|
)
|
|
(208,122
|
)
|
Retirement
of Preferred Stock
|
|
|
(2
|
)
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(3,845
|
)
|
|
(2,712
|
)
|
Dividends
Paid on Common Stock
|
|
|
(30,000
|
)
|
|
(40,000
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(172
|
)
|
|
(172
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(56,343
|
)
|
|
(95,759
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(253
|
)
|
|
89
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
3,049
|
|
|
3,715
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
2,796
|
|
$
|
3,804
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
37,372
|
|
$
|
33,748
|
|
Net
Cash Paid for Income Taxes
|
|
|
53,509
|
|
|
49,176
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
17,110
|
|
|
4,414
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
8,924
|
|
|
5,075
|
|
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
|
Note
2
|
Rate
Matters
|
Note
3
|
Customer
Choice and Industry Restructuring
|
Note
4
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Income
Taxes
|
Note
10
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
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
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
2.
|
New
Accounting Pronouncements
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
3.
|
Rate
Matters
|
APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
4.
|
Customer
Choice and Industry
Restructuring
|
CSPCo,
OPCo, SWEPCo, TCC, TNC
|
5.
|
Commitments
and Contingencies
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
6.
|
Guarantees
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
7.
|
Company-wide
Staffing and Budget Review
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
8.
|
Acquisitions,
Assets Held for Sale and Asset Impairments
|
CSPCo,
TCC
|
9.
|
Benefit
Plans
|
APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
10.
|
Income
Taxes
|
PSO,
SWEPCo, TCC, TNC
|
11.
|
Business
Segments
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
12.
|
Financing
Activities
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC,
TNC
|
1. SIGNIFICANT
ACCOUNTING MATTERS
General
The
accompanying unaudited condensed financial statements and footnotes were
prepared in accordance with accounting principles generally accepted in the
United States of America (GAAP) for interim financial information and with
the
instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities
and
Exchange Commission (SEC). Accordingly, they do not include all the information
and footnotes required by GAAP for complete financial statements.
In
the
opinion of management, the unaudited interim financial statements reflect all
normal and recurring accruals and adjustments necessary for a fair presentation
of the results of operations, financial position and cash flows for the interim
periods for each Registrant Subsidiary. The results of operations for the three
and nine months ended September 30, 2006 are not necessarily indicative of
results that may be expected for the year ending December 31, 2006. The
accompanying condensed financial statements are unaudited and should be read
in
conjunction with the audited 2005 financial statements and notes thereto, which
are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the
year ended December 31, 2005 as filed with the SEC on March 1,
2006.
Components
of Accumulated Other Comprehensive Income (Loss)
Accumulated
Other Comprehensive Income (Loss) is included on the condensed balance sheets
in
the common shareholder’s equity section. The components of Accumulated Other
Comprehensive Income (Loss) for Registrant Subsidiaries as of September 30,
2006
and December 31, 2005 are shown in the following table.
|
|
September
30,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
Components
|
|
|
|
|
|
Cash
Flow Hedges:
|
|
|
|
|
|
|
|
APCo
|
|
$
|
(3,407
|
)
|
$
|
(16,421
|
)
|
CSPCo
|
|
|
3,081
|
|
|
(859
|
)
|
I&M
|
|
|
(8,503
|
)
|
|
(3,467
|
)
|
KPCo
|
|
|
1,249
|
|
|
(194
|
)
|
OPCo
|
|
|
7,055
|
|
|
755
|
|
PSO
|
|
|
(1,116
|
)
|
|
(1,112
|
)
|
SWEPCo
|
|
|
(7,368
|
)
|
|
(5,852
|
)
|
TCC
|
|
|
-
|
|
|
(224
|
)
|
TNC
|
|
|
(1,337
|
)
|
|
(111
|
)
|
|
|
|
|
|
|
|
|
Minimum
Pension Liability:
|
|
|
|
|
|
|
|
APCo
|
|
$
|
(189
|
)
|
$
|
(189
|
)
|
CSPCo
|
|
|
(21
|
)
|
|
(21
|
)
|
I&M
|
|
|
(102
|
)
|
|
(102
|
)
|
KPCo
|
|
|
(29
|
)
|
|
(29
|
)
|
PSO
|
|
|
(152
|
)
|
|
(152
|
)
|
SWEPCo
|
|
|
(277
|
)
|
|
(277
|
)
|
TCC
|
|
|
(928
|
)
|
|
(928
|
)
|
TNC
|
|
|
(393
|
)
|
|
(393
|
)
|
Accounting
for Asset Retirement Obligations (ARO)
The
Registrant Subsidiaries implemented SFAS 143 effective January 1, 2003. SFAS
143
requires entities to record a liability at fair value for any legal obligations
for future asset retirements when the related assets are acquired or
constructed. Upon establishment of a legal liability, SFAS 143 requires a
corresponding ARO asset to be established, which will be depreciated over its
useful life. ARO accounting is being followed for regulated and nonregulated
property that has a legal obligation related to asset retirement. Upon
settlement of an ARO, any difference between the ARO liability and actual costs
is recognized as income or expense.
The
Registrant Subsidiaries have identified, but not recognized, ARO liabilities
related to electric transmission and distribution assets, as a result of certain
easements on property on which assets are owned. Generally, such easements
are
perpetual and require only the retirement and removal of assets upon the
cessation of the property’s use. The retirement obligation is not estimable for
such easements since the Registrant Subsidiaries plan to use their facilities
indefinitely. The retirement obligation would only be recognized if and when
the
Registrant Subsidiaries abandon or cease the use of specific easements, which
is
not expected.
The
following is a reconciliation of the September 30, 2006 aggregate carrying
amount of ARO for SWEPCo. The changes in components of ARO during 2006 are
immaterial for all other Registrant Subsidiaries.
|
|
ARO
at
December
31,
2005
|
|
Accretion
Expense
|
|
Liabilities
Incurred
|
|
Liabilities
Settled
|
|
Revisions
in Cash Flow
Estimates
|
|
ARO
at September 30, 2006
|
|
|
|
(in
thousands)
|
|
SWEPCo
|
|
$
|
43,077
|
|
$
|
1,781
|
|
$
|
4,200
|
|
$
|
(4,967
|
)
|
$
|
(763
|
)
|
$
|
43,328
|
|
SWEPCo’s
September 30, 2006 and December 31, 2005 aggregate carrying amounts include
ARO
related to ash ponds, asbestos removal, Sabine Mining Company and Dolet Hills
Lignite Company, LLC. The current portion of SWEPCo’s ARO totaling approximately
$1 million and $2 million at September 30, 2006 and December 31, 2005,
respectively, is included in Other in the Current Liabilities section of
SWEPCo’s Condensed Consolidated Balance Sheets.
Related
Party Transactions
The
amounts of power purchased from Ohio Valley Electric Corporation, which is
43.47
% owned by AEP and CSPCo, were:
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
Company
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
APCo
|
|
$
|
19,555
|
|
$
|
19,501
|
|
$
|
62,209
|
|
$
|
54,763
|
|
CSPCo
|
|
|
5,536
|
|
|
5,103
|
|
|
17,100
|
|
|
14,752
|
|
I&M
|
|
|
9,784
|
|
|
7,920
|
|
|
28,848
|
|
|
22,704
|
|
OPCo
|
|
|
19,303
|
|
|
16,703
|
|
|
58,626
|
|
|
47,757
|
|
CSPCo
entered into a ten year Power Purchase Agreement (PPA) with Sweeny, on behalf
of
the AEP West companies, from January 1, 2005 to December 31, 2014. The PPA
is
for unit contingent power up to a maximum of 315 MW. The delivery point for
the
power under the PPA is in TCC’s system. The power is sold in ERCOT. Prior to May
1, 2006, the purchase of Sweeny power and its sale to nonaffiliates were shared
among the AEP West companies under the CSW Operating Agreement. After May 1,
2006, the purchases and sales are shared between PSO and SWEPCo. See “Allocation
Agreement between AEP East Companies and AEP West Companies and CSW Operating
Agreement” section of Note 3. Also see Note 17 of the 2005 Annual Report for a
discussion of the CSW Operating Agreement. The purchases from Sweeny
were:
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
Company
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
PSO
|
|
$
|
13,750
|
|
$
|
11,051
|
|
$
|
39,886
|
|
$
|
31,160
|
|
SWEPCo
|
|
|
16,170
|
|
|
13,189
|
|
|
46,925
|
|
|
27,570
|
|
TCC
|
|
|
-
|
|
|
5,548
|
|
|
703
|
|
|
20,120
|
|
TNC
|
|
|
-
|
|
|
8,559
|
|
|
4,229
|
|
|
19,638
|
|
Reclassifications
Certain
prior period financial statement items have been reclassified to conform to
current period presentation. These
revisions had no impact on previously reported results of operations, financial
condition or changes in shareholders’ equity.
The
Registrant Subsidiaries’ Statements of Operations were converted from a utility
format presentation where only regulated cost-of-service items were reflected
in
Operating Income to a commercial format presentation where nonutility items
are
reflected as components of Operating Income.
2. NEW
ACCOUNTING PRONOUNCEMENTS
Upon
issuance of exposure drafts or final pronouncements, we thoroughly review the
new accounting literature to determine its relevance, if any, to our business.
The following represents a summary of new pronouncements issued or implemented
in 2006 that we determined relate to our operations.
SFAS
123 (revised 2004) “Share-Based Payment” (SFAS 123R)
In
December 2004, the FASB issued SFAS 123R. SFAS 123R requires entities to
recognize compensation expense in an amount equal to the fair value of
share-based payments granted to employees. The statement eliminates the
alternative to use the intrinsic value method of accounting previously available
under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock
Issued to Employees.” The Registrant Subsidiaries recorded insignificant
cumulative effects of a change in accounting principle in the first quarter
of
2006 for the effects of initially applying the statement, primarily reflected
in
Other Operation on their financial statements.
In
March
2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, “Share-Based
Payment” (SAB 107), which conveys the SEC staff’s views on the interaction
between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides
the SEC staff’s views regarding the valuation of share-based payment
arrangements for public companies. Also, the FASB issued three FASB Staff
Positions (FSP) during 2005 and one in February 2006 that provided additional
implementation guidance. The Registrant Subsidiaries applied the principles
of
SAB 107 and the applicable FSPs in conjunction with their adoption of SFAS
123R.
The
Registrant Subsidiaries adopted SFAS 123R in the first quarter of 2006 using
the
modified prospective method. This method requires them to record compensation
expense for all awards granted after the time of adoption and recognize the
unvested portion of previously granted awards that remain outstanding at the
time of adoption as the requisite service is rendered. The compensation cost
is
based on the grant-date fair value of the equity award. Stock-based compensation
expense recognized during the period is based on the value of the portion of
share-based payment awards that is ultimately expected to vest during the
period. Stock-based compensation expense recognized in the Registrant
Subsidiaries’ financial statements for the three and nine months ended September
30, 2006 includes compensation expense for share-based payment awards granted
prior to, but not yet vested as of, January 1, 2006 based on the grant date
fair
value estimated in accordance with the pro forma provisions of SFAS 123 and
compensation expense for the share-based payment awards granted subsequent to
January 1, 2006 based on the grant date fair value estimated in accordance
with
the provisions of SFAS 123R. Implementation of SFAS 123R did not materially
affect the Registrant Subsidiaries’ results of operations, cash flows or
financial condition.
SFAS
157 “Fair Value Measurements”
In
September 2006, the FASB issued SFAS 157. SFAS 157 enhances existing guidance
for fair value measurement of assets and liabilities as well as instruments
measured at fair value that are classified in shareholders’ equity. SFAS 157
defines fair value, establishes a fair value measurement framework and expands
fair value disclosures. SFAS 157 emphasizes that fair value is market-based
with
the highest measurement hierarchy being market prices in active markets. The
standard will change current practice and requires fair value measurements
be
disclosed by hierarchy level. SFAS 157 requires an entity include its own credit
standing in the measurement of its liabilities and modifies the transaction
price presumption.
SFAS
157
is effective for interim and annual periods in fiscal years beginning after
November 15, 2007. Management is currently in the process of determining the
effect this standard will have on the Registrant Subsidiaries’ financial
statements. Although SFAS 157 is applied prospectively upon adoption, the effect
of certain transactions is applied retrospectively as of the beginning of the
fiscal year of application, with a cumulative effect adjustment to the
appropriate balance sheet items. SFAS 157 will be effective for the Registrant
Subsidiaries starting January 1, 2008.
SFAS
158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement
Plans”
In
September 2006, the FASB issued SFAS 158. SFAS 158 amends previous standards.
It
requires employers to fully recognize the obligations associated with defined
benefit pension, retiree healthcare and other postretirement (OPEB) plans in
their balance sheets. Previous standards required an employer to disclose the
complete funded status of its plan only in the notes to the financial statements
and provided that an employer delay recognition of certain changes in plan
assets and obligations that affected the costs of providing benefits resulting
in an asset or liability that often differed from the plan’s funded status. SFAS
158 requires a defined benefit pension or postretirement plan sponsor (a)
recognize in its statement of financial position an asset for a plan’s
overfunded status or a liability for the plan’s underfunded status, (b) measure
the plan’s assets and its obligations that determine its funded status as of the
end of the employer’s fiscal year (with limited exceptions), and (c) recognize,
as a component of other comprehensive income, the changes in the funded status
of the plan that arise during the year but are not recognized as a component
of
net periodic benefit cost pursuant to SFAS 87, “Employers’ Accounting for
Pensions,” or SFAS 106, “Employer’s Accounting for Postretirement Benefits Other
Than Pensions.” It also requires an employer to disclose additional information
on how delayed recognition of certain changes in the funded status of a defined
benefit postretirement plan affects net periodic benefit costs for the next
fiscal year.
The
effect of SFAS 158 is to adjust AOCI at the end of each year, for both
underfunded and overfunded pension and OPEB plans, to an amount equal to the
remaining unrecognized SFAS 87 and SFAS 106 deferrals for unamortized actuarial
losses or gains, prior service costs, or transition obligations, such that
remaining deferred costs result in an AOCI equity reduction and deferred gains
result in an AOCI equity addition.
The
year-end AOCI measure is volatile based on fluctuating investment returns and
discount rates. Favorable changes include higher returns that increase plan
assets and higher discount rates that reduce the discounted benefit
obligation.
SFAS
158
is effective for initial recognition of a defined benefit postretirement plan
and related disclosure for fiscal years ending after December 15, 2006.
Management has not completed the process of determining the effect of this
standard on the Registrant Subsidiaries’ financial statements, including whether
a portion of the adjustment required by SFAS 158 can be deferred as a regulatory
asset under SFAS 71.
EITF
Issue 06-3 “How Taxes Collected from Customers and Remitted to Governmental
Authorities Should Be Presented in the Income Statement (That Is, Gross versus
Net Presentation)” (EITF 06-3)
In
June
2006, the EITF reached a consensus on the income statement presentation of
various types of taxes. The scope of this issue includes any tax assessed by
a
governmental authority that is directly imposed on a revenue-producing
transaction between a seller and a customer and may include, but is not limited
to, sales, use, value added, and some excise taxes. The presentation of taxes
within the scope of this issue on either a gross (included in revenues and
costs) or a net (excluded from revenues) basis is an accounting policy decision
that should be disclosed pursuant to APB Opinion No. 22, “Disclosure of
Accounting Policies.” The EITF’s decision on gross/net presentation requires
that any such taxes reported on a gross basis be disclosed on an aggregate
basis
in interim and annual financial statements, for each period for which an income
statement is presented, if those amounts are significant.
EITF
06-3
is effective for fiscal years beginning after December 15, 2006. As disclosed
in
Note 1 of the 2005 Annual Report, the Registrant Subsidiaries act as agents
for
some state and local governments and collect from customers certain excise
taxes
levied by those state or local governments on customers. The Registrant
Subsidiaries present these taxes on a net basis and do not recognize these
taxes
as revenues or expenses. Therefore, this issue will not have a material impact
on their financial statements.
FASB
Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN
48)
In
July
2006, the FASB issued FIN 48 which clarifies the application of SFAS 109,
“Accounting for Income Taxes.” FIN 48 clarifies the accounting for uncertainty
in income taxes recognized in an enterprise’s financial statements by
prescribing a recognition threshold (whether a tax position is more likely
than
not to be sustained) without which, the benefit of that position is not
recognized in the financial statements. It requires a measurement determination
for recognized tax positions based on the largest amount of benefit that is
greater than 50 percent likely of being realized upon ultimate settlement.
FIN
48 also provides guidance on derecognition, classification, interest and
penalties, accounting in interim periods, disclosure and
transition.
FIN
48
requires that the cumulative effect of applying this interpretation be reported
and disclosed as an adjustment to the opening balance of retained earnings
for
that fiscal year and presented separately. FIN 48 is effective for fiscal years
beginning after December 15, 2006. Management has not completed the process
of
determining the effect of this interpretation on the financial
statements.
SAB
No. 108 “Considering the Effects of Prior Year Misstatements When Quantifying
Misstatements in the Current Year Financial Statements” (SAB
108)
In
September 2006, the SEC staff issued SAB 108. SAB 108 addresses the diversity
in
practice when quantifying the effect of an error on financial statements. SAB
108 provides guidance on the consideration of the effects of prior year
misstatements in quantifying misstatements in current year financial statements.
The Registrant Subsidiaries will be required to adopt the provisions of SAB
108
effective December 31, 2006. Management believes that the adoption of SAB 108
will not have a material impact on the financial statements.
Future
Accounting Changes
The
FASB’s standard-setting process is ongoing and until new standards have been
finalized and issued by 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 business
combinations, revenue recognition, liabilities and equity, leases, insurance,
subsequent events 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 future results of operations and financial
position.
3. RATE
MATTERS
The
Rate
Matters note within the 2005 Annual Report should be read in conjunction with
this report to gain a complete understanding of material rate matters still
pending that could impact results of operations and cash flows. Rate matters
that are not believed to be reasonably likely to affect future results of
operations and cash flows are not included in this report or the 2005 Annual
Report. The following sections discuss ratemaking developments in 2006 updating
the 2005 Annual Report.
APCo
Virginia Environmental and Reliability Costs - Affecting APCo
The
Virginia Electric Restructuring Act (the statute) includes a provision that
permits recovery, during the extended capped rate period ending December 31,
2010, of incremental environmental compliance and transmission and distribution
(T&D) system reliability (E&R) costs prudently incurred on and after
July 1, 2004. In 2005, APCo filed a request with the Virginia SCC and updated
it
through supplemental testimony seeking recovery of $21 million of incremental
E&R costs incurred from July 2004 through September 2005. Through August 31,
2006, APCo deferred as a regulatory asset $47 million of incremental E&R
costs incurred since July 1, 2004 based on a legal opinion that such costs
were
probable of recovery under the law.
In
January 2006, the Virginia SCC staff proposed that APCo be allowed to increase
its electric rates at an ongoing level of $20 million to recover current, rather
than past, incremental E&R costs. The staff proposal would effectively
disallow the recovery of costs incurred prior to the authorization and
implementation of new rates, including all incremental E&R costs that were
deferred as a regulatory asset. At the E&R hearings, which concluded in
March 2006, the staff amended its testimony to recommend a $24 million increase
in APCo’s ongoing rates. In September 2006, the Hearing Examiner issued a report
recommending adoption of the staff proposal with minor modifications, which
would result in (a) an on-going level of E&R cost recovery of $29 million
only if the Virginia SCC decides that any rate increase from the base rate
case
(described below) does not include the $29 million ongoing level of E&R
costs, and (b) the disallowance of all previously deferred incremental E&R
costs. In the third quarter of 2006, management concluded that the Virginia
SCC
might not grant recovery of actual incremental E&R costs incurred during the
period from July 2004 through September 2006. Accordingly, APCo wrote off all
of
the E&R regulatory asset, adversely affecting pretax earnings by $36
million, net of the reinstatement of related AFUDC and capitalized interest.
Management believes that the staff’s proposal and the Hearing Examiner’s
recommendation are contrary to the statute. The Virginia SCC’s final order in
this proceeding is pending.
If
the
Virginia SCC properly implements the statute as interpreted in its October
2005
order and as supported by the Virginia Attorney General’s office in October
2006, APCo should be able to recover all of its incremental E&R costs
prudently incurred since July 1, 2004. If the Virginia SCC adopts the Hearing
Examiner's findings, based on advice of counsel, APCo will appeal the
decision.
APCo
Virginia Base Rate Case - Affecting APCo
In
May
2006, APCo filed a request with the Virginia SCC seeking an increase in base
rates of $225 million to recover increasing costs including the cost of its
investment in environmental equipment and a return on equity of 11.5%. In
addition, APCo requested to move off-system sales margins, currently credited
to
customers through base rates, to the fuel factor where they can be adjusted
annually. APCo also proposed to share the off-system sales margins with the
customers with 40% going to reduce rates and 60% being retained by APCo. This
resultant proposed off-system sales fuel rate credit, which is estimated to
be
$27 million, partially offsets the $225 million requested increase in base
rates
for a net increase in revenues of $198 million. The major components of the
$225
million rate request include $73 million for the impact of removing off-system
sales margins from the rate year ending September 30, 2007, $60 million mainly
due to projected net environmental plant additions through September 30, 2007
and $48 million for return on equity. In May 2006, the Virginia SCC issued
an
order, consistent with Virginia law, placing the net requested base rate
increase of $198 million into effect October 2, 2006, subject to refund. In
October 2006, the Virginia SCC staff filed their direct testimony recommending
a
base rate increase of $13 million. Other intervenors have recommended base
rate
increases ranging from $42 million to $112 million. APCo plans to file rebuttal
testimony in November 2006. Hearings are scheduled to begin in December 2006.
Management is unable to predict the ultimate effect of this filing on APCo’s
future revenues, cash flows and financial condition.
APCo
West Virginia Rate Case - Affecting APCo
In
July
2006, the WVPSC approved the settlement agreement APCo and WPCo reached with
the
WVPSC staff and intervenors in the West Virginia rate case filed in 2005. The
settlement agreement provided for an initial overall increase in APCo’s rates of
$40 million effective July 28, 2006 comprised of:
·
|
A
$50 million increase in Expanded Net Energy Cost (ENEC) for fuel,
purchased power expenses, off-system sales credits and other
energy-related costs;
|
·
|
A
$21 million special construction surcharge providing recovery of
the costs
of scrubbers and the Wyoming-Jacksons Ferry 765 kV line to
date;
|
·
|
A
$16 million general base rate reduction resulting predominantly from
a
reduction in the return on equity to 10.5% and a $9 million reduction
in
depreciation expense which affects cash flows but not earnings;
and
|
·
|
A
$15 million credit to refund a portion of deferred prior over-recoveries
of ENEC recorded in regulatory liabilities on APCo’s Condensed
Consolidated Balance Sheets, which will impact cash flows but not
earnings.
|
In
addition, the agreement provides a surcharge mechanism that allows APCo to
adjust its rates annually for the timely recovery in each of the next three
years of the incremental cost of ongoing environmental investments in scrubbers
at Mountaineer and John Amos power plants and the costs of the new
Wyoming-Jackson Ferry 765 kV line. Although the amount of these annual surcharge
increases cannot be determined until the incremental costs are known and
reviewed by the WVSPC, management estimates that they will result in an annual
increase in APCo’s revenues of $32 million effective July 1, 2007, $13 million
effective July 1, 2008 and $16 million effective July 1, 2009.
The
settlement further provides for the reinstatement of the ENEC mechanism
effective July 1, 2006 with over/under recovery deferral accounting and annual
ENEC proceedings to affect annual rate adjustments for changes in fuel and
purchased power costs beginning in 2007. The settlement provides for the return
to customers of the remaining portion of the prior ENEC regulatory liability
plus interest at LIBOR rate on the unrefunded balance in future ENEC
proceedings.
I&M
Depreciation Study Filing- Affecting I&M
In
December 2005, I&M filed a petition with the IURC seeking authorization to
revise its book depreciation rates applicable to its electric utility plant
in
service effective January 1, 2006. Based on a depreciation study included in
the
filing, I&M recommended a decrease in pretax annual depreciation expense of
approximately $69 million on an Indiana jurisdictional basis reflecting an
NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2
and
an extension of the service life of the Tanners Creek coal-fired generating
units. This petition was not a request for a change in customers’ electric
service rates. A
public
hearing was held in May 2006 and the final brief was filed in June 2006.
As
proposed by I&M, the
book
depreciation expense reduction would increase its earnings, but would not impact
its cash flows until electric service rates are revised.
An
order
issued by the IURC on October 19, 2006 does not dispute I&M's
revised depreciation accounting rates but, nevertheless, denied I&M’s
request to revise its book depreciation rates between base rate cases. The
IURC believes that depreciation rates for an electric utility should not be
changed between general rate cases unless it was “absolutely essential” and a
direct benefit to customers was shown. I&M has twenty days in which to file
for a rehearing or reconsideration. I&M has not yet decided whether it will
file for a rehearing or reconsideration or if and when it will file to adjust
base rates to reflect the depreciation study.
KPCo
Environmental Surcharge Filing - Affecting KPCo
In
July
2006, KPCo filed its third annual environmental compliance plan seeking
additional annual revenues of $2 million in 2007 and $6 million in 2008. The
filing seeks recovery of KPCo’s share of AEP System Power Pool charges for the
annual cost of retrofitting pollution control additions to affiliated AEP System
east zone power plants. No intervenor testimony was filed in the case.
Management expects the KPSC will rule on the filing in early 2007. Management
is
unable to predict the ultimate effect this filing will have on KPCo’s revenues
and results of operations.
KPCo
Rate Filing - Affecting KPCo
In
March
2006, the KPSC approved the settlement agreement in KPCo’s 2005 base rate case.
The approved agreement provides for a $41 million annual increase in revenues
effective on March 30, 2006 and the retention of the existing environmental
surcharge tariff. No return on equity is specified by the settlement terms
except to note that KPCo will use a 10.5% return on equity to calculate the
environmental surcharge tariff and AFUDC.
PSO
Fuel and Purchased Power and its Possible Impact on AEP East companies and
AEP
West companies
In
2002,
PSO under-recovered $44 million of fuel costs resulting from a reallocation
among AEP West companies of purchased power costs for periods prior to January
1, 2002. In July 2003, PSO proposed collection of those reallocated costs over
18 months. In August 2003, the OCC staff filed testimony recommending PSO
recover $42 million of the reallocated purchased power costs over three years
and PSO reduced its regulatory asset deferral by $2 million. The OCC
subsequently expanded the case to include a full prudence review of PSO’s 2001
through 2003 fuel and purchased power practices. In January 2006, the OCC staff
and intervenors issued supplemental testimony alleging that AEP deviated from
the FERC-approved method of allocating off-system sales margins between AEP
East
companies and AEP West companies and among AEP West companies. The OCC staff
proposed that the OCC offset the $42 million of under-recovered fuel with their
proposed reallocation of off-system sales margins of $27 million to $37 million
and with $9 million attributed to wholesale customers, which they claimed had
not been refunded. In February 2006, the OCC staff filed a report concluding
that the $9 million of reallocated purchased power costs assigned to wholesale
customers had been refunded, thus removing that issue from their
recommendation.
In
2004,
an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO
deviated from the FERC-approved allocation methodology and held that any such
complaints should be addressed at the FERC. The OCC has not ruled on appeals
by
intervenors of the ALJ’s finding. The United States District Court for the
Western District of Texas issued orders in September 2005 regarding a TNC fuel
proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the
PUCT from reallocating off-system sales margins between the AEP East companies
and AEP West companies. The federal court agreed that the FERC has sole
jurisdiction over that allocation. The PUCT appealed the ruling.
PSO
does
not agree with the intervenors’ and the OCC staff’s recommendations and
proposals and will defend its position. If the OCC denies recovery of any
portion of the $42 million under-recovery of reallocated costs or offsets
under-recovered fuel deferrals with additional reallocated off-system sales
margins, PSO’s future results of operations and cash flows could be adversely
affected. However, if the position taken by the federal court in Texas applies
to PSO’s case, the OCC could be preempted from disallowing fuel recoveries for
alleged improper allocations of off-system sales margins between AEP East
companies and AEP West companies. The OCC or another party may file a complaint
at the FERC alleging the allocation of off-system sales margins adopted by
PSO
is improper which could result in an adverse effect on future results of
operations and cash flows for AEP and the AEP East companies. To date, there
has
been no claim asserted at the FERC that AEP deviated from the approved
allocation methodologies. Management is unable to predict the ultimate effect,
if any, of these Oklahoma fuel clause proceedings and any future FERC
proceedings on the AEP East companies’ and AEP West companies’ future results of
operations, cash flows and financial condition.
In
June
2005, the OCC issued an order directing its staff to conduct a prudence review
of PSO’s fuel and purchased power practices for the year 2003. The OCC staff
filed testimony finding no disallowances in the test year data. The Attorney
General of Oklahoma filed testimony stating that they could not determine if
PSO’s gas procurement activities were prudent, but did not include a recommended
disallowance. However, an intervenor filed testimony in June 2006 proposing
the
disallowance of $22 million in fuel costs based on a historical review of
potential hedging opportunities that existed during the year. A hearing was
held
in August 2006 and management expects a recommendation from the ALJ in the
fourth quarter of 2006.
In
February 2006, a law was enacted requiring the OCC to conduct prudence reviews
on all generation and fuel procurement processes, practices and costs on either
a two or three-year cycle depending on the number of customers served. PSO
is
subject to the required biennial reviews. The OCC staff indicated that it
expects the review process to begin late 2006 or early 2007.
Management
cannot predict the outcome of the pending fuel and purchase power reviews or
planned future reviews, but believes that PSO’s fuel and purchased power
procurement practices and costs are prudent and properly incurred. If the OCC
disagrees and disallows fuel or purchased power costs including the unrecovered
2002 reallocation of such costs incurred by PSO, it would have an adverse effect
on PSO’s future results of operations and cash flows.
PSO
Rate Filing - Affecting PSO
In
September 2006, PSO filed a notice of its intent to file in November 2006 a
plan
to modify the base rates of PSO’s Oklahoma jurisdictional customers with a
proposed effective date in the second quarter of 2007.
SWEPCo
Louisiana Fuel Inquiry - Affecting SWEPCo
In
March
2006, the Louisiana Public Service Commission (LPSC) closed its inquiry into
SWEPCo’s fuel and purchased power procurement activities during the period
January 1, 2005 through October 31, 2005. The LPSC approved the LPSC staff’s
report, which concluded that SWEPCo’s activities were appropriate and did not
identify any disallowances or areas for improvement.
SWEPCo
PUCT Staff Review of Earnings - Affecting SWEPCo
In
October 2005, the staff of the PUCT reported the results of its review of
SWEPCo’s year-end 2004 earnings. Based on the staff’s adjustments to the
information submitted by SWEPCo, the report indicates that SWEPCo is receiving
excess revenues of approximately $15 million. The staff engaged SWEPCo in
discussions to reconcile the earnings calculation and to consider possible
ways
to address the results. After those discussions, the PUCT staff informed SWEPCo
in April 2006 that they would not pursue the matter further.
SWEPCo
Louisiana Compliance Filing - Affecting SWEPCo
In
October 2002, SWEPCo filed with the LPSC detailed financial information
typically utilized in a revenue requirement filing, including a jurisdictional
cost of service. This filing was required by the LPSC as a result of its order
approving the merger between AEP and CSW. In April 2004, at the request of
the
LPSC, SWEPCo filed updated financial information with a test year ending
December 31, 2003. Both filings indicated that SWEPCo’s rates should not be
reduced. Due to multiple delays, in April 2006, the LPSC and SWEPCo agreed
to
update the financial information based on a 2005 test year. SWEPCo filed updated
financial review schedules in May 2006 showing a return on equity of 9.44%
compared to the previously authorized return on equity of 11.1%.
In
July
2006, the LPSC staff’s consultants filed direct testimony recommending a base
rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana
jurisdiction customers, based on a proposed 10% return on equity. The
recommended reduction range is subject to SWEPCo validating certain ongoing
operations and maintenance expense levels and the recommended base rate
reduction does not include the impact of a proposed consolidated federal income
tax adjustment, which, if approved, would increase the proposed rate reduction.
SWEPCo filed rebuttal testimony in October 2006 strongly refuting the
consultants’ recommendations. Hearings are expected to occur late in the fourth
quarter of 2006. A decision is not expected until 2007. At this time, management
is unable to predict the outcome of this proceeding. If a rate reduction is
ultimately ordered, it would adversely impact SWEPCo’s future results of
operations and cash flows.
TCC
and TNC Rate Filings - Affecting TCC and TNC
In
September 2006, TCC and TNC announced that each will file transmission and
distribution wires rate cases in Texas in late 2006. Management anticipates
requesting an $83 million annual increase for TCC and a $25 million annual
increase for TNC. Both requests include the impact of the expiration of the
CSW merger savings credits.
ERCOT
Price-to-Beat (PTB) Fuel Factor Appeal - Affecting TCC and
TNC
Several
parties including the Office of Public Utility Counsel and cities served by
both
TCC and TNC appealed the PUCT’s December 2001 orders establishing initial PTB
fuel factors for Mutual Energy CPL and Mutual Energy WTU (TCC’s and TNC’s former
affiliated REPs, respectively). In June 2003, the District Court ruled the
PUCT
record lacked substantial evidence regarding the effect of loss of load due
to
retail competition on the generation requirements of both Mutual Energy WTU
and
Mutual Energy CPL and on the PTB rates. In an opinion issued in July 2005,
the
Texas Court of Appeals reversed the District Court. The cities appealed the
appeals court decision to the Supreme Court of Texas, which has ordered full
briefing, but has not granted review. Management cannot predict the outcome
of
further appeals, but a reversal of the favorable court of appeals decision
regarding the loss of load issue could result in the issue being returned to
the
PUCT for further consideration. If that were to happen and if the PUCT orders
refunds of PTB revenues, it could adversely impact TCC’s and TNC’s results of
operations and cash flows for the portion of the refund applicable to the period
of time that they owned the REPs.
RTO
Formation/Integration - Affecting APCo, CSPCo, I&M, KPCo and
OPCo
In
2005,
the FERC approved the amortization of approximately $18 million of deferred
RTO
formation/integration costs not billed by PJM over 15 years and $17 million
of
deferred PJM-billed integration costs over 10 years. The total amortization
related to such costs was $1 million in both the third quarter of 2006 and
2005.
In the first nine months of 2006 and 2005, total amortization related to such
costs was $4 million and $3 million, respectively.
The
AEP
East companies’ deferred unamortized RTO formation/integration costs were as
follows:
|
|
September
30, 2006
|
|
December
31, 2005
|
|
|
|
PJM-Billed
Integration Costs
|
|
Non-PJM
Billed Formation/ Integration Costs
|
|
PJM-Billed
Integration Costs
|
|
Non-PJM
Billed Formation/ Integration Costs
|
|
|
|
(in
millions)
|
|
APCo
|
|
$
|
3.7
|
|
$
|
4.8
|
|
$
|
4.1
|
|
$
|
4.9
|
|
CSPCo
|
|
|
1.5
|
|
|
1.9
|
|
|
1.7
|
|
|
1.9
|
|
I&M
|
|
|
3.0
|
|
|
3.4
|
|
|
3.2
|
|
|
3.7
|
|
KPCo
|
|
|
0.9
|
|
|
1.1
|
|
|
1.0
|
|
|
1.1
|
|
OPCo
|
|
|
4.3
|
|
|
5.0
|
|
|
4.7
|
|
|
5.1
|
|
In
a
December 2005 order, the FERC approved the inclusion of a separate rate in
the
PJM AEP zone OATT to recover the amortization of deferred RTO
formation/integration costs and related carrying costs not billed by PJM of
$2
million per year. The AEP East companies will be responsible for paying the
majority of the amortized costs assigned by the FERC to the AEP East zone since
their internal load is the bulk (about 85%) of the transmission load in the
AEP
zone. As a result, the AEP East companies will need to recover the 85% through
their retail rates.
In
May
2006, the FERC approved a settlement that provides for recovery over a ten-year
period of the PJM-billed integration costs, including related carrying charges,
of AEP, Commonwealth Edison Company (ComEd) and The Dayton Power & Light
Company (DP&L) from all present zones of the PJM region, except the Virginia
Electric & Power Company (VEPCo) zone. The net result of the settlement is
that the AEP East companies will recover approximately 50% of the deferred
PJM-billed integration costs from third parties, and will need to recover the
remaining 50% through retail rates.
As
a
result of recently approved rate increases, CSPCo, OPCo and KPCo recover the
amortization of RTO formation/integration costs billed to the AEP East companies
in Ohio and Kentucky. APCo received approval to include the amortization of
RTO
formation/integration costs in retail rates in West Virginia effective July
28,
2006. In Virginia, APCo filed a base rate case, which includes recovery of
these
costs when rates became effective October 2, 2006, subject to refund. In
Indiana, I&M is subject to a rate cap until June 30, 2007 and is precluded
from recovering its share of the deferred RTO costs until that date or until
it
can file for a rate increase in Indiana. I&M has not yet filed for recovery
in Michigan.
Until
I&M can adjust its retail rates in Indiana and Michigan to recover the
amortization of its deferred RTO formation/integration costs, its results of
operations and cash flows will be adversely affected. If the Virginia, Indiana
or Michigan commissions disallow recovery of any portion of the billed
amortization of deferred RTO formation/integration costs, it could adversely
impact APCo’s and/or I&M’s future results of operations and cash flows. In
the event of a disallowance, management would appeal that decision to the
appropriate state or federal courts.
Transmission
Rate Proceedings at the FERC - Affecting APCo, CSPCo, I&M, KPCo and
OPCo
SECA
Revenue Subject to Refund
In
accordance with FERC orders, the AEP East companies collected SECA rates to
mitigate lost through-and-out transmission service (T&O) revenues from
December 1, 2004 through March 31, 2006, when SECA rates expired. Intervenors
objected to the 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 or surcharge. The AEP East companies also paid
SECA
rates to other utilities at considerably lesser amounts than collected. If
a
refund is ordered, the AEP East companies would also receive refunds related
to
the SECA rates they paid.
The
AEP
East companies recognized gross SECA revenues as follows:
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
(a)
|
|
2005
|
|
|
|
(in
millions)
|
|
APCo
|
|
$
|
-
|
|
$
|
13.6
|
|
$
|
13.4
|
|
$
|
39.1
|
|
CSPCo
|
|
|
-
|
|
|
7.7
|
|
|
7.9
|
|
|
20.8
|
|
I&M
|
|
|
-
|
|
|
8.0
|
|
|
8.1
|
|
|
22.5
|
|
KPCo
|
|
|
-
|
|
|
3.2
|
|
|
3.2
|
|
|
9.3
|
|
OPCo
|
|
|
-
|
|
|
10.6
|
|
|
10.4
|
|
|
28.8
|
|
(a)
|
Represents
revenues through March 31, 2006, when SECA rates expired, and excludes
the
provision for refund recorded in the second quarter of 2006 discussed
below.
|
Approximately
$19 million of these recorded SECA revenues billed by PJM were never collected.
The AEP East companies filed a motion with the FERC to force payment of these
SECA billings.
A
hearing
in the SECA case was held in May 2006 to determine whether any of the SECA
revenues should be refunded. In August 2006, the 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 were not
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 unpaid SECA rates must be paid in the recommended reduced
amount.
Since
the
implementation of SECA rates in December 2004, the AEP East companies recorded
approximately $220 million of gross SECA revenues, subject to refund, and have
reached settlements with certain customers related to approximately $70 million
of such revenues. The unsettled gross SECA revenues total approximately $150
million. If the ALJ’s initial decision is upheld in its entirety, it would
disallow $126 million of the AEP East companies’ unsettled gross SECA revenues.
It would also provide refunds of SECA rates paid by the AEP East companies
in
considerably less significant amounts.
The
AEP
East companies provided for net refunds, most of which were recorded in the
second quarter of 2006 as shown in the following table.
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
APCo
|
|
$
|
-
|
|
$
|
0.3
|
|
$
|
6.1
|
|
$
|
0.7
|
|
CSPCo
|
|
|
-
|
|
|
0.2
|
|
|
3.4
|
|
|
0.4
|
|
I&M
|
|
|
-
|
|
|
0.2
|
|
|
3.6
|
|
|
0.4
|
|
KPCo
|
|
|
-
|
|
|
0.1
|
|
|
1.4
|
|
|
0.2
|
|
OPCo
|
|
|
-
|
|
|
0.3
|
|
|
4.6
|
|
|
0.5
|
|
AEP,
together with Exelon and DP&L, filed an extensive brief noting exceptions to
the initial ALJ decision and asking the FERC to reverse the decision in large
part. Reply briefs were filed in October 2006. Management
believes
that the FERC should reject the initial ALJ decision because it is contrary
to
prior related FERC decisions, which are presently subject to rehearing.
Furthermore, management believes the ALJ’s findings on key issues are largely
without merit. As a result, the AEP East companies have not provided for a
possible refund of SECA rates in excess of current provisions. If the FERC
does
adopt the ALJ’s recommendations, AEP will appeal the decision to the courts.
Although AEP believes it has meritorious arguments, management cannot predict
the ultimate outcome of any future FERC proceedings or court appeals.
If
the
FERC adopts the ALJ’s decision, it will have an adverse effect on the AEP East
companies’ future results of operations and cash flows.
AEP
East Transmission Revenue Requirement and Rates
In
December 2005, the FERC approved an uncontested settlement which allowed
increases in wholesale transmission OATT rates in three steps: first, beginning
retroactively on November 1, 2005, second, beginning on April 1, 2006 when
the
SECA revenues were eliminated and third, beginning on August 1, 2006 when the
new Wyoming-Jacksons Ferry 765 kV line went into service. Management estimates
that this rate increase will increase wholesale transmission revenues by $22
million in 2006 and $28 million in 2007.
The
Elimination of T&O and SECA Rates and the FERC PJM Regional Transmission
Rate Proceeding
In
a
separate proceeding, at AEP’s urging, the FERC instituted an investigation of
PJM’s zonal rate regime, indicating that the present rate regime may need to be
replaced through establishment of regional rates that would compensate AEP
and
other transmission owners for the regional transmission facilities they provide
to PJM, which provides service for the benefit of customers throughout PJM.
In
September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly
filed a regional transmission rate design proposal with the FERC. This filing
proposes and supports a new PJM rate regime generally referred to as
Highway/Byway.
Parties
to the regional rate proceeding proposed the following rate
regimes:
·
|
AEP/AP
proposed a Highway/Byway rate design in which:
|
·
|
The
cost of all transmission facilities in the PJM region operated at
345 kV
or higher would be included in a “Highway” rate that all load serving
entities (LSEs) would pay based on peak demand. The AEP/AP proposal
would
produce about $125 million in additional revenues per year for AEP
from
users in other zones of PJM.
|
·
|
The
cost of transmission facilities operating at lower voltages would
be
collected in the zones where those costs are presently charged under
PJM’s
existing rate design.
|
·
|
Two
other utilities, Baltimore Gas & Electric Company (BG&E) and Old
Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate
that
includes transmission facilities above 200 kV, which would produce
lower
revenues than the AEP/AP proposal.
|
·
|
In
a competing Highway/Byway proposal, a group of LSEs proposed rates
that
would include existing 500 kV and higher voltage facilities and new
facilities above 200 kV in the Highway rate, which would produce
considerably lower revenues than the AEP/AP proposal.
|
·
|
In
January 2006, the FERC staff issued testimony and exhibits supporting
a
PJM-wide flat rate or “Postage Stamp” type of rate design that would
include all transmission facilities, which would produce higher
transmission revenues than the AEP/AP
proposal.
|
All
of
these proposals were challenged by a majority of other transmission owners
in
the PJM region, who favor continuation of the PJM rate design. Hearings were
held in April 2006, and the ALJ issued an initial decision in July 2006. The
ALJ
found the existing PJM zonal rate design to be unjust and determined that it
should be replaced. The ALJ found that the Highway/Byway rates proposed by
AEP/AP and BG&E/ODEC would be just and reasonable alternatives; however, the
judge also found the Postage Stamp rate proposed by the FERC staff to be just
and reasonable, and recommended it be adopted. The ALJ also found that the
effective date of the rate change should be April 1, 2006 to coincide with
SECA
rate elimination. Because the Postage Stamp rate was found to produce greater
cost shifts than other proposals, the judge also recommended that the design
be
phased-in. Without a phase-in, the Postage Stamp method would produce somewhat
more revenue for AEP than the AEP/AP proposal, but the phase-in would delay
the
full impact of that result until about 2012.
AEP
filed
briefs noting exceptions to the initial decision and replies to the exceptions
of other parties. AEP argued that a phase-in should not be required.
Nevertheless, AEP argued that if the FERC adopts the Postage Stamp rate and
a
phase-in plan, the revenue collections curtailed by the phase-in should be
deferred and paid later, with interest. A FERC decision is likely in early
to
mid-2007.
From
the
elimination of T&O rates in December 2004 through the expiration of SECA
rates on March 31, 2006, SECA transition rates failed to fully compensate the
AEP East companies for their lost T&O revenues. Effective with the
expiration of the SECA transition rates on March 31, 2006, the increase in
the
AEP East zonal transmission rates applicable to AEP’s internal load and
wholesale transmission customers in AEP’s zone was not sufficient to replace the
prior T&O revenues or the lower temporary SECA transition rate revenues;
however, a favorable outcome in the PJM regional transmission rate proceeding,
made retroactive to April 1, 2006 could mitigate a large portion of the
shortfall. Full mitigation of the effects of eliminated T&O revenues and the
less favorable terminated SECA revenues will require cost recovery through
state
retail rate proceedings pending any resolution that may result from the above
FERC regional transmission rate proceeding. The status of such state retail
rate
proceedings is as follows:
·
|
In
Kentucky, KPCo settled a rate case, which provided for the recovery
of its
share of the transmission revenue reduction in new rates effective
March
30, 2006.
|
·
|
In
Ohio, CSPCo and OPCo recover the FERC-approved OATT which reflects
their
share of the full transmission revenue requirement retroactive to
April 1,
2006 under a May 2006 PUCO order.
|
·
|
In
West Virginia, APCo settled a rate case, which provided for the recovery
of its share of the T&O/SECA transmission revenue reduction beginning
July 28, 2006.
|
·
|
In
Virginia, APCo filed a request for revised rates, which includes
recovery
of its share of the T&O/SECA transmission revenue reduction starting
October 2, 2006, subject to refund.
|
·
|
In
Indiana, I&M is precluded by a rate cap from raising its rates until
July 1, 2007.
|
·
|
In
Michigan, I&M has not yet filed to seek recovery of the lost
transmission revenues.
|
Once
approved by the FERC, the favorable impacts of the new regional PJM rate design
will flow directly to wholesale customers and to retail customers in West
Virginia through the ENEC and to retail customers in Ohio upon PUCO approval
of
a filing the Ohio companies would make to reflect the new rates. In Kentucky,
Indiana, Virginia and Michigan, the additional transmission revenues can be
expected to reduce retail rates in future base rate proceedings.
Management
believes that the AEP/AP proposal of the Postage Stamp
proposal combined with the retail rate recovery discussed above would be an
effective replacement for the eliminated T&O and SECA rates.
Management
is unable to predict whether the FERC will approve either the ALJ’s decision or
another regional rate design. The AEP East companies’ future results of
operations, cash flows and financial condition would be adversely affected
if
the approved FERC transmission rates are not sufficient to replace the lost
T&O/SECA revenues and the resultant increase in the AEP East companies’
unrecovered transmission costs are not fully recovered in retail rates in
Indiana and Michigan.
Calpine
Oneta Power, L.P.’s Request at the FERC for Reactive Power Compensation From SPP
- Affecting PSO and SWEPCo
In
April
2003, Calpine Oneta Power (Calpine), an IPP, filed at the FERC a proposed rate
schedule to charge SPP for reactive power from Calpine’s generating facility.
The FERC rate schedule included a fixed annual fee of $2 million. PSO, SWEPCO
and a small portion of TNC operate in SPP. An ALJ initially ruled against
Calpine and management concluded that the likelihood of the FERC awarding
Calpine a reactive power capacity rate was remote. In September 2006, the FERC
issued its decision reversing the ALJ decision, granting Calpine’s request and
requiring Calpine to make a compliance filing within 30 days. PSO’s, SWEPCo’s
and TNC’s share of this SPP expense could be approximately 90% of the total
amount billed by Calpine. Based on this information, PSO and SWEPCo recorded
expense provisions, including interest, of $4 million and $4 million,
respectively, in September 2006 for the retroactive reactive power liability.
AEP will seek rehearing at the FERC and may appeal the decision if the FERC
either denies rehearing or rules in favor of Calpine on rehearing.
Allocation
Agreement between AEP East companies and AEP West companies and CSW Operating
Agreement - Affecting the AEP East companies and AEP West companies
The
SIA
provides, among other things, for the methodology of sharing trading and
marketing margins between the AEP East companies and AEP West companies. In
March 2006, the FERC approved our proposed methodology effective April 1, 2006
and beyond. The approved allocation methodology for the AEP East companies
and
AEP West companies is based upon the location of the specific trading and
marketing activity, with margins resulting from trading and marketing activities
originating in PJM and MISO generally accruing to the benefit of the AEP East
companies and trading and marketing activities originating in SPP and ERCOT
generally accruing to the benefit of PSO and SWEPCo. Previously, the SIA
allocation provided for a different method of sharing all such margins between
both AEP East companies and AEP West companies, which effectively allowed the
AEP West companies to share in PJM and MISO regional margins. In February 2006,
AEP filed with the FERC to remove TCC and TNC from the SIA and CSW Operating
Agreement because they are in the final stages of exiting the generation
business and have already ceased serving retail load. The FERC approved the
removal of TCC and TNC from the SIA and CSW Operating Agreement effective May
1,
2006. The impact on future results of operations and cash flows will depend
upon
the level of future margins by region and the status of expanded net energy
fuel
clause recovery mechanisms and related off-system sales sharing mechanisms
by
state.
4. CUSTOMER
CHOICE AND INDUSTRY RESTRUCTURING
The
Customer Choice and Industry Restructuring note in the 2005 Annual Report should
be read in conjunction with this report to gain a complete understanding of
material customer choice and industry restructuring matters without significant
changes since year-end. The following paragraphs discuss significant current
events related to customer choice and industry restructuring in those states
and
updates the 2005 Annual Report.
TEXAS
RESTRUCTURING - Affecting TCC, TNC and SWEPCo
In
February 2006, the PUCT issued an order in TCC’s $2.4 billion True-up
Proceeding, which determined that TCC’s true-up regulatory asset was $1.475
billion including carrying costs through September 2005. In December 2005,
TCC
adjusted its recorded net true-up regulatory asset to comply with the order.
The
PUCT issued an order on rehearing in April 2006, which made minor changes to,
but otherwise affirmed, the February 2006 order. TCC appealed, seeking
additional recovery consistent with the Texas Restructuring Legislation and
related rules. Other parties appealed the PUCT’s true-up order claiming it
permits TCC to over-recover stranded generation costs and other true-up
items.
TCC
Securitization Proceeding
TCC
filed
an application in March 2006 requesting recovery through securitization of
$1.8
billion of net stranded generation plant costs and related carrying costs
through August 31, 2006. The $1.8 billion request did not include TCC’s negative
other true-up items, which total $478 million. See “CTC Proceeding for Other
True-up Items” section of this note. Intervenors and the PUCT staff filed
testimony regarding TCC’s securitization request in April 2006. In May 2006, TCC
filed a letter with the PUCT reducing its request by $6 million of current
carrying costs and reduced the recorded net recoverable regulatory asset by
the
recorded debt-related component. In May 2006, TCC and the other parties filed
a
settlement with the PUCT, which further reduced the securitizable amount by
$77
million and settled several issues that would have delayed the sale of the
securitization bonds. The PUCT approved the settlement in June 2006 authorizing
$1.697 billion including carrying costs through August 31, 2006, the assumed
securitization date, plus estimated issuance costs of $23 million, for a total
of $1.72 billion. TCC issued its securitization bonds on October 11, 2006 for
$1.74 billion, including additional issuance costs and carrying costs to October
11, 2006.
TCC
performed a probability of recovery impairment test on its net true-up
regulatory asset taking into account the treatment ordered by the PUCT. TCC
determined that the projected cash flows from the securitization less the
proposed CTC refund would be more than sufficient to recover its recorded net
true-up regulatory asset due to the existence of $224 million of unrecorded
equity-related carrying costs which are not recorded until collected in
regulated rates. As a result, no additional impairment was recorded for the
approved reduction in the amount to be securitized. However, the $77 million
agreed upon reduction in the securitizable amount will have a negative impact
on
future earnings.
Consistent
with certain prior securitization determinations, the PUCT issued a specific
order in the securitization proceeding that calculated a $315 million
cost-of-money benefit from true-up related ADFIT through August 2006, of which
$75 million ($77 million through September 30, 2006) relates to the recorded
benefit prior to the date of securitization and $240 million relates to the
unrecorded benefit subsequent to the date of securitization. The PUCT included
the $315 million ADFIT-related stranded cost benefit in the CTC refund of $478
million. In June 2006, TCC transferred the effects of the ADFIT on recorded
carrying costs from the securitizable asset to the CTC refund, thereby
increasing the carrying costs identified to the securitizable assets in the
table below.
The
differences between the securitization amount ordered by the PUCT of $1.74
billion and the Recorded Securitizable True-up Regulatory Asset of $1.57 billion
by component at September 30, 2006 are detailed in the table below:
|
|
(in
millions)
|
|
Stranded
Generation Plant Costs
|
|
$
|
974
|
|
Net
Generation-related Regulatory Asset
|
|
|
249
|
|
Excess
Earnings
|
|
|
(49
|
)
|
Recorded
Net Stranded Generation Plant Costs
|
|
|
1,174
|
|
Recorded
Debt Carrying Costs on Net Stranded Generation Plant Costs
|
|
|
400
|
|
Recorded
Securitizable True-up Regulatory Asset
|
|
|
1,574
|
|
Unrecorded
But Recoverable Equity Carrying Costs
|
|
|
224
|
|
Unrecorded
Estimated October 2006 Debt Carrying Costs
|
|
|
3
|
|
Unrecorded
Excess Earnings, Related Carrying Costs and Other
|
|
|
53
|
|
Unrecorded
Settlement Reduction
|
|
|
(77
|
)
|
Reduction
for the Present Value of ADITC and EDFIT Benefits
|
|
|
(61
|
)
|
Approved
Securitizable Amount as of October 11, 2006
|
|
|
1,716
|
|
Unrecorded
Securitization Bond Issuance Costs
|
|
|
24
|
|
Amount
Securitized on October 11, 2006
|
|
$
|
1,740
|
|
Deferred
Investment Tax Credits and Excess Deferred Federal Income
Taxes
In
TCC’s
true-up and securitization orders, the PUCT reduced net stranded generation
plant costs and the amount to be securitized by $51 million related to the
present value of ADITC and by $10 million related to EDFIT associated with
TCC’s
generating assets. (See Reduction for the Present Value of ADITC and EDFIT
Benefits of $61 million in the table above.) TCC testified that the sharing
of
these tax benefits with customers might be a violation of the Internal Revenue
Code’s normalization provisions.
TCC
filed
a request for a private letter ruling from the IRS in June 2005 to determine
whether the PUCT’s action would result in a normalization violation. The IRS
issued its private letter ruling on May 9, 2006 which stated that the PUCT’s
flow through to customers of the present value of the ADITC and EDFIT benefits
would result in a normalization violation. TCC informed the PUCT on May 10,
2006
of the adverse ruling, however, the PUCT did not change its order on rehearing.
TCC filed an appeal with the PUCT. As discussed below in the “CTC Proceeding for
Other True-up Items” section of this note, TCC proposed, and the PUCT agreed, to
defer refunding the amount of the present value of its ADITC and EDFIT benefits
through its CTC until this normalization issue is resolved upon the IRS issuance
of final normalization regulations.
If
a
normalization violation occurs, it could result in the repayment of TCC’s ADITC
on all property, including transmission and distribution property, which
approximates $104 million as of September 30, 2006 and also a loss of the right
to claim accelerated tax depreciation in future tax returns. Tax counsel advised
management that a normalization violation should not occur until all remedies
under law have been exhausted and the tax benefits are returned to ratepayers
under a nonappealable order. Management intends to continue its efforts to
avoid
a normalization violation that would adversely affect future results of
operations and cash flows through the appeal of the PUCT’s true-up order and
through a CTC deferral.
CTC
Proceeding for Other True-up Items
In
June
2006, TCC filed to implement a negative CTC to refund its other true-up items
over eight years. TCC will incur interest expense on the other true-up
regulatory liability balances until it is fully refunded. The principal
components of the CTC refund liability are an over-recovered fuel balance,
the
retail clawback and the ADFIT benefit related to TCC’s stranded generation cost,
offset by a positive wholesale capacity auction true-up regulatory asset
balance.
The
differences between the components of TCC’s Recorded Net Regulatory Liabilities
- Other True-up Items of $238 million as of September 30, 2006 (including
interest expense) and its Net CTC Refund Proposed of $357 million are detailed
below:
|
|
(in
millions)
|
|
Wholesale
Capacity Auction True-up
|
|
$
|
61
|
|
Carrying
Costs on Wholesale Capacity Auction True-up
|
|
|
31
|
|
Retail
Clawback including Carrying Costs
|
|
|
(65
|
)
|
Deferred
Over-recovered Fuel Balance
|
|
|
(184
|
)
|
Retrospective
ADFIT Benefit
|
|
|
(77
|
)
|
Other
|
|
|
(4
|
)
|
Recorded
Net Regulatory Liabilities - Other True-up Items
|
|
|
(238
|
)
|
Unrecorded
Prospective ADFIT Benefit
|
|
|
(240
|
)
|
Gross
CTC Refund Proposed
|
|
|
(478
|
)
|
FERC
Jurisdictional Fuel Refund Deferral
|
|
|
16
|
|
ADITC
and EDFIT Benefit Refund Deferral
|
|
|
98
|
|
Net
CTC Refund Proposed, After Deferrals
|
|
|
(364
|
)
|
True-up
Proceeding Expense Surcharge
|
|
|
7
|
|
Net
CTC Refund Proposed, After Deferrals and Expenses
|
|
$
|
(357
|
)
|
TCC
requested that a portion of the refund be deferred, pending the outcome of
two
contingent federal matters related to the refund of $16 million of FERC
jurisdictional fuel over-recoveries (discussed below) and $98 million (including
carrying costs) related to potential tax normalization violation matters related
to the refund of ADITC and EDFIT benefits (discussed above). Under TCC’s
proposal, (a) if the two contingent federal matters are resolved consistent
with
the PUCT’s treatment, TCC will then refund the $16 million and the $98 million
plus carrying costs or (b) if these two issues are not resolved consistent
with
the PUCT’s treatment, the deferred refunds will not be made in order to avoid a
normalization violation and the violation of a Federal court order. Management
cannot predict the final outcome of this filing.
Although
TCC proposed to refund the $357 million over eight years, certain intervenors
supported accelerated refunds. In September 2006, the PUCT approved an interim
CTC that was implemented on October 12, 2006, the same day that TCC began
billing customers for the securitization bonds. The interim CTC will refund
the
entire retail clawback of $65 million (including carrying costs) to residential
customers by the end of 2006. The CTC refund to the other customer classes
during the interim period will be as proposed by TCC, with the exception of
the
large industrials, who will not receive any fuel refunds during the interim
period.
At
an
October 2006 open meeting, the PUCT announced oral decisions regarding the
CTC
refund. A final written order is expected in late November or early December
of
this year. In its decision, the PUCT confirmed that TCC can use securitization
bond proceeds to make the CTC refund. The PUCT’s decision was to continue the
interim CTC through December 2006 to complete the refund of the retail clawback
over three months. Beginning in January 2007, the Deferred Over-recovered Fuel
Balance will be refunded over six months with the large industrial customers
receiving their entire refund in January 2007. Starting in July 2007, the
remaining CTC items will be refunded over one year, except that the PUCT agreed
with TCC’s request to defer the refund of the ADITC and EDFIT Benefit Refund
Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above).
The
PUCT will decide those issues and related amounts in another
proceeding.
Fuel
Balance Recoveries
In
September 2005, the Federal District Court, Western District of Texas, issued
an
order precluding the PUCT from enforcing its ruling in the TNC fuel proceeding
regarding the PUCT’s reallocation of off-system sales margins. In August 2006,
TCC also received an order from the Federal District Court, Western District
of
Texas precluding the PUCT from enforcing its ruling regarding the PUCT’s
reallocation of off-system sales margins in connection with TCC’s final fuel
reconciliation. The favorable Federal District Court order, if upheld on appeal,
could result in reductions to the over-recovered fuel principal balances of
$8
million for TNC and $14 million ($16 million with carrying costs) for TCC.
The
PUCT appealed the TCC and TNC Federal Court decision to the United States Court
of Appeals for the Fifth Circuit. If the PUCT is unsuccessful in the federal
court system, the PUCT may file a complaint at the FERC to address the
allocation issue. TCC and TNC are unable to predict if the Federal District
Court’s decision will be upheld or whether the PUCT will file a complaint at the
FERC. Pending further clarification, TCC and TNC have not reversed their related
provisions for fuel over-recovery. If the PUCT or another party were to file
a
complaint at the FERC that results in the PUCT’s decisions being reinstated, it
could result in an adverse effect on results of operations and cash flows for
the AEP East companies because an unfavorable FERC ruling may result in a
reallocation of off-system sales margins from AEP East companies to AEP West
companies under the then existing SIA allocation method. If the adjustments
were
applied retroactively, the AEP East companies may be unable to recover the
amounts from their customers due to past frozen rates, past inactive fuel
clauses and fuel clauses that do not include off-system sales
credits.
Carrying
Costs on Net True-up Regulatory Assets Impacting Securitization and CTC
Proceedings
In
TCC’s
True-up Proceeding, the PUCT allowed TCC to recover carrying costs at an 11.79%
overall pretax weighted average cost of capital rate approved in its unbundled
cost of service rate proceeding. The recorded embedded debt component of this
carrying cost rate is 8.12%. Through September 30, 2006, TCC recorded $400
million of debt-related carrying costs on stranded generation plant costs
included in the securitization proceeding. Equity carrying costs of $224 million
related to amounts securitized will be recognized in income as collected. TCC
will accrue interest expense until its net CTC refund is fully refunded. The
interest expense on the net CTC refund totals $9 million and $11 million for
the
three and nine months ended September 30, 2006, respectively, and is included
in
Interest Expense on TCC’s Condensed Consolidated Statements of Income.
In
June
2006, the PUCT adopted a proposed rule that prospectively changes the interest
rate applied to TCC’s CTC refund balance. TCC anticipates that the rule change
will reduce the rate TCC will pay on its CTC balance from 11.79% to 7.47%.
TCC
anticipates that the change will reduce its annual refund by approximately
$8
million. The rule also provides for adjustments to the rate during subsequent
rate case proceedings.
TNC
True-up Proceeding
TNC
filed
a CTC proceeding in August 2005 to establish a rate to refund its net true-up
regulatory liability. In December 2005, that proceeding was abated, pending
a
final ruling from TNC’s appeal to the federal court regarding the fuel
proceeding (described above). In August 2006, the parties to TNC’s CTC
proceeding filed a settlement that recommended implementing an interim refund
of
the true-up regulatory liability totaling $13 million, net of the amounts at
issue in the federal court proceeding, over six months beginning in September
2006. In late August 2006, the PUCT approved the settlement and the net refund
began in September 2006. TNC accrues interest expense on the unrefunded balance
and will continue to do so until the balance is fully refunded.
Excess
Earnings
As
noted
in the 2005 Annual Report, the Texas Court of Appeals issued a decision finding
the PUCT’s prior order from the unbundled cost of service case requiring TCC to
refund excess earnings was unlawful under the Texas Restructuring Legislation.
In November 2005, the PUCT filed a petition for review with the Supreme Court
of
Texas seeking reversal of the Texas Court of Appeals’ decision. The Supreme
Court of Texas requested briefing, which has been provided, but it has not
decided whether it will hear the case. Management is unable to predict the
ultimate outcome of these proceedings.
Summary
TCC’s
recorded securitizable true-up regulatory asset at September 30, 2006 of $1.57
billion, net of the recorded net regulatory liabilities for other true-up items
of $238 million, reflects the PUCT’s orders in TCC’s True-up Proceeding and its
securitization proceeding. Barring any future disallowances to TCC’s net
recoverable true-up regulatory asset in any subsequent proceedings or court
rulings, TCC will amortize its total securitizable true-up regulatory asset
commensurate with recovery over the 14-year term of the securitized bonds issued
in October 2006. If TCC determines, as a result of future PUCT orders or appeal
court rulings, that it is probable TCC cannot recover a portion of its recorded
net true-up regulatory asset and TCC is able to estimate the amount of a
resultant impairment, it would record a provision for such amount which would
have an adverse effect on future results of operations, cash flows and possibly
financial condition. Based on advice of Texas rate counsel, TCC appealed the
PUCT orders seeking relief in both state and federal court where TCC believes
the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT
rulemakings and federal law. Municipal customers and other intervenors also
appealed the same PUCT orders seeking to further reduce TCC’s true-up
recoveries.
Although
TCC believes it has meritorious arguments, management cannot predict the
ultimate outcome of any future proceedings or court appeals. If TCC succeeds
in
future appeals, it could have a material favorable effect on TCC’s future
results of operations, cash flows and financial condition. If municipal
customers and other intervenors succeed in their appeals, or if the PUCT does
not approve TCC’s CTC filing as filed and, as a result, causes a normalization
violation, it could have a material adverse effect on TCC’s future results of
operations, cash flows and financial condition.
Texas
Restructuring - SPP
In
August
2006, the PUCT adopted a rule delaying customer choice in the SPP area of Texas
until no sooner than January 1, 2011. SWEPCo and a small portion of TNC’s
business operate in SPP. Approximately 3% of TNC’s operations are located in the
SPP territory, with $13 million in net assets in SPP. A petition was filed
in
May 2006, requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a
subsidiary of AEP C&I Company, LLC) and TNC’s customers, facilities and
certificated service located in the SPP area to SWEPCo. If this petition is
successful, SWEPCo will be AEP’s only subsidiary affected by the delay in the
SPP area.
OHIO
RESTRUCTURING - Affecting CSPCo and OPCo
Rate
Stabilization Plans
In
January 2005, the PUCO approved Rate Stabilization Plans (RSPs) for CSPCo and
OPCo (the Ohio companies). The approved plans in each of 2006, 2007 and 2008
provide, among other things, for CSPCo and OPCo to raise their generation rates
by 3% and 7%, respectively, and provide for possible additional annual
generation rate increases of up to an average of 4% per year based on supporting
the request for additional revenues for specified costs. CSPCo’s potential for
the additional annual 4% generation rate increases is diminished by
approximately three-quarters in 2006 and to a lesser extent in 2007 and 2008
due
to the power acquisition rider approved by the PUCO in the Monongahela Power
service territory acquisition proceeding and the recovery of pre-construction
costs for its share of the jointly-owned IGCC plant (see “IGCC Plant” section of
this note below). OPCo’s potential for additional annual 4% generation rate
increases is diminished in 2006 by approximately one-quarter and to a lesser
extent in 2007 due to the recovery of pre-construction costs for its share
of
the jointly-owned IGCC plant. The RSPs also provide that the Ohio companies
can
recover in 2006, 2007 and 2008 estimated 2004 and 2005 deferred environmental
carrying costs and PJM-related administrative costs and congestion costs net
of
financial transmission rights (FTR) revenue related to their obligation as
the
Provider of Last Resort (POLR) in Ohio’s customer choice program. Pretax
earnings increased by $10 million and $26 million for CSPCo and $20 million
and
$58 million for OPCo in the third quarter and first nine months of 2006,
respectively, from the RSP rate increases net of the amortization of RSP
regulatory assets. These increases also include the recognition of equity
carrying costs. As of September 30, 2006, CSPCo’s and OPCo’s unrecognized equity
carrying costs from 2004 and 2005, which are recognized over the three-year
RSP
period, totaled $4 million and $28 million, respectively. As of September 30,
2006, CSPCo’s and OPCo’s unamortized RSP regulatory assets to be recovered
through December 31, 2008 were $7 million and $36 million, respectively.
In
the
second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio
Supreme Court that challenged the RSPs and also argued that there was no POLR
obligation in Ohio and, therefore, CSPCo and OPCo are not entitled to recover
any POLR charges. In DP&L’s proceeding, the Ohio Supreme Court concluded
that there is a POLR obligation in Ohio, supporting the Ohio companies’ position
that they can recover a POLR charge. In an appeal concerning First Energy
companies’ RSP, the Ohio Supreme Court held that the PUCO’s decision to
eliminate the offer to customers of a price determined through competitive
bids
was unlawful. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP order
for the Ohio companies, which also did not include a competitive bid process,
and remanded the case to the PUCO for further proceedings, not inconsistent
with
the decision in the appeal of the First Energy companies’ RSP. In August 2006,
the PUCO acted on the Ohio companies’ remand case ordering them to file a plan
to provide an option for customer participation in the electric market through
competitive bids or other reasonable means and also held that the RSP shall
remain effective. Accordingly, the Ohio companies continued to collect RSP
revenues. In accordance with the PUCO directive, in September 2006, CSPCo and
OPCo submitted their proposal to provide additional options for customer
participation in the electric market.
In
the
Ohio companies’ case, the Ohio Supreme Court did not address any other issues
that had been raised on appeal, stating that its decision does not preclude
the
Ohio Consumers’ Counsel from raising those issues in a future appeal. Management
believes that the RSP regulatory assets remain probable of recovery and that
the
Ohio companies will continue to collect RSP revenues.
IGCC
Plant
In
March
2005, the Ohio companies filed a joint application with the PUCO seeking
authority to recover costs related to building and operating a new 600 MW IGCC
power plant using clean-coal technology. The application proposed cost recovery
associated with the IGCC plant in three phases: Phase 1, recovery of $24 million
in pre-construction costs during 2006; Phase 2, concurrent recovery of
construction-financing costs; and Phase 3, recovery, or refund, in distribution
rates of any difference between the market-based standard service offer price
for generation and the cost of operating and maintaining the plant, including
a
return on and return of the projected $1.2 billion cost of the plant along
with
fuel, consumables and replacement power costs. The proposed recoveries in Phases
1 and 2 would be applied against the 4% limit on additional generation rate
increases the Ohio companies could request in 2006, 2007 and 2008 under their
RSPs. As of September 30, 2006, CSPCo and OPCo each deferred $8 million and
each
recovered $3 million of pre-construction IGCC costs. We are currently recovering
the remaining deferred amounts through June 30, 2007.
In
April
2006, the PUCO issued an order authorizing the Ohio companies to implement
Phase
1 of the cost recovery proposal. In June 2006, the PUCO issued another order
approving a tariff to recover Phase 1 pre-construction costs over no more than
a
twelve-month period effective July 1, 2006. In its June order, the PUCO
indicated if the Ohio companies have not commenced continuous construction
of
the IGCC plant within five years of the order, all charges collected for
pre-construction costs, which are assignable to other jurisdictions, must be
refunded to Ohio ratepayers with interest. The PUCO deferred ruling on Phases
2
and 3 cost recovery until further hearings are held. No date for a further
hearing has been set.
In
June
2006, the Industrial Energy Users - Ohio (IEU), an intervenor in the PUCO
proceeding, filed a Complaint for Writ of Prohibition at the Ohio Supreme Court
to prohibit the use of the PUCO’s authorization by the Ohio companies to enforce
the collection of the Phase 1 rates and to prohibit the PUCO from further
entertaining any increase in rates for the IGCC project. The Court subsequently
granted a PUCO motion to dismiss the Complaint for Writ of Prohibition.
In
August
2006, IEU, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group
filed four separate appeals of the PUCO’s order in the IGCC proceeding. The Ohio
companies believe that the PUCO’s authorization to begin collection of Phase 1
rates is lawful. The Ohio companies, however, cannot predict the outcome of
these appeals. If the PUCO’s order is found to be unlawful, the Ohio companies’
future results of operations and cash flows will be adversely
affected.
Transmission
Rate Filing
In
accordance with the RSPs, in December 2005, the PUCO approved the recovery
of
certain RTO transmission costs through separate transmission cost recovery
riders for the Ohio companies. The transmission cost recovery riders are subject
to an annual true-up process with over/under recovery mechanisms. In February
2006, the Ohio companies filed a request with the PUCO to incorporate all
transmission costs and rates in their transmission cost recovery riders and
institute a two-step increase to reflect the increases in the FERC-approved
rates. In the filing, the first increase would be effective April 1, 2006 to
reflect the Ohio companies’ share of the loss of SECA revenues and the second
increase would be effective August 1, 2006 to recover their share of the cost
of
the new Wyoming-Jacksons Ferry 765 kV line. In May 2006, the PUCO issued an
order approving a two-step increase in the transmission cost recovery riders
with over/under recovery mechanisms, effective April 1, 2006. The new tariffs
were filed with the PUCO and implemented in June 2006.
In
October 2006, the Ohio companies filed for initial true-ups under the
transmission cost recovery riders’ over/under recovery mechanisms. The filings
reflect the refund of regulatory liabilities as of September 30, 2006 of $12
million and $16 million for CSPCo and OPCo, respectively, including carrying
charges. These over-recoveries were reflected as part of the new transmission
cost recovery rider filed to be effective January 2007. The Ohio companies
anticipate the net effect of the new transmission cost recovery riders will
result in increased cost recoveries over 2005 levels for CSPCo and OPCo of
$27
million and $36 million, respectively, in 2006 and $15 million and $16 million,
respectively, in 2007.
Distribution
Service Reliability and Restoration Costs
In
December 2003, the Ohio companies entered into a stipulation agreement regarding
distribution service reliability. The stipulation agreement covered the years
2004 and 2005 and, among other features, established certain distribution
service reliability measures that the Ohio companies were to meet. In July
2006,
based on the staff report on service reliability and responses filed by the
Ohio
companies, the PUCO directed the Ohio companies to earmark $10 million for
future measures to improve service reliability without recovery. The PUCO
further indicated that it will determine where and how the $10 million will
best
be applied.
In
March
2006, the Ohio companies filed an application with the PUCO to implement tariff
riders to recover a portion of previously expensed incremental costs of
restoring service disrupted by severe winter storms in December 2004 and January
2005. CSPCo and OPCo each requested recovery of approximately $12 million of
such costs, which was approved by the PUCO in August 2006. Effective September
1, 2006, the Ohio companies implemented the storm cost recovery riders, which
will continue until they have collected the authorized amounts or one year,
whichever is shorter. In September 2006, the Ohio Consumers’ Counsel filed a
request for rehearing with the PUCO, which was denied in October 2006.
As
a
result of the above, in September 2006 CSPCo and OPCo each
recorded regulatory assets of $7 million, favorably affecting
earnings.
Ormet
In
June
2006, the PUCO found that South Central Power Company (SCP), a
nonaffiliate, was not providing or proposing to provide physically adequate
service to Ormet Primary Aluminum Corporation and Ormet Primary Mill Products
Corporation (together, Ormet). In October 2006, the PUCO convened a hearing
to
determine if an electric supplier, other than SCP, should be authorized to
serve
Ormet’s 520 MW load.
Subsequent
to the hearing, the Ohio companies together with Ormet, its employees’ union and
certain other interested parties filed a settlement agreement with the PUCO
for
approval. The settlement agreement provides for the reallocation of the service
territories of CSPCo, OPCo and SCP so that Ormet’s Hannibal, Ohio facilities are
located in a joint CSPCo/OPCo certified territory effective January 1, 2007.
The
settlement also provides for the recovery in 2007 and 2008 by CSPCo and OPCo
of
the difference between $43 per MWH paid by Ormet and a to-be-determined market
price submitted by management and reviewed by the PUCO. The recovery is
accomplished by the amortization to income of a $57 million ($15 million for
CSPCo and $42 million for OPCo) Ohio franchise tax phase-out regulatory
liability recorded in 2005 and, if that is not sufficient, an increase in RSP
generation rates under the additional 4% provision of the RSP. The $43 per
MWH
price for generation services is above the industrial RSP generation tariff
but below current market prices.
Customer
Choice Deferrals
As
provided in stipulation agreements approved by the PUCO in 2000, the Ohio
companies defer customer choice implementation costs and related carrying costs
in excess of $20 million each. The agreements provide for the deferral of these
costs as regulatory assets until the next distribution base rate cases. Through
September 30, 2006, CSPCo and OPCo incurred $48 million and $49 million,
respectively, of such costs and, accordingly, deferred $24 million each of
such
costs for probable future recovery in distribution rates. CSPCo and OPCo have
not recorded $4 million and $5 million, respectively, of equity carrying costs,
which are not recognized until collected. Pursuant to the RSPs, recovery of
these amounts is subject to PUCO review and is deferred until the next
distribution rate filing to change rates after the December 31, 2008 end of
the
RSP period. Management believes that the deferred customer choice implementation
costs were prudently incurred to implement customer choice in Ohio and should
be
recoverable in future distribution rates. If the PUCO determines that any of
the
deferred costs are unrecoverable, it would have an adverse impact on the Ohio
companies’ future results of operations and cash flows.
5. COMMITMENTS
AND CONTINGENCIES
As
discussed in the Commitments and Contingencies note within the 2005 Annual
Report, certain Registrant Subsidiaries continue to be involved in various
legal
matters. The 2005 Annual Report should be read in conjunction with this report
in order to understand the other material nuclear and operational matters
without significant changes since their disclosure in the 2005 Annual Report.
See disclosure below for significant matters and changes in status subsequent
to
the disclosure made in the 2005 Annual Report.
ENVIRONMENTAL
Federal
EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and
OPCo
The
Federal EPA and a number of states alleged that APCo, CSPCo, I&M, OPCo and
other nonaffiliated utilities, including the Tennessee Valley Authority, Alabama
Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company,
Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa
Electric Company, Virginia Electric Power Company and Duke Energy, modified
certain units at coal-fired generating plants in violation of the NSR
requirements of the CAA. The Federal EPA filed its complaints against AEP
subsidiaries in U.S. District Court for the Southern District of Ohio. The
court
also consolidated a separate lawsuit, initiated by certain special interest
groups, with the Federal EPA case. The alleged modifications occurred at our
generating units over a 20-year period. A bench trial on the liability issues
was held during July 2005. Briefing has concluded. In June 2006, the judge
stayed the liability decision pending the issuance of a decision by the U.S.
Supreme Court in the Duke Energy case. A bench trial on remedy issues, if
necessary, is scheduled to begin four months after the U.S. Supreme Court
decision is issued.
Under
the
CAA, if a plant undertakes a major modification that directly results in an
emissions increase, permitting requirements might be triggered and the plant
may
be required to install additional pollution control technology. This requirement
does not apply to activities such as routine maintenance, replacement of
degraded equipment or failed components or other repairs needed for the
reliable, safe and efficient operation of the plant. The CAA authorizes civil
penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation
at each generating unit. In 2001, the District Court ruled claims for civil
penalties based on activities that occurred more than five years before the
filing date of the complaints cannot be imposed. There is no time limit on
claims for injunctive relief.
The
Federal EPA and eight northeastern states each filed an additional complaint
containing additional allegations against the Amos and Conesville plants. APCo
and CSPCo filed an answer to the northeastern states’ complaint and the Federal
EPA’s complaint, denying the allegations and stating their defenses. Cases are
also pending that could affect CSPCo’s share of jointly-owned units at Beckjord
(12.5% owned), Zimmer (25.4% owned) and Stuart (26% owned) stations. Similar
cases have been filed against other nonaffiliated utilities, including Allegheny
Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group,
Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara
Mohawk. Several of these cases were resolved through consent
decrees.
Courts
have reached different conclusions regarding whether the activities at issue
in
these cases are routine maintenance, repair, or replacement, and therefore
are
excluded from NSR. Similarly, courts have reached different results regarding
whether the activities at issue increased emissions from the power plants.
Appeals on these and other issues were filed in certain appellate courts,
including a petition to appeal to the U.S. Supreme Court that was granted in one
case. The Federal EPA issued a final rule that would exclude activities similar
to those challenged in these cases from NSR as “routine replacements.” In March
2006, the Court of Appeals for the District of Columbia Circuit issued a
decision vacating the rule. The Federal EPA filed a petition for rehearing
in
that case, which the Court denied. The Federal EPA also recently proposed a
rule
that would define “emissions increases” in a way that would exclude most of the
challenged activities from NSR.
Management
is
unable to estimate the loss or range of loss related to any contingent liability
AEP subsidiaries might have for civil penalties under the CAA proceedings.
Management is also unable to predict the timing of resolution of these matters
due to the number of alleged violations and the significant number of issues
yet
to be determined by the Court. If AEP subsidiaries do not prevail, management
believes AEP subsidiaries can recover any capital and operating costs of
additional pollution control equipment that may be required through regulated
rates and market prices for electricity. If
any of
the AEP subsidiaries are unable to recover such costs or if material penalties
are imposed, it would adversely affect future results of operations, cash flows
and possibly financial condition.
Notice
of Enforcement and Notice of Citizen Suit - Affecting
SWEPCo
In
July
2004, two special interest groups, Sierra Club and Public Citizen, issued a
notice of intent to commence a citizen suit under the CAA for alleged violations
of various permit conditions in permits issued to several SWEPCo generating
plants. In March 2005, the special interest groups filed a complaint in Federal
District Court for the Eastern District of Texas alleging violations of the
CAA
at Welsh Plant. SWEPCo filed a response to the complaint in May 2005. Other
preliminary motions have been filed and are pending before the
Court.
In
July
2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice
of
Enforcement to SWEPCo relating to the Welsh Plant containing a summary of
findings resulting from a compliance investigation at the plant. In April 2005,
TCEQ issued an Executive Director’s Preliminary Report and Petition recommending
the entry of an enforcement order to undertake certain corrective actions and
assessing an administrative penalty of approximately $228 thousand against
SWEPCo based on alleged violations of certain representations regarding heat
input in SWEPCo’s permit application and the violations of certain recordkeeping
and reporting requirements. SWEPCo responded to the preliminary report and
petition in May 2005. The enforcement order contains a recommendation that
would
limit the heat input on each Welsh unit to the referenced heat input contained
within the permit application within 10 days of the issuance of a final TCEQ
order and until a permit amendment is issued. SWEPCo had previously requested
a
permit alteration to remove the reference to a specific heat input value for
each Welsh unit.
Management
is unable to predict the timing of any future action by TCEQ or the special
interest groups or the effect of such actions on results of operations,
financial condition or cash flows.
Carbon
Dioxide Public Nuisance Claims - Affecting AEP East Companies and AEP West
Companies
In
July
2004, attorneys general from eight states and the corporation counsel for 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. That same day, the Natural Resources
Defense Council, on behalf of three special interest groups, filed a similar
complaint in the same court against the same defendants. The actions alleged
that CO2
emissions
from the defendants’ power plants constitute a public nuisance under federal
common law due to impacts associated with global warming and sought injunctive
relief in the form of specific emission reduction commitments from the
defendants. In September 2004, the defendants, including AEP and AEPSC, filed
a
motion to dismiss the lawsuits. In September 2005, the lawsuits were dismissed.
The trial court’s dismissal was appealed to the Second Circuit Court of Appeals.
Briefing and oral argument have been completed. Management believes the actions
are without merit and intends to defend against the claims.
Ontario
Litigation - Affecting CSPCo and OPCo
In
June
2005, CSPCo, OPCo and nineteen nonaffiliated utilities were named as defendants
in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. CSPCo
and OPCo have not been served with the lawsuit. The time limit for serving
the
defendants expired but the case has not been dismissed. The defendants are
alleged to own or operate coal-fired electric generating stations in various
states that, through negligence in design, management, maintenance and
operation, emitted NOX,
SO2
and
particulate matter that harmed the residents of Ontario. The lawsuit seeks
class
action designation and damages of approximately $49 billion, with continuing
damages of $4 billion annually. The lawsuit also seeks $1 billion in punitive
damages. Management believes CSPCo and OPCo have meritorious defenses to this
action and intend to defend against it.
OPERATIONAL
Power
Generation Facility and TEM Litigation - Affecting
OPCo
AEP
has
agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed
and financed a merchant power generation facility (Facility) near Plaquemine,
Louisiana and leased the Facility to AEP. AEP subleased the Facility to the
Dow
Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration
facility” for purposes of PURPA. In September 2006, AEP agreed to sell the
Facility to Dow.
Dow
uses
a portion of the energy produced by the Facility and sells the excess energy.
OPCo agreed to purchase up to approximately 800 MW of such excess energy from
Dow for a 20-year term. Because the Facility is a major steam supply for Dow,
Dow is expected to operate the Facility at certain minimum levels, and OPCo
is
obligated to purchase the energy generated at those minimum operating levels
(approximately 270 MW). OPCo sells the purchased energy at market prices in
the
Entergy sub-region of the Southeastern Electric Reliability Council
market.
OPCo
agreed to sell up to approximately 800 MW of energy to TEM for a period of
20
years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA),
at a price that is currently in excess of market. Beginning May 1, 2003, OPCo
tendered replacement capacity, energy and ancillary services to TEM pursuant
to
the PPA that TEM rejected as nonconforming. Commercial operation for purposes
of
the PPA began April 2, 2004.
In
September 2003, TEM and AEP separately filed declaratory judgment actions in
the
U.S. District Court for the Southern District of New York. AEP alleged that
TEM
breached the PPA and sought a determination of its rights under the PPA. TEM
alleged that the PPA never became enforceable, or alternatively, that the PPA
was terminated as the result of AEP’s breaches. The corporate parent of TEM
(SUEZ-TRACTEBEL S.A.) provided a limited guaranty.
In
April
2004, OPCo gave notice to TEM that OPCo (a) was suspending performance of its
obligations under the PPA; (b) would seek a declaration from the District Court
that the PPA was terminated; and (c) would pursue TEM and SUEZ-TRACTEBEL S.A.
under the guaranty, seeking damages and the full termination payment value
of
the PPA.
A
bench
trial was conducted in March and April 2005. In August 2005, a federal judge
ruled that TEM breached the contract and awarded damages to AEP of $123 million
plus prejudgment interest. In August 2005, both parties filed motions with
the
trial court seeking reconsideration of the judgment. AEP asked the court to
modify the judgment to (a) award a termination payment to AEP under the terms
of
the PPA; (b) grant AEP’s attorneys’ fees; and (c) render judgment against
SUEZ-TRACTEBEL S.A. on the guaranty. TEM sought reduction of the damages awarded
by the court for replacement electric power products made available by OPCo
under the PPA. In January 2006, the trial judge granted AEP’s motion for
reconsideration concerning TEM’s parent guaranty and increased AEP’s judgment
against TEM to $173 million plus prejudgment interest, and denied the remaining
motions for reconsideration. In March 2006, the trial judge amended the January
2006 order eliminating the additional $50 million damage award.
In
September 2005, TEM posted a letter of credit for $142 million as security
pending appeal of the judgment. Both parties have filed Notices of Appeal with
the United States Court of Appeals for the Second Circuit. Oral argument is
scheduled for December 2006. If the PPA is deemed terminated or found
unenforceable by the court ultimately deciding the case, OPCo could be adversely
affected to the extent OPCo is unable to find other purchasers of the power
with
similar contractual terms (if AEP’s sale of the Facility does not close) and to
the extent claimed termination value damages are not fully recovered from
TEM.
Coal
Transportation Dispute - Affecting PSO, TCC and TNC
PSO,
TCC,
TNC and two nonaffiliated entities, as joint owners of a generating station,
disputed transportation costs for coal received between July 2000 and the
present time. The joint plant remitted less than the amount billed and the
dispute is pending before the Surface Transportation Board. Based upon a
weighted average probability analysis of possible outcomes, PSO, as operator
of
the plant, recorded provisions for possible loss in 2004, 2005 and 2006. The
provision was deferred as a regulatory asset under PSO’s fuel mechanism and
immaterially affected income for TCC and TNC for their respective ownership
shares. Management continues to work toward mitigating the disputed amounts
to
the extent possible.
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 January 2006. The arbitration
board filed its decision in April 2006, which denied BNSF’s underpayments claim.
In May 2006, 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 August 2006, PSO filed its response, to which BNSF
filed
its reply. Management continues to work toward mitigating the disputed amounts
to the extent possible.
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.
In
December 2002, a FERC ALJ ruled in AEP’s favor and dismissed the complaint filed
by the Nevada utilities. In 2001, the Nevada
utilities filed complaints asserting that the prices for power supplied under
those contracts should be lowered because the market for power was allegedly
dysfunctional at the time such contracts were executed. The ALJ rejected the
Nevada
utilities' complaint, held that the markets for future delivery were not
dysfunctional and that the Nevada
utilities failed to demonstrate that the public interest required changes be
made to the contracts. In June 2003, the FERC issued an order affirming the
ALJ’s decision. The Nevada
utilities’ request for a rehearing was denied. The Nevada
utilities’ appeal of the FERC order is pending before the U.S. Court of Appeals
for the Ninth Circuit. Management
is unable to predict the outcome of this proceeding and its impact on future
results of operations and cash flows.
COMMITMENTS
Construction
- Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and
TNC
The
Registrant Subsidiaries have substantial construction commitments to support
their operations and environmental investments. The following table shows the
revised estimated construction expenditures by Registrant Subsidiary for
2006:
|
|
(in
millions)
|
|
AEGCo
|
|
$
|
12
|
|
APCo
|
|
|
928
|
|
CSPCo
|
|
|
319
|
|
I&M
|
|
|
330
|
|
KPCo
|
|
|
54
|
|
OPCo
|
|
|
1,065
|
|
PSO
|
|
|
262
|
|
SWEPCo
|
|
|
315
|
|
TCC
|
|
|
286
|
|
TNC
|
|
|
72
|
|
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, legal
reviews and the ability to access capital.
6. GUARANTEES
There
are
certain immaterial liabilities recorded for guarantees in accordance with FIN
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 the event any guarantee is drawn, there is no
recourse to third parties unless specified below.
Letters
of Credit
Certain
Registrant Subsidiaries have entered into standby letters of credit (LOCs)
with
third parties. These LOCs cover items such as insurance programs, security
deposits, debt service reserves and credit enhancements for issued bonds. All
of
these LOCs were issued in the subsidiaries’ ordinary course of business. At
September 30, 2006, the maximum future payments of the LOCs include $1 million
and $4 million for I&M and SWEPCo, respectively, with maturities ranging
from December 2006 to March 2007.
SWEPCo
In
connection with reducing the cost of the lignite mining contract for its Henry
W. Pirkey Power Plant, SWEPCo agreed, under certain conditions, to assume the
capital lease obligations and term loan payments of the mining contractor,
Sabine Mining Company (Sabine). If Sabine defaults under any of these
agreements, SWEPCo’s total future maximum payment exposure is approximately $68
million with maturity dates ranging from February 2007 to February
2012.
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 $85 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. This guarantee ends upon
depletion of reserves and final reclamation is completed. At September 30,
2006,
it is estimated the reserves will be depleted in 2029 with final reclamation
completed by 2036. The cost for final reclamation during the period 2029 through
2036 is estimated at approximately $39 million.
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, 2006, TCC entered into sales agreements with a maximum
indemnification exposure of $443 million related to the sale price of its
generation assets. See “Texas Plants - South Texas Project” and “Texas Plants -
TCC and TNC Generation Assets” sections of Note 10 of the 2005 Annual Report.
There are no material liabilities recorded for any
indemnifications.
AEP
East
companies, PSO and SWEPCo are jointly and severally liable for activity
conducted by AEPSC on behalf of AEP East companies, PSO and SWEPCo related
to
power purchase and sale activity conducted pursuant to the SIA.
Master
Operating Lease
Certain
Registrant Subsidiaries lease certain equipment under a master operating lease.
Under the lease agreement, the lessor is guaranteed to receive up to 87% of
the
unamortized balance of the equipment at the end of the lease term. If the fair
market value of the leased equipment is below the unamortized balance at the
end
of the lease term, the subsidiary has committed to pay the difference between
the fair market value and the unamortized balance, with the total guarantee
not
to exceed 87% of the unamortized balance. At September 30, 2006, the maximum
potential loss by subsidiary for these lease agreements, assuming the fair
market value of the equipment is zero at the end of the lease term, is as
follows:
Maximum
Potential Loss
|
|
Subsidiary
|
|
(in
millions)
|
|
APCo
|
|
$
|
7
|
|
CSPCo
|
|
|
4
|
|
I&M
|
|
|
5
|
|
KPCo
|
|
|
2
|
|
OPCo
|
|
|
7
|
|
PSO
|
|
|
5
|
|
SWEPCo
|
|
|
5
|
|
TCC
|
|
|
6
|
|
TNC
|
|
|
3
|
|
7. COMPANY-WIDE
STAFFING AND BUDGET REVIEW
The
following table shows the severance benefits expense recorded in 2005 (primarily
in Maintenance and Other Operation) resulting from a company-wide staffing
and
budget review, including the allocation of approximately $19.2 million of
severance benefits expense associated with AEPSC employees among the Registrant
Subsidiaries. AEGCo has no employees but received allocated
expenses.
|
|
Three
Months Ended Sept. 30, 2005
|
|
Nine
Months Ended Sept. 30, 2005
|
|
Company
|
|
(in
millions)
|
|
AEGCo
|
|
$
|
0.1
|
|
$
|
0.3
|
|
APCo
|
|
|
0.6
|
|
|
4.5
|
|
CSPCo
|
|
|
0.3
|
|
|
2.6
|
|
I&M
|
|
|
0.7
|
|
|
4.7
|
|
KPCo
|
|
|
0.4
|
|
|
1.1
|
|
OPCo
|
|
|
0.5
|
|
|
3.9
|
|
PSO
|
|
|
0.2
|
|
|
1.4
|
|
SWEPCo
|
|
|
0.2
|
|
|
1.8
|
|
TCC
|
|
|
0.5
|
|
|
4.3
|
|
TNC
|
|
|
0.2
|
|
|
1.3
|
|
Remaining
accruals, reflected primarily in Current Liabilities - Other, ranged from $8
thousand to $1.1 million as of December 31, 2005, and were settled by June
30,
2006. Payments and accrual adjustments recorded during 2006 were
immaterial.
8. ACQUISITIONS,
ASSETS HELD FOR SALE AND ASSET IMPAIRMENTS
ACQUISITIONS
Waterford
Plant - Affecting CSPCo
In
May
2005, CSPCo signed a purchase and sale agreement with Public Service Enterprise
Group Waterford Energy LLC for the purchase of an 821 MW plant in Waterford,
Ohio. This transaction was completed in September 2005 for $218 million and
the
assumption of liabilities of approximately $2 million.
ASSETS
HELD FOR SALE
Texas
Plants - Oklaunion Power Station - Affecting TCC
In
January 2004, TCC signed an agreement to sell its 7.81% share of Oklaunion
Power
Station for approximately $43 million (subject to closing adjustments) to Golden
Spread Electric Cooperative, Inc. (Golden Spread), subject to a right of first
refusal by the Oklahoma Municipal Power Authority and the Public Utilities
Board
of the City of Brownsville (the nonaffiliated co-owners). By May 2004, TCC
received notice from the nonaffiliated co-owners announcing their decision
to
exercise their right of first refusal with terms similar to the original
agreement. In June 2004 and September 2004, TCC entered into sales agreements
with both of the nonaffiliated co-owners for the sale of TCC’s 7.81% ownership
of the Oklaunion Power Station. Golden Spread challenged these agreements in
State District Court in Dallas County. Golden Spread alleges that the Public
Utilities Board of the City of Brownsville exceeded its legal authority and
that
the Oklahoma Municipal Power Authority did not exercise its right of first
refusal in a timely manner. Golden Spread requested that the court declare
the
nonaffiliated co-owners’ exercise of their rights of first refusal void. The
court entered a judgment in favor of Golden Spread in October 2005. TCC and
the
nonaffiliated co-owners filed an appeal to the Court of Appeals for the Fifth
District at Dallas. In May 2006, the Court of Appeals for the Fifth District
at
Dallas reversed the trial court’s judgment in favor of Golden Spread and held
that the City of Brownsville properly exercised its right of first refusal
to
acquire TCC’s share of Oklaunion. Golden Spread requested a rehearing in the
matter, and its petition was denied. Golden Spread then appealed to the Supreme
Court of Texas and in August 2006, the court requested a response from TCC,
the
Oklahoma Municipal Power Authority and the Public Utilities Board of the City
of
Brownsville. Responses were due October 27, 2006. TCC cannot predict when these
issues will be resolved. TCC does not expect the sale to have a significant
effect on its future results of operations. TCC’s assets related to the
Oklaunion Power Station are classified as Assets Held for Sale - Texas
Generation Plants on TCC’s Condensed Consolidated Balance Sheets at September
30, 2006 and December 31, 2005. The plant does not meet the
“component-of-an-entity” criteria because it does not have cash flows that can
be clearly distinguished operationally. The plant also does not meet the
“component-of-an-entity” criteria for financial reporting purposes because it
does not operate individually, but rather as a part of the AEP System, which
includes all of the generation facilities owned by the Registrant
Subsidiaries.
Assets
Held for Sale at September 30, 2006 and December 31, 2005 are as
follows:
Texas
Plants (TCC)
|
|
September
30, 2006
|
|
December
31, 2005
|
|
Assets:
|
|
(in
millions)
|
Other
Current Assets
|
|
$
|
2
|
|
$
|
1
|
|
Property,
Plant and Equipment, Net
|
|
|
44
|
|
|
43
|
|
Total
Assets Held for Sale - Texas Generation Plants
|
|
$
|
46
|
|
$
|
44
|
|
ASSET
IMPAIRMENTS
Conesville
Units 1 and 2 - Affecting CSPCo
In
the
third quarter of 2005, following an extensive review of the commercial viability
of CSPCo’s Conesville Units 1 and 2, CSPCo committed to a plan to retire these
units before the end of their previously estimated useful lives. As a result,
Conesville Units 1 and 2 were considered retired as of the third quarter of
2005.
CSPCo
recognized a pretax charge of approximately $39 million in the third quarter
of
2005 related to its decision to retire the units. CSPCo classified the
impairment amount in Asset Impairments and Other Related Charges on its
Condensed Consolidated Statements of Income.
9. BENEFIT
PLANS
APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP
sponsored U.S. 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, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in other
postretirement benefit plans sponsored by AEP to provide medical and death
benefits for retired employees.
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, 2006 and
2005:
Three
Months Ended September 30, 2006 and 2005:
|
|
Pension
Plans
|
|
Other
Postretirement
Benefit
Plans
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$
|
23
|
|
$
|
23
|
|
$
|
10
|
|
$
|
10
|
|
Interest
Cost
|
|
|
57
|
|
|
57
|
|
|
26
|
|
|
26
|
|
Expected
Return on Plan Assets
|
|
|
(82
|
)
|
|
(77
|
)
|
|
(24
|
)
|
|
(23
|
)
|
Amortization
of Transition (Asset) Obligation
|
|
|
-
|
|
|
(1
|
)
|
|
7
|
|
|
6
|
|
Amortization
of Net Actuarial Loss
|
|
|
20
|
|
|
13
|
|
|
5
|
|
|
5
|
|
Net
Periodic Benefit Cost
|
|
$
|
18
|
|
$
|
15
|
|
$
|
24
|
|
$
|
24
|
|
Nine
Months Ended September 30, 2006 and 2005:
|
|
Pension
Plans
|
|
Other
Postretirement
Benefit
Plans
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$
|
71
|
|
$
|
69
|
|
$
|
30
|
|
$
|
31
|
|
Interest
Cost
|
|
|
171
|
|
|
169
|
|
|
76
|
|
|
79
|
|
Expected
Return on Plan Assets
|
|
|
(248
|
)
|
|
(232
|
)
|
|
(70
|
)
|
|
(68
|
)
|
Amortization
of Transition (Asset) Obligation
|
|
|
-
|
|
|
(1
|
)
|
|
21
|
|
|
20
|
|
Amortization
of Net Actuarial Loss
|
|
|
59
|
|
|
40
|
|
|
15
|
|
|
19
|
|
Net
Periodic Benefit Cost
|
|
$
|
53
|
|
$
|
45
|
|
$
|
72
|
|
$
|
81
|
|
The
following table provides the net periodic benefit cost (credit) for the three
and nine months ended September 30, 2006 and 2005:
Three
Months Ended September 30, 2006 and 2005:
|
|
Pension
Plans
|
|
Other
Postretirement
Benefit
Plans
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
APCo
|
|
$
|
1,469
|
|
$
|
1,848
|
|
$
|
4,487
|
|
$
|
4,756
|
|
CSPCo
|
|
|
205
|
|
|
534
|
|
|
1,807
|
|
|
1,928
|
|
I&M
|
|
|
2,331
|
|
|
2,365
|
|
|
2,949
|
|
|
3,134
|
|
KPCo
|
|
|
360
|
|
|
376
|
|
|
512
|
|
|
515
|
|
OPCo
|
|
|
823
|
|
|
1,206
|
|
|
3,395
|
|
|
3,353
|
|
PSO
|
|
|
979
|
|
|
72
|
|
|
1,588
|
|
|
1,661
|
|
SWEPCo
|
|
|
1,222
|
|
|
364
|
|
|
1,578
|
|
|
1,642
|
|
TCC
|
|
|
772
|
|
|
(219
|
)
|
|
1,699
|
|
|
1,789
|
|
TNC
|
|
|
326
|
|
|
41
|
|
|
715
|
|
|
784
|
|
Nine
Months Ended September 30, 2006 and 2005:
|
|
Pension
Plans
|
|
Other
Postretirement
Benefit
Plans
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
APCo
|
|
$
|
4,406
|
|
$
|
5,544
|
|
$
|
13,465
|
|
$
|
15,248
|
|
CSPCo
|
|
|
615
|
|
|
1,602
|
|
|
5,417
|
|
|
6,273
|
|
I&M
|
|
|
6,992
|
|
|
7,095
|
|
|
8,855
|
|
|
10,229
|
|
KPCo
|
|
|
1,076
|
|
|
1,128
|
|
|
1,538
|
|
|
1,689
|
|
OPCo
|
|
|
2,478
|
|
|
3,618
|
|
|
10,187
|
|
|
10,812
|
|
PSO
|
|
|
2,935
|
|
|
216
|
|
|
4,764
|
|
|
5,329
|
|
SWEPCo
|
|
|
3,672
|
|
|
1,092
|
|
|
4,734
|
|
|
5,244
|
|
TCC
|
|
|
2,317
|
|
|
(657
|
)
|
|
5,091
|
|
|
5,732
|
|
TNC
|
|
|
978
|
|
|
123
|
|
|
2,145
|
|
|
2,507
|
|
10. INCOME
TAXES
In
the
second quarter of 2006, the Texas state legislature replaced the existing
franchise/income tax with a gross margin tax at a 1% rate for electric
utilities. Overall, the new law reduces Texas income tax rates and is effective
January 1, 2007. The new gross margin tax is income-based for purposes of the
application of SFAS 109 “Accounting for Income Taxes.” Based on the new law,
management reviewed deferred tax liabilities with consideration given to the
rate changes and changes to the allowed deductible items with temporary
differences. As a result, in the second quarter of 2006 the following
adjustments were recorded (in thousands):
Company
|
|
Decrease
in SFAS 109 Regulatory Asset, Net
|
|
Decrease
in State Income Tax Expense
|
|
Decrease
in Deferred State Income Tax Liabilities
|
|
TCC
|
|
$
|
36,315
|
|
$
|
-
|
|
$
|
36,315
|
|
TNC
|
|
|
4,801
|
|
|
1,265
|
|
|
6,066
|
|
PSO
|
|
|
-
|
|
|
3,273
|
|
|
3,273
|
|
SWEPCo
|
|
|
4,438
|
|
|
501
|
|
|
4,939
|
|
11. BUSINESS
SEGMENTS
All
of
AEP’s Registrant Subsidiaries have one reportable segment. The one reportable
segment is an integrated electricity generation, transmission and distribution
business except AEGCo, which is an electricity generation business. All of
the
Registrant Subsidiaries’ other activities are insignificant. The Registrant
Subsidiaries’ operations are managed on an integrated basis because of the
substantial impact of bundled cost-based rates and regulatory oversight on
the
business process, cost structures and operating results.
12. FINANCING
ACTIVITIES
Long-term
Debt
Long-term
debt and other securities issued, retired and principal payments made during
the
first nine months of 2006 were:
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
Pollution
Control Bonds
|
|
$
|
50,275
|
|
Variable
|
|
2036
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
250,000
|
|
5.55
|
|
2011
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
250,000
|
|
6.375
|
|
2036
|
I&M
|
|
Pollution
Control Bonds
|
|
|
50,000
|
|
Variable
|
|
2025
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
65,000
|
|
Variable
|
|
2036
|
OPCo
|
|
Senior
Unsecured Notes
|
|
|
350,000
|
|
6.00
|
|
2016
|
PSO
|
|
Senior
Unsecured Notes
|
|
|
150,000
|
|
6.15
|
|
2016
|
SWEPCo
|
|
Pollution
Control Bonds
|
|
|
81,700
|
|
Variable
|
|
2018
|
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Retirements
and Principal Payments:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
First
Mortgage Bonds
|
|
$
|
100,000
|
|
6.80
|
|
2006
|
APCo
|
|
Other
|
|
|
8
|
|
13.718
|
|
2026
|
I&M
|
|
Pollution
Control Bonds
|
|
|
50,000
|
|
6.55
|
|
2025
|
OPCo
|
|
Notes
Payable
|
|
|
4,390
|
|
6.81
|
|
2008
|
OPCo
|
|
Notes
Payable
|
|
|
6,500
|
|
6.27
|
|
2009
|
SWEPCo
|
|
Notes
Payable
|
|
|
5,039
|
|
4.47
|
|
2011
|
SWEPCo
|
|
Notes
Payable
|
|
|
2,250
|
|
Variable
|
|
2008
|
SWEPCo
|
|
Pollution
Control Bonds
|
|
|
81,700
|
|
6.10
|
|
2018
|
TCC
|
|
Securitization
Bonds
|
|
|
52,265
|
|
5.01
|
|
2010
|
In
addition to the transactions reported in the tables above, the following table
lists intercompany issuances and retirements of debt due to AEP:
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
TCC
|
|
Notes
Payable
|
|
$
|
125,000
|
|
5.14
|
|
2007
|
TCC
|
|
Notes
Payable
|
|
|
70,000
|
|
5.86
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
Retirements:
|
|
|
|
|
|
|
|
|
|
KPCo
|
|
Notes
Payable
|
|
|
40,000
|
|
6.501
|
|
2006
|
OPCo
|
|
Notes
Payable
|
|
|
200,000
|
|
3.32
|
|
2006
|
PSO
|
|
Notes
Payable
|
|
|
50,000
|
|
3.35
|
|
2006
|
In
October 2006, TCC issued $1.74 billion in securitization bonds as
follows:
Principal
Amount
|
|
Interest
|
|
Scheduled
Final Payment
|
|
Rate
|
|
Date
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
$
|
217,000
|
|
4.98
|
|
2010
|
|
341,000
|
|
4.98
|
|
2013
|
|
250,000
|
|
5.09
|
|
2015
|
|
437,000
|
|
5.17
|
|
2018
|
|
494,700
|
|
5.3063
|
|
2020
|
The
proceeds will be used to retire TCC debt and equity, which are no longer needed
to support stranded costs.
In
October 2006, TCC retired $345 million in intercompany notes payable as
follows:
Principal
Amount
|
|
Interest
|
|
Due
|
|
Rate
|
|
Date
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
$
|
150,000
|
|
4.58
|
|
2007
|
|
125,000
|
|
5.14
|
|
2007
|
|
70,000
|
|
5.86
|
|
2007
|
In
October 2006, I&M had a required remarketing of $65 million of 2.625%
pollution control bonds, which were converted from a three-year fixed rate
mode
to an auction rate mode.
In
November 2006, APCo had a required remarketing of $30 million of 2.80% pollution
control bonds, which were converted from a three-year fixed rate mode to an
auction rate mode.
In
November 2006, APCo issued $17.5 million of variable rate pollution control
bonds and retired $17.5 million, 2.70% pollution control bonds due in
2007.
In
November 2006, $100.6 million of pollution control bonds were put back to TCC
on
the put date of November 1, 2006. TCC intends to hold these bonds for reissuance
at a later date.
Lines
of Credit - AEP System
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, and a Nonutility Money Pool, which
funds the majority of the nonutility subsidiaries. The AEP System corporate
borrowing program operates in accordance with the terms and conditions approved
in a regulatory order. The Utility Money Pool participants’ money pool activity
and corresponding authorized limits for the nine months ended September 30,
2006
are described in the following table:
Company
|
|
Maximum
Borrowings from Utility Money Pool
|
|
Maximum
Loans to Utility Money Pool
|
|
Average
Borrowings from Utility Money Pool
|
|
Average
Loans to Utility Money Pool
|
|
Loans
(Borrowings) to/from Utility Money Pool as of September 30,
2006
|
|
Authorized
Short-Term Borrowing Limit
|
|
|
|
(in
thousands)
|
|
AEGCo
|
|
$
|
58,209
|
|
$
|
2,247
|
|
$
|
21,005
|
|
$
|
2,247
|
|
$
|
(14,938
|
)
|
$
|
125,000
|
|
APCo
|
|
|
283,872
|
|
|
314,064
|
|
|
200,248
|
|
|
194,781
|
|
|
93,764
|
|
|
600,000
|
|
CSPCo
|
|
|
48,337
|
|
|
95,977
|
|
|
15,133
|
|
|
35,929
|
|
|
60,417
|
|
|
350,000
|
|
I&M
|
|
|
128,071
|
|
|
-
|
|
|
64,123
|
|
|
-
|
|
|
(27,616
|
)
|
|
500,000
|
|
KPCo
|
|
|
46,156
|
|
|
11,993
|
|
|
24,285
|
|
|
4,384
|
|
|
(24,507
|
)
|
|
200,000
|
|
OPCo
|
|
|
351,302
|
|
|
40,382
|
|
|
100,212
|
|
|
15,845
|
|
|
(48,163
|
)
|
|
600,000
|
|
PSO
|
|
|
167,456
|
|
|
146,657
|
|
|
97,332
|
|
|
94,937
|
|
|
43,538
|
|
|
300,000
|
|
SWEPCo
|
|
|
127,291
|
|
|
24,209
|
|
|
56,984
|
|
|
10,722
|
|
|
7,018
|
|
|
350,000
|
|
TCC
|
|
|
117,429
|
|
|
49,193
|
|
|
44,416
|
|
|
23,779
|
|
|
25,304
|
|
|
600,000
|
|
TNC
|
|
|
22,218
|
|
|
34,574
|
|
|
6,269
|
|
|
8,381
|
|
|
(9,492
|
)
|
|
250,000
|
|
TNC
(a)
|
|
|
10
|
|
|
13,947
|
|
|
8
|
|
|
13,834
|
|
|
13,875
|
|
|
-
|
|
The
maximum and minimum interest rates for funds either borrowed from or loaned
to
the Utility Money Pool for the nine months ended September 30, 2006 were 5.41%
and 3.63%. The maximum and minimum interest rates for funds either borrowed
from
or loaned to the Utility Money Pool for the nine months ended September 30,
2005
were 3.93% and 1.63%. The average interest rates for funds borrowed from and
loaned to the Utility Money Pool for the nine months ended September 30, 2006
and 2005 are summarized for all Registrant Subsidiaries in the following
table:
Company
|
|
Average
Interest Rate
for Funds Borrowed from the Utility Money Pool for Nine Months
Ended
September
30, 2006
|
|
Average
Interest Rate
for Funds Borrowed
from the Utility
Money Pool for
Nine Months Ended
September
30, 2005
|
|
Average
Interest Rate
for Funds Loaned to the Utility
Money Pool
for Nine Months Ended
September
30, 2006
|
|
Average
Interest Rate
for Funds Loaned to the
Utility
Money Pool
for
Nine Months Ended September 30, 2005
|
|
|
|
(in
percentage)
|
|
AEGCo
|
|
|
4.85
|
|
|
2.91
|
|
|
5.11
|
|
|
3.14
|
|
APCo
|
|
|
4.62
|
|
|
3.30
|
|
|
4.98
|
|
|
2.72
|
|
CSPCo
|
|
|
4.73
|
|
|
3.92
|
|
|
4.63
|
|
|
2.76
|
|
I&M
|
|
|
4.81
|
|
|
3.25
|
|
|
-
|
|
|
2.12
|
|
KPCo
|
|
|
4.92
|
|
|
3.52
|
|
|
4.97
|
|
|
2.54
|
|
OPCo
|
|
|
4.83
|
|
|
3.67
|
|
|
5.12
|
|
|
2.40
|
|
PSO
|
|
|
5.02
|
|
|
2.62
|
|
|
4.36
|
|
|
3.52
|
|
SWEPCo
|
|
|
5.01
|
|
|
3.64
|
|
|
4.36
|
|
|
2.60
|
|
TCC
|
|
|
4.79
|
|
|
3.07
|
|
|
4.71
|
|
|
2.43
|
|
TNC
|
|
|
4.81
|
|
|
-
|
|
|
4.56
|
|
|
3.13
|
|
TNC
(a)
|
|
|
5.36
|
|
|
-
|
|
|
5.33
|
|
|
-
|
|
(a)
|
In
the third quarter of 2006, TNC created a new wholly-owned subsidiary,
AEP
Texas North Generation Company, LLC. Following the creation of this
subsidiary, TNC transferred all of its mothballed generation assets
and
related liabilities to this new subsidiary, effectively completing
the
business separation requirement of the Texas Restructuring Legislation.
Subsequently, AEP Texas North Generation Company, LLC became a participant
in the Nonutility Money Pool. For the nine months ended September
30,
2006, the maximum and minimum interest rates for funds either borrowed
from or loaned to the Nonutility Money Pool were 5.39% and 5.28%
respectively.
|
COMBINED
MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT
SUBSIDIARIES
The
following is a combined presentation of certain components of the management’s
discussion and analysis of Registrant Subsidiaries. The information in this
section completes the information necessary for management’s discussion and
analysis of financial condition and results of operations and is meant to be
read with (i) Management’s Financial Discussion and Analysis, (ii) financial
statements, and (iii) footnotes of each individual registrant. The Combined
Management’s Discussion and Analysis of Registrants Subsidiaries section of the
2005 Annual Report should also be read in conjunction with this
report.
Construction
Expenditures
The
Registrant Subsidiaries have substantial construction commitments to support
their operations and environmental investments. The following table shows the
revised estimated construction expenditures by Registrant Subsidiary for
2006:
|
|
(in
millions)
|
|
AEGCo
|
|
$
|
12
|
|
APCo
|
|
|
928
|
|
CSPCo
|
|
|
319
|
|
I&M
|
|
|
330
|
|
KPCo
|
|
|
54
|
|
OPCo
|
|
|
1,065
|
|
PSO
|
|
|
262
|
|
SWEPCo
|
|
|
315
|
|
TCC
|
|
|
286
|
|
TNC
|
|
|
72
|
|
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, legal reviews and the ability to access capital.
Environmental
Matters
The
Registrant Subsidiaries have committed to substantial capital investments and
additional operational costs to comply with new environmental control
requirements. The sources of these requirements include:
·
|
Requirements
under the CAA to reduce emissions of SO2,
NOx,
particulate matter, and mercury from fossil fuel-fired power
plants;
|
·
|
Requirements
under the Clean Water Act to reduce the impacts of water intake structures
on aquatic species at certain power plants; and
|
·
|
Possible
future requirements to reduce carbon dioxide emissions to address
concerns
about global climate change.
|
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.
Environmental
Litigation
New
Source Review (NSR) Litigation:
In 1999,
the Federal EPA and a number of states filed complaints alleging that APCo,
CSPCo, I&M, and OPCo modified certain units at coal-fired generating plants
in violation of the NSR requirements of the CAA. A separate lawsuit, initiated
by certain environmental intervenor groups, has been consolidated with the
Federal EPA case. Several similar complaints were filed in 1999 and 2000 against
other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky
Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin
Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these
cases were resolved through consent decrees. The alleged modifications at our
power plants occurred over a 20-year period. A bench trial on the liability
issues was held during July 2005. Briefing has concluded. In June 2006, the
judge stayed the liability decision pending the issuance of a decision by the
U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues,
if
necessary, is scheduled to begin four months after the U.S. Supreme Court
decision is issued.
Under
the
CAA, if a plant undertakes a major modification that directly results in an
emissions increase, permitting requirements might be triggered and the plant
may
be required to install additional pollution control technology. This requirement
does not apply to activities such as routine maintenance, replacement of
degraded equipment or failed components or other repairs needed for the
reliable, safe and efficient operation of the plant.
Courts
that considered whether the activities at issue in these cases are routine
maintenance, repair, or replacement, and therefore are excluded from NSR,
reached different conclusions. Similarly, courts that considered whether the
activities at issue increased emissions from the power plants reached different
results. Appeals on these and other issues have been filed in certain appellate
courts, including a petition to appeal to the U.S. Supreme Court that was
granted in one case. The Federal EPA issued a final rule that would exclude
activities similar to those challenged in these cases from NSR as “routine
replacements.” In March 2006, the Court of Appeals for the District of Columbia
Circuit issued a decision vacating the rule. The Federal EPA filed a petition
for rehearing in that case, which the Court denied. The Federal EPA also
recently proposed a rule that would define “emissions increases” in a way that
would exclude most of the challenged activities from NSR.
Management
is unable to estimate the loss or range of loss related to any contingent
liability the Registrant Subsidiaries might have for civil penalties under
the
CAA proceedings. Management is also unable to predict the timing of resolution
of these matters due to the number of alleged violations and the significant
number of issues yet to be determined by the court. If the Registrant
Subsidiaries do not prevail, management believes the Registrant Subsidiaries
can
recover any capital and operating costs of additional pollution control
equipment that may be required through regulated rates and market prices for
electricity. If the Registrant Subsidiaries are unable to recover such costs
or
if material penalties are imposed, it would adversely affect future results
of
operations, cash flows and possibly financial condition.
Adoption
of New Accounting Pronouncements
Beginning
in 2006, the Registrant Subsidiaries adopted SFAS No. 123 (revised 2004)
Share-Based Payment, on a modified prospective basis, resulting in an
insignificant favorable cumulative effect of a change in accounting principle.
Including stock-based compensation expense related to employee stock options
and
other share based awards, did not materially affect the Registrant Subsidiaries’
quarter-over-quarter and year-to-date net income (loss). See Note 2 - New
Accounting Pronouncements in the Condensed Notes to Condensed Financial
Statements of Registrant Subsidiaries for further discussion.
During
the third quarter of 2006, management, including the principal executive officer
and principal financial officer of each of AEP, AEGCo, APCo, CSPCo, I&M,
KPCo, OPCo, PSO, SWEPCo, TCC and TNC (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, 2006, 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 2006 that materially affected, or is reasonably likely
to
materially affect, the Registrants’ internal controls over financial
reporting.
PART
II. OTHER INFORMATION
Item
1. Legal
Proceedings
For
a
discussion of material legal proceedings, see Note 5, Commitments
and Contingencies, incorporated
herein by reference.
Item
1A. Risk
Factors
Our
Annual Report on Form 10-K for the year ended December 31, 2005 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 2005 Annual Report on Form 10-K.
General
Risks of Our Regulated Operations
Our
requests for rate recovery of additional costs may not be approved in
Virginia. (Applies
to AEP and APCo.)
In
September 2006, based on a report by the Hearing Examiner in our Virginia
Environmental and Reliability costs rate case, we wrote off all of the
regulatory asset related to environmental controls, transmission costs
(including line construction) and other system reliability work incurred July
2004 through September 2006, adversely affecting pretax earnings by $36
million.
In
addition, APCo filed a request with the Virginia SCC in May 2006 seeking an
increase in base rates of $225 million to recover increasing costs, including
a
return on equity of 11.5%. APCo also requested to apply off-system sales margins
(currently credited to customers through base rates) to the fuel factor where
they can be adjusted annually. APCo also requested to retain a portion of the
off-system sales margins. This proposed off-system sales fuel rate credit is
projected to be $27 million annually. It would partially offset the $225 million
requested increase in base rates for a net increase in revenues of $198 million.
In May 2006, the Virginia SCC issued an order placing the full requested base
rate increase into effect as of October 2, 2006, subject to refund. In October
2006, the Virginia SCC staff filed their direct testimony recommending a base
rate increase of $13 million. Other intervenors have recommended base rate
increases ranging from $42 million to $112 million. APCo plans to file rebuttal
testimony in November 2006. Hearings are scheduled to begin in December 2006.
Our
request for rate recovery of additional costs may not be approved in West
Virginia. (Applies
to AEP and APCo.)
The
West
Virginia Public Service Commission approved our pending West Virginia base
rate
case settlement agreement in July 2006. Therefore, this risk factor is no longer
applicable.
Our
request for rate recovery of additional costs may not be approved in
Kentucky.
(Applies to AEP and KPCo.)
The
Kentucky Public Service Commission approved our pending Kentucky base rate
case
settlement agreement in March 2006. Therefore, this risk factor is no longer
applicable.
The
rates that SWEPCo may charge its customers may be reduced. (Applies
to SWEPCo)
In
October 2005, the staff of the PUCT reported results of its review of SWEPCo’s
year-end 2004 earnings. Based upon the staff’s adjustments to the information
submitted by SWEPCo, the report indicates that SWEPCo is receiving excess
revenues of approximately $15 million. The staff engaged SWEPCo in discussions
to reconcile the earnings calculation and consider possible ways to address
the
results. After those discussions, the PUCT staff informed SWEPCo in April 2006
that they would not pursue the matter further.
Separately,
at the time of the CSW merger, SWEPCo agreed to file with the Louisiana Public
Service Commission (LPSC) detailed financial information typically utilized
in a
revenue requirement filing on a periodic basis in order to demonstrate the
lack
of adverse impact from the merger. The first such filing was in October 2002
and
the second was in April 2004. Both filings indicated SWEPCo’s rates should not
be reduced. In April 2006, the LPSC and SWEPCo agreed to update the financial
information based on a 2005 test year. SWEPCo filed financial review schedules
in May 2006 showing a return on equity of 9.44% compared to the previously
authorized return on equity of 11.1%. In July 2006, the LPSC staff’s consultants
filed direct testimony recommending a base rate reduction in the range of $12
million to $20 million for SWEPCo’s Louisiana jurisdiction customers, which
included a 10% return on equity. The recommended reduction range is subject
to
SWEPCo validating certain on-going operations and maintenance expense levels
and
the recommended base rate reduction does not include the impact of a proposed
consolidated federal income tax adjustment, which would increase the proposed
rate reduction. SWEPCo filed rebuttal testimony in October 2006 strongly
refuting the consultants’ recommendations. Hearings are expected to occur late
in the fourth quarter of 2006. A decision is not expected until 2007. At this
time, management is unable to predict the outcome of this proceeding. If a
rate
reduction were ultimately ordered, it would adversely impact future results
of
operations and cash flows.
In
a
separate matter in March 2006, the LPSC closed its inquiry into SWEPCo’s fuel
and purchased power procurement activities during the period January 1, 2005
through October 31, 2005. The LPSC approved the LPSC staff’s report, which
concluded that SWEPCo’s activities were appropriate and did not identify any
disallowances or areas for improvement.
Risks
Related to Owning and Operating Generating Assets and Selling
Power
The
amount we charge third parties for using our transmission facilities may be
reduced and not recovered. (Applies
to AEP and AEP’s
East zone public utility subsidiaries.)
In
July
2003, the FERC issued an order directing PJM and the MISO to make compliance
filings for their respective OATTs to eliminate the transaction-based charges
for through and out (T&O) transmission service on transactions where the
energy is delivered within the proposed MISO and PJM expanded regions (Combined
Footprint). The elimination of the T&O rates reduces the transmission
service revenues collected by the RTOs and thereby reduces the revenues received
by transmission owners under the RTOs’ revenue distribution protocols. To
mitigate the impact of lost T&O revenues, the FERC approved SECA transition
rates beginning in December 2004 and extending through March 2006. SECA fees
of
$220 million were collected subject to refund.
A
hearing
in the SECA case was held in May 2006 to determine whether any of the SECA
revenues should be refunded. In August 2006, the 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 were not
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 unpaid SECA rates must be paid in the recommended reduced
amount.
We
have
reached settlements with certain customers related to approximately $70 million
of SECA revenues. The unsettled gross SECA revenues total approximately $150
million. If the ALJ’s initial decision is upheld in its entirety, it would
disallow $126 million of the AEP East companies’ unsettled gross SECA revenues.
It would also provide refunds of SECA rates paid by the AEP East companies
in
considerably less significant amounts. Based on the completed settlements,
and
before the issuance of the ALJ’s initial decision, the AEP East companies
provided for $22 million in net refunds, of which $18 million was recorded
in
the second quarter of 2006 in Utility Operations Revenues on the Condensed
Consolidated Statements of Operations.
Approximately
$19 million of these recorded SECA revenues billed by PJM were never collected.
The AEP East companies filed a motion with the FERC to force payment of these
SECA billings. The FERC has not yet acted on the motion.
Although
we believe we have meritorious arguments, management cannot predict the ultimate
outcome of any future FERC proceedings or court appeals. If the FERC adopts
the
ALJ’s decision, it will have an adverse effect on future results of operations
and cash flows.
SECA
transition rates have
not
fully compensated AEP for lost T&O revenues.
SECA
transition rates expired at the end of March 2006, and all transmission costs
that would otherwise have been covered by T&O rates in the Combined
Footprint are now subject to recovery from native load customers of AEP’s East
zone public utility subsidiaries.
Management
is unable to predict whether the FERC will approve either the ALJ’s decision or
when, and if, the effect of the loss of T&O/SECA transmission revenues will
be recoverable on a timely basis in each of the AEP East state retail
jurisdictions and/or from transmission users within the PJM region.
Risks
Relating to State Restructuring
Our
Rate Stabilization Plans in Ohio may be modified by the PUCO such that our
deferred costs may not be recovered and rates may be reduced.
(Applies
to AEP, OPCo and CSPCo)
In
January 2005, the PUCO approved Rate Stabilization Plans (RSPs) for CSPCo and
OPCo. The RSPs provide, among other things, for CSPCo and OPCo to raise their
generation rates on an annual basis through 2008 by 3% and 7%, respectively.
The
RSPs also provide for possible additional annual generation rate increases
of up
to an average of 4% per year for specified costs. The RSPs also provide that
CSPCo and OPCo can recover certain environmental carrying costs, PJM-related
administrative costs and certain congestion costs. As of September 30, 2006,
the
unamortized RSP deferrals were $7 million for CSPCo and $36 million for OPCo.
In
the
second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio
Supreme Court that challenged the validity of the RSPs under Ohio’s electricity
restructuring law. In May 2006, the Ohio Supreme Court remanded the rate
stabilization plan of First Energy on the grounds that it failed to provide
customers with a competitive bid generation supply option, as contemplated
by
the restructuring law. In July 2006, the Ohio Supreme Court vacated the PUCO’s
RSP order for CSPCo and OPCo, which did not include a competitive process,
and
remanded the case to the PUCO for further proceedings.
In
August
2006, the PUCO acted on the Ohio companies’ remand case ordering them to file a
plan to provide an option for customer participation in the electric market
through competitive bids or other reasonable means and also held that the RSP
shall remain effective. Accordingly, the Ohio companies continued to collect
RSP
revenues. In the first nine months of 2006, CSPCo and OPCo have collected an
additional $89 million and $87 million, respectively, as a result of the RSPs.
In accordance with the PUCO directive, in September 2006, CSPCo and OPCo
submitted their proposal to provide additional options for customer
participation in the electric market.
We
are contractually required to operate a power generation facility that may
indirectly force us to sell the facility’s excess energy at a
loss.
(Applies to AEP.)
We
have
agreed to lease from Juniper Capital L.P. a merchant power generation facility
(“Facility”) near Plaquemine, Louisiana. We sublease the Facility to Dow. We
operate the Facility for Dow. Dow uses a portion of the energy produced by
the
Facility and sells the excess power to us. We have agreed to sell up to all
of
the excess 800 MW to Tractebel
at a
price that is currently in excess of market. Tractebel alleged that the power
purchase agreement was unenforceable. This agreement is now being litigated.
A
bench
trial was conducted in March and April 2005. In August 2005, a federal judge
ruled that Tractebel had breached the contract and awarded us damages of $123
million plus prejudgment interest. Both parties have filed appeals. In January
2006, the trial court increased AEP’s judgment against Tractebel to $173 million
plus prejudgment interest. In March 2006, the trial judge amended the January
2006 order to eliminate the additional $50 million damage award. If
the
trial award is reversed or if Tractebel does not pay the judgment, our cash
flow
will be adversely affected.
In
August
2006, we reached an agreement to sell the Facility to Dow for $64 million.
We
expect the sale to close in November 2006. We recorded a pretax impairment
of
$209 million ($136 million, net of tax) in the third quarter of 2006 based
on
our agreement to sell the Facility to Dow. The sale agreement also allows us
to
participate in gross margin sharing on the Facility for five years. In addition,
Dow will reduce an existing below-current-market long-term power supply contract
with us in Texas by 50 MW. We also retain the right to any judgment paid by
TEM
for breaching the original PPA, as discussed above.
If
the
sale of the Facility to Dow does not close, we will be required to find new
purchasers for up to 800 MW. There can be no assurance that the power
produced will be sold at prices that will exceed our costs to produce it. If
that were the case, as a result of our obligations to Dow, we would be required
to operate the Facility at a loss.
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, 2006 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
|
|
07/01/06
- 07/31/06
|
|
|
-
|
|
|
|
|
$
|
-
|
|
|
-
|
|
$
|
-
|
|
08/01/06
- 08/31/06
|
|
|
12
|
|
|
(a
|
)
|
|
73.00
|
|
|
-
|
|
|
-
|
|
09/01/06
- 09/30/06
|
|
|
30
|
|
|
(b
|
)
|
|
79.75
|
|
|
-
|
|
|
-
|
|
(a)
|
I&M
repurchased 12 shares of its 4-1/8% cumulative preferred stock, in
a
privately-negotiated transaction outside of an announced
program.
|
(b)
|
APCo
repurchased 30 shares of its 4-1/2% cumulative preferred stock, in
a
privately-negotiated transaction outside of an announced
program.
|
Item
5. Other
Information
NONE
Item
6. Exhibits
AEP,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
12
-
Computation of Consolidated Ratio of Earnings to Fixed Charges.
AEP
31(a)
-
Certification of AEP Chief Executive Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31(c)
-
Certification of AEP Chief Financial Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
31(b)
-
Certification of Registrant Subsidiaries’ Chief Executive Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
31(d)
-
Certification of Registrant Subsidiaries’ Chief Financial Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
AEP,
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and
TNC
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
AEP
GENERATING COMPANY
AEP
TEXAS
CENTRAL COMPANY
AEP
TEXAS
NORTH COMPANY
APPALACHIAN
POWER COMPANY
COLUMBUS
SOUTHERN POWER COMPANY
INDIANA
MICHIGAN POWER COMPANY
KENTUCKY
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:
November 6, 2006