mabaird@aep.com
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 March
31, 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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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
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|
1
Riverside Plaza, Columbus, Ohio 43215-2373
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|
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Telephone
(614) 716-1000
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Indicate
by check mark whether the registrants (1) have filed all reports
required
to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934
during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been
subject
to such filing requirements for the past 90 days.
|
Yes
X
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No
___
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Indicate
by check mark whether American Electric Power Company, Inc. is a
large
accelerated filer, an accelerated filer, 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
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Indicate
by check mark whether the registrants are shell companies (as defined
in
Rule 12b-2 of the Exchange Act.)
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Yes
___
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No X
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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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Aggregate
market value of voting and non-voting common equity held by non-affiliates
of the registrants as
of June 30, 2005, the last trading date of the registrants’ most recently
completed second fiscal quarter
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Number
of shares of common stock outstanding of the registrants
at
April
28, 2006
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AEP
Generating Company
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None
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1,000
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($1,000
par value)
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AEP
Texas Central Company
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None
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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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None
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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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$14,172,701,867
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393,914,882
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($6.50
par value)
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Appalachian
Power Company
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None
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13,499,500
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(no
par value)
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Columbus
Southern Power Company
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None
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16,410,426
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(no
par value)
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Indiana
Michigan Power Company
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None
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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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None
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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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None
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27,952,473
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(no
par value)
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Public
Service Company of Oklahoma
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None
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9,013,000
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($15
par value)
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Southwestern
Electric Power Company
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None
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7,536,640
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|
|
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($18
par value)
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AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX
TO QUARTERLY REPORTS ON FORM 10-Q
March
31, 2006
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Glossary
of Terms
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Forward-Looking
Information
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Part
I. FINANCIAL INFORMATION
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Items
1, 2 and 3 - Financial Statements, Management’s Financial Discussion and
Analysis and Quantitative and Qualitative Disclosures About Risk
Management Activities:
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American
Electric Power Company, Inc. and Subsidiary
Companies:
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Management’s
Financial Discussion and Analysis of Results of Operations
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Consolidated Financial
Statements
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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 Subsidiary:
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Management’s
Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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AEP
Texas North Company:
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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
Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Appalachian
Power Company and Subsidiaries:
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Management’s
Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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|
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Columbus
Southern Power Company and Subsidiaries:
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Management’s
Narrative Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Indiana
Michigan Power Company and Subsidiaries:
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Management’s
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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Kentucky
Power Company:
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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
Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Ohio
Power Company Consolidated:
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Management’s
Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Public
Service Company of Oklahoma:
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Management’s
Narrative Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Southwestern
Electric Power Company Consolidated:
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Management’s
Financial Discussion and Analysis
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Quantitative
and Qualitative Disclosures About Risk Management
Activities
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Condensed
Consolidated Financial Statements
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Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Condensed
Notes to Condensed Financial Statements of Registrant
Subsidiaries
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Combined
Management’s Discussion and Analysis of Registrant
Subsidiaries
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Item
4.
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Controls
and Procedures
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Part
II. OTHER INFORMATION
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Item
1.
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Legal
Proceedings
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Item
1A.
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Risk
Factors
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Item
2.
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Unregistered
Sales of Equity Securities and Use of Proceeds
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Item
5.
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Other
Information
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Item
6.
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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.
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GLOSSARY
OF TERMS
When
the following terms and abbreviations appear in the text of this report, they
have the meanings indicated below.
AEGCo
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AEP
Generating Company, an AEP electric generating
subsidiary.
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AEP
or Parent
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American
Electric Power Company, Inc.
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AEP
Consolidated
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AEP
and its majority owned consolidated subsidiaries and consolidated
entities.
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AEP
East companies
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APCo,
CSPCo, I&M, KPCo and OPCo.
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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.
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AEP
System Power Pool or AEP
Power Pool
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Members
are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation,
cost of generation and resultant wholesale off-system sales of the
member
companies.
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AEPSC
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American
Electric Power Service Corporation, a service subsidiary providing
management and professional services to AEP and its
subsidiaries.
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AEP
West companies
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PSO,
SWEPCo, TCC and TNC.
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AFUDC
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Allowance
for Funds Used During Construction.
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ALJ
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Administrative
Law Judge.
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APCo
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Appalachian
Power Company, an AEP electric utility subsidiary.
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CAA
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Clean
Air Act.
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Cook
Plant
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Donald
C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by
I&M.
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CSPCo
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Columbus
Southern Power Company, an AEP electric utility
subsidiary.
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CSW
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Central
and South West Corporation, a subsidiary of AEP (Effective January
21,
2003, the legal name of Central and South West Corporation was changed
to
AEP Utilities, Inc.).
|
CSW
Operating Agreement
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|
Agreement,
dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing
their generating capacity allocation. AEPSC acts as the
agent.
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CTC
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Competition
Transition Charge.
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DETM
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Duke
Energy Trading and Marketing L.L.C., a risk management
counterparty.
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EPACT
|
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Energy
Policy Act of 2005.
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ERCOT
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Electric
Reliability Council of Texas.
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FASB
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Financial
Accounting Standards Board.
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Federal
EPA
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|
United
States Environmental Protection Agency.
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FERC
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Federal
Energy Regulatory Commission.
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GAAP
|
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Accounting
Principles Generally Accepted in the United States of
America.
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HPL
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Houston
Pipe Line Company LP, a former AEP subsidiary that was sold in January
2005.
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IGCC
|
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Integrated
Gasification Combined Cycle, technology that turns coal into a
cleaner-burning gas.
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I&M
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Indiana
Michigan Power Company, an AEP electric utility
subsidiary.
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IRS
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Internal
Revenue Service.
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IPP
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Independent
Power Producers.
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IURC
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Indiana
Utility Regulatory Commission.
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KPCo
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Kentucky
Power Company, an AEP electric utility subsidiary.
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KPSC
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Kentucky
Public Service Commission.
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kV
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Kilovolt.
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KWH
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Kilowatthour.
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MISO
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Midwest
Independent Transmission System
Operator.
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MTM
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Mark-to-Market.
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MW
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Megawatt.
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MWH
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Megawatthour.
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NOx
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Nitrogen
oxide.
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Nonutility
Money Pool
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AEP
System’s Nonutility Money Pool.
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NRC
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Nuclear
Regulatory Commission.
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NSR
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New
Source Review.
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NYMEX
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New
York Mercantile Exchange.
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OATT
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Open
Access Transmission Tariff.
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OCC
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Corporation
Commission of the State of Oklahoma.
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OPCo
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Ohio
Power Company, an AEP electric utility subsidiary.
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OTC
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Over
the counter.
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PJM
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Pennsylvania
- New Jersey - Maryland regional transmission
organization.
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PSO
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Public
Service Company of Oklahoma, an AEP electric utility
subsidiary.
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PTB
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Price-to-Beat.
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PUCO
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Public
Utilities Commission of Ohio.
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PUCT
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Public
Utility Commission of Texas.
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PURPA
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Public
Utility Regulatory Policies Act of 1978.
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Registrant
Subsidiaries
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AEP
subsidiaries which are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC.
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REP
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Texas
Retail Electric Provider.
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Risk
Management Contracts
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Trading
and nontrading derivatives, including those derivatives designated
as cash
flow and fair value hedges.
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Rockport
Plant
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A
generating plant, consisting of two 1,300 MW coal-fired generating
units
near Rockport, Indiana owned by AEGCo and I&M.
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RTO
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Regional
Transmission Organization.
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S&P
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Standard
and Poor’s.
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SEC
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United
States Securities and Exchange Commission.
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SECA
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Seams
Elimination Cost Allocation.
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SFAS
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Statement
of Financial Accounting Standards issued by the FASB.
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SFAS
133
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Statement
of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities.”
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SIA
|
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System
Integration Agreement.
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SO2
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Sulfur
Dioxide.
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SPP
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Southwest
Power Pool.
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STP
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South
Texas Project Nuclear Generating Plant.
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Sweeny
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Sweeny
Cogeneration Limited Partnership, owner and operator of a four unit,
480
MW gas-fired generation facility, owned 50% by AEP.
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SWEPCo
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Southwestern
Electric Power Company, an AEP electric utility
subsidiary.
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TCC
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AEP
Texas Central Company, an AEP electric utility subsidiary.
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TEM
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SUEZ
Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing,
Inc.).
|
Texas
Restructuring Legislation
|
|
Legislation
enacted in 1999 to restructure the electric utility industry in
Texas.
|
TNC
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|
AEP
Texas North Company, an AEP electric utility subsidiary.
|
True-up
Proceeding
|
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A
filing made under the Texas Restructuring Legislation to finalize
the
amount of stranded costs and other true-up items and the recovery
of such
amounts.
|
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.
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WPCo
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Wheeling
Power Company, an AEP electric distribution subsidiary.
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WVPSC
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|
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 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.
|
·
|
Our
ability to sell assets at acceptable prices and other acceptable
terms.
|
·
|
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
Regulatory
Activity
Our
significant regulatory activity progressed with the following major
developments:
·
|
In January 2006, we implemented
our Ohio Rate Stabilization Plans, resulting in increased revenues
of $49
million for the three months ended March 31, 2006. |
·
|
The
Kentucky Public Service Commission approved our $41 million rate
case
settlement agreement. New rates became effective on March 30,
2006.
|
·
|
In
March 2006, after the February 2006 receipt of an order in our Texas
stranded costs proceeding, we filed with the Public Utility Commission
of
Texas (PUCT) for approval of a financing order to issue $1.8 billion
in
securitization bonds. We expect an order in June or July
2006.
|
·
|
In
April 2006, the Public Utilities Commission of Ohio (PUCO) approved
our
recovery of the pre-construction costs for the Integrated Gasification
Combined Cycle (IGCC) clean-coal plant in Meigs County, Ohio. The
PUCO
also ruled that it is reasonable to recover the pre-construction
costs of
the facility through a provider of last resort recovery mechanism.
We
subsequently submitted tariffs for PUCO approval related to recovery
of
our IGCC pre-construction costs.
|
·
|
In
April 2006, we reached a tentative settlement in our APCo and WPCo
rate
case, subject to approval by the Public Service Commission of West
Virginia, providing for a $44 million increase in rates effective
July 28,
2006.
|
·
|
In
May 2006, we filed a base rate case in Virginia requesting a net
rate
increase of $198 million.
|
Our
near-term additional activity includes:
·
|
A
TCC competition transition charge (CTC) filing with the PUCT in the
second
quarter to address a $491 million credit to customers from the True-up
Proceeding.
|
·
|
Issuance
of securitization bonds in Texas in the third quarter of
2006.
|
Fuel
Costs
Market
prices for coal, natural gas and oil continued increasing in the first quarter
of 2006. These increasing fuel costs result from increasing worldwide demand,
supply interruptions and uncertainty, anticipation and ultimate promulgation
of
clean air rules, transportation constraints and other market factors. We manage
price and performance risk through a portfolio of contracts of varying durations
and other fuel procurement and management activities. Fuel recovery mechanisms
exist for about 55% of our fuel costs in our various jurisdictions.
Additionally, about 25% of our fuel is used for off-system sales where prices
for our power should allow us to recover our cost of fuel. Accordingly, we
should recover approximately 80% of fuel cost increases. The remaining 20%
of
our fuel costs relate primarily to Ohio customers, where fuel is a fixed
component of costs included in our rates, but we do not have an active fuel
cost
recovery adjustment mechanism. Such percentages are subject to change over
time
based on fuel cost impacts and changes to the recovery adjustment mechanisms
at
jurisdictions in our individual operating companies. 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 currently
expect under recoveries during 2006 and under-recovered $4 million for the
quarter ended March 31, 2006. In West Virginia, we received permission to begin
deferral accounting for over- or under-recovery of fuel and related costs
effective July 1, 2006. In addition, our Ohio companies increased their
generation rates in 2006, as previously approved by the PUCO in our Rate
Stabilization Plans. While these items should help to offset some of the
negative impact on our gross margins, we expect an additional eleven to thirteen
percent increase in coal costs in 2006.
RESULTS
OF OPERATIONS
Segments
Our
principal operating business segments and their major activities
were:
·
|
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 months ended
March 31, 2006 and 2005 were as follows (Earnings and Weighted Average Basic
Shares Outstanding in millions):
|
|
2006
|
|
2005
|
|
|
|
Earnings
|
|
EPS
(c)
|
|
Earnings
|
|
EPS
(c)
|
|
Utility
Operations
|
|
$
|
365
|
|
$
|
0.93
|
|
$
|
353
|
|
$
|
0.90
|
|
Investments
- Other
|
|
|
16
|
|
|
0.04
|
|
|
5
|
|
|
0.01
|
|
All
Other (a)
|
|
|
(2
|
)
|
|
(0.01
|
)
|
|
(14
|
)
|
|
(0.04
|
)
|
Investments
- Gas Operations (b)
|
|
|
(1
|
)
|
|
-
|
|
|
10
|
|
|
0.03
|
|
Income
Before Discontinued Operations
|
|
$
|
378
|
|
$
|
0.96
|
|
$
|
354
|
|
$
|
0.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average Basic Shares Outstanding
|
|
|
|
|
|
394
|
|
|
|
|
|
393
|
|
(a)
|
All
Other includes the parent company’s 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.
|
|
First
Quarter of 2006 Compared to First Quarter of 2005
Income
Before Discontinued Operations in 2006 increased $24 million compared to 2005
due to increased utility operations revenue primarily related to rate increases
in our Ohio jurisdiction as approved by the PUCO in CSPCo’s and OPCo’s Rate
Stabilization Plans (RSP).
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. 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
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Revenues
|
|
$
|
2,969
|
|
$
|
2,684
|
|
Fuel
and Purchased Energy
|
|
|
1,127
|
|
|
923
|
|
Gross
Margin
|
|
|
1,842
|
|
|
1,761
|
|
Depreciation
and Amortization
|
|
|
333
|
|
|
318
|
|
Other
Operating Expenses
|
|
|
846
|
|
|
805
|
|
Operating
Income
|
|
|
663
|
|
|
638
|
|
Other
Income (Expense), Net
|
|
|
42
|
|
|
30
|
|
Interest
Expense and Preferred Stock Dividend Requirements
|
|
|
154
|
|
|
144
|
|
Income
Tax Expense
|
|
|
186
|
|
|
171
|
|
Income
Before Discontinued Operations
|
|
$
|
365
|
|
$
|
353
|
|
Summary
of Selected Sales and Weather Data
For
Utility Operations
For
the Three Months Ended March 31, 2006 and 2005
|
|
2006
|
|
2005
|
|
Energy
Summary
|
|
(in
millions of KWH)
|
|
Retail:
|
|
|
|
|
|
Residential
|
|
|
12,938
|
|
|
13,224
|
|
Commercial
|
|
|
8,909
|
|
|
8,732
|
|
Industrial
|
|
|
13,221
|
|
|
12,774
|
|
Miscellaneous
|
|
|
589
|
|
|
645
|
|
Subtotal
|
|
|
35,657
|
|
|
35,375
|
|
Texas
Retail and Other
|
|
|
68
|
|
|
228
|
|
Total |
|
|
35,725 |
|
|
35,603 |
|
|
|
|
|
|
|
|
|
Wholesale
|
|
|
10,844
|
|
|
12,635
|
|
|
|
|
|
|
|
|
|
Texas
Wires Delivery
|
|
|
5,546
|
|
|
5,519
|
|
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. Cooling
degree days and heating degree days in our service territory for the quarters
ended March 31, 2006 and 2005 were as follows:
|
|
2006
|
|
2005
|
|
|
Weather
Summary
|
|
(in
degree days)
|
|
Eastern
Region
|
|
|
|
|
|
|
Actual
- Heating (a)
|
|
1,456
|
|
1,774
|
|
|
Normal
- Heating (b)
|
|
1,817
|
|
1,811
|
|
|
|
|
|
|
|
|
|
Actual
- Cooling (c)
|
|
1
|
|
-
|
|
|
Normal
- Cooling (b)
|
|
3
|
|
3
|
|
|
|
|
|
|
|
|
|
Western
Region
(d)
|
|
|
|
|
|
|
Actual
- Heating (a)
|
|
658
|
|
769
|
|
|
Normal
- Heating (b)
|
|
972
|
|
973
|
|
|
|
|
|
|
|
|
|
Actual
- Cooling (c)
|
|
43
|
|
20
|
|
|
Normal
- Cooling (b)
|
|
17
|
|
18
|
|
|
|
|
|
(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.
|
|
|
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006
Income
from Utility Operations Before Discontinued Operations
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
353
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
111
|
|
|
|
|
Off-system
Sales
|
|
|
(24
|
)
|
|
|
|
Other
|
|
|
(6
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
81
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Maintenance
and Other Operation
|
|
|
6
|
|
|
|
|
Gain
on Sales of Assets, Net
|
|
|
(46
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(15
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1
|
)
|
|
|
|
Other
Income (Expense), Net
|
|
|
12
|
|
|
|
|
Interest
and Other Charges
|
|
|
(10
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(54
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
365
|
|
Income
from Utility Operations Before Discontinued Operations increased $12 million
to
$365 million in 2006. The key driver of the increase was an $81 million net
increase in Gross Margin, offset in part by a $54 million increase in Operating
Expenses and Other and a $15 million increase in Income Tax Expense.
The
major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $111 million primarily due to the
following:
|
·
|
A
$49 million increase related to new rates implemented in our Ohio
jurisdiction as approved by the PUCO in our RSPs;
|
·
|
A
$28 million increase related to increased usage and customer growth
in the
industrial and commercial classes;
|
·
|
An
$11 million increase related to increased usage and customer growth
in the
residential class; and
|
·
|
A
$26 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
|
·
|
A
$25 million decrease in usage related to mild weather. As compared
to the
prior year, heating degree days were 18% lower in the east and 14%
lower
in the west.
|
·
|
Margins
from Off-system Sales for 2006 were $24 million lower than in 2005
due to
lower volumes in part from the sale of STP in May 2005 and lower
optimization activities.
|
·
|
Other
revenues decreased $6 million primarily due to a decrease in construction
activities performed for third
parties.
|
Utility
Operating Expenses and Other changed between years as follows:
·
|
Maintenance
and Other Operation expenses decreased $6 million primarily due to
a
decrease in construction activities performed for third parties.
|
·
|
Gain
on Sales of Assets, Net decreased $46 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 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 $15 million primarily due to increased
Ohio and Texas regulatory asset amortization.
|
·
|
Other
Income (Expense), Net increased $12 million primarily due to capitalized
carrying costs on environmental and system reliability capital
expenditures for APCo. APCo began capitalizing carrying costs in
conjunction with its environmental and reliability costs filing in
Virginia in the third quarter of 2005.
|
·
|
Interest
and Other Charges increased $10 million from the prior period primarily
due to new debt issued during 2005 and increasing interest
rates.
|
·
|
Income
Tax Expense increased $15 million due to the increase in pretax income.
See “AEP System Income Taxes” section below for further discussion of
fluctuations related to income
taxes.
|
Investments
- Other
First
Quarter of 2006 Compared to First Quarter of 2005
Income
Before Discontinued Operations from our Investments - Other segment increased
from $5 million in 2005 to $16 million in 2006. The increase was primarily
due
to favorable barging activity at AEP MEMCO LLC due to strong demand and a tight
supply of barges which increased the barge fees. Additionally, the first quarter
of 2006 operating conditions for our barging operations improved from 2005
when
severe ice and flooding caused increased operating costs.
Other
Parent
First
Quarter of 2006 Compared to First Quarter of 2005
The
parent company’s loss decreased $12 million from 2005 primarily due to lower
interest expense related to the redemption of $550 million senior unsecured
notes in April 2005 and increased affiliated interest income related to
favorable results from the corporate borrowing program.
Investments
- Gas Operations
First
Quarter of 2006 Compared to First Quarter of 2005
The
$1
million Loss Before Discontinued Operations compares with $10 million of income
recorded for 2005. Prior year results included one month of HPL’s operations due
to the sale of HPL in January 2005. Current year results primarily relate to
gas
contracts that were not sold with the gas pipeline and storage
assets.
AEP
System Income Taxes
The
increase in income tax expense of $17 million between the first quarter of
2006
and first quarter of 2005 is primarily due to an increase in pretax book income
and changes in certain book/tax differences accounted for on a flow-through
basis.
FINANCIAL
CONDITION
We
measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.
Debt
and Equity Capitalization
($ in millions)
|
|
March
31, 2006
|
|
December
31, 2005
|
|
Common
Equity
|
|
$
|
9,384
|
|
|
43.0
|
%
|
$
|
9,088
|
|
|
42.5
|
%
|
Preferred
Stock
|
|
|
61
|
|
|
0.3
|
|
|
61
|
|
|
0.3
|
|
Long-term
Debt, including amounts due within one year
|
|
|
12,142
|
|
|
55.7
|
|
|
12,226
|
|
|
57.2
|
|
Short-term
Debt
|
|
|
226
|
|
|
1.0
|
|
|
10
|
|
|
0.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt and Equity Capitalization
|
|
$
|
21,813
|
|
|
100.0
|
%
|
$
|
21,385
|
|
|
100.0
|
%
|
Our
common equity increased primarily due to earnings exceeding the amount of
dividends paid in 2006. As a consequence of the capital changes during 2006,
we
improved our ratio of total debt to total capital from 57.2% to
56.7%.
The
FASB’s current pension and postretirement benefit accounting project could have
a major negative impact on our debt to capital ratio in future years. The
potential change could require 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. If adopted, this could require
recognition of a significant net of tax accumulated other comprehensive income
reduction to common equity. We cannot predict the ultimate effects of the final
rule or its effective date.
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 March
31, 2006, our available liquidity was approximately $2.7 billion as illustrated
in the table below:
|
Amount
|
|
Maturity
|
|
(in
millions)
|
|
|
Commercial
Paper Backup:
|
|
|
|
|
|
Revolving
Credit Facility
|
$
|
1,000
|
|
May
2007
|
|
Revolving
Credit Facility
|
|
1,500
|
|
March
2010
|
Letter
of Credit Facility
|
|
200
|
|
September
2006
|
Total
|
|
2,700
|
|
|
Cash
and Cash Equivalents
|
|
276
|
|
|
Total
Liquidity Sources
|
|
2,976
|
|
|
Less:
AEP Commercial Paper Outstanding
|
|
215
|
|
|
|
Letter
of Credit Drawn on Credit Facility
|
|
31
|
|
|
Net
Available Liquidity
|
$
|
2,730
|
|
|
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, 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. If the amendments
had occurred prior to March 31, 2006 our Net Available Liquidity would have
been
$3,030 million.
Debt
Covenants and Borrowing Limitations
Our
revolving credit agreements contain certain covenants and require us to maintain
our percentage of debt to total capitalization at a level that does not exceed
67.5%. The method for calculating our outstanding debt and other capital is
contractually defined. At March 31, 2006, this contractually-defined percentage
was 53.6%. Nonperformance of these covenants could result in an event of default
under these credit agreements. At March 31, 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.
We
do not
believe that our rights under the amended facilities would be affected by a
material adverse change.
Under
a
regulatory order, our utility subsidiaries cannot incur additional indebtedness
if the issuer’s common equity would constitute less than 30% (25% for TCC) 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 March 31,
2006, all utility subsidiaries were in compliance with this order.
Utility
Money Pool borrowings and external borrowings may not exceed amounts authorized
by regulatory orders. At March 31, 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
Our
cash
flows are a major factor in managing and maintaining our liquidity
strength.
|
|
Three
Month Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
401
|
|
$
|
320
|
|
Net
Cash Flows From Operating Activities
|
|
|
590
|
|
|
667
|
|
Net
Cash Flows From (Used For) Investing Activities
|
|
|
(757
|
)
|
|
842
|
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
42
|
|
|
(568
|
)
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(125
|
)
|
|
941
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
276
|
|
$
|
1,261
|
|
Cash
from
operations, combined with a bank-sponsored receivables purchase agreement and
short-term borrowings, provides working capital and allows us to meet other
short-term cash needs. 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 March 31, 2006,
we had credit facilities totaling $2.5 billion to support our commercial paper
program. In April 2006, we increased our credit facilities to $3
billion.
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.
Operating
Activities
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Net
Income
|
|
$
|
381
|
|
$
|
355
|
|
Less:
Income From Discontinued Operations
|
|
|
(3
|
)
|
|
(1
|
)
|
Income
From Continuing Operations
|
|
|
378
|
|
|
354
|
|
Noncash
Items Included in Earnings
|
|
|
317
|
|
|
325
|
|
Changes
in Assets and Liabilities
|
|
|
(105
|
)
|
|
(12
|
)
|
Net
Cash Flows From Operating Activities
|
|
$
|
590
|
|
$
|
667
|
|
2006
Operating Cash Flow
Net
Cash
Flows From Operating Activities were $590 million in 2006. We produced Income
from Continuing Operations of $378 million. Income from Continuing Operations
included noncash expense items primarily for depreciation, amortization,
accretion, deferred taxes and deferred investment tax credits. In 2005, we
initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking
recovery of our increased fuel costs. Under-recovered fuel costs decreased
due
to recovery of higher cost of fuel, especially natural gas. 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 these asset and liability
accounts relates to a number of items; the most significant are a $99 million
cash increase from net Accounts Receivable/Accounts Payable due to a lower
balance of Customer Accounts Receivable at March 31, 2006 and
an
increase
in Accrued Taxes of $176 million. We did not make a federal income tax payment
during the first quarter of 2006.
2005
Operating Cash Flow
Net
Cash
Flows From Operating Activities were $667 million in 2005 consisting of our
Income from Continuing Operations of $354 million and noncash charges of $327
million for Depreciation and Amortization. We realized gains of $115
million
on sales
of assets. 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 is a $245 million increase in Accrued
Taxes. We
did
not make a federal income tax payment during the first quarter of
2005.
Investing
Activities
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Construction
Expenditures
|
|
$
|
(772
|
)
|
$
|
(434
|
)
|
Change
in Other Temporary Cash Investments, Net
|
|
|
27
|
|
|
(9
|
)
|
Investment
Securities:
|
|
|
|
|
|
|
|
Purchases
of Investment Securities
|
|
|
(2,469
|
)
|
|
(1,311
|
)
|
Sales
of Investment Securities
|
|
|
2,380
|
|
|
1,396
|
|
Change
in Investment Securities, Net
|
|
|
(89
|
)
|
|
85
|
|
Proceeds
from Sales of Assets
|
|
|
111
|
|
|
1,184
|
|
Other
|
|
|
(34
|
)
|
|
16
|
|
Net
Cash Flows From (Used for) Investing Activities
|
|
$
|
(757
|
)
|
$
|
842
|
|
Net
Cash
Flows Used For Investing Activities were $757 million in 2006 primarily due
to
Construction Expenditures. Construction Expenditures increased due to our
environmental investment plan.
During
2006, we purchased $2.5 billion of investments and received $2.4 billion of
proceeds from the sales of securities. During 2005, we purchased $1.3 billion
of
investments and received $1.4 billion of proceeds from the sales of securities.
We purchase auction rate securities and variable rate demand notes with cash
available for short-term investments. These amounts also include purchases
and
sales within our nuclear trusts.
Net
Cash
Flows From Investing Activities were $842 million in 2005 primarily due to
the
proceeds from the sale of HPL. During 2005, we sold HPL and used a portion
of
the proceeds from the sale to repurchase common stock. Our Construction
Expenditures of $434 million included environmental, transmission and
distribution investment.
We
forecast $2.9 billion of Construction Expenditures for the remainder of 2006.
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, and the ability to access capital. These
construction expenditures will be funded through results of operations and
financing activities.
Financing
Activities
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Issuance
of Common Stock
|
|
$
|
5
|
|
$
|
17
|
|
Repurchase
of Common Stock
|
|
|
-
|
|
|
(434
|
)
|
Issuance/Retirement
of Debt, Net
|
|
|
129
|
|
|
65
|
|
Dividends
Paid on Common Stock
|
|
|
(146
|
)
|
|
(138
|
)
|
Other
|
|
|
54
|
|
|
(78
|
)
|
Net
Cash Flows From (Used for) Financing Activities
|
|
$
|
42
|
|
$
|
(568
|
)
|
Net
Cash
Flows From Financing Activities in 2006 were $42 million. During the first
quarter of 2006, we issued $50 million of obligations relating to pollution
control bonds and increased our short-term commercial paper outstanding. See
Note 12 for a complete discussion of long-term debt issuances and retirements.
The Other amount of $54 million in the above table primarily consists of $68
million received from a coal supplier related to a long-term coal purchase
contract amended in March 2006.
Net
Cash
Flows Used For Financing Activities in 2005 were $568 million. During the first
quarter of 2005, we repurchased common stock using a portion of the proceeds
from the sale of HPL. In addition, our subsidiaries retired $66 million of
cumulative preferred stock, which is reflected in the Other amount in the above
table.
In
April
2006, APCo issued $500 million of debt consisting of $250 million of 5.55%
notes
due 2011 and $250 million of 6.375% notes due 2036. Also in April, OPCo issued
obligations relating to auction rate pollution control bonds in the amount
of
$65 million. The new bonds bear variable interest at a 28-day auction rate.
The
proceeds from this issuance will contribute to our investment in environmental
equipment.
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 off-balance sheet arrangements have not changed significantly
from
year-end. 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
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 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, is capped at $20 million and, to the extent payable,
will be paid in the first quarter of 2007. See “Texas REPs” section of Note
8.
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.
Texas
Regulatory Activity
Texas
Restructuring
The
PUCT
issued an order in TCC’s True-up Proceeding in February 2006, which determined
that TCC’s true-up regulatory asset was $1.475 billion, which included carrying
costs through September 2005. TCC filed an application in March 2006 requesting
to securitize $1.8 billion of net stranded generation plant costs and related
carrying costs to September 1, 2006. The $1.8 billion does not include TCC’s
other true-up items, which are partially offsetting in nature. These obligations
total $491 million and would be payable through a CTC over a period determined
by the PUCT. Intervenors and the PUCT staff filed testimony in April 2006.
Hearings are scheduled for May. It is possible that the PUCT could reduce the
securitization amount by all or some portion of the negative other true-up
items. If that occurs, a negative impact on the timing of cash flows could
result. Cash flows from securitization would be adversely impacted if the PUCT
reduces TCC’s computation of the amount to be securitized in the securitization
proceeding.
The
PUCT
has not addressed the allocation of stranded costs to TCC’s wholesale
jurisdiction. TCC estimates the amount allocated to wholesale to be less than
$1
million, while intervenors and PUCT staff filed testimony recommending that
$77
million of stranded costs be allocated to TCC’s wholesale jurisdiction. TCC
cannot predict the ultimate amount the PUCT will allocate to the wholesale
jurisdiction that TCC will not be able to securitize or recover.
Consistent
with certain prior securitization determinations, the PUCT may deduct the
cost-of-money benefit of accumulated deferred federal income taxes (ADFIT)
from
the securitization request. Then, the future cost-of-money benefit would be
transferred to a separate regulatory asset recoverable in normal delivery rates
outside of the securitization process, which would affect the timing of cash
recovery. We estimate the total cost-of-money benefit to be $328 million, which
TCC plans to include in its estimated CTC request. Intervenors filed testimony
recommending an increase in this amount, along with the retrospective ADFIT
amounts, by as much as $175 million.
In
addition, the intervenors raised three issues totaling $138 million that were
addressed by the PUCT in prior proceedings - the appropriate interest rate
for
both stranded cost and deferred fuel and the treatment of excess earnings
refunds. Other issues raised by the intervenors dealt with the amounts to be
securitized versus refunded to customers through the CTC, customer class
allocation issues and debt defeasance strategies.
The
difference between the recorded securitizable true-up regulatory asset of $1.5
billion at March 31, 2006 and our securitization request of $1.8 billion is
detailed in the table below:
|
|
(in
millions)
|
|
Stranded
Generation Plant Costs
|
|
$
|
969
|
|
Net
Generation-related Regulatory Asset
|
|
|
249
|
|
Excess
Earnings
|
|
|
(49
|
)
|
Recorded
Net Stranded Generation Plant Costs
|
|
|
1,169
|
|
Recorded
Debt Carrying Costs on Recorded Net Stranded Generation Plant
Costs
|
|
|
284
|
|
Recorded
Securitizable True-up Regulatory Asset
|
|
|
1,453
|
|
Unrecorded
But Recoverable Equity Carrying Costs
|
|
|
212
|
|
Unrecorded
Estimated April 2006 - August 2006 Debt Carrying Costs
|
|
|
40
|
|
Unrecorded
Securitization Issuance Costs
|
|
|
24
|
|
Unrecorded
Excess Earnings, Related Return and Other
|
|
|
75
|
|
Securitization
Request
|
|
$
|
1,804
|
|
The
principal components of the CTC rate reduction 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. TCC will incur carrying costs on the net negative
other true-up regulatory liability balances until fully refunded. TCC
anticipates filing to implement a negative CTC (as a rate reduction) for its
net
other true-up items in the second quarter of 2006.
The
difference between the components of TCC’s recorded net regulatory liabilities -
other true-up items as of March 31, 2006 and the amount expected to be requested
in the CTC proceeding are detailed below:
|
|
(in
millions)
|
|
Wholesale
Capacity Auction True-up
|
|
$
|
61
|
|
Carrying
Costs on Wholesale Capacity Auction True-up
|
|
|
17
|
|
Retail
Clawback
|
|
|
(61
|
)
|
Deferred
Over-recovered Fuel Balance
|
|
|
(177
|
)
|
Recorded
Net Regulatory Liabilities - Other True-up Items
|
|
|
(160
|
)
|
ADFIT
Benefit
|
|
|
(328
|
)
|
Unrecorded
Carrying Costs and Other
|
|
|
(3
|
)
|
Estimated
CTC Request
|
|
$
|
(491
|
)
|
If
we
determine in future securitization and CTC proceedings 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 such nonrecovery, we would record a provision
for
such amount which could have an adverse effect on future results of operations,
cash flows and possibly financial condition. TCC intends to pursue rehearing
and
appeals to vigorously seek relief as necessary in both federal and state court
where it believes the PUCT’s rulings are contrary to the Texas Restructuring
Legislation, PUCT rulemakings and federal law. It is expected that the cities
and other intervenors will also pursue vigorously court appeals 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, requested rehearings or court appeals. If the municipal customers
and other intervenors succeed in their expected appeals, it could have a
material adverse effect on future results of operations, cash flows and
financial condition.
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. An adverse result
in
these proceedings has 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 Clean Air Act (CAA) to reduce emissions of sulfur dioxide
(SO2),
nitrogen oxide (NOx),
particulate matter (PM), and mercury from fossil fuel-fired power
plants;
|
·
|
Requirements
under the Clean Water Act (CWA) 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 (CO2)
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.
Clean
Air Act Requirements
The
CAA
establishes a comprehensive program to protect and improve the nation’s air
quality, and control mobile and stationary sources of air emissions. The major
CAA programs affecting our power plants are briefly described below. Many of
these programs are implemented and administered by the states, which can impose
additional or more stringent requirements.
National
Ambient Air Quality Standards:
The CAA
requires the Federal EPA to periodically review the available scientific data
for six criteria pollutants and establish a concentration level in the ambient
air for those substances that is adequate to protect the public health and
welfare with an extra margin for safety. These concentration levels are known
as
“national ambient air quality standards” or NAAQS.
Each
state identifies those areas within its boundaries that meet the NAAQS
(attainment areas) and those that do not (nonattainment areas). Each state
must
then develop a state implementation plan (SIP) to bring nonattainment areas
into
compliance with the NAAQS and maintain good air quality in attainment areas.
All
SIPs are then submitted to the Federal EPA for approval. If a state fails to
develop adequate plans, the Federal EPA must develop and implement a plan.
In
addition, as the Federal EPA reviews the NAAQS, the attainment status of areas
can change, and states may be required to develop new SIPs. The Federal EPA
recently proposed a new PM NAAQS and is conducting periodic reviews for
additional criteria pollutants.
In
1997,
the Federal EPA established new NAAQS that required further reductions in
SO2
and
NOx
emissions. In 2005, the Federal EPA issued a final model federal rule, the
Clean
Air Interstate Rule (CAIR), that assists states developing new SIPs to meet
the
new NAAQS. CAIR reduces regional emissions of SO2
and
NOx
from
power plants in the Eastern U.S. (29 states and the District of Columbia).
CAIR
requires power plants within these states to reduce emissions of SO2
by 50
percent by 2010, and by 65 percent by 2015. NOx
emissions will be subject to additional limits beginning in 2009, and will
be
reduced by a total of 70 percent from current levels by 2015. Reduction of
both
SO2
and
NOx
would be
achieved through a cap-and-trade program. The Federal EPA reconsidered and
affirmed certain aspects of the final CAIR, and the rule has been challenged
in
the courts. States must develop and submit SIPs to implement CAIR by November
2006. Nearly all of the states in which our power plants are located will be
covered by CAIR. Oklahoma is not affected, while Texas and Arkansas will be
covered only by certain parts of CAIR. A SIP that complies with CAIR will also
establish compliance with other CAA requirements, including certain visibility
goals.
Hazardous
Air Pollutants:
As a
result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous
air pollutant (HAP) emissions from the electric utility sector and submitted
a
report to Congress, identifying mercury emissions from coal-fired power plants
as warranting further study. In March 2005, the Federal EPA issued a final
Clean
Air Mercury Rule (CAMR) setting mercury standards for new coal-fired power
plants and requiring all states to issue new SIPs including mercury requirements
for existing coal-fired power plants. The Federal EPA issued a model federal
rule based on a cap-and-trade program for mercury emissions from existing
coal-fired power plants that would reduce mercury emissions to 38 tons per
year
from all existing plants in 2010, and to 15 tons per year in 2018. The national
cap of 38 tons per year in 2010 is intended to reflect the level of reduction
in
mercury emissions that will be achieved as a result of installing controls
to
reduce SO2
and
NOx
emissions in order to comply with CAIR. The Federal EPA is currently
reconsidering certain aspects of the final CAMR, and the rule has been
challenged in the courts. States must develop and submit their SIPs to implement
CAMR by November 2006.
The
Acid Rain Program:
The 1990
Amendments to the CAA included a cap-and-trade emission reduction program for
SO2
emissions from power plants, implemented in two phases. By 2000, the program
established a nationwide cap on power plant SO2
emissions of 8.9 million tons per year. The 1990 Amendments also contained
requirements for power plants to reduce NOx
emissions through the use of available combustion controls.
The
success of the SO2
cap-and-trade program encouraged the Federal EPA and the states to use it as
a
model for other emission reduction programs, including CAIR and CAMR. We meet
our obligations under the Acid Rain Program through the installation of
controls, use of alternate fuels, and participation in the emissions allowance
markets. CAIR uses the SO2
allowances originally allocated through the Acid Rain Program as the basis
for
its SO2
cap-and
trade system.
Regional
Haze:
The CAA
also establishes visibility goals for certain federally designated areas,
including national parks, and requires states to submit SIPs that will
demonstrate reasonable progress toward preventing impairment and remedying
any
existing impairment of visibility in these areas. This is commonly called the
“Regional Haze” program. In June 2005, the Federal EPA issued its final Clean
Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit
technology (BART) requirements will be applied to facilities built between
1962
and 1977 that emit more than 250 tons per year of certain pollutants in specific
industrial categories, including power plants. The final rule contains a
demonstration that for power plants subject to CAIR, CAIR will result in more
visibility improvements than BART would provide. Thus, states are allowed to
substitute CAIR requirements in their Regional Haze SIPs for controls that
would
otherwise be required by BART. For BART-eligible facilities located in states
not subject to CAIR requirements for SO2
and
NOx,
some
additional controls will be required. The final rule has been challenged in
the
courts.
Estimated
Air Quality Environmental Investments
As
discussed in the 2005 Annual Report, the CAIR and CAMR programs described above
will require us to make significant additional investments, some of which are
estimable. However, many of the rules described above are the subject of
reconsideration by the Federal EPA, have been challenged in the courts and
have
not yet been incorporated into SIPs. As a result, these rules may be further
modified. Our estimates disclosed in the 2005 Annual Report, are subject to
significant uncertainties, and will be affected by any changes in the outcome
of
several interrelated variables and assumptions, including: the timing of
implementation, required levels of reductions, methods for allocation of
allowances and our selected compliance alternatives. In short, we cannot
estimate our compliance costs with certainty.
We
will
seek recovery of expenditures for pollution control technologies, replacement
or
additional generation and associated operating costs from customers through
our
regulated rates (in regulated jurisdictions). We should be able to recover
these
expenditures through market prices in deregulated jurisdictions. If not, those
costs could adversely affect future results of operations, cash flows and
possibly financial condition.
Potential
Regulation of CO2
Emissions
At
the
Third Conference of the Parties to the United Nations Framework Convention
on
Climate Change held in Kyoto, Japan in December 1997, more than 160 countries,
including the U.S., negotiated a treaty requiring legally-binding reductions
in
emissions of greenhouse gases, chiefly CO2,
which
many scientists believe are contributing to global climate change. The U.S.
signed the Kyoto Protocol in November 1998, but the treaty was not submitted
to
the Senate for its advice and consent. In March 2001, President Bush announced
his opposition to the treaty. During 2004, enough countries ratified the treaty
for it to become enforceable against the ratifying countries in February 2005.
Several bills have been introduced in Congress seeking regulation of greenhouse
gas emissions, including CO2
emissions from power plants, but none has passed either house of
Congress.
The
Federal EPA stated that it does not have authority under the CAA to regulate
greenhouse gas emissions that may affect global climate trends. This decision
was challenged in the courts and upheld. A petition to appeal to the U.S.
Supreme Court has been filed. While mandatory requirements to reduce
CO2
emissions at our power plants do not appear to be imminent, we participate
in a
number of voluntary programs to monitor, mitigate, and reduce greenhouse gas
emissions.
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 special interest 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. 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 been completed, but
no
decision has been issued. A bench trial on remedy issues is scheduled for
January 2007.
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 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 and the Federal EPA filed a petition for rehearing
in
that case. The Federal EPA also recently proposed a rule that would define
“emissions increases” in a way that most of the challenged activities would be
excluded 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.
Other
Environmental Concerns
We
perform environmental reviews and audits on a regular basis for the purpose
of
identifying, evaluating and addressing environmental concerns and issues. In
addition to the matters discussed above, we are managing other environmental
concerns that we do not believe are material or potentially material at this
time. If they become significant or if any new matters arise that we believe
could be material, they could have a material adverse effect on 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, the
trend in our quarter-over-quarter net income and earnings per share is not
materially different. As of March 31, 2006, we have $46 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 1.67 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, because we procure some services and materials in our
energy business from foreign suppliers we have foreign currency risk.
They 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 some physical contracts, which will gradually
liquidate and completely expire in 2011. Our risk objective and outcomes to-date
keep these positions risk neutral through maturity.
We
employ
risk management contracts including physical forward purchase and sale
contracts, exchange futures and options, over-the-counter options, swaps and
other derivative contracts to offset price risk where appropriate. 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 risk management
operations and our Chief Risk Officer and risk management staff. When risk
management activities exceed certain predetermined limits, the positions are
modified or hedged 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 are 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 of the 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 March 31, 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
March
31, 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
|
$
|
437
|
|
$
|
134
|
|
$
|
571
|
|
$
|
54
|
|
$
|
625
|
|
Noncurrent
Assets
|
|
449
|
|
|
199
|
|
|
648
|
|
|
7
|
|
|
655
|
|
Total
Assets
|
|
886
|
|
|
333
|
|
|
1,219
|
|
|
61
|
|
|
1,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
(379
|
)
|
|
(139
|
)
|
|
(518
|
)
|
(21
|
)
|
|
(539
|
)
|
Noncurrent
Liabilities
|
|
(293
|
)
|
|
(204
|
)
|
|
(497
|
)
|
|
(3
|
)
|
|
(500
|
)
|
Total
Liabilities
|
|
(672
|
)
|
|
(343
|
)
|
|
(1,015
|
)
|
|
(24
|
)
|
|
(1,039
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative
Contract Net
Assets (Liabilities)
|
$
|
214
|
|
$
|
(10
|
)
|
$
|
204
|
|
$
|
37
|
|
$
|
241
|
|
MTM
Risk Management Contract Net Assets (Liabilities)
Three
Months Ended March 31, 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
|
|
|
(5
|
)
|
|
7
|
|
|
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
|
|
|
(4
|
)
|
|
-
|
|
|
(4
|
)
|
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)
|
|
|
8
|
|
|
2
|
|
|
10
|
|
Changes
in Fair Value Allocated to Regulated
Jurisdictions (c)
|
|
|
(2
|
)
|
|
-
|
|
|
(2
|
)
|
Total
MTM Risk Management Contract Net
Assets (Liabilities) at March 31, 2006
|
|
$
|
214
|
|
$
|
(10
|
)
|
|
204
|
|
Net
Cash Flow and Fair Value Hedge Contracts
|
|
|
|
|
|
|
|
|
37
|
|
Ending
Net Risk Management Assets at March
31, 2006
|
|
|
|
|
|
|
|
$
|
241
|
|
(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)
|
“Change
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.
|
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 March 31, 2006
(in
millions)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Utility
Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted - Exchange Traded Contracts
|
|
$
|
38
|
|
$
|
(1
|
)
|
$
|
3
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
40
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
13
|
|
|
39
|
|
|
28
|
|
|
23
|
|
|
-
|
|
|
-
|
|
|
103
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(7
|
)
|
|
17
|
|
|
14
|
|
|
14
|
|
|
29
|
|
|
4
|
|
|
71
|
|
Total
|
|
$
|
44
|
|
$
|
55
|
|
$
|
45
|
|
$
|
37
|
|
$
|
29
|
|
$
|
4
|
|
$
|
214
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments
-
Gas
Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted - Exchange Traded Contracts
|
|
$
|
(3
|
)
|
$
|
12
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
9
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
(1
|
)
|
|
(9
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(10
|
)
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(2
|
)
|
|
-
|
|
|
(1
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|
1
|
|
|
(9
|
)
|
Total
|
|
$
|
(6
|
)
|
$
|
3
|
|
$
|
(1
|
)
|
$
|
(4
|
)
|
$
|
(3
|
)
|
$
|
1
|
|
$
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted - Exchange Traded Contracts
|
|
$
|
35
|
|
$
|
11
|
|
$
|
3
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
49
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
12
|
|
|
30
|
|
|
28
|
|
|
23
|
|
|
-
|
|
|
-
|
|
|
93
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(9
|
)
|
|
17
|
|
|
13
|
|
|
10
|
|
|
26
|
|
|
5
|
|
|
62
|
|
Total
|
|
$
|
38
|
|
$
|
58
|
|
$
|
44
|
|
$
|
33
|
|
$
|
26
|
|
$
|
5
|
|
$
|
204
|
|
(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.
|
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 March 31, 2006
Commodity
|
|
Transaction
Class
|
|
Market/Region
|
|
Tenor
|
|
|
|
|
|
|
(in
Months)
|
Natural
Gas
|
|
Futures
|
|
NYMEX
/ Henry Hub
|
|
60
|
|
|
Physical
Forwards
|
|
Gulf
Coast, Texas
|
|
21
|
|
|
Swaps
|
|
Northeast,
Mid-Continent, Gulf Coast, Texas
|
|
21
|
|
|
Exchange
Option Volatility
|
|
NYMEX
/ Henry Hub
|
|
12
|
Power
|
|
Futures
|
|
AEP
East - PJM
|
|
36
|
|
|
Physical
Forwards
|
|
AEP
East
|
|
45
|
|
|
Physical
Forwards
|
|
AEP
West
|
|
45
|
|
|
Physical
Forwards
|
|
West
Coast
|
|
45
|
|
|
Peak
Power Volatility (Options)
|
AEP
East - Cinergy, PJM
|
|
12
|
Emissions
|
|
Credits
|
|
SO2,
NOx
|
|
33
|
Coal
|
|
Physical
Forwards
|
|
PRB,
NYMEX, CSX
|
|
33
|
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 March 31, 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
Three
Months Ended March 31, 2006
(in
millions)
|
|
Power
and Gas
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI, December 31, 2005
|
|
$
|
(6
|
)
|
$
|
(21
|
)
|
$
|
(27
|
)
|
Changes
in Fair Value
|
|
|
22
|
|
|
9
|
|
|
31
|
|
Reclassifications
from AOCI to Net Income for Cash
Flow Hedges
Settled
|
|
|
3
|
|
|
1
|
|
|
4
|
|
Ending
Balance in AOCI, March 31, 2006
|
|
$
|
19
|
|
$
|
(11
|
)
|
$
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
After
Tax Portion Expected to be Reclassified to Earnings
During Next 12 Months
|
|
$
|
18
|
|
$
|
(1
|
)
|
$
|
17
|
|
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 March 31, 2006, our credit
exposure net of credit collateral to sub investment grade counterparties was
approximately 3.13%, expressed in terms of net MTM assets and net receivables.
As of March 31, 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
|
|
$
|
807
|
|
$
|
145
|
|
$
|
662
|
|
|
1
|
|
$
|
87
|
|
Split
Rating
|
|
|
4
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
2
|
|
Noninvestment
Grade
|
|
|
134
|
|
|
125
|
|
|
9
|
|
|
1
|
|
|
8
|
|
No
External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internal
Investment Grade
|
|
|
85
|
|
|
-
|
|
|
85
|
|
|
1
|
|
|
64
|
|
Internal
Noninvestment Grade
|
|
|
32
|
|
|
17
|
|
|
15
|
|
|
2
|
|
|
14
|
|
Total
|
|
$
|
1,062
|
|
$
|
289
|
|
$
|
773
|
|
|
7
|
|
$
|
175
|
|
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. Please note that 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 March 31, 2006
|
Remainder
2006
|
2007
|
2008
|
Estimated
Plant Output Hedged
|
90%
|
91%
|
92%
|
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 March 31, 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
Three
Months Ended
March
31, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
millions)
|
|
|
|
|
(in
millions)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$2
|
|
$6
|
|
$3
|
|
$2
|
|
|
|
|
$3
|
|
$5
|
|
$3
|
|
$1
|
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 $531 million at March 31, 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 Months Ended March 31, 2006 and 2005
(in
millions, except per-share amounts)
(Unaudited)
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Utility
Operations
|
|
$
|
2,987
|
|
$
|
2,605
|
|
Gas
Operations
|
|
|
(18
|
)
|
|
357
|
|
Other
|
|
|
139
|
|
|
103
|
|
TOTAL
|
|
|
3,108
|
|
|
3,065
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
961
|
|
|
789
|
|
Purchased
Energy for Resale
|
|
|
166
|
|
|
130
|
|
Purchased
Gas for Resale
|
|
|
-
|
|
|
249
|
|
Maintenance
and Other Operation
|
|
|
828
|
|
|
837
|
|
Gain/Loss
on Disposition of Assets, Net
|
|
|
(68
|
)
|
|
(115
|
)
|
Depreciation
and Amortization
|
|
|
341
|
|
|
327
|
|
Taxes
Other Than Income Taxes
|
|
|
191
|
|
|
188
|
|
TOTAL
|
|
|
2,419
|
|
|
2,405
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
689
|
|
|
660
|
|
|
|
|
|
|
|
|
|
Interest
and Investment Income
|
|
|
8
|
|
|
11
|
|
Carrying
Costs Income
|
|
|
30
|
|
|
20
|
|
Allowance
For Equity Funds Used During Construction
|
|
|
6
|
|
|
6
|
|
Gain
on Disposition of Equity Investments, Net
|
|
|
3
|
|
|
-
|
|
|
|
|
|
|
|
|
|
INTEREST
AND OTHER CHARGES
|
|
|
|
|
|
|
|
Interest
Expense
|
|
|
168
|
|
|
173
|
|
Preferred
Stock Dividend Requirements of Subsidiaries
|
|
|
1
|
|
|
2
|
|
TOTAL
|
|
|
169
|
|
|
175
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE, MINORITY
INTEREST
EXPENSE AND EQUITY EARNINGS
|
|
|
567
|
|
|
522
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
189
|
|
|
172
|
|
Minority
Interest Expense
|
|
|
-
|
|
|
1
|
|
Equity
Earnings of Unconsolidated Subsidiaries
|
|
|
-
|
|
|
5
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS
|
|
|
378
|
|
|
354
|
|
|
|
|
|
|
|
|
|
DISCONTINUED
OPERATIONS, Net of Tax
|
|
|
3
|
|
|
1
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
381
|
|
$
|
355
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
|
|
394
|
|
|
393
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations
|
|
$
|
0.96
|
|
$
|
0.90
|
|
Discontinued
Operations, Net of Tax
|
|
|
0.01
|
|
|
-
|
|
TOTAL
BASIC EARNINGS PER SHARE
|
|
$
|
0.97
|
|
$
|
0.90
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
|
|
|
396
|
|
|
394
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations
|
|
$
|
0.95
|
|
$
|
0.90
|
|
Discontinued
Operations, Net of Tax
|
|
|
0.01
|
|
|
-
|
|
TOTAL
DILUTED EARNINGS PER SHARE
|
|
$
|
0.96
|
|
$
|
0.90
|
|
|
|
|
|
|
|
|
|
CASH
DIVIDENDS PAID PER SHARE
|
|
$
|
0.37
|
|
$
|
0.35
|
|
|
|
|
|
|
|
|
|
See Condensed Notes
to
Condensed Consolidated Financial Statements. |
|
|
|
|
|
|
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2006 and December 31, 2005
(in
millions)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
276
|
|
$
|
401
|
|
Other
Temporary Cash Investments
|
|
|
202
|
|
|
127
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
673
|
|
|
826
|
|
Accrued
Unbilled Revenues
|
|
|
315
|
|
|
374
|
|
Miscellaneous
|
|
|
45
|
|
|
51
|
|
Allowance
for Uncollectible Accounts
|
|
|
(33
|
)
|
|
(31
|
)
|
Total Receivables
|
|
|
1,000
|
|
|
1,220
|
|
Fuel,
Materials and Supplies
|
|
|
776
|
|
|
726
|
|
Risk
Management Assets
|
|
|
625
|
|
|
926
|
|
Margin
Deposits
|
|
|
171
|
|
|
221
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
92
|
|
|
197
|
|
Other
|
|
|
107
|
|
|
127
|
|
TOTAL
|
|
|
3,249
|
|
|
3,945
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
16,726
|
|
|
16,653
|
|
Transmission
|
|
|
6,477
|
|
|
6,433
|
|
Distribution
|
|
|
10,895
|
|
|
10,702
|
|
Other
(including gas, coal mining and nuclear fuel)
|
|
|
3,146
|
|
|
3,116
|
|
Construction
Work in Progress
|
|
|
2,538
|
|
|
2,217
|
|
Total
|
|
|
39,782
|
|
|
39,121
|
|
Accumulated
Depreciation and Amortization
|
|
|
14,974
|
|
|
14,837
|
|
TOTAL
- NET
|
|
|
24,808
|
|
|
24,284
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
3,213
|
|
|
3,262
|
|
Securitized
Transition Assets and Other
|
|
|
583
|
|
|
593
|
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,160
|
|
|
1,134
|
|
Investments
in Power and Distribution Projects
|
|
|
47
|
|
|
97
|
|
Goodwill
|
|
|
76
|
|
|
76
|
|
Long-term
Risk Management Assets
|
|
|
655
|
|
|
886
|
|
Employee
Benefits and Pension Assets
|
|
|
1,090
|
|
|
1,105
|
|
Other
|
|
|
840
|
|
|
746
|
|
TOTAL
|
|
|
7,664
|
|
|
7,899
|
|
|
|
|
|
|
|
|
|
Assets
Held for Sale
|
|
|
44
|
|
|
44
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
35,765
|
|
$
|
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
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
millions)
|
|
Accounts
Payable
|
$
|
1,033
|
|
$
|
1,144
|
|
Short-term
Debt
|
|
226
|
|
|
10
|
|
Long-term
Debt Due Within One Year
|
|
1,061
|
|
|
1,153
|
|
Risk
Management Liabilities
|
|
539
|
|
|
906
|
|
Accrued
Taxes
|
|
829
|
|
|
651
|
|
Accrued
Interest
|
|
180
|
|
|
183
|
|
Customer
Deposits
|
|
415
|
|
|
571
|
|
Other
|
|
581
|
|
|
842
|
|
TOTAL
|
|
4,864
|
|
|
5,460
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
Long-term
Debt
|
|
11,081
|
|
|
11,073
|
|
Long-term
Risk Management Liabilities
|
|
500
|
|
|
723
|
|
Deferred
Income Taxes
|
|
4,847
|
|
|
4,810
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
2,760
|
|
|
2,747
|
|
Asset
Retirement Obligations
|
|
950
|
|
|
936
|
|
Employee
Benefits and Pension Obligations
|
|
342
|
|
|
355
|
|
Deferred
Gain on Sale and Leaseback - Rockport Plant Unit 2
|
|
155
|
|
|
157
|
|
Deferred
Credits and Other
|
|
821
|
|
|
762
|
|
TOTAL
|
|
21,456
|
|
|
21,563
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
26,320
|
|
|
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
|
|
|
415,412,203
|
|
|
415,218,830
|
|
|
|
|
|
|
|
(21,499,992
shares were held in treasury at March 31, 2006 and
December
31, 2005)
|
|
2,700
|
|
|
2,699
|
|
Paid-in
Capital
|
|
4,137
|
|
|
4,131
|
|
Retained
Earnings
|
|
2,520
|
|
|
2,285
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
27
|
|
|
(27
|
)
|
TOTAL
|
|
9,384
|
|
|
9,088
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
35,765
|
|
$
|
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 Three Months Ended March 31, 2006 and 2005
(in
millions)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
381
|
|
$
|
355
|
|
Less:
Income from Discontinued Operations
|
|
|
(3
|
)
|
|
(1
|
)
|
Income
from Continuing Operations
|
|
|
378
|
|
|
354
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
341
|
|
|
327
|
|
Accretion
of Asset Retirement Obligations
|
|
|
15
|
|
|
18
|
|
Deferred
Income Taxes
|
|
|
7
|
|
|
(19
|
)
|
Deferred
Investment Tax Credits
|
|
|
(7
|
)
|
|
(8
|
)
|
Carrying
Costs Income
|
|
|
(30
|
)
|
|
(20
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(9
|
)
|
|
27
|
|
Deferred
Property Taxes
|
|
|
(82
|
)
|
|
(82
|
)
|
Pension
Contributions to Qualified Plan Trusts |
|
|
- |
|
|
(102 |
) |
Fuel
Under-Recovery
|
|
|
103
|
|
|
52
|
|
Gain
on Sales of Assets and Equity Investments, Net
|
|
|
(71
|
)
|
|
(115
|
)
|
Change
in Other Noncurrent Assets
|
|
|
73
|
|
|
(60
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
(5
|
)
|
|
(45
|
)
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
214
|
|
|
104
|
|
Fuel,
Materials and Supplies
|
|
|
(50
|
)
|
|
64
|
|
Accounts
Payable
|
|
|
(115
|
)
|
|
7
|
|
Accrued
Taxes
|
|
|
176
|
|
|
245
|
|
Customer
Deposits
|
|
|
(157
|
)
|
|
55
|
|
Other
Current Assets
|
|
|
69
|
|
|
(8
|
)
|
Other
Current Liabilities
|
|
|
(260
|
)
|
|
(127
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
590
|
|
|
667
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(772
|
)
|
|
(434
|
)
|
Change
in Other Temporary Cash Investments, Net
|
|
|
27
|
|
|
(9
|
)
|
Purchases
of Investment Securities
|
|
|
(2,469
|
)
|
|
(1,311
|
)
|
Sales
of Investment Securities
|
|
|
2,380
|
|
|
1,396
|
|
Proceeds
from Sales of Assets
|
|
|
111
|
|
|
1,184
|
|
Other
|
|
|
(34
|
)
|
|
16
|
|
Net
Cash Flows From (Used For) Investing Activities
|
|
|
(757
|
)
|
|
842
|
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Common Stock
|
|
|
5
|
|
|
17
|
|
Repurchase
of Common Stock
|
|
|
-
|
|
|
(434
|
)
|
Change
in Short-term Debt, Net
|
|
|
216
|
|
|
(5
|
)
|
Issuance
of Long-term Debt
|
|
|
55
|
|
|
580
|
|
Retirement
of Long-term Debt
|
|
|
(142
|
)
|
|
(510
|
)
|
Dividends
Paid on Common Stock
|
|
|
(146
|
)
|
|
(138
|
)
|
Other
|
|
|
54
|
|
|
(78
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
42
|
|
|
(568
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(125
|
)
|
|
941
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
401
|
|
|
320
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
276
|
|
$
|
1,261
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
Cash
paid for interest (net of capitalized amounts)
|
|
$
|
159
|
|
$
|
170
|
|
Cash
paid (received) for income taxes, net of refunds
|
|
|
13
|
|
|
(57
|
)
|
Noncash
acquisitions under capital leases
|
|
|
20
|
|
|
9
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
246
|
|
|
146
|
|
|
|
|
|
|
|
|
|
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 Three Months Ended March 31, 2006 and 2005
(in
millions)
(Unaudited)
|
|
Common
Stock
|
|
|
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
|
|
|
Shares
|
|
Amount
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
|
Total
|
|
DECEMBER
31, 2004
|
|
|
405
|
|
$
|
2,632
|
|
$
|
4,203
|
|
$
|
2,024
|
|
$
|
(344
|
)
|
$
|
8,515
|
|
Issuance
of Common Stock
|
|
|
|
|
|
3
|
|
|
14
|
|
|
|
|
|
|
|
|
17
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
(138
|
)
|
|
|
|
|
(138
|
)
|
Repurchase
of Common Stock
|
|
|
|
|
|
|
|
|
(434
|
)
|
|
|
|
|
|
|
|
(434
|
)
|
Other
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
3
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign
Currency Translation Adjustments,
Net
of Tax of $0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
1
|
|
|
Cash
Flow Hedges, Net of Tax of $28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(51
|
)
|
|
(51
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
355
|
|
|
|
|
|
355
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
305
|
|
MARCH
31, 2005
|
|
|
405
|
|
$
|
2,635
|
|
$
|
3,786
|
|
$
|
2,241
|
|
$
|
(394
|
)
|
$
|
8,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
|
415
|
|
$
|
2,699
|
|
$
|
4,131
|
|
$
|
2,285
|
|
$
|
(27
|
)
|
$
|
9,088
|
|
Issuance
of Common Stock
|
|
|
|
|
|
1
|
|
|
4
|
|
|
|
|
|
|
|
|
5
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
(146
|
)
|
|
|
|
|
(146
|
)
|
Other
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
2
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,949
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
|
|
|
35
|
|
|
Securities
Available for Sale, Net of Tax of $10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
19
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
381
|
|
|
|
|
|
381
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
435
|
|
MARCH
31, 2006
|
|
|
415
|
|
$
|
2,700
|
|
$
|
4,137
|
|
$
|
2,520
|
|
$
|
27
|
|
$
|
9,384
|
|
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.
|
Dispositions,
Discontinued Operations and Assets Held for Sale
|
9.
|
Benefit
Plans
|
10.
|
Stock-Based
Compensation
|
11.
|
Business
Segments
|
12.
|
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 interim financial statements should be read in
conjunction with the 2005 Annual Report as incorporated in and filed with our
2005 Form 10-K.
In
the
opinion of management, the unaudited interim financial statements reflect all
normal and recurring accruals and adjustments that are necessary for a fair
presentation of our results of operations for interim periods.
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):
|
|
March
31,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
Components
|
|
(in
millions)
|
|
Securities
Available for Sale, Net of Tax
|
|
$
|
38
|
|
$
|
19
|
|
Cash
Flow Hedges, Net of Tax
|
|
|
8
|
|
|
(27
|
)
|
Minimum
Pension Liability, Net of Tax
|
|
|
(19
|
)
|
|
(19
|
)
|
Total
|
|
$
|
27
|
|
$
|
(27
|
)
|
At
March
31, 2006, we expect to reclassify approximately $17 million of net losses 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. Twenty-one
months is the maximum length of time that we hedge our exposure to variability
in future cash flows with contracts designated as cash flow hedges.
Stock-Based
Compensation Plans
At
March
31, 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.
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 first quarter of 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
quarter ended March 31, 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. No options were granted
during the first quarter of 2005. For the quarters ended March 31, 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 months
ended
March 31, 2005:
|
|
2005
|
|
|
|
(in
millions, except
per
share data)
|
|
Net
Income, as reported
|
|
$
|
355
|
|
Add:
Stock-based compensation expense included in reported Net Income,
net of related
tax effects
|
|
|
2
|
|
Deduct:
Stock-based compensation expense determined under fair
value based method for
all awards, net
of related tax effects
|
|
|
(2
|
)
|
Pro
Forma Net Income
|
|
$
|
355
|
|
|
|
|
|
|
Earnings
Per Share:
|
|
|
|
|
Basic
- as Reported
|
|
$
|
0.90
|
|
Basic
- Pro Forma (a)
|
|
$
|
0.90
|
|
|
|
|
|
|
Diluted
- as Reported
|
|
$
|
0.90
|
|
Diluted
- Pro Forma (a)
|
|
$
|
0.90
|
|
(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 March 31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
$/share
|
|
|
|
$/share
|
|
Earnings
applicable to common stock
|
|
$
|
381
|
|
|
|
|
$
|
355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
number of basic shares outstanding
|
|
|
393.7
|
|
$
|
0.97
|
|
|
393.1
|
|
$
|
0.90
|
|
Average
dilutive effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
1.4
|
|
|
(0.01
|
)
|
|
0.8
|
|
|
-
|
|
Stock
Options
|
|
|
0.3
|
|
|
-
|
|
|
0.3
|
|
|
-
|
|
Restricted
Stock Units
|
|
|
0.1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Restricted
Shares
|
|
|
0.1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Average
number of diluted shares outstanding
|
|
|
395.6
|
|
$
|
0.96
|
|
|
394.2
|
|
$
|
0.90
|
|
Our
stock
option and other equity compensation plans are discussed in Note
10.
Related
Party Transactions
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
AEP
Consolidated Purchased Energy:
|
|
|
|
|
|
Ohio
Valley Electric Corporation (43.47% Owned)
|
|
$
|
55
|
|
$
|
43
|
|
Sweeny
Cogeneration Limited Partnership (50% Owned)
|
|
|
34
|
|
|
29
|
|
AEP
Consolidated Other Revenues - Barging and Other Transportation
Services - Ohio Valley Electric
Corporation (43.47% Owned)
|
|
|
7
|
|
|
4
|
|
Reclassifications
Certain
prior period financial statement items have been reclassified to conform to
current period presentation.
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.
These
revisions had no impact on our previously reported results of operations,
financial condition or changes in shareholders’ equity.
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 have determined relate to our operations.
SFAS
123 (revised 2004) “Share-Based Payment”
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 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 Operation.
In
March
2005, the SEC issued Staff Accounting Bulletin 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 months ended March 31, 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
156 “Accounting for Servicing of Financial Assets - An Amendment of FASB
Statement No. 140” (SFAS 156)
In
March
2006, the FASB issued SFAS 156. SFAS 156 requires an entity to recognize a
servicing asset or servicing liability each time it undertakes an obligation
to
service a financial asset by entering into a servicing contract in certain
situations and requires all separately recognized servicing assets and servicing
liabilities to be initially measured at fair value, if practicable. SFAS 156
also requires separate presentation of servicing assets and servicing
liabilities subsequently measured at fair value in the statement of financial
position and additional disclosures for all separately recognized servicing
assets and servicing liabilities. The requirements for recognition and initial
measurement of servicing assets and servicing liabilities should be applied
prospectively to all transactions after the effective date of this statement.
This statement will be effective on January 1, 2007. Management has not
completed the process of determining the effect of this statement 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 accounting
for uncertain tax positions, fair value measurements, business combinations,
revenue recognition, pension and postretirement benefit plans, liabilities
and
equity, earnings per share calculations, 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 proceedings that are not
expected to adversely affect future results of operations and cash flows are
not
included in this report. The following sections discuss current activities
and
update the 2005 Annual Report.
APCo
Virginia Environmental and Reliability Costs
The
Virginia Electric Restructuring Act 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 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 March 31, 2006, APCo deferred
$26
million of incurred E&R costs.
In
January 2006, the Virginia SCC staff proposed that APCo recover current, rather
than past, incremental E&R costs in its electric rates at an ongoing level
of $20 million. 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 established as a regulatory
asset. We believe the staff’s position is contrary to the statute and an October
2005 Virginia SCC order, which denied APCo’s original request to recover
projected costs in favor of the Virginia SCC’s interpretation that the law only
permits recovery of actual incurred incremental E&R costs that the
commission found prudent.
Hearings
concluded in March 2006. At the hearings, the staff amended its testimony to
recommend a $24 million increase in APCo’s ongoing rates. If the Virginia SCC
reverses its position and adopts the staff’s recommendation or denies recovery
of any of APCo’s deferred E&R costs, future results of operations and cash
flows could be adversely impacted.
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 an equity return.
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. This proposed off-system sales rate credit of $27 million partially
offsets the $225 million requested increase in base rates for a net increase
of
$198 million. APCo requested that the new rates be implemented on an interim
basis beginning in the June 2006 customer billings. 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
April
2006, APCo and WPCo reached agreement with the WVPSC staff and intervenors
in
the West Virginia rate case filed in 2005. The parties filed a settlement
agreement with the WVPSC, providing for an initial overall increase in rates
of
$44 million effective July 28, 2006. The initial annual increase in rates is
comprised of :
·
|
An
Expanded Net Energy Cost (ENEC) increase of $56 million for fuel
and
purchased power expenses;
|
·
|
A
$23 million special construction surcharge providing recovery of
the costs
of the Wyoming-Jacksons Ferry 765 kV line and scrubbers to
date;
|
·
|
A
general base rate reduction of $18 million of which $9 million relates
to
a reduction in depreciation expense which affects cash flows but
not
earnings; and
|
·
|
A
$17 million credit for prior over-recoveries of ENEC costs, currently
recorded in regulatory liabilities on the Condensed Consolidated
Balance
Sheets. Therefore, this item impacts cash flows but has no effect
on
earnings.
|
In
addition, the agreement provides a mechanism that allows APCo and WPCo to adjust
their rates annually for the timely recovery of the ongoing investments in
scrubbers at APCo’s Mountaineer and John Amos power plants. The estimated
future annual increases based on the level of incremental investment in the
scrubbers as proposed in the settlement, are projected to result in a $36
million increase in rates effective July 1, 2007, a $14 million increase in
rates effective July 1, 2008 and an $18 million increase in rates effective
July
1, 2009. The settlement further provides for the reinstatement of ENEC
proceedings and its related annual rate adjustment mechanism for changes in
fuel
and purchased power costs. Although the agreement is comprehensive in all
respects, one issue regarding the rates for a special contract industrial
customer remains unresolved. The WVPSC ordered legal briefs to be filed by
May
4, 2006 with responses to be filed by May 15, 2006. At this time, the WVPSC
has
not approved the settlement agreement and therefore, management is unable to
predict the ultimate effect of this filing on future revenues and cash
flows.
I&M
Depreciation Study Filing
In
December 2005, I&M filed a petition with the IURC, seeking authorization to
revise the book depreciation rates applicable to its electric utility plant
in
service. 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 Nuclear Plant licenses for Units 1 and 2 and
an
extension of the service life of the Tanners Creek coal-fired generating units.
This petition is not a request for a change in customers’ electric service
rates. Intervenors filed testimony in March 2006 and I&M filed its rebuttal
testimony in April 2006.
Hearings
are scheduled for May 2006. As
proposed by I&M, the
book
depreciation expense reduction would increase earnings, but would not impact
cash flows. If approved by the IURC, I&M will currently adjust its book
depreciation expense from the approved effective date forward. Management is
unable to predict the outcome of this proceeding.
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 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 for AFUDC purposes.
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 reallocation of purchased power costs over three
years. 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. In February 2006, the OCC staff filed a report regarding $9
million of the reallocation assigned to wholesale customers. In that report,
the
OCC staff concluded that the reallocation assigned to wholesale customers has
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. In September 2005, the United States District
Court for the Western District of Texas issued an order in a TNC 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 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 vigorously. 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
of
these Oklahoma fuel clause proceedings and future FERC proceedings, if any,
on
future results of operations, cash flows and financial condition.
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 has 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
that they will not further pursue the matter.
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 on July 28, 2005,
the Texas Court of Appeals reversed the District Court. The cities are appealing
the appeals court decision to the Texas Supreme Court. 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 the PUCT were to reverse
its
decision and order refunds of PTB revenues, it could adversely impact results
of
operations and cash flows.
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. The total amortization
related to such costs was $1 million in both the first quarter of 2006 and
2005.
As of both March 31, 2006 and December 31, 2005, the AEP East companies had
$31
million of deferred unamortized RTO 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 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.
In
2005,
the FERC denied a request we jointly filed with two other utilities to recover
deferred PJM-billed integration costs from all load-serving entities in the
PJM
RTO zone over a ten-year period. Instead, the FERC ordered the companies to
make
a compliance filing to recover the PJM-billed integration costs solely from
the
zones of the requesting companies. Subsequently, the FERC approved the
compliance rate, and PJM began charging the rate to load serving entities in
the
AEP zone (and the other companies’ zones), including the AEP East companies on
behalf of the load they serve in the AEP zone (about 85% of the total load
in
the AEP zone). In June 2005, AEP filed a request for rehearing. In October
2005,
the FERC granted our rehearing request and set the following two issues for
settlement discussions and, if necessary, for hearing: (i) whether the PJM
OATT
is unjust and unreasonable without PJM region-wide recovery of PJM-billed
integration costs and (ii) a determination of a just and reasonable carrying
charge rate on the deferred PJM-billed integration costs. In April 2006, a
settlement was filed with the FERC that allows recovery of our deferred
PJM-billed integration costs from the PJM region over ten years. In addition,
the settlement reduced the return on equity component included in our carrying
charge rate to 10.5%, which will have an immaterial impact on future results
of
operations.
We
recover the amortization of RTO formation/integration costs billed to our AEP
East companies in Ohio for CSPCo and OPCo, and in Kentucky for KPCo. We have
not
commenced recovery in West Virginia (where APCo filed a settlement agreement
in
its base rate case with the WVPSC that included the recovery of its amortization
of these costs), Virginia (where APCo filed a base rate case which includes
recovery of these costs) or Indiana (where I&M is subject to a rate cap
until June 30, 2007).
Until
APCo and I&M can adjust their retail rates to recover the amortization of
both RTO-related deferred costs, results of operations and cash flows will
be
adversely affected by the amortizations. If the Virginia, West Virginia or
Indiana commissions disallow recovery of any portion of the billed amortization
of deferred RTO formation/integration costs or no appeal is ultimately
successful, it would have an adverse impact on future results of operations
and
cash flows.
Transmission
Rate Proceedings at the FERC
SECA
Revenue
In
accordance with FERC orders, we collected SECA rates to mitigate lost
through-and-out transmission service (T&O) revenues through March 31, 2006,
when SECA rates expired. The FERC set SECA rate issues for hearing and indicated
that the SECA rate revenues are subject to refund or surcharge. The AEP East
companies recognized net SECA revenues of $35 million and $26 million during
the
first quarter of 2006 and 2005, respectively. Since the implementation of SECA
rates in December 2004 through March 2006, we have recognized net SECA revenues
of $174 million. Intervenors in the SECA proceeding are objecting to the SECA
rates and our method of determining those rates. The SECA hearings are scheduled
to begin in early May 2006. At this time, management is unable to determine
the
outcome of the FERC’s SECA rate proceeding and if it will impact future results
of operations and cash flows.
AEP
East Transmission Revenue Requirement and Rates
In
December 2005, the FERC approved an uncontested settlement allowing increases
to
our wholesale transmission rates in three steps: first, beginning November
1,
2005, second, beginning April 1, 2006 when the SECA revenues were eliminated
and
third, on the later of August 1, 2006 or the first day of the month following
the date when our Wyoming-Jacksons Ferry transmission line enters service,
currently expected in June 2006.
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,
among others, for the regional transmission service provided with their owned
extra-high-voltage facilities that benefit 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. Under our proposed Highway/Byway rate design, the cost of all
transmission facilities in the PJM region operated at a voltage of 345 kV or
higher would be included in a “Highway” rate that all load serving entities
(LSEs) would pay based on peak demand. The cost of transmission facilities
operating at lower voltages would be collected in the zones where those costs
are presently charged under PJM’s rate design. In a competing Highway/Byway
proposal, a group of LSEs proposed rates that would include 500 kV and higher
existing facilities and some facilities at lower voltages in the Highway rate.
Another proposal uses facilities 200 kV or higher in the Highway rate. These
alternative Highway/Byway proposals are being challenged by a majority of
transmission owners in the PJM region who favor continuation of the PJM rate
design. In January 2006, the FERC staff issued testimony and exhibits supporting
a PJM-wide flat rate or “Postage Stamp” type of rate design. Hearings were held
in April 2006.
The
AEP/AP Highway/Byway design would result in incremental net revenues of
approximately $125 million per year for the transmission-owning AEP East
companies. The competing Highway/Byway proposals filed by others would also
produce incremental net revenues to the AEP East transmission-owning companies,
but at a much lower level. The staff rate design would produce slightly more
net
revenue for AEP than the original AEP/AP proposal. We cannot at this time
estimate the outcome of the proceeding; however, adoption of any of the new
proposals would have a positive effect on our revenues and results of
operations, compared to the continuation of the PJM rates that went into effect
on April 1, 2006 when the SECA rates expired.
As
of
March 31, 2006, SECA transition rates did not 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 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 expected shortfall. Full mitigation of the effects of eliminated T&O
revenues and the less favorable terminated SECA revenues will require cost
recovery through retail rate proceedings. The status of the retail rate
proceedings are as follows:
·
|
In
Kentucky, KPCo settled a rate case, which provides for the recovery
of the
transmission revenue shortfall.
|
·
|
APCo
filed a settlement agreement in West Virginia, which included recovery
of
the lost T&O/SECA transmission revenues.
|
·
|
A
pending rate request filed in February 2006 in Ohio addresses the
significant reduction in FERC transmission revenues.
|
·
|
In
Virginia, APCo filed a request for revised rates, which includes
recovery
of the lost T&O/SECA transmission revenues.
|
·
|
In
Indiana, I&M is precluded by a rate cap from raising its rates until
July 1, 2007.
|
Management
is unable to predict whether the FERC will approve a regional rate to mitigate
the loss of T&O/SECA revenues, or if not, when, and if, the effect of the
loss of T&O/SECA transmission revenues will be recoverable on a timely basis
in all of the AEP East state retail jurisdictions and from wholesale LSEs within
the PJM region.
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, or the FERC’s review of our previously collected SECA rates results in a
refund to customers.
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 our 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 SWEPCo. 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 and cash flows will depend upon
the
level of future margins by region and the status of cost recovery mechanisms
by
state; however, in general, it is expected to have a favorable effect on future
results of operations and cash flows. 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 current events
related to customer choice and industry restructuring and update the 2005 Annual
Report.
TEXAS
RESTRUCTURING
The
PUCT
issued an order in TCC’s True-up Proceeding in February 2006, which determined
that TCC’s true-up regulatory asset was $1.475 billion, which included carrying
costs through September 2005. An order on rehearing was issued by the PUCT
in
April 2006, which made minor changes to, but otherwise affirmed, the February
2006 order. We expect to appeal, seeking additional recovery consistent with
the
Texas Restructuring Legislation and related rules. Other parties may appeal
the
PUCT’s order claiming it permits TCC to over-recover its stranded
costs.
TCC
Securitization Proceeding
TCC
filed
an application in March 2006 requesting to securitize $1.8 billion of net
stranded generation plant costs and related carrying costs to September 1,
2006.
The $1.8 billion does not include TCC’s other true-up items, which are partially
offsetting in nature. These obligations total $491 million and would be payable
through a CTC over a period determined by the PUCT. See “CTC Proceeding for
Other True-up Items” section of this note. Intervenors and the PUCT staff filed
testimony in April 2006. Hearings are scheduled for May. It is possible that
the
PUCT could reduce the securitization amount by all or some portion of the
negative other true-up items. If that occurs, a negative impact on the timing
of
cash flows could result. Cash flows from securitization would be adversely
impacted if the PUCT reduces TCC’s computation of the amount to be
securitized.
The
PUCT
has not addressed the allocation of stranded costs to TCC’s wholesale
jurisdiction. TCC estimates the amount allocated to wholesale to be less than
$1
million, while intervenors and PUCT staff filed testimony recommending that
$77
million of stranded costs be allocated to TCC’s wholesale jurisdiction. TCC
cannot predict the ultimate amount the PUCT will allocate to the wholesale
jurisdiction that TCC will not be able to securitize or recover.
Consistent
with certain prior securitization determinations, the PUCT may deduct the
cost-of-money benefit of accumulated deferred federal income taxes (ADFIT)
from
the securitization request. Then, the future cost-of-money benefit would be
transferred to a separate regulatory asset recoverable in normal delivery rates
outside of the securitization process, which would affect the timing of cash
recovery. We estimate the total cost-of-money benefit to be $328 million, which
TCC plans to include in its estimated CTC request. Intervenors filed testimony
recommending an increase in this amount, along with the retrospective ADFIT
amounts, by as much as $175 million.
In
addition, the intervenors raised three issues totaling $138 million which were
addressed by the PUCT in prior proceedings - the appropriate interest rate
for
both stranded cost and deferred fuel and the treatment of excess earnings
refunds. Other issues raised by the intervenors dealt with the amounts to be
securitized versus refunded to customers through the CTC, customer class
allocation issues and debt defeasance strategies.
The
difference between the recorded securitizable true-up regulatory asset of $1.5
billion at March 31, 2006 and our securitization request of $1.8 billion is
detailed in the table below:
|
|
(in
millions)
|
|
Stranded
Generation Plant Costs
|
|
$
|
969
|
|
Net
Generation-related Regulatory Asset
|
|
|
249
|
|
Excess
Earnings
|
|
|
(49
|
)
|
Recorded
Net Stranded Generation Plant Costs
|
|
|
1,169
|
|
Recorded
Debt Carrying Costs on Recorded Net Stranded Generation Plant
Costs
|
|
|
284
|
|
Recorded
Securitizable True-up Regulatory Asset
|
|
|
1,453
|
|
Unrecorded
But Recoverable Equity Carrying Costs
|
|
|
212
|
|
Unrecorded
Estimated April 2006 - August 2006 Debt Carrying Costs
|
|
|
40
|
|
Unrecorded
Securitization Issuance Costs
|
|
|
24
|
|
Unrecorded
Excess Earnings, Related Return and Other
|
|
|
75
|
|
Securitization
Request
|
|
$
|
1,804
|
|
Deferred
Investment Tax Credits and Excess Deferred Federal Income
Taxes
In
TCC’s
true-up order, the PUCT reduced net stranded generation plant costs by $51
million related to the present value of accumulated deferred investment tax
credits (ADITC) and by $10 million related to excess deferred federal income
taxes (EDFIT) associated with TCC’s generating assets. TCC testified that the
sharing of these tax benefits with customers may be a violation of the Internal
Revenue Code’s normalization provisions. The federal tax statutes require
public utilities to "normalize" or sychronize the tax benefits derived from
ADITC and EDFIT with the financial and regulatory life of the regulated plant
assets that give rise to the benefit. The normalization rules
prohibit returning the benefits to ratepayers faster than the
underlying assets are recovered for rate purposes. Once these
assets are no longer regulated, the normalization provisions do not
permit these benefits to be returned to ratepayers. In the true-up
order, the PUCT agreed to consider revisiting this issue if the IRS ruled that
the flow-through of ADITC and EDFIT constituted a normalization violation.
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 final, nonappealable rate order. Although ADITC and EDFIT
are
recorded as a liability on TCC’s books, such amounts are not reflected as a
reduction of TCC’s recorded securitizable true-up regulatory asset in the above
reconciliation.
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. On April
21, 2006 the IRS informed TCC that they are ruling against the PUCT treatment
and consider the flowthrough of ADITC and EDFIT a normalization
violation.
In
a
motion for rehearing, TCC asked the PUCT to reconsider its treatment of ADITC
and EDFIT in light of the position of the IRS. In its order on rehearing, the
PUCT declined to change its treatment. The PUCT withdrew the language stating
it
would revisit the issue if their treatment was ruled a normalization violation
by the IRS and replaced it with an additional explanation of the basis for
its
original decision. In a motion for a second rehearing filed April 24, 2006,
TCC
informed the PUCT that the IRS intended to rule adversely on the private letter
ruling request.
If
a
normalization violation occurs, it could result in the repayment of TCC’s ADITC
on all property, including transmission and distribution, which approximates
$105 million as of March 31, 2006 and also a loss of the accelerated tax
depreciation election in the future. Management intends to continue working
with
the PUCT to avoid a normalization violation that would adversely affect future
results of operations and cash flows.
CTC
Proceeding for Other True-up Items
TCC
incurs carrying costs on the net negative other true-up regulatory liability
balances until fully refunded. The principal components of the CTC rate
reduction 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. TCC anticipates
filing to implement a negative CTC (as a rate reduction) for its net other
true-up items in the second quarter of 2006.
The
difference between the components of TCC’s recorded net regulatory liabilities -
other true-up items as of March 31, 2006 and its planned CTC proceeding request
are detailed below:
|
|
(in
millions)
|
|
Wholesale
Capacity Auction True-up
|
|
$
|
61
|
|
Carrying
Costs on Wholesale Capacity Auction True-up
|
|
|
17
|
|
Retail
Clawback
|
|
|
(61
|
)
|
Deferred
Over-recovered Fuel Balance
|
|
|
(177
|
)
|
Recorded
Net Regulatory Liabilities - Other True-up Items
|
|
|
(160
|
)
|
ADFIT
Benefit
|
|
|
(328
|
)
|
Unrecorded
Carrying Costs and Other
|
|
|
(3
|
)
|
Estimated
CTC Request
|
|
$
|
(491
|
)
|
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. TCC has a similar
appeal outstanding and believes that the same ruling should result. The impact
of the favorable Federal District court order, if upheld on appeal, could result
in reductions to the over-recovered fuel balances of $8 million for TNC and
$14
million for TCC. The PUCT appealed the Federal Court decision to the United
States Court of Appeals for the Fifth Circuit. If the PUCT is unsuccessful
in
the federal court system, it 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 and is successful, it could result in an adverse effect
on
results of operations and cash flows for the AEP East companies. An unfavorable
FERC ruling may result in a reallocation of off-system sales margins from AEP
East companies to AEP West companies. 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 from its unbundled cost
of
service rate proceeding. The recorded embedded debt component of the carrying
cost rate is 8.12%. Through March 2006, TCC recorded $301 million of
debt-related carrying costs ($284 million on stranded generation plant costs
impacting the securitization proceeding and $17 million on wholesale capacity
auction true-up impacting the CTC proceeding). The remaining equity component
of
$166 million will be recognized in income as collected. TCC will continue to
accrue a debt-related carrying cost until its net true-up regulatory asset
is
fully recovered. Equity carrying costs are recognized in income as
collected.
In
January 2006, the PUCT approved publication of a proposed rule that would reduce
the 11.79% overall carrying cost rate on nonsecuritized true-up amounts to
the
most recently approved weighted average cost of debt, which would be 5.70%
for
TCC. The effective date of the change is proposed to be (i) January 1, 2002
for
utilities that have not received a final true-up order or (ii) the date the
rule
is adopted for utilities that have received a final order. There will be a
45-day comment period from the date of adoption. TCC received an order in the
True-up Proceeding in February 2006 and an order on rehearing in April 2006
(which is subject to rehearing). TCC asserted in comments filed in the
rulemaking proceeding that the rule change should not have retroactive
application. However, TCC cannot predict if the rule will be adopted, or if
it
will be adopted in its present prospective form for utilities that have received
their final true-up order. If adopted retroactively, it would have an adverse
effect on future results of operations and cash flows.
Summary
Our
recorded securitizable true-up regulatory asset at March 31, 2006 of $1.5
billion, net of regulatory liabilities - other true-up items of $160 million,
accurately reflects the PUCT’s order in TCC’s True-up Proceeding. TCC performed
a probability of recovery impairment test on its net true-up regulatory asset
taking into account the treatment ordered by the PUCT and determined that the
projected cash flows from the net transition charges would be more than
sufficient to recover TCC’s recorded net true-up regulatory asset. As a result,
we have not recorded any additional impairment. Barring any future disallowances
to TCC’s net recoverable true-up regulatory asset in its true-up or subsequent
proceedings, TCC expects to amortize its total net true-up regulatory asset
commensurate with recovery over periods established by the PUCT in future
securitization and CTC proceedings. If we determine in future securitization
and
CTC proceedings 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 such
nonrecovery, we would record a provision for such amount which could have an
adverse effect on future results of operations, cash flows and possibly
financial condition. TCC intends to pursue rehearing and appeals to vigorously
seek relief as necessary in both federal and state court where it believes
the
PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT
rulemakings and federal law. It is expected that municipal customers and other
intervenors will also pursue vigorously court appeals 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,
requested rehearings or court appeals. If municipal customers and other
intervenors succeed in their expected appeals, it could have a material adverse
effect on future results of operations, cash flows and financial condition.
Texas
Restructuring - SPP
In
April
2006, the PUCT proposed a possible delay in 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.
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 the IGCC Plant (see “IGCC Plant” section of this note below). OPCo’s
potential for the 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 the IGCC plant. The RSPs also provide
that the Ohio companies can recover in 2006, 2007 and 2008 estimated 2004 and
2005 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 $8 million for CSPCo and $20 million
for
OPCo in the first quarter of 2006 from all the RSP recoveries less the
amortization of RSP deferrals net of the recognition of equity carrying charges
from 2004 and 2005.
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
POLR charges. In Dayton Power and Light Company'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 another Ohio Supreme Court
decision involving FirstEnergy Corporation's Ohio electric companies,
the Court held that the PUCO-approved RSPs for Ohio electric companies did
not
comply with the statutory provision regarding the availability of a competitive
bid alternative for customers. The Ohio companies believe their RSPs are
factually different from FirstEnergy Corporation's Ohio electric companies'
RSPs
and comply with the applicable statute. However, if the Ohio Supreme Court
reverses the PUCO’s authorization of the POLR charge, CSPCo and OPCo’s future
earnings will be adversely affected. In addition, if the RSP order were
determined on appeal to be illegal in its entirety under the Ohio Electric
Restructuring Act of 1999, it would have an initial adverse effect on results
of
operations, cash flows and possibly financial condition. Although we believe
that the RSP plan is legal and we intend to defend vigorously the PUCO’s order,
we cannot predict the ultimate outcome of the pending litigation.
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, 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. 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
March 31, 2006, the Ohio companies deferred $10 million of pre-construction
IGCC
costs.
On
April
10, 2006, the PUCO issued an order finding that the PUCO has the jurisdiction
to
approve the proposed cost recovery and authorizing the Ohio companies to
implement Phase 1 of the cost recovery proposal. The Ohio companies filed a
tariff to recover Phase 1 pre-construction costs over a twelve-month period.
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.
Transmission
Rate Filing
In
February 2006, the Ohio companies filed a request with the PUCO for a two-step
increase in their transmission rates. In the filing, the first increase would
be
effective April 1, 2006 to reflect their share of the loss of SECA revenues
and
the second increase would be effective the later of August 2006 or the first
day
of the month following the date when AEP’s Wyoming-Jacksons Ferry transmission
line enters service, currently expected to occur on June 30, 2006. We
anticipate, if approved, the filing will result in increased revenues for CSPCo
and OPCo of $32 million and $42 million, respectively, in 2006 and increasing
in
2007 to $46 million and $59 million for CSPCo and OPCo, respectively. This
filing intends to recover the new OATT rates resulting from the settlement
of
our March 2005 filing with the FERC requesting increased OATT rates in a
three-step increase. In March 2006, the PUCO suspended the effective date of
the
new rates to provide its staff additional time to conduct its review of the
application. In their application, the Ohio companies requested permission
to
defer for future recovery their unrecovered transmission costs as a result
of
the loss of SECA revenues starting April 1, 2006 if the PUCO did not issue
an
order in this case in time to implement the increase on April 1, 2006. If the
PUCO does not approve the future recovery of the unrecovered transmission costs
effective April 1, 2006 when the SECA revenues ceased, results of operations
and
cash flows will be adversely affected.
Storm
Cost Recovery Filing
In
March
2006, the Ohio companies filed an application with the PUCO to implement tariff
riders to recover a portion of previously-expensed 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.
PUCO
Staff Report on Service Reliability
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 April
2006, the staff of the PUCO submitted a commission-ordered investigative report
on the Ohio companies’ compliance with the stipulation agreement. In the report,
the staff asserted that the Ohio companies failed to fulfill all the terms
of
the stipulation agreement. The staff recommended various consequences for the
PUCO’s consideration, including the potential for civil forfeitures, monthly
payments until the terms of the stipulation agreement have been met and
providing credits to customers. The staff also suggested that the PUCO could
explore possible improvements in the Ohio companies’ management of the
reliability process. Finally, the staff recommended that the Ohio companies
file, in a companion docket, a comprehensive plan to improve their system
reliability. The PUCO ordered the Ohio companies to respond to the staff's
recommendations concerning consequences by May 23, 2006, after which the PUCO
will determine how to proceed. In the companion docket, the PUCO directed
the Ohio companies to prepare a plan to enhance service reliability. A
timeline for submission of that plan has not been set. The PUCO
indicated that it will set a procedural schedule in the future. Although
we believe that the Ohio companies have substantially met the terms and
expectations of the stipulation agreement, we cannot predict the outcome of
these proceedings. If the PUCO adopts the staff’s recommendations, results of
operations and cash flows could be adversely affected.
Customer
Choice Deferrals
As
provided in stipulation agreements approved by the PUCO in 2000, we defer
customer choice implementation costs and related carrying costs in excess of
$40
million. The agreements provide for the deferral of these costs as regulatory
assets until the next distribution base rate cases. Through March 31, 2006,
we
incurred $101 million of such costs and, accordingly, we deferred $53 million
of
such costs for probable future recovery in distribution rates. We have not
recorded $8 million of equity carrying costs, which are not recognized until
collected. Recovery of these regulatory assets is subject to PUCO review in
future Ohio filings for new distribution rates. Pursuant to the RSPs, recovery
of these amounts is deferred until the next distribution rate filing to change
rates after December 31, 2008. 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 have alleged that APCo, CSPCo, I&M, OPCo
and other nonaffiliated utilities, including the Tennessee Valley Authority,
Alabama Power Company, Cincinnati Gas and 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 but no decision has
been issued. A bench trial on remedy issues is scheduled for January
2007.
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.
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 have been filed in certain appellate courts,
including a petition to appeal to the U.S. Supreme Court 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 and the Federal EPA filed a petition for rehearing in that case. The
Federal EPA also recently proposed a rule that would define “emissions
increases” in a way that most of the challenged activities would be excluded
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 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.
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
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 Tennesse 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 has been completed and the case is scheduled to be argued
this summer. We believe the actions are without merit and intend to defend
vigorously against the claims.
Ontario
Litigation
In
June
2005, we and 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, have emitted
NOX,
SO2
and
particulate matter that have 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 vigorously 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 nonregulated 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 now 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.
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
(expected to be approximately 220 MW through May 31, 2006 and 270 MW
thereafter). 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 Tractebel Energy
Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period
of 20 years under a Power Purchase and Sale Agreement 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
United States 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 (i) was suspending performance of its
obligations under the PPA; (ii) would seek a declaration from the District
Court
that the PPA was terminated; and (iii) would pursue against 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 (i) award a termination payment to us under the terms of the PPA;
(ii) grant our attorneys’ fees; and (iii) 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. 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 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
court granted partial summary judgment in favor of the BOA Syndicate. HPL
appealed this decision. The state court of appeals scheduled oral argument
on
the appeal for June 2006. 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 defend vigorously 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.
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 is dependent on the ultimate
resolution of the BOA dispute and the costs, if any, associated with the
resolution of this matter (see Note 8).
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 are pending in Federal
District Court, Columbus, Ohio. In these actions, the plaintiffs seek recovery
of an unstated amount of compensatory damages, attorney fees and costs. We
filed
a Motion to Dismiss these actions, which the Court denied. The cases are in
the
discovery stage. The Court scheduled a hearing on class certification for June
2006. We intend to continue to defend vigorously against these
claims.
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 vigorously 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. The defendants filed a petition for leave to appeal this
decision. We intend to continue to defend vigorously against these
claims.
FERC
Long-term Contracts
In
2002,
the FERC held a hearing related to a complaint filed by certain wholesale
customers located in Nevada. 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 two Nevada utilities. In 2001, the 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 utilities’ complaint, held that
the markets for future delivery were not dysfunctional, and that the 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 utilities’ request for a rehearing was denied. The 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 March
31, 2006, the maximum future payments for all the LOCs are approximately $31
million with maturities ranging from July 2006 to March 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 $55
million with maturity dates ranging from July 2006 to February
2012.
As
part
of the process to receive a renewal of a Texas Railroad Commission permit for
lignite mining, SWEPCo provided 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. At March 31, 2006, the cost
to
reclaim the mine in 2035 is estimated at approximately $39 million. This
guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to
complete reclamation.
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 March 31, 2006,
we
entered into several sale agreements. The status of certain sales agreements
is
discussed in the “Dispositions” section of Note 8. These sale agreements include
indemnifications with a maximum exposure related to the collective purchase
price, which is approximately $2.3 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
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 March 31, 2006, the maximum potential loss for these
lease agreements was approximately $52 million ($34 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 lease term from
approximately 86% to 77% of the projected fair market value of the equipment.
At
March 31, 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 rail car 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 $28 million was recorded (primarily in Maintenance
and Other Operation within the Utility Operations segment) in 2005, primarily
in
the second quarter. The company subsequently made payments of $16 million during
2005. The following table shows the accrual as of December 31, 2005, the
activity during the first quarter of 2006 and the remaining accrual (reflected
primarily in Current Liabilities - Other) as of March 31, 2006:
|
|
Amount
(in
millions)
|
|
Accrual
at December 31, 2005
|
|
$
|
12
|
|
Less:
Total Payments
|
|
|
8
|
|
Less:
Accrual Adjustments
|
|
|
2
|
|
Remaining
Accrual at March 31, 2006
|
|
$
|
2
|
|
The
acrual adjustments were recorded primarily in Maintenance and Other Operation
on
our Condensed Consolidated Statements of Operations. The settlement of the
remaining accrual is expected by the end of the second quarter of
2006.
8. DISPOSITIONS,
DISCONTINUED OPERATIONS AND ASSETS HELD FOR
SALE
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. The sale was completed 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 March 31, 2006 and December 31, 2005,
which is reflected in Deferred Credits and Other on our accompanying Condensed
Consolidated Balance Sheets. We provided an indemnity in an amount up to the
purchase price to the purchaser 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 do 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 to hold forward gas
contracts not sold with the gas pipeline and storage assets.
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 capped at $20 million.
The payments are reflected in Gain/Loss on Disposition of Assets, Net on our
accompanying 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 March 31, 2006 and 2005:
|
|
|
SEEBOARD
(a)
|
|
U.K.
Generation (b)
|
|
Total
|
|
2006
Revenue
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
2006
Pretax Income
|
|
|
-
|
|
|
5
|
|
|
5
|
|
2006
Earnings, Net of Tax
|
|
|
-
|
|
|
3
|
(c)
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
Revenue (Expense)
|
|
$
|
-
|
|
$
|
(8
|
)
|
$
|
(8
|
)
|
2005
Pretax Loss
|
|
|
-
|
|
|
(8
|
)
|
|
(8
|
)
|
2005
Earnings (Loss), Net of Tax
|
|
|
6
|
|
|
(5
|
)(d)
|
|
1
|
|
(a)
|
Relates
to purchase price true-up adjustments and tax adjustments from the
sale of
SEEBOARD.
|
(b)
|
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.
|
(c)
|
Earnings
per share related to the UK Operations was $0.01.
|
(d)
|
Earnings
per share related to the UK Operations was
$(0.01).
|
There
were no cash flows used for or provided by operating, investing or financing
activities related to our discontinued operations for the three months ended
March 31, 2006 and 2005.
ASSETS
HELD FOR SALE
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 Brownsfield (the
"nonaffiliated co-owners"). By May 2004, we received notice from
the nonaffiliated co-owners of the Oklaunion Power Station, 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. These agreements were challenged
in
Dallas County, Texas State District Court by Golden Spread. Golden Spread
alleges that the Public Utilities Board of the City of Brownsfield 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 co-owners’ exercise of their rights of first refusal void. The
court entered a judgment in favor of Golden Spread on October 10,
2005. TCC and the nonaffiliated co-owners filed an appeal to the Fifth
State Court of Appeals in Dallas. The case was briefed and argued before the
court and is awaiting a decision. We cannot predict when these issues will
be
resolved. We do not expect the sale to have a significant effect on our future
results of operations. TCC’s assets related to the Oklaunion Power Station have
been classified as Assets Held for Sale on our Condensed Consolidated Balance
Sheets at March 31, 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.
Assets
Held for Sale at March 31, 2006 and December 31, 2005 are as
follows:
|
|
March
31,
|
|
December
31,
|
|
Texas
Plants
|
|
2006
|
|
2005
|
|
Assets:
|
|
(in
millions)
|
|
Other
Current Assets
|
|
$
|
1
|
|
$
|
1
|
|
Property,
Plant and Equipment, Net
|
|
|
43
|
|
|
43
|
|
Total
Assets Held for Sale
|
|
$
|
44
|
|
$
|
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 months ended March 31, 2006 and 2005:
|
|
Pension
Plans
|
|
Other
Postretirement Benefit Plans
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$
|
24
|
|
$
|
23
|
|
$
|
10
|
|
$
|
11
|
|
Interest
Cost
|
|
|
57
|
|
|
56
|
|
|
25
|
|
|
27
|
|
Expected
Return on Plan Assets
|
|
|
(83
|
)
|
|
(77
|
)
|
|
(23
|
)
|
|
(23
|
)
|
Amortization
of Transition Obligation
|
|
|
-
|
|
|
-
|
|
|
7
|
|
|
7
|
|
Amortization
of Net Actuarial Loss
|
|
|
20
|
|
|
13
|
|
|
5
|
|
|
7
|
|
Net
Periodic Benefit Cost
|
|
$
|
18
|
|
$
|
15
|
|
$
|
24
|
|
$
|
29
|
|
10. STOCK-BASED
COMPENSATION
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 shares 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. Except for 10,000 stock options granted in the third quarter
of 2005, we have not granted stock options since 2004. The
following sections provide further information regarding each type of
stock-based compensation award we have 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 we have 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.
AEP
did
not award any stock options during the three months ended March 31, 2006 and
2005.
The
total
fair value of stock options vested during the three months ended March 31,
2006
and 2005 were $3,664,624 and $5,030,424, respectively. The total intrinsic
value
of options exercised during the three months ended March 31, 2006 and 2005
was
$1,389,409 and $4,319,995, 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 three months ended March 31, 2006
is
as follows:
|
|
Options
|
|
Weighted
Average Exercise Price
|
|
|
|
|
|
|
|
Outstanding
at beginning of quarter
|
|
|
6,221,839
|
|
$
|
34.16
|
|
Granted
|
|
|
-
|
|
|
N/A
|
|
Exercised/converted
|
|
|
(172,722
|
)
|
|
28.67
|
|
Expired
|
|
|
(87,611
|
)
|
|
48.43
|
|
Forfeited
|
|
|
-
|
|
|
N/A
|
|
Outstanding
at end of quarter
|
|
|
5,961,506
|
|
|
34.11
|
|
|
|
|
|
|
|
|
|
Options
exercisable at end of quarter
|
|
|
5,689,652
|
|
$
|
34.34
|
|
|
|
|
|
|
|
|
|
Weighted
average exercise price of options:
|
|
|
|
|
|
|
|
Granted
above Market Price
|
|
|
-
|
|
$
|
N/A
|
|
Granted
at Market Price
|
|
|
-
|
|
$
|
N/A
|
|
The
following table summarizes information about AEP stock options outstanding
at
March 31, 2006.
Options
Outstanding
2006
Range of
Exercise
Prices
|
|
Number
Outstanding
|
|
Weighted
Average
Remaining
Life
|
|
Weighted
Average
Exercise
Price
|
|
Aggregate
Intrinsic
Value
|
|
|
|
|
|
(in
years)
|
|
|
|
|
|
$25.73
- $27.95
|
|
|
1,465,615
|
|
|
6.9
|
|
$
|
27.37
|
|
$
|
9,693,895
|
|
$30.76
- $38.65
|
|
|
4,110,408
|
|
|
4.6
|
|
|
35.45
|
|
|
823,032
|
|
$43.79
- $49.00
|
|
|
385,483
|
|
|
5.4
|
|
|
45.52
|
|
|
-
|
|
|
|
|
5,961,506
|
|
|
5.2
|
|
|
34.11
|
|
$
|
10,516,927
|
|
The
following table summarizes information about AEP stock options exercisable
at
March 31, 2006.
Options
Exercisable
2006
Range of
Exercise
Prices
|
|
Number
Exercisable
|
|
Weighted
Average
Remaining
Life
|
|
Weighted
Average
Exercise
Price
|
|
Aggregate
Intrinsic
Value
|
|
|
|
|
|
(in
years)
|
|
|
|
|
|
$25.73
- $27.95
|
|
|
1,260,528
|
|
|
6.1
|
|
$
|
27.29
|
|
$
|
8,473,587
|
|
$30.76
- $38.65
|
|
|
4,050,741
|
|
|
3.6
|
|
|
35.50
|
|
|
602,951
|
|
$43.79
- $49.00
|
|
|
378,383
|
|
|
5.0
|
|
|
45.49
|
|
|
-
|
|
|
|
|
5,689,652
|
|
|
4.2
|
|
|
34.34
|
|
$
|
9,076,538
|
|
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.
We
awarded performance units and reinvested dividends on outstanding performance
units and AEP Career Shares for the three months ended March 31, 2006 and 2005
as follows:
|
|
2006
|
|
2005
|
|
Performance
Units
|
|
|
|
|
|
Awarded
Units
|
|
|
864,420
|
|
|
1,012,597
|
|
Unit
Fair Value at Grant Date
|
|
$
|
37.36
|
|
$
|
34.02
|
|
Vesting
Period (years)
|
|
|
3
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
Performance
Units and AEP Career Shares
(Reinvested
Dividends Portion)
|
|
|
|
|
|
|
|
Awarded
Units
|
|
|
30,277
|
|
|
23,939
|
|
Unit
Fair Value at Grant Date
|
|
$
|
35.31
|
|
$
|
34.21
|
|
Vesting
Period (years)
|
|
|
3
|
|
|
3
|
|
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 payout for these performance units was $2,629,537 for
the
three months ended March 31, 2006.
The
score
for the 2002 through 2004 performance period was discretionarily reduced to
0%
by the HR Committee so no performance units were earned, paid or deferred during
the three months ended March 31, 2005.
The
cash
payouts for AEP Career Share distributions, which occur after a participant’s
termination of employment, for the three months ended March 31, 2006 and 2005
were $475,685 and $564,598, respectively.
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
We
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. The maximum
term for these restricted shares is eight years. We have not granted other
restricted shares. Dividends on our restricted shares are paid in
cash.
We
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, we 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.
We
awarded restricted stock units, including units awarded for dividends, for
the
three months ended March 31, 2006 and 2005 as follows:
|
|
2006
|
|
2005
|
|
Restricted
Stock Units
|
|
|
|
|
|
Awarded
Units
|
|
|
37,199
|
|
|
27,100
|
|
Weighted
Average Grant Date Fair Value
|
|
$
|
35.80
|
|
$
|
33.11
|
|
The
total
fair value of restricted shares and restricted stock units vested during the
three months ended March 31, 2006 and 2005 were $2,279,551
and $2,132,922, respectively. The total intrinsic value of restricted shares
and
restricted stock units vested during the three months ended March 31, 2006
and
2005 was $2,944,138 and $2,577,752, respectively.
A
summary
of the status of our nonvested restricted shares and restricted stock units
as
of March 31, 2006, and changes during the three months ended March 31, 2006,
are
presented below:
Nonvested
Restricted Shares and Restricted Stock Units
|
|
Shares/Units
|
|
Weighted
Average
Grant
Date Fair Value
|
|
|
|
|
|
|
|
Nonvested
at beginning of quarter
|
|
|
496,716
|
|
$
|
32.19
|
|
Granted
|
|
|
37,199
|
|
|
35.80
|
|
Vested
|
|
|
(78,944
|
)
|
|
28.88
|
|
Forfeited
|
|
|
(565
|
)
|
|
32.81
|
|
Nonvested
at end of quarter
|
|
|
454,406
|
|
|
33.06
|
|
The
total
aggregate intrinsic value of nonvested restricted shares and restricted stock
units as of March 31, 2006 was $15,458,892 and the weighted average remaining
contractual life was 3.14 years.
Share-based
Compensation Plans
Compensation
cost for share-based payment arrangements recognized in income for the three
months ended March 31, 2006 and 2005 was $2,429,868 and $2,916,484,
respectively. The actual tax benefit realized for the tax deductions from
compensation cost from share-based payment arrangements recognized in income
for
the three months ended March 31, 2006 and 2005 totaled $850,454 and $1,020,769,
respectively. The total compensation cost capitalized in relation to the cost
of
an asset for the three months ended March 31, 2006 and 2005 was $578,434 and
$401,159, respectively.
During
the three months ended March 31, 2006 and 2005, there were no significant
modifications affecting any of our share-based payment arrangements.
As
of
March 31, 2006, there was $45,936,136 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 1.67 years.
Cash
received from stock options exercised during the three months ended March 31,
2006 and 2005 was $4,952,298 and $15,153,465, respectively. The actual tax
benefit realized for the tax deductions from stock options exercised during
the
three months ended March 31, 2006 and 2005 totaled $486,293 and $1,515,268,
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. 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 that we no longer pursue business interests outside of the footprint
of
our domestic core utility assets led us to embark on a divestiture of 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.
|
·
|
Our
gas pipeline and storage assets were disposed of 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.
|
·
|
UK
Operations were classified as Discontinued Operations during 2003
and were
sold during 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 months
ended March 31, 2006 and 2005 and balance sheet information as of March 31,
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
March
31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
2,987
|
|
$
|
(18
|
) |
$
|
-
|
|
$
|
139
|
|
$
|
-
|
|
$
|
-
|
|
$
|
3,108
|
|
Other
Operating Segments
|
|
|
(18
|
) |
|
21
|
|
|
-
|
|
|
3
|
|
|
1
|
|
|
(7
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
2,969
|
|
$
|
3
|
|
$
|
-
|
|
$
|
142
|
|
$
|
1
|
|
$
|
(7
|
)
|
$
|
3,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued Operations
|
|
$
|
365
|
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
16
|
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
378
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
3
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
3
|
|
Net
Income (Loss)
|
|
$
|
365
|
|
$
|
(1
|
)
|
$
|
3
|
|
$
|
16
|
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
381
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
Gas
Operations
|
|
UK
Operations
|
|
Other
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Three
Months Ended
March
31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
2,605
|
|
$
|
357
|
|
$
|
-
|
|
$
|
103
|
|
$
|
-
|
|
$
|
-
|
|
$
|
3,065
|
|
Other
Operating Segments
|
|
|
79
|
|
|
(73
|
) |
|
-
|
|
|
6
|
|
|
1
|
|
|
(13
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
2,684
|
|
$
|
284
|
|
$
|
-
|
|
$
|
109
|
|
$
|
1
|
|
$
|
(13
|
)
|
$
|
3,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued Operations
|
|
$
|
353
|
|
$
|
10
|
|
$
|
-
|
|
$
|
5
|
|
$
|
(14
|
)
|
$
|
-
|
|
$
|
354
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
(5
|
) |
|
6
|
|
|
-
|
|
|
-
|
|
|
1
|
|
Net
Income (Loss)
|
|
$
|
353
|
|
$
|
10
|
|
$
|
(5
|
) |
$
|
11
|
|
$
|
(14
|
)
|
$
|
-
|
|
$
|
355
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
Gas
Operations
|
|
UK
Operations
|
|
Other
|
|
All
Other
|
|
Reconciling
Adjustments (b)
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
As
of March 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Property, Plant and Equipment
|
|
$
|
38,943
|
|
$
|
2
|
|
$
|
-
|
|
$
|
834
|
|
|
3
|
|
$
|
-
|
|
$
|
39,782
|
|
Accumulated
Depreciation and Amortization
|
|
|
14,852
|
|
|
1
|
|
|
-
|
|
|
119
|
|
|
2
|
|
|
-
|
|
|
14,974
|
|
Total
Property, Plant and Equipment - Net
|
|
$
|
24,091
|
|
$
|
1
|
|
$
|
-
|
|
$
|
715
|
|
$
|
1
|
|
$
|
-
|
|
$
|
24,808
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
34,178
|
|
$
|
830
|
(c)
|
$
|
625
|
(d)
|
$
|
593
|
|
$
|
10,782
|
|
$
|
(11,243
|
)
|
$
|
35,765
|
|
Assets
Held for Sale
|
|
|
44
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
44
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
Gas
Operations
|
|
UK
Operations
|
|
Other
|
|
All
Other
|
|
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 interest, litigation and other miscellaneous parent
company
expenses.
|
(b)
|
Reconciling
Adjustments for Total Assets primarily include the elimination of
intercompany advances to affiliates and intercompany accounts receivable
along with the elimination of AEP’s investments in subsidiary
companies.
|
(c)
|
Total
Assets of $830 million for the Investments-Gas Operations segment
include
$349 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 $481 million in assets
represents third party risk management contracts, margin deposits,
and
accounts receivable.
|
(d)
|
Total
Assets of $625 million for the Investments-UK Operations segment
include
$613 million in affiliated accounts receivable related mainly to
federal
income taxes that are eliminated in consolidation. The majority of
the
remaining $12 million in assets represents cash equivalents with
value-added tax receivables.
|
(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 with value-added
tax
receivables.
|
12. FINANCING
ACTIVITIES
Long-term
Debt
|
|
March
31,
|
|
December
31,
|
|
Type
of Debt
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
|
|
|
|
|
|
Pollution
Control Bonds
|
|
$
|
1,985
|
|
$
|
1,935
|
|
Senior
Unsecured Notes
|
|
|
8,226
|
|
|
8,226
|
|
First
Mortgage Bonds
|
|
|
96
|
|
|
196
|
|
Defeased
First Mortgage Bonds (a)
|
|
|
26
|
|
|
26
|
|
Notes
Payable
|
|
|
899
|
|
|
904
|
|
Securitization
Bonds
|
|
|
617
|
|
|
648
|
|
Notes
Payable To Trust
|
|
|
113
|
|
|
113
|
|
Other
Long-Term Debt (b)
|
|
|
238
|
|
|
236
|
|
Unamortized
Discount (net)
|
|
|
(58
|
)
|
|
(58
|
)
|
Total
Long-term Debt Outstanding
|
|
|
12,142
|
|
|
12,226
|
|
Less
Portion Due Within One Year
|
|
|
1,061
|
|
|
1,153
|
|
Long-term
Portion
|
|
$
|
11,081
|
|
$
|
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 March 31,
2006
and December 31, 2005. Trust fund assets related to this obligation
of $2
million are included in Other Temporary Cash Investments at both
March 31,
2006 and December 31, 2005 and $21 million is included in Other Noncurrent
Assets in the Condensed Consolidated Balance Sheets at both March
31, 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 March 31, 2006 and December 31, 2005. Trust fund
assets
related to this obligation of $1 million at both March 31, 2006 and
December 31, 2005 are included in Other Temporary Cash Investments
and $9
million and $8 million are included in Other Noncurrent Assets in
the
Condensed Consolidated Balance Sheets at March 31, 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 $266 million
and $264 million related to this obligation are included in Spent
Nuclear
Fuel and Decommissioning Trusts in the Condensed Consolidated Balance
Sheets at March 31, 2006 and December 31, 2005,
respectively.
|
Long-term
debt and other securities issued, retired and principal payments made during
the
first three 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
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
6
|
|
Variable
|
|
2006
|
|
Total
Issuances
|
|
|
|
$
|
56
|
(a)
|
|
|
|
|
The
above borrowing arrangements do not contain guarantees, collateral or dividend
restrictions.
(a)
|
Amount
indicated on statement of cash flows of $55 million is net of issuance
costs and unamortized premium or
discount.
|
In
April
2006, APCo issued $250 million, 5.55% senior notes due in 2011 and $250 million,
6.375% senior notes due in 2036. The proceeds will be used for general corporate
purposes including funding the construction program, repaying advances from
affiliates and replenishing working capital.
In
April
2006, OPCo incurred obligations of $65 million relating to variable rate
pollution control bonds due in 2036. The proceeds will be used to finance the
cost of solid waste disposal facilities at the Mitchell Generating
Station.
Company
|
|
Type
of Debt
|
|
Principal
Amount Paid
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
|
(in
millions)
|
|
(%)
|
|
|
|
Retirements
and
Principal Payments:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
First
Mortgage Bonds
|
|
$
|
100
|
|
6.80
|
|
2006
|
|
OPCo
|
|
Notes
Payable
|
|
|
1
|
|
6.81
|
|
2008
|
|
OPCo
|
|
Notes
Payable
|
|
|
3
|
|
6.27
|
|
2009
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
2
|
|
4.47
|
|
2011
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
1
|
|
Variable
|
|
2006
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
1
|
|
Variable
|
|
2008
|
|
TCC
|
|
Securitization
Bonds
|
|
|
31
|
|
5.01
|
|
2010
|
|
Non-Registrant:
|
|
|
|
|
|
|
|
|
|
|
AEP
Subsidiaries
|
|
Notes
Payable
|
|
|
3
|
|
Variable
|
|
2017
|
|
Total
Retirements
|
|
|
|
$
|
142
|
|
|
|
|
|
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. Costs of operating the plant are divided between the
co-owners.
Results
of Operations
Net
Income increased $0.4 million for 2006 compared with 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 are calculated and adjusted
monthly.
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006 Net
Income
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
2.5
|
|
|
|
|
|
|
|
|
|
Change
in Gross Margin:
|
|
|
|
|
|
|
|
Wholesale
Sales
|
|
|
|
|
|
2.8
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(1.7
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(0.1
|
)
|
|
|
|
Interest
Expense
|
|
|
(0.1
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(1.9
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(0.5
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
2.9
|
|
Gross
Margin, Operating Revenues less Fuel for Electric Generation, increased $2.8
million primarily due to recovery of higher expenses and higher returns earned
on plant and capital investment.
The
increase in Other Operation and Maintenance expenses resulted from increased
maintenance cost at Rockport Plant during a planned outage in 2006 and credits
allocated to us from the cancellation and settlement of corporate owned life
insurance policies in February 2005.
Income
Taxes
The
increase in Income Tax Expense is primarily due to an increase in pretax
book
income, state income taxes 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
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 Months Ended March 31, 2006 and 2005
(Unaudited)
(in
thousands)
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
|
$
|
78,151
|
|
$
|
66,546
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
for Electric Generation
|
|
|
43,961
|
|
|
35,135
|
|
Rent
- Rockport Plant Unit 2
|
|
|
17,071
|
|
|
17,071
|
|
Other
Operation
|
|
|
3,095
|
|
|
2,447
|
|
Maintenance
|
|
|
2,786
|
|
|
1,718
|
|
Depreciation
and Amortization
|
|
|
5,948
|
|
|
5,956
|
|
Taxes
Other Than Income Taxes
|
|
|
1,070
|
|
|
1,024
|
|
TOTAL
|
|
|
73,931
|
|
|
63,351
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
4,220
|
|
|
3,195
|
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
|
(722
|
)
|
|
(634
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
3,498
|
|
|
2,561
|
|
Income
Tax Expense
|
|
|
570
|
|
|
45
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
2,928
|
|
$
|
2,516
|
|
CONDENSED
STATEMENTS OF RETAINED EARNINGS
For
the Three Months Ended March 31, 2006 and 2005
(Unaudited)
(in
thousands)
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
BALANCE
AT BEGINNING OF PERIOD
|
|
$
|
26,038
|
|
$
|
24,237
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
|
2,928
|
|
|
2,516
|
|
|
|
|
|
|
|
|
|
Cash
Dividends Declared
|
|
|
1,998
|
|
|
940
|
|
|
|
|
|
|
|
|
|
BALANCE
AT END OF PERIOD
|
|
$
|
26,968
|
|
$
|
25,813
|
|
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
March
31, 2006 and December 31, 2005
(Unaudited)
(in
thousands)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Accounts
Receivable - Affiliated Companies
|
|
$
|
28,064
|
|
$
|
29,671
|
|
Fuel
|
|
|
15,675
|
|
|
14,897
|
|
Materials
and Supplies
|
|
|
7,283
|
|
|
7,017
|
|
Accrued
Tax Benefits
|
|
|
-
|
|
|
2,074
|
|
Prepayments
and Other
|
|
|
44
|
|
|
9
|
|
TOTAL
|
|
|
51,066
|
|
|
53,668
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric
- Production
|
|
|
688,479
|
|
|
684,721
|
|
Other
|
|
|
2,240
|
|
|
2,369
|
|
Construction
Work in Progress
|
|
|
9,818
|
|
|
12,252
|
|
Total
|
|
|
700,537
|
|
|
699,342
|
|
Accumulated
Depreciation and Amortization
|
|
|
387,933
|
|
|
382,925
|
|
TOTAL
- NET
|
|
|
312,604
|
|
|
316,417
|
|
|
|
|
|
|
|
|
|
Noncurrent
Assets
|
|
|
9,312
|
|
|
6,618
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
372,982
|
|
$
|
376,703
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
GENERATING COMPANY
CONDENSED
BALANCE SHEETS
LIABILITIES
AND SHAREHOLDER’S EQUITY
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
13,317
|
|
$
|
35,131
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
1,569
|
|
|
926
|
|
Affiliated
Companies
|
|
|
19,450
|
|
|
22,161
|
|
Long-term
Debt Due Within One Year
|
|
|
44,831
|
|
|
44,828
|
|
Accrued
Taxes
|
|
|
7,160
|
|
|
3,055
|
|
Accrued
Rent - Rockport Plant Unit 2
|
|
|
23,427
|
|
|
4,963
|
|
Other
|
|
|
849
|
|
|
1,228
|
|
TOTAL
|
|
|
110,603
|
|
|
112,292
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Deferred
Income Taxes
|
|
|
22,659
|
|
|
23,617
|
|
Asset
Retirement Obligations
|
|
|
1,397
|
|
|
1,370
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
82,107
|
|
|
82,689
|
|
Deferred
Gain on Sale and Leaseback - Rockport Plant Unit 2
|
|
|
92,941
|
|
|
94,333
|
|
Obligations
Under Capital Leases
|
|
|
11,873
|
|
|
11,930
|
|
TOTAL
|
|
|
210,977
|
|
|
213,939
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
321,580
|
|
|
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
|
|
|
26,968
|
|
|
26,038
|
|
TOTAL
|
|
|
51,402
|
|
|
50,472
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$
|
372,982
|
|
$
|
376,703
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
GENERATING COMPANY
CONDENSED
STATEMENTS OF CASH FLOWS
For
the Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
2,928
|
|
$
|
2,516
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
5,948
|
|
|
5,956
|
|
Deferred
Income Taxes
|
|
|
(1,126
|
)
|
|
(1,192
|
)
|
Deferred
Investment Tax Credits
|
|
|
(827
|
)
|
|
(834
|
)
|
Amortization
of Deferred Gain on Sale and Leaseback
- Rockport Plant Unit 2
|
|
|
(1,392
|
)
|
|
(1,392
|
)
|
Deferred
Property Taxes
|
|
|
(2,734
|
)
|
|
(2,884
|
)
|
Changes
in Other Noncurrent Assets
|
|
|
(376
|
)
|
|
(233
|
)
|
Changes
in Other Noncurrent Liabilities
|
|
|
374
|
|
|
448
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
|
1,607
|
|
|
(1,170
|
)
|
Fuel,
Materials and Supplies
|
|
|
(1,044
|
)
|
|
5,416
|
|
Accounts
Payable
|
|
|
(2,068
|
)
|
|
(2,953
|
)
|
Accrued
Taxes, Net
|
|
|
6,179
|
|
|
359
|
|
Accrued
Rent - Rockport Plant Unit 2
|
|
|
18,464
|
|
|
18,464
|
|
Other
Current Assets
|
|
|
(35
|
)
|
|
(35
|
)
|
Other
Current Liabilities
|
|
|
(379
|
)
|
|
(351
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
25,519
|
|
|
22,115
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(1,693
|
)
|
|
(1,379
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
(21,814
|
)
|
|
(19,784
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(14
|
)
|
|
(12
|
)
|
Dividends
Paid
|
|
|
(1,998
|
)
|
|
(940
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(23,826
|
)
|
|
(20,736
|
)
|
|
|
|
|
|
|
|
|
Net
Change in Cash and Cash Equivalents
|
|
|
-
|
|
|
-
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
-
|
|
|
-
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
-
|
|
$
|
-
|
|
SUPPLEMENTAL
DISCLOSURE:
|
Cash
paid for interest net of capitalized amounts was $1,109,000 and
$1,021,000
and for income taxes net of refunds was $0 and $5,439,000 in 2006
and
2005, respectively. Noncash capital lease acquisitions were $27,000
and
$18,000 in 2006 and 2005,
respectively.
|
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
10
|
Financing
Activities
|
Note
11
|
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARY
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARY
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006 Net
Income
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Texas
Supply
|
|
|
(44
|
)
|
|
|
|
Texas
Wires
|
|
|
3
|
|
|
|
|
Transmission
Revenues
|
|
|
(4
|
)
|
|
|
|
Other
|
|
|
(3
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
31
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(4
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
2
|
|
|
|
|
Carrying
Costs on Stranded Cost Recovery
|
|
|
24
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
53
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
4
|
|
Net
Income increased $3 million in the first quarter of 2006. The key drivers
of the
increase were a $31 million decrease in Other Operation and Maintenance expenses
and increased Carrying Costs on Stranded Cost Recovery of $24 million, partially
offset by a decrease in Gross Margin of $48 million.
The
major
components of our change in Gross Margin, defined as revenues less the related
direct cost of fuel and purchased power were as follows:
·
|
Texas
Supply margins decreased $44 million primarily due to lower nonaffiliated
sales of $54 million and lower ERCOT energy sales of $4 million.
These
decreases were partially offset by lower fuel and purchased power
expenses
of $18 million. We substantially exited the generation market with
the
sale of STP in May 2005.
|
·
|
Texas
Wires revenues increased $3 million primarily due to an increase
in sales
volumes resulting in large part from an increase in degree
days.
|
·
|
Transmission
Revenues decreased $4 million primarily due to lower ERCOT rates.
|
·
|
Other
revenues decreased $3 million primarily due to lower third party
construction project revenues, primarily 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 $31 million primarily
due to
an $8 million decrease in power plant operations, $10 million decrease
in
plant maintenance and the absence of $5 million in accretion expense
related to the sale of STP. An additional $6 million decrease resulted
from lower expenses related to construction activities performed
for third
parties, primarily the Lower Colorado River Authority.
|
·
|
Carrying
Costs on Stranded Cost Recovery increased $24 million primarily
due to a
$27 million negative adjustment recorded in the first quarter of
2005
related to prior years.
|
Income
Taxes
The
increase in Income Tax Expense of $2 million is primarily due to an increase
in
pretax book income.
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 three months ended March 31, 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
|
|
|
45,728
|
|
|
(118,918
|
)
|
Investing
Activities
|
|
|
(57,795
|
)
|
|
1,716
|
|
Financing
Activities
|
|
|
12,067
|
|
|
118,185
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
-
|
|
|
983
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
-
|
|
$
|
1,009
|
|
Operating
Activities
Our
Net
Cash Flows From Operating Activities were $46 million in the first three
months
of 2006. We produced Net income of $4 million during the period and incurred
noncash items of $33 million for Depreciation and Amortization and $(19)
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 current period activity in working capital relates to a number of items;
the
most significant are decreases in Accounts Payable and Interest Accrued offset
in part by a decrease of $121 million in Accounts Receivable. Accounts Payable
decreased $53 million primarily due to lower energy related transactions.
Interest Accrued decreased $16 million as a result of interest payments on
debentures and senior unsecured notes offset by monthly accruals. Cash receipts
related to the retail clawback and 2005 storm restoration for nonaffiliated
companies as well as fewer energy related receivables reduced outstanding
Accounts Receivable by $121 million.
Our
Net
Cash Flows Used For Operating Activities were $119 million in the first three
months of 2005. We
produced income of $1 million during the period including noncash expense
items
of $29 million for Depreciation and Amortization and $(30) million for Deferred
Property Taxes, offset in Accrued Taxes, as noted below. 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 are decreases in Accounts Payable,
Accrued
Taxes, Net and Accrued Interest offset in part by a decrease in Accounts
Receivable, Net. Accounts Payable decreased $25 million primarily due to
lower
vendor-related payables and lower third party energy transactions. Taxes
Accrued
decreased $118 million primarily due to a Federal income tax payment offset
by
the annual tax accruals related to 2005 property taxes. Interest Accrued
decreased $22 million primarily due to interest payments on debentures and
senior unsecured notes partially offset by monthly accruals.
Investing
Activities
Our
Net
Cash Flows Used For Investing Activities in 2006 were $58 million primarily
due
to $59 million of Construction Expenditures focused on improved service
reliability projects for transmission and distribution systems.
Our
Net
Cash Flows From Investing Activities in 2005 were $2 million primarily due
to a
decrease of $32 million in Other Cash Deposits, Net related to principal
payments on Securitization Bonds partially offset by Construction Expenditures
of $26 million related to projects for improved transmission and distribution
service reliability.
For
the
remainder of 2006, we expect our Construction Expenditures to be approximately
$220 million.
Financing
Activities
Our
Net
Cash Flows From Financing Activities in 2006 were $12 million primarily due
to
the issuance of a $125 million affiliated note 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 $31 million of Securitization
Bonds.
Our
Net
Cash Flows From Financing Activities in 2005 were $118 million primarily
due to
a $238 million increase in Advances from Affiliates, Net and issuances of
Pollution Control Bonds of $159 million offset by retirements of Senior
Unsecured Notes Payables and Securitization Bonds of $279 million.
Financing
Activity
Long-term
debt issuances and retirements during the first three months of 2006
were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Notes
Payable-Affiliated
|
|
$
|
125,000
|
|
5.14
|
|
2007
|
Retirements
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Securitization
Bonds
|
|
$
|
30,641
|
|
5.01
|
|
2010
|
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 any proceeds received from the securitization (discussed below under
Texas
Regulatory Activity) to pay down a portion of our equity and debt.
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 disclosed above.
Significant
Factors
Texas
Restructuring
The
PUCT
issued an order in our True-up Proceeding in February 2006, which determined
that our true-up regulatory asset was $1.475 billion, which included carrying
costs through September 2005. We filed an application in March 2006 requesting
to securitize $1.8 billion of net stranded generation plant costs and related
carrying costs to September 1, 2006. The $1.8 billion does not include our
other
true-up items, which are partially offsetting in nature. These obligations
total
$491 million and would be payable through a CTC over a period determined
by the
PUCT. Intervenors and the PUCT staff filed testimony in April 2006. Hearings
are
scheduled for May. It is possible that the PUCT could reduce the securitization
amount by all or some portion of the negative other true-up items. If that
occurs, a negative impact on the timing of cash flows could result. Cash
flows
from securitization would be adversely impacted if the PUCT reduces our
computation of the amount to be securitized in the securitization
proceeding.
The
PUCT
has not addressed the allocation of stranded costs to our wholesale
jurisdiction. We estimate the amount allocated to wholesale to be less than
$1
million, while intervenors and PUCT staff filed testimony recommending that
$77
million of stranded costs be allocated to our wholesale jurisdiction. We
cannot
predict the ultimate amount the PUCT will allocate to the wholesale jurisdiction
that we will not be able to securitize or recover.
Consistent
with certain prior securitization determinations, the PUCT may deduct the
cost-of-money benefit of accumulated deferred federal income taxes (ADFIT)
from
the securitization request. Then, the future cost-of-money benefit would
be
transferred to a separate regulatory asset recoverable in normal delivery
rates
outside of the securitization process, which would affect the timing of cash
recovery. We estimate the total cost-of-money benefit to be $328 million,
which
we plan to include in our estimated CTC request. Intervenors filed testimony
recommending an increase in this amount, along with the retrospective ADFIT
amounts, by as much as $175 million.
In
addition, the intervenors raised three issues totaling $138 million which
were
addressed by the PUCT in prior proceedings - the appropriate interest rate
for
both stranded cost and deferred fuel and the treatment of excess earnings
refunds. Other issues raised by the intervenors dealt with the amounts to
be
securitized versus refunded to customers through the CTC, customer class
allocation issues and debt defeasance strategies.
The
difference between the recorded securitizable true-up regulatory asset of
$1.5
billion at March 31, 2006 and our securitization request of $1.8 billion
is
detailed in the table below:
|
|
(in
millions)
|
|
Stranded
Generation Plant Costs
|
|
$
|
969
|
|
Net
Generation-related Regulatory Asset
|
|
|
249
|
|
Excess
Earnings
|
|
|
(49
|
)
|
Recorded
Net Stranded Generation Plant Costs
|
|
|
1,169
|
|
Recorded
Debt Carrying Costs on Recorded Net Stranded Generation Plant
Costs
|
|
|
284
|
|
Recorded
Securitizable True-up Regulatory Asset
|
|
|
1,453
|
|
Unrecorded
But Recoverable Equity Carrying Costs
|
|
|
212
|
|
Unrecorded
Estimated April 2006 - August 2006 Debt Carrying Costs
|
|
|
40
|
|
Unrecorded
Securitization Issuance Costs
|
|
|
24
|
|
Unrecorded
Excess Earnings, Related Return and Other
|
|
|
75
|
|
Securitization
Request
|
|
$
|
1,804
|
|
The
principal components of the CTC rate reduction are an over-recovered fuel
balance, the retail clawback and the ADFIT benefit related to our stranded
generation cost, offset by a positive wholesale capacity auction true-up
regulatory asset balance. We will incur carrying costs on the net negative
other
true-up regulatory liability balances until fully refunded. We anticipate
filing
to implement a negative CTC (as a rate reduction) for our net other true-up
items in the second quarter of 2006.
The
difference between the components of our recorded net regulatory liabilities
-
other true-up items as of March 31, 2006 and the amount expected to be requested
in the CTC proceeding are detailed below:
|
|
(in
millions)
|
|
Wholesale
Capacity Auction True-up
|
|
$
|
61
|
|
Carrying
Costs on Wholesale Capacity Auction True-up
|
|
|
17
|
|
Retail
Clawback
|
|
|
(61
|
)
|
Deferred
Over-recovered Fuel Balance
|
|
|
(177
|
)
|
Recorded
Net Regulatory Liabilities - Other True-up Items
|
|
|
(160
|
)
|
ADFIT
Benefit
|
|
|
(328
|
)
|
Unrecorded
Carrying Costs and Other
|
|
|
(3
|
)
|
Estimated
CTC Request
|
|
$
|
(491
|
)
|
If
we
determine in future securitization and CTC proceedings 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 such nonrecovery, we would record a provision
for
such amount which could have an adverse effect on future results of operations,
cash flows and possibly financial condition. We intend to pursue rehearing
and
appeals to vigorously seek relief as necessary in both federal and state
court
where we believe the PUCT’s rulings are contrary to the Texas Restructuring
Legislation, PUCT rulemakings and federal law. We expect that the cities
and
other intervenors will also pursue vigorously court appeals to further reduce
our true-up recoveries. Although we believe we have meritorious arguments,
management cannot predict the ultimate outcome of any future proceedings,
requested rehearings or court appeals. If the cities and other intervenors
succeed in their expected appeals, it could have a material adverse effect
on
future results of operations, cash flows and financial condition.
Removal
from CSW Operating Agreement and SIA
Under
the
Texas Restructuring Legislation, we are completing the final stage of exiting
the generation business and have already 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. Therefore, our sharing of
margins
under the CSW Operating Agreement and the SIA ceased effective May 1, 2006,
which affects our future results of operations and cash flows.
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. An adverse result in these proceedings has 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 March 31, 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 March 31, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
Total
|
|
Current
Assets
|
|
$
|
536
|
|
$
|
84
|
|
$
|
620
|
|
Noncurrent
Assets
|
|
|
536
|
|
|
5
|
|
|
541
|
|
Total
MTM Derivative Contract Assets
|
|
|
1,072
|
|
|
89
|
|
|
1,161
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(455
|
)
|
|
(31
|
)
|
|
(486
|
)
|
Noncurrent
Liabilities
|
|
|
(316
|
)
|
|
(3
|
)
|
|
(319
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(771
|
)
|
|
(34
|
)
|
|
(805
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
|
|
$
|
301
|
|
$
|
55
|
|
$
|
356
|
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 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
|
|
|
(944
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
2
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
(7
|
)
|
Changes
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
5
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(4,181
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
-
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
301
|
|
Net
Cash Flow Hedge Contracts
|
|
|
55
|
|
Total
MTM Risk Management Contract Net Assets at March 31,
2006
|
|
$
|
356
|
|
(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)
|
“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
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 March 31, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
68
|
|
$
|
14
|
|
$
|
6
|
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
87
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes
(a)
|
|
|
28
|
|
|
17
|
|
|
44
|
|
|
41
|
|
|
-
|
|
|
-
|
|
|
130
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(26
|
)
|
|
28
|
|
|
17
|
|
|
11
|
|
|
34
|
|
|
20
|
|
|
84
|
|
Total
|
|
$
|
70
|
|
$
|
59
|
|
$
|
67
|
|
$
|
51
|
|
$
|
34
|
|
$
|
20
|
|
$
|
301
|
|
(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 March 31, 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
Three
Months Ended March 31, 2006
(in
thousands)
|
|
Power
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(224
|
)
|
Changes
in Fair Value
|
|
|
255
|
|
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
|
|
7
|
|
Ending
Balance in AOCI March 31, 2006
|
|
$
|
38
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $36 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 March 31, 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:
Three
Months Ended
March
31, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$5
|
|
$11
|
|
$6
|
|
$3
|
|
|
|
|
$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 $79 million and $93 million at March 31,
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 SUBSIDIARY
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
123,211
|
|
$
|
182,147
|
|
Sales
to AEP Affiliates
|
|
|
1,598
|
|
|
4,964
|
|
Other
- Nonaffiliated
|
|
|
10,479
|
|
|
14,246
|
|
TOTAL
|
|
|
135,288
|
|
|
201,357
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
1,726
|
|
|
6,098
|
|
Purchased
Electricity for Resale
|
|
|
1,680
|
|
|
15,370
|
|
Other
Operation
|
|
|
58,927
|
|
|
80,749
|
|
Maintenance
|
|
|
7,789
|
|
|
17,039
|
|
Depreciation
and Amortization
|
|
|
33,335
|
|
|
29,286
|
|
Taxes
Other Than Income Taxes
|
|
|
20,363
|
|
|
22,531
|
|
TOTAL
|
|
|
123,820
|
|
|
171,073
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
11,468
|
|
|
30,284
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
505
|
|
|
1,498
|
|
Carrying
Costs Income (Expense)
|
|
|
19,423
|
|
|
(5,141
|
)
|
Allowance
for Equity Funds Used During Construction
|
|
|
373
|
|
|
551
|
|
Interest
Expense
|
|
|
(26,773
|
)
|
|
(27,079
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
4,996
|
|
|
113
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense (Credit)
|
|
|
1,223
|
|
|
(1,024
|
)
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
3,773
|
|
|
1,137
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
60
|
|
|
60
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
3,713
|
|
$
|
1,077
|
|
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 SUBSIDIARY
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Three Months Ended March 31, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(60
|
)
|
|
|
|
|
(60
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,268,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,335
|
|
|
|
|
|
|
|
|
|
|
|
(4,336
|
)
|
|
(4,336
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
1,137
|
|
|
|
|
|
1,137
|
|
TOTAL
COMPREHENSIVE LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,199
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2005
|
|
$
|
55,292
|
|
$
|
132,606
|
|
$
|
1,085,981
|
|
$
|
(8,495
|
)
|
$
|
1,265,384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
55,292
|
|
$
|
132,606
|
|
$
|
760,884
|
|
$
|
(1,152
|
)
|
$
|
947,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(60
|
)
|
|
|
|
|
(60
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
947,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $141
|
|
|
|
|
|
|
|
|
|
|
|
262
|
|
|
262
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
3,773
|
|
|
|
|
|
3,773
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2006
|
|
$
|
55,292
|
|
$
|
132,606
|
|
$
|
764,597
|
|
$
|
(890
|
)
|
$
|
951,605
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
-
|
|
$
|
-
|
|
Other
Cash Deposits
|
|
|
36,417
|
|
|
66,153
|
|
Advances
to Affiliates
|
|
|
32,101
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
93,123
|
|
|
209,957
|
|
Affiliated
Companies
|
|
|
22,304
|
|
|
23,486
|
|
Accrued
Unbilled Revenues
|
|
|
22,488
|
|
|
25,606
|
|
Allowance
for Uncollectible Accounts
|
|
|
(376
|
)
|
|
(143
|
)
|
Total
Accounts Receivable
|
|
|
137,539
|
|
|
258,906
|
|
Unbilled
Construction Costs
|
|
|
19,784
|
|
|
19,440
|
|
Materials
and Supplies
|
|
|
16,237
|
|
|
13,897
|
|
Risk
Management Assets
|
|
|
620
|
|
|
14,311
|
|
Prepayments
and Other
|
|
|
2,259
|
|
|
5,231
|
|
TOTAL
|
|
|
244,957
|
|
|
377,938
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Transmission
|
|
|
827,837
|
|
|
817,351
|
|
Distribution
|
|
|
1,506,415
|
|
|
1,476,683
|
|
Other
|
|
|
227,411
|
|
|
233,361
|
|
Construction
Work in Progress
|
|
|
133,785
|
|
|
129,800
|
|
Total
|
|
|
2,695,448
|
|
|
2,657,195
|
|
Accumulated
Depreciation and Amortization
|
|
|
629,538
|
|
|
636,078
|
|
TOTAL
- NET
|
|
|
2,065,910
|
|
|
2,021,117
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
1,698,100
|
|
|
1,688,787
|
|
Securitized
Transition Assets
|
|
|
582,513
|
|
|
593,401
|
|
Long-term
Risk Management Assets
|
|
|
541
|
|
|
11,609
|
|
Employee
Benefits and Pension Assets
|
|
|
114,004
|
|
|
114,733
|
|
Deferred
Charges and Other
|
|
|
78,200
|
|
|
53,011
|
|
TOTAL
|
|
|
2,473,358
|
|
|
2,461,541
|
|
|
|
|
|
|
|
|
|
Assets
Held for Sale - Texas Generation Plants
|
|
|
44,435
|
|
|
44,316
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
4,828,660
|
|
$
|
4,904,912
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
-
|
|
$
|
82,080
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
67,644
|
|
|
82,666
|
|
Affiliated
Companies
|
|
|
26,405
|
|
|
65,574
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
154,383
|
|
|
152,900
|
|
Risk
Management Liabilities
|
|
|
486
|
|
|
13,024
|
|
Accrued
Taxes
|
|
|
61,420
|
|
|
54,566
|
|
Accrued
Interest
|
|
|
16,345
|
|
|
32,497
|
|
Other
|
|
|
31,952
|
|
|
45,927
|
|
TOTAL
|
|
|
358,635
|
|
|
529,234
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
1,518,525
|
|
|
1,550,596
|
|
Long-term
Debt - Affiliated
|
|
|
275,000
|
|
|
150,000
|
|
Long-term
Risk Management Liabilities
|
|
|
319
|
|
|
7,857
|
|
Deferred
Income Taxes
|
|
|
1,046,944
|
|
|
1,048,372
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
658,887
|
|
|
652,143
|
|
Deferred
Credits and Other
|
|
|
12,805
|
|
|
13,140
|
|
TOTAL
|
|
|
3,512,480
|
|
|
3,422,108
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
3,871,115
|
|
|
3,951,342
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
5,940
|
|
|
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
|
|
|
764,597
|
|
|
760,884
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(890
|
)
|
|
(1,152
|
)
|
TOTAL
|
|
|
951,605
|
|
|
947,630
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
4,828,660
|
|
$
|
4,904,912
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
3,773
|
|
$
|
1,137
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
33,335
|
|
|
29,286
|
|
Accretion
of Asset Retirement Obligations
|
|
|
18
|
|
|
4,529
|
|
Deferred
Income Taxes
|
|
|
2,928
|
|
|
(5,045
|
)
|
Carrying
Costs on Stranded Cost Recovery
|
|
|
(19,423
|
)
|
|
5,141
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
5,125
|
|
|
6,879
|
|
Over/Under
Fuel Recovery
|
|
|
-
|
|
|
2,900
|
|
Deferred
Property Taxes
|
|
|
(25,755
|
)
|
|
(29,820
|
)
|
Change
in Other Noncurrent Assets
|
|
|
(683
|
)
|
|
(7,892
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
1,380
|
|
|
4,898
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
121,367
|
|
|
39,038
|
|
Fuel,
Materials and Supplies
|
|
|
(2,569
|
)
|
|
98
|
|
Accounts
Payable
|
|
|
(53,124
|
)
|
|
(25,008
|
)
|
Accrued
Taxes, Net
|
|
|
6,854
|
|
|
(117,785
|
)
|
Customer
Deposits
|
|
|
(6,514
|
)
|
|
(1,173
|
)
|
Accrued
Interest
|
|
|
(16,152
|
)
|
|
(21,638
|
)
|
Other
Current Assets
|
|
|
2,629
|
|
|
(1,879
|
)
|
Other
Current Liabilities
|
|
|
(7,461
|
)
|
|
(2,584
|
)
|
Net
Cash Flows From (Used for) Operating Activities
|
|
|
45,728
|
|
|
(118,918
|
)
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(58,645
|
)
|
|
(26,402
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
29,736
|
|
|
31,541
|
|
Change
in Advances to Affiliates, Net
|
|
|
(32,101
|
)
|
|
-
|
|
Purchases
of Investment Securities
|
|
|
-
|
|
|
(26,872
|
)
|
Sales
of Investment Securities
|
|
|
-
|
|
|
23,349
|
|
Proceeds
from Sale of Assets
|
|
|
3,215
|
|
|
-
|
|
Other
|
|
|
-
|
|
|
100
|
|
Net
Cash Flows From (Used For) Investing Activities
|
|
|
(57,795
|
)
|
|
1,716
|
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt - Affiliated
|
|
|
125,000
|
|
|
-
|
|
Issuance
of Long-term Debt - Nonaffiliated
|
|
|
-
|
|
|
159,252
|
|
Change
in Advances from Affiliates, Net
|
|
|
(82,080
|
)
|
|
238,486
|
|
Retirement
of Long-term Debt
|
|
|
(30,641
|
)
|
|
(279,386
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(152
|
)
|
|
(107
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(60
|
)
|
|
(60
|
)
|
Net
Cash From Financing Activities
|
|
|
12,067
|
|
|
118,185
|
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
-
|
|
|
983
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
-
|
|
|
26
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
-
|
|
$
|
1,009
|
|
SUPPLEMENTAL
DISCLOSURE: |
Cash
paid for interest net of capitalized amounts was $40,646,000 and
$44,721,000 and for income taxes
net of refunds
was $485,000 and $132,960,000 in 2006 and 2005, respectively. Noncash
capital lease acquisitions were $680,000 and $157,000 in 2006 and
2005,
respectively. Noncash construction expenditures included in Accounts
Payable of $9,970,000 and $2,970,000 were outstanding as of March
31, 2006
and 2005, respectively.
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARY
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
|
Assets
Held for Sale
|
Note
8
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
10
|
Financing
Activities
|
Note
11
|
AEP
TEXAS NORTH COMPANY
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006 Net
Income
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
7
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Texas
Supply
|
|
|
(3
|
)
|
|
|
|
Off-system
Sales
|
|
|
1
|
|
|
|
|
Other
|
|
|
(39
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(41
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
34
|
|
|
|
|
Interest
Expense
|
|
|
1
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
4
|
|
Net
Income decreased $3 million in the first quarter of 2006 primarily due to
a
decrease in Gross Margin of $41 million partially offset by a reduction in
Other
Operation and Maintenance expenses of $34 million.
The
major
components of our change in Gross Margin, defined as revenues less the related
direct cost of fuel, consumption of emissions allowances and purchased power
were as follows:
·
|
Texas
Supply margins decreased $3 million primarily due to a $7 million
decrease
in dedicated ERCOT energy sales, offset by an increase of $1 million
in
provision for refund primarily due to the fuel reconciliation adjustment
in 2005 and $3 million of lower fuel and purchased power
cost.
|
·
|
Other
revenues decreased $39 million primarily due to a $36 million decrease
in
revenue resulting from the completion of certain third party construction
projects, primarily with the Lower Colorado River Authority.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses decreased $34 million primarily
due to
lower expenses related to the completion of certain third party
construction projects, primarily with the Lower Colorado River
Authority, of $36 million offset by slightly increased maintenance
expenses.
|
Income
Taxes
The
decrease in Income Tax Expense of $3 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
recently moved us to 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 three 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
Removal
from CSW Operating Agreement and SIA
Under
the
Texas Restructuring Legislation, we are completing the final stage of exiting
the generation business and have already 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. Therefore, our sharing of
margins
under the CSW Operating Agreement and the SIA ceased effective May 1, 2006,
which affects our future results of operations and cash flows.
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. An adverse result in these proceedings has 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 March 31, 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 March 31, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
Total
|
|
Current
Assets
|
|
$
|
1,109
|
|
$
|
173
|
|
$
|
1,282
|
|
Noncurrent
Assets
|
|
|
1,108
|
|
|
11
|
|
|
1,119
|
|
Total
MTM Derivative Contract Assets
|
|
|
2,217
|
|
|
184
|
|
|
2,401
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(855
|
)
|
|
(64
|
)
|
|
(919
|
)
|
Noncurrent
Liabilities
|
|
|
(653
|
)
|
|
(6
|
)
|
|
(659
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(1,508
|
)
|
|
(70
|
)
|
|
(1,578
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
|
|
$
|
709
|
|
$
|
114
|
|
$
|
823
|
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 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
|
|
|
(395
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
4
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
(13
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
11
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(1,596
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
-
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
709
|
|
Net
Cash Flow Hedge Contracts
|
|
|
114
|
|
Total
MTM Risk Management Contract Net Assets at March 31,
2006
|
|
$
|
823
|
|
(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)
|
“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.
|
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 March 31, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
141
|
|
$
|
29
|
|
$
|
13
|
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
182
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
58
|
|
|
35
|
|
|
91
|
|
|
85
|
|
|
-
|
|
|
-
|
|
|
269
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
30
|
|
|
57
|
|
|
36
|
|
|
22
|
|
|
71
|
|
|
42
|
|
|
258
|
|
Total
|
|
$
|
229
|
|
$
|
121
|
|
$
|
140
|
|
$
|
106
|
|
$
|
71
|
|
$
|
42
|
|
$
|
709
|
|
(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.
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 March 31, 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
Three
Months Ended March 31, 2006
(in
thousands)
|
|
Power
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(111
|
)
|
Changes
in Fair Value
|
|
|
176
|
|
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
|
|
13
|
|
Ending
Balance in AOCI March 31, 2006
|
|
$
|
78
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $74 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 March 31, 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:
Three
Months Ended
March
31, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$10
|
|
$23
|
|
$13
|
|
$6
|
|
|
|
|
$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 $13 million at both March 31, 2006 and
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 negatively affect our results of operations or financial
position.
AEP
TEXAS NORTH COMPANY
CONDENSED
STATEMENTS OF INCOME
For
the Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
68,825
|
|
$
|
71,889
|
|
Sales
to AEP Affiliates
|
|
|
6,025
|
|
|
11,290
|
|
Other
|
|
|
(184
|
)
|
|
35,728
|
|
TOTAL
|
|
|
74,666
|
|
|
118,907
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
12,115
|
|
|
12,983
|
|
Purchased
Electricity for Resale
|
|
|
14,396
|
|
|
16,360
|
|
Other
Operation
|
|
|
18,556
|
|
|
53,670
|
|
Maintenance
|
|
|
5,201
|
|
|
4,219
|
|
Depreciation
and Amortization
|
|
|
10,223
|
|
|
10,155
|
|
Taxes
Other Than Income Taxes
|
|
|
5,540
|
|
|
5,705
|
|
TOTAL
|
|
|
66,031
|
|
|
103,092
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
8,635
|
|
|
15,815
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
219
|
|
|
256
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
382
|
|
|
73
|
|
Interest
Expense
|
|
|
(4,362
|
)
|
|
(4,984
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
4,874
|
|
|
11,160
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
1,040
|
|
|
3,766
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
3,834
|
|
|
7,394
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
26
|
|
|
26
|
|
Gain
on Reacquired Preferred Stock
|
|
|
2
|
|
|
-
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
3,810
|
|
$
|
7,368
|
|
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
CONDENSED
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Three Months Ended March 31, 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
|
|
|
|
|
|
|
|
|
(9,427
|
)
|
|
|
|
|
(9,427
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(26
|
)
|
|
|
|
|
(26
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
300,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $416
|
|
|
|
|
|
|
|
|
|
|
|
(774
|
)
|
|
(774
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
7,394
|
|
|
|
|
|
7,394
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,620
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2005
|
|
$
|
137,214
|
|
$
|
2,351
|
|
$
|
168,925
|
|
$
|
(902
|
)
|
$
|
307,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
137,214
|
|
$
|
2,351
|
|
$
|
174,858
|
|
$
|
(504
|
)
|
$
|
313,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(8,000
|
)
|
|
|
|
|
(8,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(26
|
)
|
|
|
|
|
(26
|
)
|
Gain
on Reacquired Preferred Stock
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
2
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
305,895
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $102
|
|
|
|
|
|
|
|
|
|
|
|
189
|
|
|
189
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
3,834
|
|
|
|
|
|
3,834
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2006
|
|
$
|
137,214
|
|
$
|
2,351
|
|
$
|
170,668
|
|
$
|
(315
|
)
|
$
|
309,918
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY
CONDENSED
BALANCE SHEETS
ASSETS
March
31, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
-
|
|
$
|
-
|
|
Advances
to Affiliates
|
|
|
3,046
|
|
|
34,286
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
55,249
|
|
|
77,678
|
|
Affiliated
Companies
|
|
|
12,340
|
|
|
26,149
|
|
Accrued
Unbilled Revenues
|
|
|
4,423
|
|
|
5,016
|
|
Allowance
for Uncollectible Accounts
|
|
|
(23
|
)
|
|
(18
|
)
|
Total
Accounts Receivable
|
|
|
71,989
|
|
|
108,825
|
|
Fuel
|
|
|
4,342
|
|
|
2,636
|
|
Materials
and Supplies
|
|
|
7,308
|
|
|
6,858
|
|
Risk
Management Assets
|
|
|
1,282
|
|
|
7,114
|
|
Prepayments
and Other
|
|
|
2,736
|
|
|
5,204
|
|
TOTAL
|
|
|
90,703
|
|
|
164,923
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
289,505
|
|
|
288,934
|
|
Transmission
|
|
|
294,733
|
|
|
289,029
|
|
Distribution
|
|
|
497,005
|
|
|
492,878
|
|
Other
|
|
|
161,710
|
|
|
167,849
|
|
Construction
Work in Progress
|
|
|
51,030
|
|
|
46,424
|
|
Total
|
|
|
1,293,983
|
|
|
1,285,114
|
|
Accumulated
Depreciation and Amortization
|
|
|
477,100
|
|
|
478,519
|
|
TOTAL
- NET
|
|
|
816,883
|
|
|
806,595
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
9,432
|
|
|
9,787
|
|
Long-term
Risk Management Assets
|
|
|
1,119
|
|
|
5,772
|
|
Employee
Benefits and Pension Assets
|
|
|
45,996
|
|
|
46,289
|
|
Deferred
Charges and Other
|
|
|
23,067
|
|
|
10,468
|
|
TOTAL
|
|
|
79,614
|
|
|
72,316
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
987,200
|
|
$
|
1,043,834
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY
CONDENSED
BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’
EQUITY
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
$
|
28,806
|
|
$
|
19,739
|
|
Affiliated
Companies
|
|
|
38,137
|
|
|
84,923
|
|
Risk
Management Liabilities
|
|
|
919
|
|
|
6,475
|
|
Accrued
Taxes
|
|
|
25,271
|
|
|
21,212
|
|
Other
|
|
|
10,304
|
|
|
21,050
|
|
TOTAL
|
|
|
103,437
|
|
|
153,399
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
276,868
|
|
|
276,845
|
|
Long-term
Risk Management Liabilities
|
|
|
659
|
|
|
3,906
|
|
Deferred
Income Taxes
|
|
|
131,683
|
|
|
132,335
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
141,102
|
|
|
139,732
|
|
Deferred
Credits and Other
|
|
|
21,184
|
|
|
21,341
|
|
TOTAL
|
|
|
571,496
|
|
|
574,159
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
674,933
|
|
|
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
|
|
|
170,668
|
|
|
174,858
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(315
|
)
|
|
(504
|
)
|
TOTAL
|
|
|
309,918
|
|
|
313,919
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
987,200
|
|
$
|
1,043,834
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY
CONDENSED
STATEMENTS OF CASH FLOWS
For
the Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
3,834
|
|
$
|
7,394
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
10,223
|
|
|
10,155
|
|
Deferred
Income Taxes
|
|
|
(1,323
|
)
|
|
(1,221
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
1,989
|
|
|
2,973
|
|
Over/Under
Fuel Recovery
|
|
|
-
|
|
|
1,400
|
|
Deferred
Property Taxes
|
|
|
(12,360
|
)
|
|
(12,218
|
)
|
Change
in Other Noncurrent Assets
|
|
|
(2,003
|
)
|
|
(1,705
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
652
|
|
|
1,613
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
36,836
|
|
|
24,967
|
|
Fuel,
Materials and Supplies
|
|
|
(2,156
|
)
|
|
(2,704
|
)
|
Accounts
Payable
|
|
|
(36,932
|
)
|
|
1,108
|
|
Accrued
Taxes, Net
|
|
|
4,059
|
|
|
(10,912
|
)
|
Other
Current Assets
|
|
|
1,676
|
|
|
4,361
|
|
Other
Current Liabilities
|
|
|
(9,775
|
)
|
|
(4,368
|
)
|
Net
Cash Flows From (Used For) Operating Activities
|
|
|
(5,280
|
)
|
|
20,843
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(18,662
|
)
|
|
(10,045
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
792
|
|
|
-
|
|
Change
In Advances to Affiliates, Net
|
|
|
31,240
|
|
|
(1,232
|
)
|
Proceeds
from Sale of Assets
|
|
|
-
|
|
|
250
|
|
Net
Cash Flows From (Used For) Investing Activities
|
|
|
13,370
|
|
|
(11,027
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(64
|
)
|
|
(59
|
)
|
Dividends
Paid on Common Stock
|
|
|
(8,000
|
)
|
|
(9,427
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(26
|
)
|
|
(26
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(8,090
|
)
|
|
(9,512
|
)
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
-
|
|
|
304
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
-
|
|
|
-
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
-
|
|
$
|
304
|
|
SUPPLEMENTAL
DISCLOSURE:
|
Cash
paid for interest net of capitalized amounts was $6,113,000 and
$6,236,000
and for income taxes
net of refunds was
$0 and $17,447,000 in 2006 and 2005, respectively. Noncash capital
lease
acquisitions were $224,000 and $137,000 in 2006 and 2005, respectively.
Noncash Construction Expenditures included in Accounts Payable
of
$2,372,000 and $1,081,000 were outstanding as of March 31, 2006
and 2005,
respectively.
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
AEP
TEXAS NORTH COMPANY
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
|
Business
Segments
|
Note
10
|
Financing
Activities
|
Note
11
|
APPALACHIAN
POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006 Net
Income
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
47
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
28
|
|
|
|
|
Transmission
Revenues
|
|
|
1
|
|
|
|
|
Other
|
|
|
2
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
13
|
|
|
|
|
Depreciation
and Amortization
|
|
|
2
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
1
|
|
|
|
|
Carrying
Costs Income
|
|
|
6
|
|
|
|
|
Interest
Expense
|
|
|
(6
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
74
|
|
Net
Income increased by $27 million to $74 million in 2006. The key drivers of
the
increase were a $31 million net increase in Gross Margin and a $16 million
net
decrease in Operating Expenses and Other offset by a $20 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 by $28 million in comparison to 2005 primarily
due to a
$16 million increase in revenues related to financial transmission
rights,
net of congestion, and a $10 million increase in retail revenues
related
to two new industrial customers. The increase in financial transmission
rights revenue is due to improved management of price risk related
to
serving retail load.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses decreased by $13 million primarily
due
to a decrease of $14 million related to planned outages and a decrease
of
$5 million in removal costs in comparison to 2005. These decreases
were
partially offset by a $6 million increase related to the settlement
and
cancellation of the COLI (corporate owned life insurance) policy
in
February 2005.
|
·
|
Carrying
Costs Income increased $6 million primarily due to the establishment
of a
regulatory asset for carrying costs related to the Virginia environmental
and reliability costs incurred.
|
·
|
Interest
Expense increased $6 million primarily due to recent long-term
debt
issuances and higher interest rates on replacement
debt.
|
Income
Taxes
The
increase in Income Tax Expense of $20 million is primarily due to an increase
in
pretax book income.
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 three months ended March 31, 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
|
|
|
212,542
|
|
|
80,946
|
|
Investing
Activities
|
|
|
(196,459
|
)
|
|
(165,691
|
)
|
Financing
Activities
|
|
|
(16,372
|
)
|
|
85,337
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(289
|
)
|
|
592
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,452
|
|
$
|
2,135
|
|
Operating
Activities
Our
Net
Cash Flows From Operating Activities were $213 million in 2006. We produced
income of $74 million during the period and a noncash expense item of $48
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 had two significant items,
an
increase in Accounts Receivable, Net and Accrued Taxes, Net. During the first
quarter of 2006, we did not make any federal income tax payments and collected
receivables from our affiliates related to power sales, settled litigation
and
emission allowances.
Our
Net
Cash Flows From Operating Activities were $81 million in 2005. We produced
income of $47 million during the period and a noncash expense item of $50
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 had no significant
items.
Investing
Activities
Our
Net
Cash Flows Used For Investing Activities during 2006 and 2005 primarily reflect
our construction expenditures of $197 million and $130 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 are primarily related to the Wyoming-Jacksons Ferry 765 kV line.
Environmental upgrades include the installation of selective catalytic reduction
(SCR) equipment on various plants and the flue gas desulfurization (FGD)
project
at the Amos and Mountaineer Plants. For the remainder of 2006, we expect
construction expenditures to be approximately $750 million.
Financing
Activities
Our
Net
Cash Flows Used For Financing Activities were $16 million in 2006. We retired
a
First Mortgage Bond of $100 million and incurred obligations of $50 million
relating to pollution control bonds. We repaid short-term borrowings from
the
Utility Money Pool of $30 million. In addition, we received funds of $68
million
related to a long-term coal purchase contract amended in March 2006. See
“Coal
Contract Amendment” within “Significant Factors” for additional
information.
Our
Net
Cash Flows From Financing Activities were $85 million in 2005.
We
issued Senior Unsecured Notes of $200 million and received a capital
contribution from our parent of $100 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 three months of 2006
were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Pollution
Control Bonds
|
|
$
|
50,275
|
|
Variable
|
|
2036
|
Retirements
|
|
Principal
Amount
Paid
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
First
Mortgage Bonds
|
|
$
|
100,000
|
|
6.80
|
|
2006
|
Other
Debt
|
|
|
3
|
|
13.718
|
|
2026
|
In
April
2006, we issued $250 million, 5.55% senior notes due in 2011 and $250 million,
6.375% senior notes due in 2036. The proceeds were used for general corporate
purposes including funding our construction program, repaying advances from
the
Utility Money Pool and replenishing working capital.
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. An adverse result in
these proceedings has 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 March 31, 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 March 31, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow &
Fair
Value Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
101,475
|
|
$
|
20,235
|
|
$
|
-
|
|
$
|
121,710
|
|
Noncurrent
Assets
|
|
|
158,144
|
|
|
755
|
|
|
-
|
|
|
158,899
|
|
Total
MTM Derivative Contract Assets
|
|
|
259,619
|
|
|
20,990
|
|
|
-
|
|
|
280,609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(83,014
|
)
|
|
(5,006
|
)
|
|
(1,240
|
)
|
|
(89,260
|
)
|
Noncurrent
Liabilities
|
|
|
(114,717
|
)
|
|
(1,581
|
)
|
|
(10,863
|
)
|
|
(127,161
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(197,731
|
)
|
|
(6,587
|
)
|
|
(12,103
|
)
|
|
(216,421
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
61,888
|
|
$
|
14,403
|
|
$
|
(12,103
|
)
|
$
|
64,188
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 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
|
|
|
(3,099
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
170
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
(1,182
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
448
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
2,406
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
6,738
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
61,888
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
14,403
|
|
DETM
Assignment (d)
|
|
|
(12,103
|
)
|
Total
MTM Risk Management Contract Net Assets at March 31,
2006
|
|
$
|
64,188
|
|
(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 Income. These net gains (losses) are
recorded
as regulatory liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
(d)
|
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 March 31, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
9,768
|
|
$
|
2,033
|
|
$
|
903
|
|
$
|
(72
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
12,632
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
7,005
|
|
|
5,987
|
|
|
8,140
|
|
|
6,725
|
|
|
-
|
|
|
-
|
|
|
27,857
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(1,427
|
)
|
|
5,761
|
|
|
3,863
|
|
|
3,976
|
|
|
8,515
|
|
|
711
|
|
|
21,399
|
|
Total
|
|
$
|
15,346
|
|
$
|
13,781
|
|
$
|
12,906
|
|
$
|
10,629
|
|
$
|
8,515
|
|
$
|
711
|
|
$
|
61,888
|
|
(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 March 31, 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
Three
Months Ended March 31, 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
|
|
|
5,964
|
|
|
-
|
|
|
5,340
|
|
|
11,304
|
|
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
|
|
899
|
|
|
2
|
|
|
1,063
|
|
|
1,964
|
|
Ending
Balance in AOCI March 31, 2006
|
|
$
|
5,383
|
|
$
|
(169
|
)
|
$
|
(8,367
|
)
|
$
|
(3,153
|
)
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $3,502 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 March 31, 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:
Three
Months Ended
March
31, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$682
|
|
$1,604
|
|
$867
|
|
$427
|
|
|
|
|
$732
|
|
$1,216
|
|
$579
|
|
$209
|
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 $123 million
and $142 million at March 31, 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 Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
559,993
|
|
$
|
476,027
|
|
Sales
to AEP Affiliates
|
|
|
71,772
|
|
|
79,170
|
|
Other
|
|
|
2,676
|
|
|
2,498
|
|
TOTAL
|
|
|
634,441
|
|
|
557,695
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
166,853
|
|
|
115,144
|
|
Purchased
Electricity for Resale
|
|
|
27,616
|
|
|
28,233
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
122,399
|
|
|
126,963
|
|
Other
Operation
|
|
|
70,197
|
|
|
73,773
|
|
Maintenance
|
|
|
37,839
|
|
|
47,190
|
|
Depreciation
and Amortization
|
|
|
47,972
|
|
|
49,959
|
|
Taxes
Other Than Income Taxes
|
|
|
23,092
|
|
|
24,074
|
|
TOTAL
|
|
|
495,968
|
|
|
465,336
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
138,473
|
|
|
92,359
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
951
|
|
|
562
|
|
Carrying
Costs Income
|
|
|
6,011
|
|
|
98
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
2,476
|
|
|
2,211
|
|
Interest
Expense
|
|
|
(30,268
|
)
|
|
(24,199
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
117,643
|
|
|
71,031
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
44,049
|
|
|
24,359
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
73,594
|
|
|
46,672
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements including Capital Stock Expense
|
|
|
238
|
|
|
797
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
73,356
|
|
$
|
45,875
|
|
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 Three Months Ended March 31, 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
|
|
|
|
|
|
100,000
|
|
|
|
|
|
|
|
|
100,000
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(200
|
)
|
|
|
|
|
(200
|
)
|
Capital
Stock Expense
|
|
|
|
|
|
597
|
|
|
(597
|
)
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,509,518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $4,151
|
|
|
|
|
|
|
|
|
|
|
|
(7,710
|
)
|
|
(7,710
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
46,672
|
|
|
|
|
|
46,672
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,962
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2005
|
|
$
|
260,458
|
|
$
|
822,911
|
|
$
|
554,493
|
|
$
|
(89,382
|
)
|
$
|
1,548,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
260,458
|
|
$
|
924,837
|
|
$
|
635,016
|
|
$
|
(16,610
|
)
|
$
|
1,803,701
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(2,500
|
)
|
|
|
|
|
(2,500
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(200
|
)
|
|
|
|
|
(200
|
)
|
Capital
Stock Expense
|
|
|
|
|
|
38
|
|
|
(38
|
)
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,801,001
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of
$7,144
|
|
|
|
|
|
|
|
|
|
|
|
13,268
|
|
|
13,268
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
73,594
|
|
|
|
|
|
73,594
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2006
|
|
$
|
260,458
|
|
$
|
924,875
|
|
$
|
705,872
|
|
$
|
(3,342
|
)
|
$
|
1,887,863
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
1,452
|
|
$
|
1,741
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
171,749
|
|
|
141,810
|
|
Affiliated
Companies
|
|
|
63,086
|
|
|
153,453
|
|
Accrued
Unbilled Revenues
|
|
|
34,704
|
|
|
51,201
|
|
Miscellaneous
|
|
|
3,908
|
|
|
527
|
|
Allowance
for Uncollectible Accounts
|
|
|
(3,539
|
)
|
|
(1,805
|
)
|
Total
Accounts Receivable
|
|
|
269,908
|
|
|
345,186
|
|
Fuel
|
|
|
52,128
|
|
|
64,657
|
|
Materials
and Supplies
|
|
|
54,468
|
|
|
54,967
|
|
Risk
Management Assets
|
|
|
121,710
|
|
|
132,247
|
|
Accrued
Tax Benefits
|
|
|
-
|
|
|
32,979
|
|
Margin
Deposits
|
|
|
36,888
|
|
|
28,936
|
|
Prepayments
and Other
|
|
|
32,714
|
|
|
46,193
|
|
TOTAL
|
|
|
569,268
|
|
|
706,906
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
2,818,411
|
|
|
2,798,157
|
|
Transmission
|
|
|
1,275,354
|
|
|
1,266,855
|
|
Distribution
|
|
|
2,190,230
|
|
|
2,141,153
|
|
Other
|
|
|
326,997
|
|
|
323,158
|
|
Construction
Work in Progress
|
|
|
735,480
|
|
|
647,638
|
|
Total
|
|
|
7,346,472
|
|
|
7,176,961
|
|
Accumulated
Depreciation and Amortization
|
|
|
2,541,697
|
|
|
2,524,855
|
|
TOTAL
- NET
|
|
|
4,804,775
|
|
|
4,652,106
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
454,658
|
|
|
457,294
|
|
Long-term
Risk Management Assets
|
|
|
158,899
|
|
|
176,231
|
|
Deferred
Charges and Other
|
|
|
262,869
|
|
|
261,556
|
|
TOTAL
|
|
|
876,426
|
|
|
895,081
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
6,250,469
|
|
$
|
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
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
164,192
|
|
$
|
194,133
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
222,271
|
|
|
230,570
|
|
Affiliated
Companies
|
|
|
65,134
|
|
|
85,941
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
46,927
|
|
|
146,999
|
|
Risk
Management Liabilities
|
|
|
89,260
|
|
|
121,165
|
|
Customer
Deposits
|
|
|
66,324
|
|
|
79,854
|
|
Accrued
Taxes
|
|
|
73,034
|
|
|
49,833
|
|
Accrued
Interest
|
|
|
44,125
|
|
|
28,614
|
|
Other
|
|
|
60,079
|
|
|
80,132
|
|
TOTAL
|
|
|
831,346
|
|
|
1,017,241
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
1,954,664
|
|
|
1,904,379
|
|
Long-term
Debt - Affiliated
|
|
|
100,000
|
|
|
100,000
|
|
Long-term
Risk Management Liabilities
|
|
|
127,161
|
|
|
147,117
|
|
Deferred
Income Taxes
|
|
|
948,109
|
|
|
952,497
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
206,492
|
|
|
201,230
|
|
Deferred
Credits and Other
|
|
|
177,050
|
|
|
110,144
|
|
TOTAL
|
|
|
3,513,476
|
|
|
3,415,367
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,344,822
|
|
|
4,432,608
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
17,784
|
|
|
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
|
|
|
924,875
|
|
|
924,837
|
|
Retained
Earnings
|
|
|
705,872
|
|
|
635,016
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(3,342
|
)
|
|
(16,610
|
)
|
TOTAL
|
|
|
1,887,863
|
|
|
1,803,701
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
6,250,469
|
|
$
|
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 Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
73,594
|
|
$
|
46,672
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
47,972
|
|
|
49,959
|
|
Deferred
Income Taxes
|
|
|
(11,423
|
)
|
|
9,445
|
|
Carrying
Costs Income
|
|
|
(6,011
|
)
|
|
(98
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(5,696
|
)
|
|
(13,360
|
)
|
Pension
Contributions to Qualified Plan Trusts
|
|
|
-
|
|
|
(19,937
|
)
|
Over/Under
Fuel Recovery, Net
|
|
|
7,832
|
|
|
3,320
|
|
Change
in Other Noncurrent Assets
|
|
|
5,878
|
|
|
(19,490
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
5,848
|
|
|
(414
|
)
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
75,278
|
|
|
3,113
|
|
Fuel,
Materials and Supplies
|
|
|
13,028
|
|
|
(5,764
|
)
|
Accounts
Payable
|
|
|
(30,148
|
)
|
|
32,411
|
|
Accrued
Taxes, Net
|
|
|
56,180
|
|
|
(21,316
|
)
|
Customer
Deposits
|
|
|
(13,530
|
)
|
|
13,557
|
|
Accrued
Interest
|
|
|
15,511
|
|
|
16,965
|
|
Other
Current Assets
|
|
|
(1,718
|
)
|
|
(7,918
|
)
|
Other
Current Liabilities
|
|
|
(20,053
|
)
|
|
(6,199
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
212,542
|
|
|
80,946
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(196,561
|
)
|
|
(129,823
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
-
|
|
|
(13,947
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
(29,054
|
)
|
Proceeds
from Sales of Assets
|
|
|
102
|
|
|
7,133
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(196,459
|
)
|
|
(165,691
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Capital
Contributions from Parent
|
|
|
-
|
|
|
100,000
|
|
Issuance
of Long-term Debt - Nonaffiliated
|
|
|
49,677
|
|
|
198,189
|
|
Change
in Advances from Affiliates, Net
|
|
|
(29,941
|
)
|
|
(211,060
|
)
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
(100,003
|
)
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(1,483
|
)
|
|
(1,592
|
)
|
Funds
From Amended Coal Contract
|
|
|
68,078
|
|
|
-
|
|
Dividends
Paid on Common Stock
|
|
|
(2,500
|
)
|
|
-
|
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(200
|
)
|
|
(200
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
(16,372
|
)
|
|
85,337
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(289
|
)
|
|
592
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,741
|
|
|
1,543
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,452
|
|
$
|
2,135
|
|
SUPPLEMENTAL
DISCLOSURE:
|
Cash
paid for interest net of capitalized amounts was $14,686,000 and
$5,842,000 and for income taxes
net of refunds was
$1,771,000 and $38,845,000 in 2006 and 2005, respectively. Noncash
capital
lease acquisitions were $1,184,000 and $460,000 in 2006 and 2005,
respectively. Noncash Construction Expenditures included in Accounts
Payable of $83,682,000 and $46,146,000 were outstanding as of March
31,
2006 and 2005, respectively.
|
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
10
|
Financing
Activities
|
Note
11
|
COLUMBUS
SOUTHERN POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006 Net
Income
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
47
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
24
|
|
|
|
|
Off-system
Sales
|
|
|
8
|
|
|
|
|
Transmission
Revenues
|
|
|
2
|
|
|
|
|
Other
|
|
|
6
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
40
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(15
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(8
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(3
|
)
|
|
|
|
Carrying
Costs Income
|
|
|
(2
|
)
|
|
|
|
Interest
Expense
|
|
|
(5
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
51
|
|
Net
Income remained relatively flat in the first quarter of 2006 compared to
the
first quarter of 2005.
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 were $24 million higher than the prior period primarily
due to
Rate Stabilization Plan and Transition Regulatory Asset rate increases
effective January 1, 2006 as well as the addition of Monongahela
Power
Ohio customers on December 31, 2005, partially offset by reduced
fuel
margins.
|
·
|
Off-system
Sales increased $8 million primarily due to increased AEP Power
Pool sales
partially offset by lower optimization activity.
|
·
|
Other
revenues increased $6 million primarily due to higher gains on
sale of
emission allowances.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expense increased $15 million due to
the 2005
establishment of a regulatory asset for PJM administrative fees,
an
increase in transmission expenses related to the AEP Transmission
Equalization Agreement and favorable adjustments in the prior year
quarter
related to the corporate owned life insurance policy and storm
expense.
|
·
|
Depreciation
and Amortization expense increased $8 million primarily due to
increased
amortization of regulatory assets and an increase in depreciation
expense
due to a greater depreciable base resulting primarily from the
acquisitions of the Waterford Plant and Monongahela Power’s Ohio
assets.
|
·
|
Taxes
Other Than Income Taxes increased $3 million due to increases in
real and
personal property taxes.
|
·
|
Interest
Expense increased $5 million primarily due to a new long-term debt
issuance during the fourth quarter of
2005.
|
Income
Tax
The
increase of $3 million in Income Tax Expense 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
|
A3
|
|
BBB
|
|
A-
|
Financing
Activity
There
were no long-term debt issuances or retirements during the first three 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. An adverse result in these proceedings has 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 March 31, 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 March 31, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
59,753
|
|
$
|
7,087
|
|
$
|
-
|
|
$
|
66,840
|
|
Noncurrent
Assets
|
|
|
93,183
|
|
|
446
|
|
|
-
|
|
|
93,629
|
|
Total
MTM Derivative Contract Assets
|
|
|
152,936
|
|
|
7,533
|
|
|
-
|
|
|
160,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(48,676
|
)
|
|
(2,614
|
)
|
|
(733
|
)
|
|
(52,023
|
)
|
Noncurrent
Liabilities
|
|
|
(67,300
|
)
|
|
(231
|
)
|
|
(6,423
|
)
|
|
(73,954
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(115,976
|
)
|
|
(2,845
|
)
|
|
(7,156
|
)
|
|
(125,977
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
36,960
|
|
$
|
4,688
|
|
$
|
(7,156
|
)
|
$
|
34,492
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 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
|
|
|
(3,337
|
)
|
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
|
|
|
(665
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
456
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
7,022
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(11
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
36,960
|
|
Net
Cash Flow Hedge Contracts
|
|
|
4,688
|
|
DETM
Assignment (d)
|
|
|
(7,156
|
)
|
Total
MTM Risk Management Contract Net Assets at March 31,
2006
|
|
$
|
34,492
|
|
(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 Income. These net gains (losses) are
recorded
as regulatory liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
(d)
|
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 March 31, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
5,775
|
|
$
|
1,202
|
|
$
|
534
|
|
$
|
(42
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
7,469
|
|
Prices
Provided by Other External Sources
- OTC
Broker Quotes (a)
|
|
|
4,260
|
|
|
3,399
|
|
|
4,766
|
|
|
3,976
|
|
|
-
|
|
|
-
|
|
|
16,401
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(820
|
)
|
|
3,667
|
|
|
2,438
|
|
|
2,351
|
|
|
5,034
|
|
|
420
|
|
|
13,090
|
|
Total
|
|
$
|
9,215
|
|
$
|
8,268
|
|
$
|
7,738
|
|
$
|
6,285
|
|
$
|
5,034
|
|
$
|
420
|
|
$
|
36,960
|
|
(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 March 31, 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
Three
Months Ended March 31, 2006
(in
thousands)
|
|
Power
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(859
|
)
|
Changes
in Fair Value
|
|
|
3,510
|
|
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
|
|
531
|
|
Ending
Balance in AOCI March 31, 2006
|
|
$
|
3,182
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $3,043 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 March 31, 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:
Three
Months Ended
March
31, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$403
|
|
$948
|
|
$513
|
|
$253
|
|
|
|
|
$424
|
|
$705
|
|
$335
|
|
$121
|
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 $76 million
and $86 million at March 31, 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.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
413,669
|
|
$
|
328,603
|
|
Sales
to AEP Affiliates
|
|
|
13,769
|
|
|
34,814
|
|
Other
|
|
|
1,330
|
|
|
3,716
|
|
TOTAL
|
|
|
428,768
|
|
|
367,133
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
69,820
|
|
|
66,435
|
|
Purchased
Electricity for Resale
|
|
|
24,765
|
|
|
9,203
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
82,477
|
|
|
79,775
|
|
Other
Operation
|
|
|
55,961
|
|
|
43,229
|
|
Maintenance
|
|
|
17,934
|
|
|
15,384
|
|
Depreciation
and Amortization
|
|
|
45,812
|
|
|
38,198
|
|
Taxes
Other Than Income Taxes
|
|
|
39,502
|
|
|
36,242
|
|
TOTAL
|
|
|
336,271
|
|
|
288,466
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
92,497
|
|
|
78,667
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
455
|
|
|
917
|
|
Carrying
Costs Income
|
|
|
716
|
|
|
2,757
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
464
|
|
|
279
|
|
Interest
Expense
|
|
|
(17,520
|
)
|
|
(12,912
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
76,612
|
|
|
69,708
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
25,275
|
|
|
22,240
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
51,337
|
|
|
47,468
|
|
|
|
|
|
|
|
|
|
Capital
Stock Expense
|
|
|
39
|
|
|
254
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
51,298
|
|
$
|
47,214
|
|
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 Three Months Ended March 31, 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
|
|
|
|
|
|
|
|
|
(28,500
|
)
|
|
|
|
|
(28,500
|
)
|
Capital
Stock Expense
|
|
|
|
|
|
254
|
|
|
(254
|
)
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
870,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $3,109
|
|
|
|
|
|
|
|
|
|
|
|
(5,774
|
)
|
|
(5,774
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
47,468
|
|
|
|
|
|
47,468
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,694
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2005
|
|
$
|
41,026
|
|
$
|
577,669
|
|
$
|
359,739
|
|
$
|
(66,590
|
)
|
$
|
911,844
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
41,026
|
|
$
|
580,035
|
|
$
|
361,365
|
|
$
|
(880
|
)
|
$
|
981,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(22,500
|
)
|
|
|
|
|
(22,500
|
)
|
Capital
Stock Expense
|
|
|
|
|
|
39
|
|
|
(39
|
)
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
959,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,176
|
|
|
|
|
|
|
|
|
|
|
|
4,041
|
|
|
4,041
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
51,337
|
|
|
|
|
|
51,337
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2006
|
|
$
|
41,026
|
|
$
|
580,074
|
|
$
|
390,163
|
|
$
|
3,161
|
|
$
|
1,014,424
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
757
|
|
$
|
940
|
|
Advances
to Affiliates
|
|
|
6,867
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
57,283
|
|
|
43,143
|
|
Affiliated
Companies
|
|
|
22,610
|
|
|
67,694
|
|
Accrued
Unbilled Revenues
|
|
|
6,080
|
|
|
10,086
|
|
Miscellaneous
|
|
|
3,828
|
|
|
2,012
|
|
Allowance
for Uncollectible Accounts
|
|
|
(1,243
|
)
|
|
(1,082
|
)
|
Total
Accounts Receivable
|
|
|
88,558
|
|
|
121,853
|
|
Fuel
|
|
|
36,099
|
|
|
28,579
|
|
Materials
and Supplies
|
|
|
27,430
|
|
|
27,519
|
|
Emission
Allowances
|
|
|
15,350
|
|
|
20,181
|
|
Risk
Management Assets
|
|
|
66,840
|
|
|
76,507
|
|
Margin
Deposits
|
|
|
21,809
|
|
|
16,832
|
|
Accrued
Tax Benefits
|
|
|
15,417
|
|
|
36,838
|
|
Prepayments
and Other
|
|
|
8,760
|
|
|
6,714
|
|
TOTAL
|
|
|
287,887
|
|
|
335,963
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
1,883,412
|
|
|
1,874,652
|
|
Transmission
|
|
|
468,553
|
|
|
457,937
|
|
Distribution
|
|
|
1,411,856
|
|
|
1,380,722
|
|
Other
|
|
|
186,223
|
|
|
184,096
|
|
Construction
Work in Progress
|
|
|
152,937
|
|
|
129,246
|
|
Total
|
|
|
4,102,981
|
|
|
4,026,653
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,539,816
|
|
|
1,500,858
|
|
TOTAL
- NET
|
|
|
2,563,165
|
|
|
2,525,795
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
225,936
|
|
|
231,599
|
|
Long-term
Risk Management Assets
|
|
|
93,629
|
|
|
101,512
|
|
Deferred
Charges and Other
|
|
|
228,604
|
|
|
237,925
|
|
TOTAL
|
|
|
548,169
|
|
|
571,036
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
3,399,221
|
|
$
|
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
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
-
|
|
$
|
17,609
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
84,371
|
|
|
59,134
|
|
Affiliated
Companies
|
|
|
47,503
|
|
|
59,399
|
|
Risk
Management Liabilities
|
|
|
52,023
|
|
|
69,036
|
|
Customer
Deposits
|
|
|
39,112
|
|
|
47,013
|
|
Accrued
Taxes
|
|
|
128,435
|
|
|
157,729
|
|
Accrued
Interest
|
|
|
14,781
|
|
|
18,908
|
|
Other
|
|
|
24,750
|
|
|
31,321
|
|
TOTAL
|
|
|
390,975
|
|
|
460,149
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
1,097,021
|
|
|
1,096,920
|
|
Long-term
Debt - Affiliated
|
|
|
100,000
|
|
|
100,000
|
|
Long-term
Risk Management Liabilities
|
|
|
73,954
|
|
|
84,291
|
|
Deferred
Income Taxes
|
|
|
504,062
|
|
|
498,232
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
171,700
|
|
|
165,344
|
|
Deferred
Credits and Other
|
|
|
47,085
|
|
|
46,312
|
|
TOTAL
|
|
|
1,993,822
|
|
|
1,991,099
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,384,797
|
|
|
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
|
|
|
580,074
|
|
|
580,035
|
|
Retained
Earnings
|
|
|
390,163
|
|
|
361,365
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
3,161
|
|
|
(880
|
)
|
TOTAL
|
|
|
1,014,424
|
|
|
981,546
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$
|
3,399,221
|
|
$
|
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 Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
51,337
|
|
$
|
47,468
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
45,812
|
|
|
38,198
|
|
Deferred
Income Taxes
|
|
|
3,816
|
|
|
(2,613
|
)
|
Carrying
Costs Income
|
|
|
(716
|
)
|
|
(2,757
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(3,624
|
)
|
|
(5,120
|
)
|
Pension
Contributions to Qualified Plan Trusts
|
|
|
-
|
|
|
(12,611
|
)
|
Deferred
Property Taxes
|
|
|
10,884
|
|
|
15,938
|
|
Change
in Other Noncurrent Assets
|
|
|
(11,084
|
)
|
|
(18,027
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
5,800
|
|
|
171
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
33,295
|
|
|
14,059
|
|
Fuel,
Materials and Supplies
|
|
|
(7,431
|
)
|
|
7,529
|
|
Accounts
Payable
|
|
|
12,540
|
|
|
(18,636
|
)
|
Accrued
Taxes, Net
|
|
|
(7,873
|
)
|
|
(61,908
|
)
|
Customer
Deposits
|
|
|
(7,901
|
)
|
|
6,173
|
|
Accrued
Interest
|
|
|
(4,127
|
)
|
|
(8,271
|
)
|
Other
Current Assets
|
|
|
(728
|
)
|
|
(3,926
|
)
|
Other
Current Liabilities
|
|
|
(6,571
|
)
|
|
(8,031
|
)
|
Net
Cash Flows From (Used For) Operating Activities
|
|
|
113,429
|
|
|
(12,364
|
)
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(65,032
|
)
|
|
(36,227
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
(1,151
|
)
|
|
(7,125
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
(6,867
|
)
|
|
82,134
|
|
Proceeds
from Sale of Assets
|
|
|
306
|
|
|
3,663
|
|
Net
Cash Flows From (Used For) Investing Activities
|
|
|
(72,744
|
)
|
|
42,445
|
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
(17,609
|
)
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(759
|
)
|
|
(935
|
)
|
Dividends
Paid on Common Stock
|
|
|
(22,500
|
)
|
|
(28,500
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(40,868
|
)
|
|
(29,435
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(183
|
)
|
|
646
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
940
|
|
|
58
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
757
|
|
$
|
704
|
|
SUPPLEMENTAL
DISCLOSURE:
|
Cash
paid for interest net of capitalized amounts was $22,320,000 and
$21,898,000 and for income taxes net of refunds was $2,533,000
and
$57,037,000 in 2006 and 2005, respectively. Noncash capital lease
acquisitions in 2006 and 2005 were $1,102,000 and $160,000, respectively.
Noncash construction expenditures included in Accounts Payable
of
$12,054,000 and $2,771,000 were outstanding as of March 31, 2006
and 2005,
respectively.
|
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
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
10
|
Financing
Activities
|
Note
11
|
INDIANA
MICHIGAN POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006 Net
Income
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
40
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
6
|
|
|
|
|
Off-System
Sales (a)
|
|
|
16
|
|
|
|
|
Transmission
Revenues
|
|
|
2
|
|
|
|
|
Other
|
|
|
12
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(4
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(1
|
)
|
|
|
|
Interest
Expense
|
|
|
(2
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(11
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
58
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income increased $18 million to $58 million in 2006. The key drivers of
the
increase were a $36 million increase in Gross Margin partially offset by
an $11
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
Margins increased $6 million primarily due to increases in industrial
sales and capacity settlement revenues of $3 million under the
Interconnection Agreement.
|
·
|
Off-system
Sales increased $16 million primarily due to the addition of
new municipal
contracts including new rates and increased demand beginning
January
2006.
|
·
|
Other
revenues
increased $12 million primarily due to increased River Transportation
Division (RTD) revenues for barging coal to affiliated companies’ plants
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
an
approved return.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other Operation
and Maintenance expenses increased $4 million primarily due to
higher
expenses for RTD and the gain for settlement and cancellation
of the
corporate owned life insurance policies in February 2005 partially
offset
by a reduction in distribution maintenance expense. Prior year
distribution maintenance expense for overhead power lines included
the
costs of the January 2005 ice
storm.
|
Income
Taxes
Income
Tax Expense increased $11 million primarily due to an increase in pretax
book
income.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Current ratings, unchanged
since first quarter of 2003, are as follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
Baa2
|
|
BBB
|
|
BBB
|
Cash
Flow
Cash
flows for the three months ended March 31, 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
|
|
|
195,328
|
|
|
70,893
|
|
Investing
Activities
|
|
|
(139,649
|
)
|
|
(82,849
|
)
|
Financing
Activities
|
|
|
(55,924
|
)
|
|
12,019
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(245
|
)
|
|
63
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
609
|
|
$
|
574
|
|
Operating
Activities
Our
Net
Cash Flows From Operating Activities were $195 million in 2006. We produced
Net
Income of $58 million during the period and a noncash expense item of $44
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 relates to Accrued Taxes, Net and Accounts Receivable,
Net.
During the first quarter of 2006, we did not make any federal income tax
payments and collected receivables from our affiliates related to power
sales,
settled litigation and emission allowances.
Our
Net
Cash Flows From Operating Activities were $71 million in 2005. We produced
Net
Income of $40 million during the period and a noncash expense item of $43
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 $46 million change in Accrued Taxes, Net reflecting
taxes paid during 2005.
Investing
Activities
Net
Cash
Flows Used For Investing Activities during 2006 and 2005 primarily reflect
our
construction expenditures of $89 million and $52 million and acquisition
of
nuclear fuel of $34 million and $21 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 our Construction Expenditures to be approximately
$222 million.
Financing
Activities
Our
Net
Cash Flows Used For Financing Activities were $56 million in 2006. We used
cash
from operations to repay Advances from Affiliates and pay common dividends.
Our
cash
flows from financing activities were $12 million in 2005. Advances from
Affiliates funded our construction expenditures.
Financing
Activity
There
were no long-term debt issuances or retirements during the first three
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.
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
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. An adverse result in
these proceedings has 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 March 31, 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 March 31, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow &
Fair
Value Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
60,866
|
|
$
|
7,239
|
|
$
|
-
|
|
$
|
68,105
|
|
Noncurrent
Assets
|
|
|
94,960
|
|
|
456
|
|
|
-
|
|
|
95,416
|
|
Total
MTM Derivative Contract Assets
|
|
|
155,826
|
|
|
7,695
|
|
|
-
|
|
|
163,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(49,439
|
)
|
|
(3,264
|
)
|
|
(749
|
)
|
|
(53,452
|
)
|
Noncurrent
Liabilities
|
|
|
(68,380
|
)
|
|
(237
|
)
|
|
(6,560
|
)
|
|
(75,177
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(117,819
|
)
|
|
(3,501
|
)
|
|
(7,309
|
)
|
|
(128,629
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
38,007
|
|
$
|
4,194
|
|
$
|
(7,309
|
)
|
$
|
34,892
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 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
|
|
|
977
|
|
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
|
|
|
(655
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(2,054
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
5,807
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
38,007
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
4,194
|
|
DETM
Assignment (d)
|
|
|
(7,309
|
)
|
Total
MTM Risk Management Contract Net Assets at March 31,
2006
|
|
$
|
34,892
|
|
(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 our
Condensed
Consolidated Statements of Income. These net gains (losses) are
recorded
as regulatory liabilities/assets for those subsidiaries that
operate in
regulated jurisdictions.
|
(d)
|
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 March 31, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
5,899
|
|
$
|
1,228
|
|
$
|
545
|
|
$
|
(43
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
7,629
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
4,433
|
|
|
3,374
|
|
|
4,836
|
|
|
4,061
|
|
|
-
|
|
|
-
|
|
|
16,704
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(819
|
)
|
|
3,926
|
|
|
2,595
|
|
|
2,401
|
|
|
5,142
|
|
|
429
|
|
|
13,674
|
|
Total
|
|
$
|
9,513
|
|
$
|
8,528
|
|
$
|
7,976
|
|
$
|
6,419
|
|
$
|
5,142
|
|
$
|
429
|
|
$
|
38,007
|
|
(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 March 31, 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
Three
Months Ended March 31, 2006
(in
thousands)
|
|
Power
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(877
|
)
|
$
|
(2,590
|
)
|
$
|
(3,467
|
)
|
Changes
in Fair Value
|
|
|
3,585
|
|
|
-
|
|
|
3,585
|
|
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
|
|
542
|
|
|
80
|
|
|
622
|
|
Ending
Balance in AOCI March 31, 2006
|
|
$
|
3,250
|
|
$
|
(2,510
|
)
|
$
|
740
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $2,786 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 March 31, 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:
Three
Months Ended
March
31, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$412
|
|
$968
|
|
$524
|
|
$258
|
|
|
|
|
$433
|
|
$720
|
|
$343
|
|
$124
|
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 $49 million
and $55 million at March 31, 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 Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
403,769
|
|
$
|
348,353
|
|
Sales
to AEP Affiliates
|
|
|
88,534
|
|
|
92,538
|
|
Other
- Affiliated
|
|
|
15,094
|
|
|
10,339
|
|
Other
- Nonaffiliated
|
|
|
8,382
|
|
|
6,329
|
|
TOTAL
|
|
|
515,779
|
|
|
457,559
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
89,452
|
|
|
79,237
|
|
Purchased
Electricity for Resale
|
|
|
11,010
|
|
|
11,272
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
86,422
|
|
|
74,009
|
|
Other
Operation
|
|
|
117,206
|
|
|
104,402
|
|
Maintenance
|
|
|
45,219
|
|
|
54,322
|
|
Depreciation
and Amortization
|
|
|
44,126
|
|
|
42,745
|
|
Taxes
Other Than Income Taxes
|
|
|
18,906
|
|
|
18,682
|
|
TOTAL
|
|
|
412,341
|
|
|
384,669
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
103,438
|
|
|
72,890
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
694
|
|
|
433
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
1,924
|
|
|
1,649
|
|
Interest
Expense
|
|
|
(17,533
|
)
|
|
(15,606
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
88,523
|
|
|
59,366
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
30,645
|
|
|
19,697
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
57,878
|
|
|
39,669
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements including Capital Stock Expense
|
|
|
85
|
|
|
118
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
57,793
|
|
$
|
39,551
|
|
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 Three Months Ended March 31, 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
|
|
|
|
|
|
|
|
|
(21,000
|
)
|
|
|
|
|
(21,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(85
|
)
|
|
|
|
|
(85
|
)
|
Capital
Stock Expense
|
|
|
|
|
|
33
|
|
|
(33
|
)
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,070,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $3,400
|
|
|
|
|
|
|
|
|
|
|
|
(6,313
|
)
|
|
(6,313
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
39,669
|
|
|
|
|
|
39,669
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2005
|
|
$
|
56,584
|
|
$
|
858,868
|
|
$
|
239,881
|
|
$
|
(51,564
|
)
|
$
|
1,103,769
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
56,584
|
|
$
|
861,290
|
|
$
|
305,787
|
|
$
|
(3,569
|
)
|
$
|
1,220,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(10,000
|
)
|
|
|
|
|
(10,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(85
|
)
|
|
|
|
|
(85
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,210,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,265
|
|
|
|
|
|
|
|
|
|
|
|
4,207
|
|
|
4,207
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
57,878
|
|
|
|
|
|
57,878
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2006
|
|
$
|
56,584
|
|
$
|
861,290
|
|
$
|
353,580
|
|
$
|
638
|
|
$
|
1,272,092
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
609
|
|
$
|
854
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
68,193
|
|
|
62,614
|
|
Affiliated
Companies
|
|
|
79,243
|
|
|
127,981
|
|
Miscellaneous
|
|
|
2,131
|
|
|
1,982
|
|
Allowance
for Uncollectible Accounts
|
|
|
(907
|
)
|
|
(898
|
)
|
Total
Accounts Receivable
|
|
|
148,660
|
|
|
191,679
|
|
Fuel
|
|
|
29,747
|
|
|
25,894
|
|
Materials
and Supplies
|
|
|
121,380
|
|
|
118,039
|
|
Risk
Management Assets
|
|
|
68,105
|
|
|
78,134
|
|
Accrued
Tax Benefits
|
|
|
26,000
|
|
|
51,846
|
|
Margin
Deposits
|
|
|
22,276
|
|
|
17,115
|
|
Prepayments
and Other
|
|
|
8,602
|
|
|
14,188
|
|
TOTAL
|
|
|
425,379
|
|
|
497,749
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
3,146,481
|
|
|
3,128,078
|
|
Transmission
|
|
|
1,031,154
|
|
|
1,028,496
|
|
Distribution
|
|
|
1,053,772
|
|
|
1,029,498
|
|
Other
(including nuclear fuel and coal mining)
|
|
|
463,346
|
|
|
465,130
|
|
Construction
Work in Progress
|
|
|
332,470
|
|
|
311,080
|
|
Total
|
|
|
6,027,223
|
|
|
5,962,282
|
|
Accumulated
Depreciation, Depletion and Amortization
|
|
|
2,850,675
|
|
|
2,822,558
|
|
TOTAL
- NET
|
|
|
3,176,548
|
|
|
3,139,724
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
215,523
|
|
|
222,686
|
|
Nuclear
Decommissioning and Spent Nuclear Fuel Disposal Trust
Funds
|
|
|
1,160,089
|
|
|
1,133,567
|
|
Long-term
Risk Management Assets
|
|
|
95,416
|
|
|
103,645
|
|
Deferred
Charges and Other
|
|
|
171,164
|
|
|
164,938
|
|
TOTAL
|
|
|
1,642,192
|
|
|
1,624,836
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
5,244,119
|
|
$
|
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
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
49,137
|
|
$
|
93,702
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
117,455
|
|
|
139,334
|
|
Affiliated
Companies
|
|
|
40,241
|
|
|
60,324
|
|
Long-term
Debt Due Within One Year
|
|
|
364,406
|
|
|
364,469
|
|
Risk
Management Liabilities
|
|
|
53,452
|
|
|
71,032
|
|
Customer
Deposits
|
|
|
41,227
|
|
|
49,258
|
|
Accrued
Taxes
|
|
|
73,592
|
|
|
56,567
|
|
Other
|
|
|
110,506
|
|
|
112,839
|
|
TOTAL
|
|
|
850,016
|
|
|
947,525
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt
|
|
|
1,083,098
|
|
|
1,080,471
|
|
Long-term
Risk Management Liabilities
|
|
|
75,177
|
|
|
86,159
|
|
Deferred
Income Taxes
|
|
|
340,347
|
|
|
335,264
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
729,080
|
|
|
710,015
|
|
Asset
Retirement Obligations
|
|
|
749,858
|
|
|
737,959
|
|
Deferred
Credits and Other
|
|
|
136,367
|
|
|
136,740
|
|
TOTAL
|
|
|
3,113,927
|
|
|
3,086,608
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
3,963,943
|
|
|
4,034,133
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
8,084
|
|
|
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
|
|
|
353,580
|
|
|
305,787
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
638
|
|
|
(3,569
|
)
|
TOTAL
|
|
|
1,272,092
|
|
|
1,220,092
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
5,244,119
|
|
$
|
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 Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
57,878
|
|
$
|
39,669
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
44,126
|
|
|
42,745
|
|
Accretion
of Asset Retirement Obligations
|
|
|
11,907
|
|
|
11,664
|
|
Deferred
Income Taxes
|
|
|
3,493
|
|
|
(876
|
)
|
Deferred
Investment Tax Credits
|
|
|
(1,820
|
)
|
|
(1,832
|
)
|
Amortization
(Deferral) of Incremental Nuclear Refueling Outage Expenses,
Net
|
|
|
(1,639
|
)
|
|
5,517
|
|
Amortization
of Nuclear Fuel
|
|
|
13,596
|
|
|
14,394
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(4,060
|
)
|
|
(5,722
|
)
|
Pension
Contributions to Qualified Plan Trusts
|
|
|
-
|
|
|
(15,350
|
)
|
Deferred
Property Taxes
|
|
|
(9,839
|
)
|
|
(9,089
|
)
|
Change
in Other Noncurrent Assets
|
|
|
11,184
|
|
|
4,699
|
|
Change
in Other Noncurrent Liabilities
|
|
|
8,752
|
|
|
2,830
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
43,019
|
|
|
23,265
|
|
Fuel,
Materials and Supplies
|
|
|
(7,194
|
)
|
|
4,455
|
|
Accounts
Payable
|
|
|
(7,010
|
)
|
|
(12,771
|
)
|
Accrued
Taxes, Net
|
|
|
42,871
|
|
|
(46,291
|
)
|
Accrued
Interest
|
|
|
11,623
|
|
|
9,607
|
|
Customer
Deposits
|
|
|
(8,031
|
)
|
|
4,751
|
|
Accrued
Rent - Rockport Plant Unit 2
|
|
|
18,464
|
|
|
18,464
|
|
Other
Current Assets
|
|
|
428
|
|
|
(5,072
|
)
|
Other
Current Liabilities
|
|
|
(32,420
|
)
|
|
(14,164
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
195,328
|
|
|
70,893
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(89,411
|
)
|
|
(52,456
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
5,093
|
|
Changes
in Other Cash Deposits, Net
|
|
|
(3
|
)
|
|
(7,966
|
)
|
Purchases
of Investment Securities
|
|
|
(150,239
|
)
|
|
(151,980
|
)
|
Sales
of Investment Securities
|
|
|
134,258
|
|
|
136,743
|
|
Acquisitions
of Nuclear Fuel
|
|
|
(34,427
|
)
|
|
(21,444
|
)
|
Proceeds
from Sales of Assets
|
|
|
173
|
|
|
9,161
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(139,649
|
)
|
|
(82,849
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
(44,565
|
)
|
|
95,967
|
|
Retirement
of Cumulative Preferred Stock
|
|
|
-
|
|
|
(61,445
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(1,274
|
)
|
|
(1,418
|
)
|
Dividends
Paid on Common Stock
|
|
|
(10,000
|
)
|
|
(21,000
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(85
|
)
|
|
(85
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
(55,924
|
)
|
|
12,019
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(245
|
)
|
|
63
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
854
|
|
|
511
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
609
|
|
$
|
574
|
|
SUPPLEMENTAL
DISCLOSURE:
|
Cash
paid for interest net of capitalized amounts was $4,776,000 and
$5,035,000
and for income taxes net of refunds was $1,324,000 and $82,338,000
in 2006
and 2005, respectively. Noncash capital lease acquisitions were
$2,218,000
and $404,000 in 2006 and 2005, respectively. Noncash construction
expenditures included in Accounts Payable of $27,624,000 and
$16,823,000
were outstanding as of March 31, 2006 and 2005,
respectively.
|
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
10
|
Financing
Activities
|
Note
11
|
KENTUCKY
POWER COMPANY
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006 Net
Income
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(4
|
)
|
|
|
|
Off-system
Sales
|
|
|
1
|
|
|
|
|
Other
|
|
|
6
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
Net
Income was unchanged in comparison to 2005.
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 by $4 million in comparison to 2005 primarily
due to
increased capacity settlement payments.
|
·
|
Other
revenues increased
$6 million due primarily to a $3 million adjustment of the Demand
Side
Management Program regulatory asset in March 2005 and current
period gains
on the sale of emission allowances.
|
Income
Taxes
The
increase in Income Tax Expense of $2 million is primarily due to an increase
in
pretax book income and state income taxes 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
There
were no long-term debt issuances or retirements during the first three
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
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. An
adverse result in these proceedings has 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 March 31, 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 March 31, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow &
Fair
Value Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
24,318
|
|
$
|
2,874
|
|
$
|
-
|
|
$
|
27,192
|
|
Noncurrent
Assets
|
|
|
37,902
|
|
|
181
|
|
|
-
|
|
|
38,083
|
|
Total
MTM Derivative Contract Assets
|
|
|
62,220
|
|
|
3,055
|
|
|
-
|
|
|
65,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(19,880
|
)
|
|
(1,687
|
)
|
|
(297
|
)
|
|
(21,864
|
)
|
Noncurrent
Liabilities
|
|
|
(27,474
|
)
|
|
(473
|
)
|
|
(2,605
|
)
|
|
(30,552
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(47,354
|
)
|
|
(2,160
|
)
|
|
(2,902
|
)
|
|
(52,416
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
14,866
|
|
$
|
895
|
|
$
|
(2,902
|
)
|
$
|
12,859
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 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
|
|
|
457
|
|
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
|
|
|
(281
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(918
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
2,090
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
14,866
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
895
|
|
DETM
Assignment (d)
|
|
|
(2,902
|
)
|
Total
MTM Risk Management Contract Net Assets at March 31, 2006
|
|
$
|
12,859
|
|
(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
Statements of Income. These net gains (losses) are recorded as
regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
|
(d)
|
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 March 31, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
2,342
|
|
$
|
487
|
|
$
|
217
|
|
$
|
(17
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
3,029
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
1,688
|
|
|
1,426
|
|
|
1,949
|
|
|
1,612
|
|
|
-
|
|
|
-
|
|
|
6,675
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(340
|
)
|
|
1,399
|
|
|
937
|
|
|
954
|
|
|
2,042
|
|
|
170
|
|
|
5,162
|
|
Total
|
|
$
|
3,690
|
|
$
|
3,312
|
|
$
|
3,103
|
|
$
|
2,549
|
|
$
|
2,042
|
|
$
|
170
|
|
$
|
14,866
|
|
(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 March 31, 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
Three
Months Ended March 31, 2006
(in
thousands)
|
|
Power
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(352
|
)
|
$
|
158
|
|
$
|
(194
|
)
|
Changes
in Fair Value
|
|
|
1,427
|
|
|
-
|
|
|
1,427
|
|
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
|
|
216
|
|
|
(22
|
)
|
|
194
|
|
Ending
Balance in AOCI March 31, 2006
|
|
$
|
1,291
|
|
$
|
136
|
|
$
|
1,427
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,320 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 March 31, 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:
Three
Months Ended
March
31, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$164
|
|
$385
|
|
$208
|
|
$102
|
|
|
|
|
$174
|
|
$289
|
|
$138
|
|
$50
|
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 March 31, 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 Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
137,620
|
|
$
|
109,081
|
|
Sales
to AEP Affiliates
|
|
|
13,968
|
|
|
18,548
|
|
Other
|
|
|
259
|
|
|
431
|
|
TOTAL
|
|
|
151,847
|
|
|
128,060
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
43,966
|
|
|
28,679
|
|
Purchased
Electricity for Resale
|
|
|
973
|
|
|
2,124
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
49,526
|
|
|
42,739
|
|
Other
Operation
|
|
|
13,748
|
|
|
13,942
|
|
Maintenance
|
|
|
7,141
|
|
|
5,916
|
|
Depreciation
and Amortization
|
|
|
11,457
|
|
|
11,152
|
|
Taxes
Other Than Income Taxes
|
|
|
2,512
|
|
|
2,425
|
|
TOTAL
|
|
|
129,323
|
|
|
106,977
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
22,524
|
|
|
21,083
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
166
|
|
|
140
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
101
|
|
|
92
|
|
Interest
Expense
|
|
|
(7,296
|
)
|
|
(7,370
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
15,495
|
|
|
13,945
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
5,665
|
|
|
4,060
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
9,830
|
|
$
|
9,885
|
|
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 Three Months Ended March 31, 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 $1,415
|
|
|
|
|
|
|
|
|
|
|
|
(2,627
|
)
|
|
(2,627
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
9,885
|
|
|
|
|
|
9,885
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2005
|
|
$
|
50,450
|
|
$
|
208,750
|
|
$
|
80,440
|
|
$
|
(11,402
|
)
|
$
|
328,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
50,450
|
|
$
|
208,750
|
|
$
|
88,864
|
|
$
|
(223
|
)
|
$
|
347,841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(2,500
|
)
|
|
|
|
|
(2,500
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
345,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $873
|
|
|
|
|
|
|
|
|
|
|
|
1,621
|
|
|
1,621
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
9,830
|
|
|
|
|
|
9,830
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2006
|
|
$
|
50,450
|
|
$
|
208,750
|
|
$
|
96,194
|
|
$
|
1,398
|
|
$
|
356,792
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
KENTUCKY
POWER COMPANY
CONDENSED
BALANCE SHEETS
ASSETS
March
31, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
423
|
|
$
|
526
|
|
Advances
to Affiliates
|
|
|
5,923
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
28,183
|
|
|
26,533
|
|
Affiliated
Companies
|
|
|
7,287
|
|
|
23,525
|
|
Accrued
Unbilled Revenues
|
|
|
4,393
|
|
|
6,311
|
|
Miscellaneous
|
|
|
455
|
|
|
35
|
|
Allowance
for Uncollectible Accounts
|
|
|
(210
|
)
|
|
(147
|
)
|
Total
Accounts Receivable
|
|
|
40,108
|
|
|
56,257
|
|
Fuel
|
|
|
11,892
|
|
|
8,490
|
|
Materials
and Supplies
|
|
|
9,587
|
|
|
10,181
|
|
Risk
Management Assets
|
|
|
27,192
|
|
|
31,437
|
|
Margin
Deposits
|
|
|
8,845
|
|
|
6,895
|
|
Accrued
Tax Benefits
|
|
|
3,920
|
|
|
6,598
|
|
Prepayments
and Other
|
|
|
2,305
|
|
|
6,324
|
|
TOTAL
|
|
|
110,195
|
|
|
126,708
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
473,778
|
|
|
472,575
|
|
Transmission
|
|
|
388,292
|
|
|
386,945
|
|
Distribution
|
|
|
462,999
|
|
|
456,063
|
|
Other
|
|
|
60,989
|
|
|
63,382
|
|
Construction
Work in Progress
|
|
|
35,289
|
|
|
35,461
|
|
Total
|
|
|
1,421,347
|
|
|
1,414,426
|
|
Accumulated
Depreciation and Amortization
|
|
|
427,358
|
|
|
425,817
|
|
TOTAL
- NET
|
|
|
993,989
|
|
|
988,609
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
115,885
|
|
|
117,432
|
|
Long-term
Risk Management Assets
|
|
|
38,083
|
|
|
41,810
|
|
Deferred
Charges and Other
|
|
|
43,055
|
|
|
45,467
|
|
TOTAL
|
|
|
197,023
|
|
|
204,709
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
1,301,207
|
|
$
|
1,320,026
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
KENTUCKY
POWER COMPANY
CONDENSED
BALANCE SHEETS
LIABILITIES
AND SHAREHOLDER’S EQUITY
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
-
|
|
$
|
6,040
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
32,895
|
|
|
32,454
|
|
Affiliated
Companies
|
|
|
19,199
|
|
|
29,326
|
|
Long-term
Debt Due Within One Year - Affiliated
|
|
|
39,374
|
|
|
39,771
|
|
Risk
Management Liabilities
|
|
|
21,864
|
|
|
28,770
|
|
Customer
Deposits
|
|
|
18,516
|
|
|
21,643
|
|
Accrued
Taxes
|
|
|
8,803
|
|
|
8,805
|
|
Accrued
Interest
|
|
|
9,361
|
|
|
7,428
|
|
Other
|
|
|
10,683
|
|
|
14,096
|
|
TOTAL
|
|
|
160,695
|
|
|
188,333
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
427,435
|
|
|
427,219
|
|
Long-term
Debt - Affiliated
|
|
|
20,000
|
|
|
20,000
|
|
Long-term
Risk Management Liabilities
|
|
|
30,552
|
|
|
35,302
|
|
Deferred
Income Taxes
|
|
|
238,993
|
|
|
234,719
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
56,852
|
|
|
56,794
|
|
Deferred
Credits and Other
|
|
|
9,888
|
|
|
9,818
|
|
TOTAL
|
|
|
783,720
|
|
|
783,852
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
944,415
|
|
|
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
|
|
|
96,194
|
|
|
88,864
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
1,398
|
|
|
(223
|
)
|
TOTAL
|
|
|
356,792
|
|
|
347,841
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$
|
1,301,207
|
|
$
|
1,320,026
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
KENTUCKY
POWER COMPANY
CONDENSED
STATEMENTS OF CASH FLOWS
For
the Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
9,830
|
|
$
|
9,885
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
11,457
|
|
|
11,152
|
|
Deferred
Income Taxes
|
|
|
2,217
|
|
|
988
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(1,378
|
)
|
|
(3,290
|
)
|
Pension
Contributions to Qualified Plan Trusts
|
|
|
-
|
|
|
(3,045
|
)
|
Change
in Other Noncurrent Assets
|
|
|
2,650
|
|
|
1,722
|
|
Change
in Other Noncurrent Liabilities
|
|
|
1,845
|
|
|
4,533
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
16,149
|
|
|
(1,133
|
)
|
Fuel,
Materials and Supplies
|
|
|
(2,808
|
)
|
|
(873
|
)
|
Accounts
Payable
|
|
|
(6,212
|
)
|
|
1,717
|
|
Accrued
Taxes, Net
|
|
|
2,676
|
|
|
2,415
|
|
Customer
Deposits
|
|
|
(3,127
|
)
|
|
3,400
|
|
Accrued
Interest
|
|
|
1,933
|
|
|
2,238
|
|
Over/Under
Fuel Recovery, Net
|
|
|
2,682
|
|
|
(5,203
|
)
|
Other
Current Assets
|
|
|
(613
|
)
|
|
(2,234
|
)
|
Other
Current Liabilities
|
|
|
(3,413
|
)
|
|
(833
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
33,888
|
|
|
21,439
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(19,376
|
)
|
|
(8,987
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
-
|
|
|
(3,314
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
(5,923
|
)
|
|
(8,607
|
)
|
Proceeds
from Sale of Assets
|
|
|
191
|
|
|
-
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(25,108
|
)
|
|
(20,908
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
(6,040
|
)
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(343
|
)
|
|
(382
|
)
|
Dividends
Paid on Common Stock
|
|
|
(2,500
|
)
|
|
-
|
|
Net
Cash Flows Used For Financing Activities
|
|
|
(8,883
|
)
|
|
(382
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(103
|
)
|
|
149
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
526
|
|
|
132
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
423
|
|
$
|
281
|
|
SUPPLEMENTAL
DISCLOSURE:
|
Cash
paid for interest net of capitalized amounts was $4,156,000 and
$3,570,000
and for income taxes net
of refunds was
$214,000 and $691,000 in 2006 and 2005, respectively. Noncash
capital
lease acquisitions were $224,000 and $126,000 in 2006 and 2005,
respectively. Noncash Construction Expenditures included in Accounts
Payable of $3,079,000 and $1,289,000 were outstanding as of March
31, 2006
and 2005, respectively.
|
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
10
|
Financing
Activities
|
Note
11
|
OHIO
POWER COMPANY CONSOLIDATED
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006 Net
Income
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
99
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
25
|
|
|
|
|
Off-system
Sales
|
|
|
(3
|
)
|
|
|
|
Transmission
Revenues
|
|
|
2
|
|
|
|
|
Other
|
|
|
9
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
33
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(23
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(5
|
)
|
|
|
|
Carrying
Costs Income
|
|
|
(18
|
)
|
|
|
|
Interest
Expense
|
|
|
3
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(43
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
95
|
|
Net
Income remained relatively flat in the first quarter of 2006 compared to
the
first quarter of 2005.
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 were $25 million higher than the prior period primarily
due to the
Rate Stabilization Plan rate increase effective January 1, 2006
and a
favorable variance from the receipt of SO2
allowances from Buckeye Power, Inc. under the Cardinal Station
Allowance
Agreement, partially offset by decreased capacity settlements
under the
Interconnection Agreement related to an increase in an affiliate’s peak
load.
|
·
|
Other
revenues increased $9 million primarily due to higher gains on
sale of
emission allowances.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $23 million primarily
due to
a planned outage at the Gavin Plant and the establishment of
a regulatory
asset for PJM administrative fees which reduced expenses in the
prior year
quarter partially offset by major ice storm expense in the same
period.
|
·
|
Depreciation
and Amortization expense increased $5 million due to increased
amortization of regulatory assets and an increase in depreciation
expense
due to a greater depreciable base in electric utility plants.
|
·
|
Carrying
Costs Income decreased $18 million primarily due to the completion
of
deferrals on the environmental carrying costs from 2004 and 2005
that are
being recovered during 2006 through 2008 according to the Rate
Stabilization Plan. We recorded $16 million in environmental
carrying
costs in the first quarter of 2005 related to
2004.
|
Income
Taxes
The
decrease of $6 million in Income Tax Expense 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 three months ended March 31, 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
|
|
|
184,391
|
|
|
41,223
|
|
Investing Activities
|
|
|
(224,251
|
)
|
|
(24,025
|
)
|
Financing Activities
|
|
|
39,577
|
|
|
(25,418
|
)
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(283
|
)
|
|
(8,220
|
)
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
957
|
|
$
|
1,117
|
|
Operating
Activities
Our
Net
Cash Flows From Operating Activities were $184 million in 2006. We produced
income of $95 million during the period and a noncash expense item of $79
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 primarily relates to two
items,
Accounts Receivable, Net and Accounts Payable. Accounts Receivable, Net
decreased $102 million due to collected receivables from our affiliates
related
to power sales, settled litigation and emission allowances. Accounts Payable
decreased $60 million due to emission allowance payments in January 2006
and
temporary timing differences for payments to affiliates.
Our
Net
Cash Flows From Operating Activities were $41 million in 2005. We produced
income of $99 million during the period and a noncash expense item of $74
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 primarily relates to a $73
million decrease in Accrued Taxes, Net due to a 2004 federal income tax
payment
made in the first quarter of 2005.
Investing
Activities
Our
Net
Cash Flows Used For Investing Activities for the first three months of
2006 and
2005 were $224 million and $24 million, respectively, primarily due to
Construction Expenditures for environmental upgrades, as well as projects
to
improve service reliability for transmission and distribution. In 2005,
Construction Expenditures of $106 million were offset by a decrease in
Advances
to Affiliates, Net. For the remainder of 2006, we expect our Construction
Expenditures to be approximately $850 million.
Financing
Activities
Our
Net
Cash Flows From Financing Activities during the first three months of 2006
were
$40 million due to a $35 million capital contribution from AEP.
Our
Net
Cash Flows Used For Financing Activities during the first three months
of 2005
were $25 million related to a refinancing and payment of dividends.
Financing
Activity
Long-term
debt issuances and retirements during the first three months of 2006
were:
Issuances
None
Retirements
and Principal Payments
|
|
Principal
|
|
Interest
|
|
Due
|
|
Type
of Debt
|
|
Amount
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
Notes
Payable
|
|
$
|
1,463
|
|
|
6.81
|
|
|
2008
|
|
Notes
Payable
|
|
|
3,250
|
|
|
6.27
|
|
|
2009
|
|
In
April
2006, we issued $65 million variable rate pollution control bonds due in
2036.
The proceeds will be used to finance the cost of solid waste disposal facilities
at the Mitchell Generating Station.
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. An adverse result in these proceedings has 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 March 31, 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 March 31, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
79,205
|
|
$
|
12,434
|
|
$
|
-
|
|
$
|
91,639
|
|
Noncurrent
Assets
|
|
|
121,959
|
|
|
575
|
|
|
-
|
|
|
122,534
|
|
Total
MTM Derivative Contract Assets
|
|
|
201,164
|
|
|
13,009
|
|
|
-
|
|
|
214,173
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(67,418
|
)
|
|
(4,008
|
)
|
|
(944
|
)
|
|
(72,370
|
)
|
Noncurrent
Liabilities
|
|
|
(89,828
|
)
|
|
(298
|
)
|
|
(8,274
|
)
|
|
(98,400
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(157,246
|
)
|
|
(4,306
|
)
|
|
(9,218
|
)
|
|
(170,770
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
43,918
|
|
$
|
8,703
|
|
$
|
(9,218
|
)
|
$
|
43,403
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 in the 2005 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 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
|
|
|
(1,742
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
223
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired
Option
Contracts Entered During the Period
|
|
|
(1,060
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
587
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
5,037
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(21
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
43,918
|
|
Net
Cash Flow Hedge Contracts
|
|
|
8,703
|
|
DETM
Assignment (d)
|
|
|
(9,218
|
)
|
Total
MTM Risk Management Contract Net Assets at March 31, 2006
|
|
$
|
43,403
|
|
(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 Income. These net gains (losses) are
recorded
as regulatory liabilities/assets for those subsidiaries that
operate in
regulated jurisdictions.
|
(d)
|
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 March 31, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded Contracts
|
|
$
|
7,439
|
|
$
|
1,548
|
|
$
|
688
|
|
$
|
(55
|
)
|
$
|
-
|
|
$ |
- |
|
$
|
$9,620
|
|
Prices
Provided by Other External Sources - OTC
Broker Quotes (a)
|
|
|
3,302
|
|
|
5,245
|
|
|
6,416
|
|
|
5,122
|
|
|
-
|
|
|
-
|
|
|
20,085
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(1,241
|
)
|
|
3,173
|
|
|
2,227
|
|
|
3,028
|
|
|
6,485
|
|
|
541
|
|
|
14,213
|
|
Total
|
|
$
|
9,500
|
|
$
|
9,966
|
|
$
|
9,331
|
|
$
|
8,095
|
|
$
|
6,485
|
|
$
|
541
|
|
$
|
43,918
|
|
(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 March 31, 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
Three
Months Ended March 31, 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
|
|
|
4,564
|
|
|
-
|
|
|
1,833
|
|
|
6,397
|
|
Reclassifications
from AOCI to Net Income for
Cash Flow Hedges Settled
|
|
|
(89
|
)
|
|
3
|
|
|
(135
|
)
|
|
(221
|
)
|
Ending
Balance in AOCI March 31, 2006
|
|
$
|
4,083
|
|
$
|
(341
|
)
|
$
|
3,189
|
|
$
|
6,931
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $4,581 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 March 31, 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:
Three
Months Ended
March
31, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$520
|
|
$1,221
|
|
$660
|
|
$325
|
|
|
|
|
$583
|
|
$968
|
|
$461
|
|
$166
|
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 $95 million
and $111 million at March 31, 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 Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
544,639
|
|
$
|
471,010
|
|
Sales
to AEP Affiliates
|
|
|
149,259
|
|
|
173,726
|
|
Other
- Affiliated
|
|
|
3,709
|
|
|
3,454
|
|
Other
- Nonaffiliated
|
|
|
4,999
|
|
|
6,964
|
|
TOTAL
|
|
|
702,606
|
|
|
655,154
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
235,130
|
|
|
227,049
|
|
Purchased
Electricity for Resale
|
|
|
21,714
|
|
|
18,762
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
28,572
|
|
|
25,618
|
|
Other
Operation
|
|
|
86,637
|
|
|
64,570
|
|
Maintenance
|
|
|
47,524
|
|
|
46,475
|
|
Depreciation
and Amortization
|
|
|
78,813
|
|
|
73,947
|
|
Taxes
Other Than Income Taxes
|
|
|
47,153
|
|
|
47,299
|
|
TOTAL
|
|
|
545,543
|
|
|
503,720
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
157,063
|
|
|
151,434
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
637
|
|
|
887
|
|
Carrying
Costs Income
|
|
|
3,383
|
|
|
22,037
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
738
|
|
|
427
|
|
Interest
Expense
|
|
|
(23,414
|
)
|
|
(26,163
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
138,407
|
|
|
148,622
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
43,375
|
|
|
49,139
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
95,032
|
|
|
99,483
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
183
|
|
|
183
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
94,849
|
|
$
|
99,300
|
|
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 Three Months Ended March 31, 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
|
|
|
|
|
|
|
|
|
(7,500
|
)
|
|
|
|
|
(7,500
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(183
|
)
|
|
|
|
|
(183
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,466,155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $4,273
|
|
|
|
|
|
|
|
|
|
|
|
(7,936
|
)
|
|
(7,936
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
99,483
|
|
|
|
|
|
99,483
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2005
|
|
$
|
321,201
|
|
$
|
462,485
|
|
$
|
856,216
|
|
$
|
(82,200
|
)
|
$
|
1,557,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
321,201
|
|
$
|
466,637
|
|
$
|
979,354
|
|
$
|
755
|
|
$
|
1,767,947
|
|
Capital
Contribution From Parent
|
|
|
|
|
|
35,000
|
|
|
|
|
|
|
|
|
35,000
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(183
|
)
|
|
|
|
|
(183
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,802,764
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $3,326
|
|
|
|
|
|
|
|
|
|
|
|
6,176
|
|
|
6,176
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
95,032
|
|
|
|
|
|
95,032
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2006
|
|
$
|
321,201
|
|
$
|
501,637
|
|
$
|
1,074,203
|
|
$
|
6,931
|
|
$
|
1,903,972
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
957
|
|
$
|
1,240
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
119,430
|
|
|
125,404
|
|
Affiliated
Companies
|
|
|
76,327
|
|
|
167,579
|
|
Accrued
Unbilled Revenues
|
|
|
21,640
|
|
|
14,817
|
|
Miscellaneous
|
|
|
5,134
|
|
|
15,644
|
|
Allowance
for Uncollectible Accounts
|
|
|
(2,470
|
)
|
|
(1,517
|
)
|
Total
Accounts Receivable
|
|
|
220,061
|
|
|
321,927
|
|
Fuel
|
|
|
114,508
|
|
|
97,600
|
|
Materials
and Supplies
|
|
|
62,267
|
|
|
60,937
|
|
Emission
Allowances
|
|
|
30,679
|
|
|
39,251
|
|
Risk
Management Assets
|
|
|
91,639
|
|
|
115,020
|
|
Accrued
Tax Benefits
|
|
|
-
|
|
|
39,965
|
|
Margin
Deposits
|
|
|
28,594
|
|
|
23,053
|
|
Prepayments
and Other
|
|
|
9,807
|
|
|
4,386
|
|
TOTAL
|
|
|
558,512
|
|
|
703,379
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
4,284,994
|
|
|
4,278,553
|
|
Transmission
|
|
|
1,000,501
|
|
|
1,002,255
|
|
Distribution
|
|
|
1,271,554
|
|
|
1,258,518
|
|
Other
|
|
|
293,835
|
|
|
293,794
|
|
Construction
Work in Progress
|
|
|
876,384
|
|
|
690,168
|
|
Total
|
|
|
7,727,268
|
|
|
7,523,288
|
|
Accumulated
Depreciation and Amortization
|
|
|
2,772,156
|
|
|
2,738,899
|
|
TOTAL
- NET
|
|
|
4,955,112
|
|
|
4,784,389
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
377,447
|
|
|
398,007
|
|
Long-term
Risk Management Assets
|
|
|
122,534
|
|
|
144,015
|
|
Deferred
Charges and Other
|
|
|
283,348
|
|
|
300,880
|
|
TOTAL
|
|
|
783,329
|
|
|
842,902
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
6,296,953
|
|
$
|
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
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
81,043
|
|
$
|
70,071
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
207,220
|
|
|
210,752
|
|
Affiliated
Companies
|
|
|
97,767
|
|
|
147,470
|
|
Short-term
Debt - Nonaffiliated
|
|
|
11,002
|
|
|
10,366
|
|
Long-term
Debt Due Within One Year - Affiliated
|
|
|
200,000
|
|
|
200,000
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
12,354
|
|
|
12,354
|
|
Risk
Management Liabilities
|
|
|
72,370
|
|
|
108,797
|
|
Customer
Deposits
|
|
|
38,712
|
|
|
51,209
|
|
Accrued
Taxes
|
|
|
121,925
|
|
|
158,774
|
|
Accrued
Interest
|
|
|
25,300
|
|
|
36,298
|
|
Other
|
|
|
87,284
|
|
|
111,480
|
|
TOTAL
|
|
|
954,977
|
|
|
1,117,571
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
1,782,749
|
|
|
1,787,316
|
|
Long-term
Debt - Affiliated
|
|
|
200,000
|
|
|
200,000
|
|
Long-term
Risk Management Liabilities
|
|
|
98,400
|
|
|
119,247
|
|
Deferred
Income Taxes
|
|
|
995,059
|
|
|
987,386
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
177,394
|
|
|
168,492
|
|
Deferred
Credits and Other
|
|
|
149,853
|
|
|
154,770
|
|
TOTAL
|
|
|
3,403,455
|
|
|
3,417,211
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,358,432
|
|
|
4,534,782
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
17,910
|
|
|
11,302
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
16,639
|
|
|
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
|
|
|
501,637
|
|
|
466,637
|
|
Retained
Earnings
|
|
|
1,074,203
|
|
|
979,354
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
6,931
|
|
|
755
|
|
TOTAL
|
|
|
1,903,972
|
|
|
1,767,947
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
6,296,953
|
|
$
|
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 Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
95,032
|
|
$
|
99,483
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
78,813
|
|
|
73,947
|
|
Deferred
Income Taxes
|
|
|
3,604
|
|
|
4,092
|
|
Carrying
Costs Income
|
|
|
(3,383
|
)
|
|
(22,037
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(3,616
|
)
|
|
(2,477
|
)
|
Pension
Contributions to Qualified Plan Trusts
|
|
|
-
|
|
|
(20,007
|
)
|
Deferred
Property Taxes
|
|
|
17,331
|
|
|
15,658
|
|
Change
in Other Noncurrent Assets
|
|
|
4,852
|
|
|
(19,261
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
13,855
|
|
|
20,969
|
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
101,866
|
|
|
(25,474
|
)
|
Fuel,
Materials and Supplies
|
|
|
(18,238
|
)
|
|
(483
|
)
|
Accounts
Payable
|
|
|
(60,411
|
)
|
|
(38,830
|
)
|
Accrued
Taxes, Net
|
|
|
3,116
|
|
|
(73,250
|
)
|
Customer
Deposits
|
|
|
(12,497
|
)
|
|
8,371
|
|
Interest
Accrued
|
|
|
(10,998
|
)
|
|
(16,209
|
)
|
Other
Current Assets
|
|
|
(739
|
)
|
|
40,237
|
|
Other
Current Liabilities
|
|
|
(24,196
|
)
|
|
(3,506
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
184,391
|
|
|
41,223
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(222,600
|
)
|
|
(105,707
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
(1,651
|
)
|
|
(9,952
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
84,564
|
|
Proceeds
from Sale of Assets
|
|
|
-
|
|
|
7,070
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(224,251
|
)
|
|
(24,025
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Capital
Contributions from Parent Company
|
|
|
35,000
|
|
|
-
|
|
Issuance
of Long-term Debt - Nonaffiliated
|
|
|
-
|
|
|
216,798
|
|
Change
in Short-term Debt, Net - Nonaffiliated
|
|
|
636
|
|
|
(4,796
|
)
|
Change
in Advances from Affiliates, Net
|
|
|
10,972
|
|
|
-
|
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
(4,713
|
)
|
|
(222,713
|
)
|
Retirement
of Cumulative Preferred Stock
|
|
|
-
|
|
|
(5,000
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(2,135
|
)
|
|
(2,024
|
)
|
Dividends
Paid on Common Stock
|
|
|
-
|
|
|
(7,500
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(183
|
)
|
|
(183
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
39,577
|
|
|
(25,418
|
)
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(283
|
)
|
|
(8,220
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,240
|
|
|
9,337
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
957
|
|
$
|
1,117
|
|
SUPPLEMENTAL
DISCLOSURE:
|
Cash
paid for interest net of capitalized amounts was $29,152,000
and
$37,519,000 and for income taxes net of refunds was $922,000
and
$87,763,000 in 2006 and 2005, respectively. Noncash acquisitions
under
capital leases were $927,000 and $555,000 in 2006 and 2005, respectively.
Noncash construction expenditures included in Accounts Payable
of
$82,024,000 and $64,611,000 were outstanding as of March 31,
2006 and
2005, respectively.
|
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
10
|
Financing
Activities
|
Note
11
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006 Net Income
(Loss)
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
3
|
|
|
|
|
Transmission
Revenues
|
|
|
1
|
|
|
|
|
Other
|
|
|
2
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(15
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
1
|
|
|
|
|
Interest
Expense
|
|
|
(1
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Credit
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
(5
|
)
|
Net
Income (Loss) decreased $6 million in the first quarter of 2006. The key
driver
of the decrease was a $15 million increase in Other Operation and Maintenance
expenses, partially offset by a $6 million increase in Gross
Margin.
The
major
components of our increase in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of emission allowances and purchased
power, were as follows:
·
|
Retail
and Off-system Sales Margins increased $3 million primarily
due to an increase in capacity revenue.
|
·
|
Other
revenues
increased
$2 million primarily due to a settlement with an electric
cooperative.
|
Operating
Expenses and Other increased between years as follows:
·
|
Other
Operation and Maintenance expenses increased $15 million. Maintenance
expense increased $9 million primarily due to a $5 million increase
in
scheduled power plant maintenance and a $3 million increase in
scheduled
overhead line maintenance. Other Operation expense increased
$6 million
primarily due to increased customer-related expenses, factoring
of
accounts receivable and outside
services.
|
Income
Taxes
The
$3
million increase in Income Tax Credit is primarily due to the increase
in pretax
book loss.
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
There
were no long-term debt issuances or retirements during the first three
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
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. An
adverse result in these proceedings has 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 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 March 31, 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 March 31, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
Total
|
|
Current
Assets
|
|
$
|
10,922
|
|
$
|
1,635
|
|
$
|
12,557
|
|
Noncurrent
Assets
|
|
|
11,068
|
|
|
103
|
|
|
11,171
|
|
Total
MTM Derivative Contract Assets
|
|
|
21,990
|
|
|
1,738
|
|
|
23,728
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(9,717
|
)
|
|
(603
|
)
|
|
(10,320
|
)
|
Noncurrent
Liabilities
|
|
|
(7,165
|
)
|
|
(53
|
)
|
|
(7,218
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(16,882
|
)
|
|
(656
|
)
|
|
(17,538
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
|
|
$
|
5,108
|
|
$
|
1,082
|
|
$
|
6,190
|
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 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
|
|
|
164
|
|
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
|
|
|
(196
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(64
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(9,010
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
5,108
|
|
Net
Cash Flow Hedge Contracts
|
|
|
1,082
|
|
Total
MTM Risk Management Contract Net Assets at March 31,
2006
|
|
$
|
6,190
|
|
(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)
|
“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.
|
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 March 31, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
1,151
|
|
$
|
277
|
|
$
|
123
|
|
$
|
(10
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
1,541
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
304
|
|
|
603
|
|
|
951
|
|
|
801
|
|
|
-
|
|
|
-
|
|
|
2,659
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(455
|
)
|
|
39
|
|
|
46
|
|
|
205
|
|
|
673
|
|
|
400
|
|
|
908
|
|
Total
|
|
$
|
1,000
|
|
$
|
919
|
|
$
|
1,120
|
|
$
|
996
|
|
$
|
673
|
|
$
|
400
|
|
$
|
5,108
|
|
(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 March 31, 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
Three
Months Ended March 31, 2006
(in
thousands)
|
|
Power
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(629
|
)
|
$
|
(483
|
)
|
$
|
(1,112
|
)
|
Changes
in Fair Value
|
|
|
1,240
|
|
|
-
|
|
|
1,240
|
|
Reclassifications
from AOCI to Net Income for Cash
Flow Hedges Settled
|
|
|
123
|
|
|
28
|
|
|
151
|
|
Ending
Balance in AOCI March 31, 2006
|
|
$
|
734
|
|
$
|
(455
|
)
|
$
|
279
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $592 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 March 31, 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:
Three
Months Ended
March
31, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$93
|
|
$219
|
|
$118
|
|
$58
|
|
|
|
|
$311
|
|
$517
|
|
$246
|
|
$89
|
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 $31 million and $34 million at March
31, 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 OPERATIONS
For
the Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
339,601
|
|
$
|
250,098
|
|
Sales
to AEP Affiliates
|
|
|
14,068
|
|
|
2,632
|
|
Other
|
|
|
1,060
|
|
|
352
|
|
TOTAL
|
|
|
354,729
|
|
|
253,082
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
213,173
|
|
|
134,178
|
|
Purchased
Electricity for Resale
|
|
|
33,217
|
|
|
14,793
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
21,231
|
|
|
22,845
|
|
Other
Operation
|
|
|
36,867
|
|
|
30,498
|
|
Maintenance
|
|
|
20,307
|
|
|
11,359
|
|
Depreciation
and Amortization
|
|
|
21,021
|
|
|
22,619
|
|
Taxes
Other Than Income Taxes
|
|
|
10,076
|
|
|
9,677
|
|
TOTAL
|
|
|
355,892
|
|
|
245,969
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME (LOSS)
|
|
|
(1,163
|
)
|
|
7,113
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
569
|
|
|
165
|
|
Interest
Expense
|
|
|
(9,135
|
)
|
|
(7,875
|
)
|
|
|
|
|
|
|
|
|
LOSS
BEFORE INCOME TAXES
|
|
|
(9,729
|
)
|
|
(597
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Credit
|
|
|
(4,372
|
)
|
|
(1,102
|
)
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
|
(5,357
|
)
|
|
505
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
53
|
|
|
53
|
|
|
|
|
|
|
|
|
|
EARNINGS
(LOSS) APPLICABLE TO COMMON STOCK
|
|
$
|
(5,410
|
)
|
$
|
452
|
|
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 Three Months Ended March 31, 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
|
|
|
|
|
|
|
|
|
(8,500
|
)
|
|
|
|
|
(8,500
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(53
|
)
|
|
|
|
|
(53
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
520,703
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $534
|
|
|
|
|
|
|
|
|
|
|
|
(993
|
)
|
|
(993
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
505
|
|
|
|
|
|
505
|
|
TOTAL
COMPREHENSIVE LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(488
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2005
|
|
$
|
157,230
|
|
$
|
230,016
|
|
$
|
133,887
|
|
$
|
(918
|
)
|
$
|
520,215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
157,230
|
|
$
|
230,016
|
|
$
|
162,615
|
|
$
|
(1,264
|
)
|
$
|
548,597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(53
|
)
|
|
|
|
|
(53
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
548,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $749
|
|
|
|
|
|
|
|
|
|
|
|
1,391
|
|
|
1,391
|
|
NET
LOSS
|
|
|
|
|
|
|
|
|
(5,357
|
)
|
|
|
|
|
(5,357
|
)
|
TOTAL
COMPREHENSIVE LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,966
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2006
|
|
$
|
157,230
|
|
$
|
230,016
|
|
$
|
157,205
|
|
$
|
127
|
|
$
|
544,578
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
BALANCE SHEETS
ASSETS
March
31, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
1,190
|
|
$
|
1,520
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
29,004
|
|
|
37,740
|
|
Affiliated
Companies
|
|
|
49,057
|
|
|
73,321
|
|
Miscellaneous
|
|
|
9,699
|
|
|
10,501
|
|
Allowance
for Uncollectible Accounts
|
|
|
(290
|
)
|
|
(240
|
)
|
Total
Accounts Receivable
|
|
|
87,470
|
|
|
121,322
|
|
Fuel
|
|
|
14,552
|
|
|
16,431
|
|
Materials
and Supplies
|
|
|
40,450
|
|
|
38,545
|
|
Risk
Management Assets
|
|
|
12,557
|
|
|
40,383
|
|
Accrued
Tax Benefits
|
|
|
-
|
|
|
11,972
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
34,451
|
|
|
108,732
|
|
Prepayments
and Other
|
|
|
8,195
|
|
|
14,287
|
|
TOTAL
|
|
|
198,865
|
|
|
353,192
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
1,086,284
|
|
|
1,072,928
|
|
Transmission
|
|
|
481,783
|
|
|
479,272
|
|
Distribution
|
|
|
1,156,783
|
|
|
1,140,535
|
|
Other
|
|
|
221,777
|
|
|
211,805
|
|
Construction
Work in Progress
|
|
|
77,757
|
|
|
90,455
|
|
Total
|
|
|
3,024,384
|
|
|
2,994,995
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,178,101
|
|
|
1,175,858
|
|
TOTAL
- NET
|
|
|
1,846,283
|
|
|
1,819,137
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
36,159
|
|
|
50,723
|
|
Long-term
Risk Management Assets
|
|
|
11,171
|
|
|
33,566
|
|
Employee
Benefits and Pension Assets
|
|
|
81,607
|
|
|
82,559
|
|
Deferred
Charges and Other
|
|
|
40,346
|
|
|
16,287
|
|
TOTAL
|
|
|
169,283
|
|
|
183,135
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
2,214,431
|
|
$
|
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
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
118,815
|
|
$
|
75,883
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
83,618
|
|
|
130,627
|
|
Affiliated
Companies
|
|
|
57,135
|
|
|
89,786
|
|
Long-term
Debt Due Within One Year - Affiliated
|
|
|
50,000
|
|
|
50,000
|
|
Risk
Management Liabilities
|
|
|
10,320
|
|
|
38,243
|
|
Customer
Deposits
|
|
|
40,788
|
|
|
53,844
|
|
Accrued
Taxes
|
|
|
44,644
|
|
|
22,420
|
|
Other
|
|
|
28,500
|
|
|
51,548
|
|
TOTAL
|
|
|
433,820
|
|
|
512,351
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
521,086
|
|
|
521,071
|
|
Long-term
Risk Management Liabilities
|
|
|
7,218
|
|
|
22,582
|
|
Deferred
Income Taxes
|
|
|
413,991
|
|
|
436,382
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
264,034
|
|
|
284,640
|
|
Deferred
Credits and Other
|
|
|
24,442
|
|
|
24,579
|
|
TOTAL
|
|
|
1,230,771
|
|
|
1,289,254
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
1,664,591
|
|
|
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
|
|
|
157,205
|
|
|
162,615
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
127
|
|
|
(1,264
|
)
|
TOTAL
|
|
|
544,578
|
|
|
548,597
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
2,214,431
|
|
$
|
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 Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income (Loss)
|
|
$
|
(5,357
|
)
|
$
|
505
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
21,021
|
|
|
22,619
|
|
Deferred
Income Taxes
|
|
|
(23,436
|
)
|
|
2,126
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
9,106
|
|
|
10,473
|
|
Deferred
Property Taxes
|
|
|
(24,295
|
)
|
|
(24,368
|
)
|
Change
in Other Noncurrent Assets
|
|
|
11,229
|
|
|
(5,816
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
(20,806
|
)
|
|
(9,579
|
)
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
33,852
|
|
|
14,815
|
|
Fuel,
Materials and Supplies
|
|
|
(26
|
)
|
|
(2,871
|
)
|
Accounts
Payable
|
|
|
(77,217
|
)
|
|
(7,779
|
)
|
Accrued
Taxes, Net
|
|
|
34,196
|
|
|
14,982
|
|
Customer
Deposits
|
|
|
(13,056
|
)
|
|
110
|
|
Over/Under
Fuel Recovery
|
|
|
74,281
|
|
|
40,895
|
|
Other
Current Assets
|
|
|
6,086
|
|
|
2,285
|
|
Other
Current Liabilities
|
|
|
(23,048
|
)
|
|
(13,262
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
2,530
|
|
|
45,135
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(45,539
|
)
|
|
(20,501
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
6
|
|
|
-
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(45,533
|
)
|
|
(20,501
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
42,932
|
|
|
(15,414
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(206
|
)
|
|
(148
|
)
|
Dividends
Paid on Common Stock
|
|
|
-
|
|
|
(8,500
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(53
|
)
|
|
(53
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
42,673
|
|
|
(24,115
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(330
|
)
|
|
519
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,520
|
|
|
279
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,190
|
|
$
|
798
|
|
SUPPLEMENTAL
DISCLOSURE:
|
Cash
paid (received) for interest net of capitalized amounts was $8,681,000
and
$7,806,000 and for income taxes
net of refunds was
$575,000 and $(1,366,000) in 2006 and 2005, respectively. Noncash
capital
lease acquisitions were $564,000 and $551,000 in 2006 and 2005,
respectively. Noncash Construction Expenditures included in Accounts
Payable of $6,052,000 and $2,208,000 were outstanding as of March
31, 2006
and 2005, respectively.
|
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
|
Business
Segments
|
Note
10
|
Financing
Activities
|
Note
11
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2006 Compared to First Quarter of 2005
Reconciliation
of First Quarter of 2005 to First Quarter of 2006 Net
Income
(in
millions)
First
Quarter of 2005
|
|
|
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
13
|
|
|
|
|
Transmission
Revenues
|
|
|
3
|
|
|
|
|
Other
|
|
|
8
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
|
|
|
(14
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2006
|
|
|
|
|
$
|
18
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income increased $6 million to $18 million in the first quarter of 2006.
The key
driver of the increase was a $24 million increase in Gross Margin, offset
by a
$14 million increase in Other Operation and Maintenance expenses and a
$4
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 $13 million compared to
2005
primarily due to a $5 million increase related to wholesale prices
and an
$8 million increase in capacity revenue.
|
·
|
Transmission
Revenues increased $3 million primarily due to higher rates within
SPP.
|
·
|
Other
revenues increased $8 million primarily due to the gain on sale
of
emission allowances.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $14 million. This
was
primarily due to a $9 million increase in maintenance during
scheduled
power plant outages. In addition, Other Operation expense increased
$2
million due to right-of-way clearing and increased tree trimming.
Other
Operation expense also increased $2 million
primarily due to customer-related expenses and factoring of accounts
receivable.
|
Income
Taxes
The
$4
million increase in Income Tax Expense is primarily due to the increase
in
pretax book income.
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 three months ended March 31, 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
|
|
|
41,293
|
|
|
54,957
|
|
Investing Activities
|
|
|
(54,294
|
)
|
|
(34,751
|
)
|
Financing Activities
|
|
|
12,501
|
|
|
(15,329
|
)
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(500
|
)
|
|
4,877
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
2,549
|
|
$
|
8,592
|
|
Operating
Activities
Our
Net
Cash Flows From Operating Activities were $41 million in 2006. We produced
Net
Income of $18 million during the period and noncash expense items of $33
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 $27
million
inflow from Accounts Receivable, Net was due
to
lower affiliated energy transactions. The $18 million outflow from Fuel,
Materials and Supplies was the result of reduced fuel consumption during
scheduled power plant outages. The $45 million inflow from Accrued Taxes,
Net
was due to increased income taxes. We did not make a federal income tax
payment
in 2006. The $16 million outflow from Customer Deposits was due to lower
trading-related deposits. In
addition, our cash flow related to Over/Under Fuel Recovery was favorably
impacted by the new fuel surcharges effective December 2005 in our Arkansas
service territory and in January 2006 in our Texas service territory. The
$15
million outflow from Accounts Payable was the result of lower expenditures
related to tree trimming and right-of-way clearing, energy purchases and
general
operations.
Our
Net
Cash Flows From Operating Activities were $55 million in 2005. We produced
Net
Income of $12 million during the period and noncash expense items of $32
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 $15
million
inflow from Accounts Receivable, Net was the result of decreased affiliated
energy transactions. The $16 million inflow from Accrued Taxes, Net was
primarily due to a reduction of income tax related accruals.
Investing
Activities
Cash
Flows Used For Investing Activities during 2006 and 2005 were $54 million
and
$35 million, respectively. The cash flows were comprised primarily of
Construction Expenditures related to projects for improved transmission
and
distribution service reliability. For the remainder of 2006, we expect
our
Construction Expenditures to be approximately $230 million.
Financing
Activities
Cash
Flows From Financing Activities were $13 million during 2006. During the
quarter, the net change in short-term debt was $4 million. Long-term debt
retirements were $2 million. In addition, we borrowed $21 million from
the
Utility Money Pool. We also paid $10 million in Common Stock
Dividends.
Cash
Flows Used For Financing Activities were $15 million during 2005. We retired
$2
million of Notes Payable. We paid $13 million in Common Stock
Dividends.
Financing
Activity
Long-term
debt retirements and principal payments during the first three months of
2006
were:
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
Notes
Payable
|
|
$
|
1,707
|
|
4.47
|
|
2011
|
Notes
Payable
|
|
|
750
|
|
Variable
|
|
2008
|
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 retirements 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. An adverse result in these proceedings has 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 March 31, 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 March 31, 2006
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
Total
|
|
Current
Assets
|
|
$
|
12,790
|
|
$
|
1,911
|
|
$
|
14,701
|
|
Noncurrent
Assets
|
|
|
12,969
|
|
|
121
|
|
|
13,090
|
|
Total
MTM Derivative Contract Assets
|
|
|
25,759
|
|
|
2,032
|
|
|
27,791
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(11,410
|
)
|
|
(724
|
)
|
|
(12,134
|
)
|
Noncurrent
Liabilities
|
|
|
(8,430
|
)
|
|
(107
|
)
|
|
(8,537
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(19,840
|
)
|
|
(831
|
)
|
|
(20,671
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
|
|
$
|
5,919
|
|
$
|
1,201
|
|
$
|
7,120
|
|
MTM
Risk Management Contract Net Assets
Three
Month Ended March 31, 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
|
|
|
30
|
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
16
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired
Option
Contracts Entered During the Period
|
|
|
(233
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
43
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(3,098
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(7,226
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
5,919
|
|
Net
Cash Flow Hedge Contracts
|
|
|
1,201
|
|
Total
MTM Risk Management Contract Net Assets at March 31,
2006
|
|
$
|
7,120
|
|
(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)
|
“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
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 March 31, 2006
(in
thousands)
|
|
Remainder
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
After
2010
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
1,376
|
|
$
|
324
|
|
$
|
144
|
|
$
|
(11
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
1,833
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
342
|
|
|
720
|
|
|
1,116
|
|
|
936
|
|
|
-
|
|
|
-
|
|
|
3,114
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(576
|
)
|
|
17
|
|
|
38
|
|
|
240
|
|
|
786
|
|
|
467
|
|
|
972
|
|
Total
|
|
$
|
1,142
|
|
$
|
1,061
|
|
$
|
1,298
|
|
$
|
1,165
|
|
$
|
786
|
|
$
|
467
|
|
$
|
5,919
|
|
(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 March 31, 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
Three
Months Ended March 31, 2006
(in
thousands)
|
|
Power
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2005
|
|
$
|
(736
|
)
|
$
|
(5,116
|
)
|
$
|
(5,852
|
)
|
Changes
in Fair Value
|
|
|
1,449
|
|
|
-
|
|
|
1,449
|
|
Reclassifications
from AOCI to Net Income for Cash
Flow Hedges Settled
|
|
|
144
|
|
|
135
|
|
|
279
|
|
Ending
Balance in AOCI March 31, 2006
|
|
$
|
857
|
|
$
|
(4,981
|
)
|
$
|
(4,124
|
)
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $282 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 March 31, 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:
Three
Months Ended
March
31, 2006
|
|
|
|
|
Twelve
Months Ended
December
31, 2005
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$109
|
|
$256
|
|
$138
|
|
$68
|
|
|
|
|
$363
|
|
$604
|
|
$287
|
|
$104
|
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 $27 million and $31 million at March
31, 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 Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
293,993
|
|
$
|
229,808
|
|
Sales
to AEP Affiliates
|
|
|
10,765
|
|
|
17,122
|
|
Other
|
|
|
374
|
|
|
281
|
|
TOTAL
|
|
|
305,132
|
|
|
247,211
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables for Electric Generation
|
|
|
90,661
|
|
|
90,418
|
|
Purchased
Electricity for Resale
|
|
|
29,218
|
|
|
13,380
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
23,337
|
|
|
5,864
|
|
Other
Operation
|
|
|
49,783
|
|
|
44,615
|
|
Maintenance
|
|
|
24,657
|
|
|
15,715
|
|
Depreciation
and Amortization
|
|
|
32,534
|
|
|
32,393
|
|
Taxes
Other Than Income Taxes
|
|
|
15,982
|
|
|
15,663
|
|
TOTAL
|
|
|
266,172
|
|
|
218,048
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
38,960
|
|
|
29,163
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
543
|
|
|
455
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
185
|
|
|
649
|
|
Interest
Expense
|
|
|
(12,771
|
)
|
|
(12,780
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES AND MINORITY INTEREST
EXPENSE
|
|
|
26,917
|
|
|
17,487
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
8,823
|
|
|
4,396
|
|
Minority
Interest Expense
|
|
|
222
|
|
|
886
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
17,872
|
|
|
12,205
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
57
|
|
|
57
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
17,815
|
|
$
|
12,148
|
|
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 Three Months Ended March 31, 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
|
|
|
|
|
|
|
|
|
(12,500
|
)
|
|
|
|
|
(12,500
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(57
|
)
|
|
|
|
|
(57
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
756,061
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $824
|
|
|
|
|
|
|
|
|
|
|
|
(1,529
|
)
|
|
(1,529
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
12,205
|
|
|
|
|
|
12,205
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2005
|
|
$
|
135,660
|
|
$
|
245,003
|
|
$
|
388,783
|
|
$
|
(2,709
|
)
|
$
|
766,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2005
|
|
$
|
135,660
|
|
$
|
245,003
|
|
$
|
407,844
|
|
$
|
(6,129
|
)
|
$
|
782,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(10,000
|
)
|
|
|
|
|
(10,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(57
|
)
|
|
|
|
|
(57
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
772,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net
of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $930
|
|
|
|
|
|
|
|
|
|
|
|
1,728
|
|
|
1,728
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
17,872
|
|
|
|
|
|
17,872
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2006
|
|
$
|
135,660
|
|
$
|
245,003
|
|
$
|
415,659
|
|
$
|
(4,401
|
)
|
$
|
791,921
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2006 and December 31, 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
2,549
|
|
$
|
3,049
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
44,030
|
|
|
47,515
|
|
Affiliated
Companies
|
|
|
27,060
|
|
|
49,226
|
|
Miscellaneous
|
|
|
6,721
|
|
|
7,984
|
|
Allowance
for Uncollectible Accounts
|
|
|
(482
|
)
|
|
(548
|
)
|
Total
Accounts Receivable
|
|
|
77,329
|
|
|
104,177
|
|
Fuel
|
|
|
55,627
|
|
|
40,333
|
|
Materials
and Supplies
|
|
|
37,048
|
|
|
34,821
|
|
Risk
Management Assets
|
|
|
14,701
|
|
|
47,319
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
32,990
|
|
|
51,387
|
|
Prepayments
and Other
|
|
|
23,330
|
|
|
34,010
|
|
TOTAL
|
|
|
243,574
|
|
|
315,096
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
1,660,255
|
|
|
1,660,392
|
|
Transmission
|
|
|
649,066
|
|
|
645,297
|
|
Distribution
|
|
|
1,167,991
|
|
|
1,153,026
|
|
Other
|
|
|
445,320
|
|
|
443,749
|
|
Construction
Work in Progress
|
|
|
119,090
|
|
|
104,175
|
|
Total
|
|
|
4,041,722
|
|
|
4,006,639
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,782,450
|
|
|
1,776,216
|
|
TOTAL
- NET
|
|
|
2,259,272
|
|
|
2,230,423
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
72,372
|
|
|
81,776
|
|
Long-term
Risk Management Assets
|
|
|
13,090
|
|
|
39,796
|
|
Employee
Benefits and Pension Assets
|
|
|
82,165
|
|
|
83,330
|
|
Deferred
Charges and Other
|
|
|
74,933
|
|
|
46,926
|
|
TOTAL
|
|
|
242,560
|
|
|
251,828
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
2,745,406
|
|
$
|
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
March
31, 2006 and December 31, 2005
(Unaudited)
|
|
2006
|
|
2005
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
49,198
|
|
$
|
28,210
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
59,922
|
|
|
71,138
|
|
Affiliated
Companies
|
|
|
51,510
|
|
|
53,019
|
|
Short-term
Debt - Nonaffiliated
|
|
|
5,788
|
|
|
1,394
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
19,693
|
|
|
15,755
|
|
Risk
Management Liabilities
|
|
|
12,134
|
|
|
45,098
|
|
Customer
Deposits
|
|
|
34,987
|
|
|
50,848
|
|
Accrued
Taxes
|
|
|
88,037
|
|
|
42,799
|
|
Other
|
|
|
58,000
|
|
|
82,699
|
|
TOTAL
|
|
|
379,269
|
|
|
390,960
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
672,476
|
|
|
678,886
|
|
Long-term
Debt - Affiliated
|
|
|
50,000
|
|
|
50,000
|
|
Long-term
Risk Management Liabilities
|
|
|
8,537
|
|
|
27,083
|
|
Deferred
Income Taxes
|
|
|
402,767
|
|
|
409,513
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
306,120
|
|
|
320,066
|
|
Deferred
Credits and Other
|
|
|
128,101
|
|
|
131,477
|
|
TOTAL
|
|
|
1,568,001
|
|
|
1,617,025
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
1,947,270
|
|
|
2,007,985
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
1,515
|
|
|
2,284
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
4,700
|
|
|
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
|
|
|
415,659
|
|
|
407,844
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(4,401
|
)
|
|
(6,129
|
)
|
TOTAL
|
|
|
791,921
|
|
|
782,378
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
2,745,406
|
|
$
|
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 Three Months Ended March 31, 2006 and 2005
(in
thousands)
(Unaudited)
|
|
2006
|
|
2005
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
17,872
|
|
$
|
12,205
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
32,534
|
|
|
32,393
|
|
Deferred
Income Taxes
|
|
|
(9,101
|
)
|
|
(4,312
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
10,468
|
|
|
12,419
|
|
Deferred
Property Taxes
|
|
|
(28,997
|
)
|
|
(28,570
|
)
|
Change
in Other Noncurrent Assets
|
|
|
9,541
|
|
|
3,552
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(19,121
|
)
|
|
(10,308
|
)
|
Changes
in Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
26,848
|
|
|
14,582
|
|
Fuel,
Materials and Supplies
|
|
|
(17,521
|
)
|
|
2,427
|
|
Accounts
Payable
|
|
|
(15,304
|
)
|
|
(6,021
|
)
|
Accrued
Taxes, Net
|
|
|
45,238
|
|
|
16,116
|
|
Customer
Deposits
|
|
|
(15,861
|
)
|
|
(866
|
)
|
Over/Under
Fuel Recovery, Net
|
|
|
15,216
|
|
|
8,451
|
|
Other
Current Assets
|
|
|
10,736
|
|
|
4,849
|
|
Other
Current Liabilities
|
|
|
(21,255
|
)
|
|
(1,960
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
41,293
|
|
|
54,957
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(54,238
|
)
|
|
(33,931
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
(928
|
)
|
Other
|
|
|
(56
|
)
|
|
108
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(54,294
|
)
|
|
(34,751
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Short-term Debt, Net - Nonaffiliated
|
|
|
4,394
|
|
|
-
|
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
(2,457
|
)
|
|
(2,457
|
)
|
Change
in Advances from Affiliates, Net
|
|
|
20,988
|
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(367
|
)
|
|
(315
|
)
|
Dividends
Paid on Common Stock
|
|
|
(10,000
|
)
|
|
(12,500
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(57
|
)
|
|
(57
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
12,501
|
|
|
(15,329
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(500
|
)
|
|
4,877
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
3,049
|
|
|
3,715
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
2,549
|
|
$
|
8,592
|
|
SUPPLEMENTAL
DISCLOSURE:
|
Cash
paid for interest net of capitalized amounts was $11,892,000
and
$12,304,000 and for income taxes
net of refunds was
$1,282,000 and $22,257,000 in 2006 and 2005, respectively. Noncash
capital
lease acquisitions were $3,412,000 and $1,329,000 in 2006 and
2005,
respectively. Noncash Construction Expenditures included in Accounts
Payable of $12,800,000 and $4,700,000 were outstanding as of
March 31,
2006 and 2005, respectively.
|
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
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
10
|
Financing
Activities
|
Note
11
|
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, 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.
|
Assets
Held for Sale
|
TCC
|
9.
|
Benefit
Plans
|
APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
10.
|
Business
Segments
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
11.
|
Financing
Activities
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC,
TNC
|
1. SIGNIFICANT
ACCOUNTING MATTERS
General
The
accompanying unaudited interim financial statements should be read in
conjunction with the 2005 Annual Report as incorporated in and filed with
the
2005 Form 10-K.
In
the
opinion of management, the unaudited interim financial statements reflect
all
normal and recurring accruals and adjustments which are necessary for a fair
presentation of the results of operations for interim periods.
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. Accumulated Other Comprehensive Income
(Loss) for Registrant Subsidiaries as of March 31, 2006 and December 31,
2005 is
shown in the following table.
|
|
March
31,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
Components
|
|
|
|
|
|
Cash
Flow Hedges:
|
|
|
|
|
|
APCo
|
|
$
|
(3,153
|
)
|
$
|
(16,421
|
)
|
CSPCo
|
|
|
3,182
|
|
|
(859
|
)
|
I&M
|
|
|
740
|
|
|
(3,467
|
)
|
KPCo
|
|
|
1,427
|
|
|
(194
|
)
|
OPCo
|
|
|
6,931
|
|
|
755
|
|
PSO
|
|
|
279
|
|
|
(1,112
|
)
|
SWEPCo
|
|
|
(4,124
|
)
|
|
(5,852
|
)
|
TCC
|
|
|
38
|
|
|
(224
|
)
|
TNC
|
|
|
78
|
|
|
(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
|
)
|
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
March
31,
|
|
Company
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
APCo
|
|
$
|
21,974
|
|
$
|
16,952
|
|
CSPCo
|
|
|
5,665
|
|
|
4,594
|
|
I&M
|
|
|
8,552
|
|
|
6,113
|
|
OPCo
|
|
|
18,630
|
|
|
14,963
|
|
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. The purchase
of Sweeny power and its sale to nonaffiliates are shared among the AEP West
companies under the CSW Operating Agreement. See Note 17 of the 2005 Annual
Report for a discussion of the CSW Operating Agreement. The purchases from
Sweeny were:
|
|
Three
Months Ended
March
31,
|
|
Company
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
PSO
|
|
$
|
11,693
|
|
$
|
13,297
|
|
SWEPCo
|
|
|
17,547
|
|
|
7,494
|
|
TCC
|
|
|
582
|
|
|
2,072
|
|
TNC
|
|
|
3,831
|
|
|
5,652
|
|
Reclassifications
Certain
prior period financial statement items have been reclassified to conform
to
current period presentation.
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.
These
revisions had no impact on our previously reported results of operations,
financial conditions or changes in shareholders’ equity.
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 that we have 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 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 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 months ended March 31, 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
156 “Accounting for Servicing of Financial Assets - An Amendment of FASB
Statement No. 140” (SFAS 156)
In
March
2006, the FASB issued SFAS 156. SFAS 156 requires an entity to recognize
a
servicing asset or servicing liability each time it undertakes an obligation
to
service a financial asset by entering into a servicing contract in certain
situations and requires all separately recognized servicing assets and servicing
liabilities to be initially measured at fair value, if practicable. SFAS
156
also requires separate presentation of servicing assets and servicing
liabilities subsequently measured at fair value in the statement of financial
position and additional disclosures for all separately recognized servicing
assets and servicing liabilities. The requirements for recognition and initial
measurement of servicing assets and servicing liabilities should be applied
prospectively to all transactions after the effective date of this statement.
This statement will be effective on January 1, 2007. Management has not
completed the process of determining the effect of this statement 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 accounting
for uncertain tax positions, fair value measurements, business combinations,
revenue recognition, pension and postretirement benefit plans, liabilities
and
equity, 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 proceedings
that are not expected to adversely affect future results of operations and
cash
flows are not included in this report. The following sections discuss current
activities and update the 2005 Annual Report.
APCo
Virginia Environmental and Reliability Costs - Affecting APCo
The
Virginia Electric Restructuring Act 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 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 March 31, 2006, APCo deferred
$26
million of incurred E&R costs.
In
January 2006, the Virginia SCC staff proposed that APCo recover current,
rather
than past, incremental E&R costs in its electric rates at an ongoing level
of $20 million. 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 established as a regulatory
asset. Management believes the staff’s position is contrary to the statute and
an October 2005 Virginia SCC order, which denied APCo’s original request to
recover projected costs in favor of the Virginia SCC’s interpretation that the
law only permits recovery of actual incurred incremental E&R costs that the
commission found prudent.
Hearings
concluded in March 2006. At the hearings, the staff amended its testimony
to
recommend a $24 million increase in APCo’s ongoing rates. If the Virginia SCC
reverses its position and adopts the staff’s recommendation or denies recovery
of any of APCo’s deferred E&R costs, APCo’s future results of operations and
cash flows could be adversely impacted.
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 an equity return.
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. This proposed off-system sales rate credit of $27 million partially
offsets the $225 million requested increase in base rates for a net increase
in
revenues of $198 million. APCo requested that the new rates be implemented
on an
interim basis beginning in the June 2006 customer billings. We are 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
April
2006, APCo and WPCo reached agreement with the WVPSC staff and intervenors
in
the West Virginia rate case filed in 2005. The parties filed a settlement
agreement with the WVPSC, providing for an initial overall increase in APCo’s
rates of $40 million effective July 28, 2006. The initial annual increase
in
rates is comprised of :
·
|
An
Expanded Net Energy Cost (ENEC) increase of $50 million for fuel
and
purchased power expenses;
|
·
|
A
$21 million special construction surcharge providing recovery of
the costs
of the Wyoming-Jacksons Ferry 765 kV line and scrubbers to
date;
|
·
|
A
general base rate reduction of $16 million of which a portion relates
to a
reduction in depreciation expense which affects cash flows but
not
earnings; and
|
·
|
A
$15 million credit for prior over-recoveries of ENEC costs, currently
recorded in regulatory liabilities on the Condensed Consolidated
Balance
Sheets. Therefore, this item impacts cash flows but has no effect
on
earnings.
|
In
addition, the agreement provides a mechanism that allows APCo to adjust its
rates annually for the timely recovery of the ongoing investments in scrubbers
at its Mountaineer and John Amos power plants. The estimated future annual
increases based on the level of incremental investment in the scrubbers as
proposed in the settlement, are projected to result in a $32 million increase
in
revenues effective July 1, 2007, a $13 million increase in revenues effective
July 1, 2008 and a $16 million increase in revenues effective July 1, 2009.
The
settlement further provides for the reinstatement of ENEC proceedings and
its
related annual rate adjustment mechanism for changes in fuel and purchased
power
costs. Although the agreement is comprehensive in all respects, one issue
regarding the rates for a special contract industrial customer remains
unresolved. The WVPSC ordered legal briefs to be filed by May 4, 2006 with
responses to be filed by May 15, 2006. At this time, the WVPSC has not approved
the settlement agreement and therefore, management is unable to predict the
ultimate effect of this filing on future revenues and cash flows.
I&M
Depreciation Study Filing- Affecting I&M
In
December 2005, I&M filed a petition with the IURC, seeking authorization to
revise the book depreciation rates applicable to its electric utility plant
in
service. 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 Nuclear Plant licenses for Units 1 and 2 and
an
extension of the service life of the Tanners Creek coal-fired generating
units.
This petition is not a request for a change in customers’ electric service
rates. Intervenors filed testimony in March 2006 and I&M filed its rebuttal
testimony in April 2006.
Hearings
are scheduled for May 2006. As
proposed by I&M, the
book
depreciation expense reduction would increase its earnings, but would not
impact
cash flows. If approved by the IURC, I&M will currently adjust its book
depreciation expense from the approved effective date forward. Management
is
unable to predict the outcome of this proceeding.
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 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 for AFUDC purposes.
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 reallocation of purchased power costs over three
years. 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. In February 2006, the OCC staff filed a report regarding
$9
million of the reallocation assigned to wholesale customers. In that report,
the
OCC staff concluded that the reallocation assigned to wholesale customers
has
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. In September 2005, the United States District
Court for the Western District of Texas issued an order in a TNC 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 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 vigorously. 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
of
these Oklahoma fuel clause proceedings and future FERC proceedings, if any,
on
the AEP West companies’ and AEP East companies’ future results of operations,
cash flows and financial condition.
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 has 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
that they will not further pursue the matter.
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 on July 28,
2005,
the Texas Court of Appeals reversed the District Court. The cities are appealing
the appeals court decision to the Texas Supreme Court. 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 the PUCT were to reverse
its
decision and order refunds of PTB revenues, it could adversely impact TCC’s and
TNC’s results of operations and cash flows.
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 first quarter of 2006 and
2005.
The
AEP
East companies’ deferred unamortized RTO formation/integration costs were as
follows:
|
|
March
31, 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
|
|
$
|
4.0
|
|
$
|
4.8
|
|
$
|
4.1
|
|
$
|
4.9
|
|
CSPCo
|
|
|
1.6
|
|
|
1.9
|
|
|
1.7
|
|
|
1.9
|
|
I&M
|
|
|
3.1
|
|
|
3.5
|
|
|
3.2
|
|
|
3.7
|
|
KPCo
|
|
|
1.0
|
|
|
1.1
|
|
|
1.0
|
|
|
1.1
|
|
OPCo
|
|
|
4.5
|
|
|
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 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.
In
2005,
the FERC denied a request AEP jointly filed with two other utilities to recover
deferred PJM-billed integration costs from all load-serving entities in the
PJM
RTO zone over a ten-year period. Instead, the FERC ordered the companies
to make
a compliance filing to recover the PJM-billed integration costs solely from
the
zones of the requesting companies. Subsequently, the FERC approved the
compliance rate, and PJM began charging the rate to load serving entities
in the
AEP zone (and the other companies’ zones), including the AEP East companies on
behalf of the load they serve in the AEP zone (about 85% of the total load
in
the AEP zone). In June 2005, AEP filed a request for rehearing. In October
2005,
the FERC granted AEP’s rehearing request and set the following two issues for
settlement discussions and, if necessary, for hearing: (i) whether the PJM
OATT
is unjust and unreasonable without PJM region-wide recovery of PJM-billed
integration costs and (ii) a determination of a just and reasonable carrying
charge rate on the deferred PJM-billed integration costs. In April 2006,
a
settlement was filed with the FERC that allows recovery of deferred PJM-billed
integration costs from the PJM region over ten years. In addition, the
settlement reduced the return on equity component included in the AEP East
companies’ carrying charge rates to 10.5%, which will have an immaterial impact
on their future results of operations.
CSPCo,
OPCo and KPCo recover the amortization of RTO formation/integration costs
billed. APCo has not commenced recovery in West Virginia (where APCo filed
a
settlement agreement in its base rate case with the WVPSC that included the
recovery of its amortization of these costs) or Virginia (where APCo filed
a base rate case which includes recovery of these costs). I&M has not
commenced recovery in Indiana where it is subject to a rate cap until June
30,
2007.
Until
APCo and I&M can adjust their retail rates to recover the amortization of
both RTO-related deferred costs, their results of operations and cash flows
will
be adversely affected by the amortizations. If the Virginia, West Virginia
or
Indiana commissions disallow recovery of any portion of the billed amortization
of deferred RTO formation/integration costs and no appeal is ultimately
successful, it would have an adverse impact on APCo’s or I&M’s future
results of operations and cash flows.
Transmission
Rate Proceedings at the FERC - Affecting APCo, CSPCo, I&M, KPCo and
OPCo
SECA
Revenue
In
accordance with FERC orders, the AEP East companies collected SECA rates
to
mitigate lost through-and-out transmission service (T&O) revenues through
March 31, 2006, when SECA rates expired. The FERC set SECA rate issues for
hearing and indicated that the SECA rate revenues are subject to refund or
surcharge. Intervenors in the SECA proceeding are objecting to the SECA rates
and the method of determining those rates. The SECA hearings are scheduled
to
begin in early May 2006. At this time, management is unable to determine
the
outcome of the FERC’s SECA rate proceeding and if it will impact the AEP East
companies’ future results of operations and cash flows.
The
AEP
East companies recognized net SECA revenues as follows:
|
|
Three
Months Ended
March
31,
|
|
Total
Net SECA Revenues
Through
|
|
|
|
2006
|
|
2005
|
|
March
2006
|
|
|
|
(in
millions)
|
|
APCo
|
|
$
|
11.0
|
|
$
|
8.6
|
|
$
|
55.5
|
|
CSPCo
|
|
|
6.5
|
|
|
4.4
|
|
|
30.8
|
|
I&M
|
|
|
6.7
|
|
|
4.9
|
|
|
32.7
|
|
KPCo
|
|
|
2.7
|
|
|
2.0
|
|
|
13.2
|
|
OPCo
|
|
|
8.6
|
|
|
6.1
|
|
|
42.2
|
|
AEP
East Transmission Revenue Requirement and Rates
In
December 2005, the FERC approved an uncontested settlement allowing increases
to
the AEP East companies’ wholesale transmission rates in three steps: first,
beginning November 1, 2005, second, beginning April 1, 2006 when the SECA
revenues were eliminated and third, on the later of August 1, 2006 or the
first
day of the month following the date when APCO’s Wyoming-Jacksons Ferry
transmission line enters service, currently expected in June 2006.
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,
among others, for the regional transmission service provided with their owned
extra-high-voltage facilities that benefit 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. Under AEP’s proposed Highway/Byway rate design, the cost of all
transmission facilities in the PJM region operated at a voltage of 345 kV
or
higher would be included in a “Highway” rate that all load serving entities
(LSEs) would pay based on peak demand. The cost of transmission facilities
operating at lower voltages would be collected in the zones where those costs
are presently charged under PJM’s rate design. In a competing Highway/Byway
proposal, a group of LSEs proposed rates that would include 500 kV and higher
existing facilities and some facilities at lower voltages in the Highway
rate.
Another proposal uses facilities 200 kV or higher in the Highway rate. These
alternative Highway/Byway proposals are being challenged by a majority of
transmission owners in the PJM region who favor continuation of the PJM rate
design. In January 2006, the FERC staff issued testimony and exhibits supporting
a PJM-wide flat rate or “Postage Stamp” type of rate design. Hearings were held
in April 2006.
The
AEP/AP Highway/Byway design would result in incremental net revenues of
approximately $125 million per year for the transmission-owning AEP East
companies. The competing Highway/Byway proposals filed by others would also
produce incremental net revenues to the AEP East transmission-owning companies,
but at a much lower level. The staff rate design would produce slightly more
net
revenue for the AEP East companies than the original AEP/AP proposal. Management
cannot at this time estimate the outcome of the proceeding; however, adoption
of
any of the new proposals would have a positive effect on the AEP East companies’
revenues and results of operations, compared to the continuation of the PJM
rates that went into effect on April 1, 2006 when the SECA rates
expired.
As
of
March 31, 2006, SECA transition rates did not 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 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 expected shortfall. Full mitigation of the effects of eliminated T&O
revenues and the less favorable terminated SECA revenues will require cost
recovery through retail rate proceedings. The status of the retail rate
proceedings are as follows:
·
|
In
Kentucky, KPCo settled a rate case, which provides for the recovery
of the
transmission revenue shortfall.
|
·
|
APCo
filed a settlement agreement in West Virginia, which included recovery
of
the lost T&O/SECA transmission revenues.
|
·
|
A
pending rate request filed in February 2006 in Ohio addresses the
significant reduction in FERC transmission revenues.
|
·
|
In
Virginia, APCo filed a request for revised rates,
which includes recovery of the lost T&O/SECA
transmission revenues.
|
·
|
In
Indiana, I&M is precluded by a rate cap from raising its rates until
July 1, 2007.
|
Management
is unable to predict whether the FERC will approve a regional rate to mitigate
the loss of T&O/SECA revenues, or if not, when, and if, the effect of the
loss of T&O/SECA transmission revenues will be recoverable on a timely basis
in all of the AEP East state retail jurisdictions and from wholesale LSEs
within
the PJM region.
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, or the FERC’s review of previously collected SECA
rates results in a refund to customers.
Allocation
Agreement between AEP East companies and AEP West companies - 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 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 SWEPCo. 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 and cash flows will depend upon
the
level of future margins by region and the status of cost recovery mechanisms
by
state.
4. CUSTOMER
CHOICE AND INDUSTRY RESTRUCTURING
With
the
passage of restructuring legislation, six of AEP’s twelve electric utility
companies (CSPCo, I&M, APCo, OPCo, TCC and TNC) are in various stages of
transitioning to customer choice and/or market pricing for the supply of
electricity in four of the eleven state retail jurisdictions (Ohio, Michigan,
Virginia and Texas) in which the AEP electric utility companies operate.
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
The
PUCT
issued an order in TCC’s True-up Proceeding in February 2006, which determined
that TCC’s true-up regulatory asset was $1.475 billion, which included carrying
costs through September 2005. An order on rehearing was issued by the PUCT
in
April 2006, which made minor changes to, but otherwise affirmed, the February
2006 order. TCC expects to appeal, seeking additional recovery consistent
with
the Texas Restructuring Legislation and related rules. Other parties may
appeal
the PUCT’s order claiming it permits TCC to over-recover its stranded
costs.
TCC
Securitization Proceeding
TCC
filed
an application in March 2006 requesting to securitize $1.8 billion of net
stranded generation plant costs and related carrying costs to September 1,
2006.
The $1.8 billion does not include TCC’s other true-up items, which are partially
offsetting in nature. These obligations total $491 million and would be payable
through a CTC over a period determined by the PUCT. See “CTC Proceeding for
Other True-up Items” section of this note. Intervenors and the PUCT staff filed
testimony in April 2006. Hearings are scheduled for May. It is possible that
the
PUCT could reduce the securitization amount by all or some portion of the
negative other true-up items. If that occurs, a negative impact on the timing
of
cash flows could result. Cash flows from securitization would be adversely
impacted if the PUCT reduces TCC’s computation of the amount to be
securitized.
The
PUCT
has not addressed the allocation of stranded costs to TCC’s wholesale
jurisdiction. TCC estimates the amount allocated to wholesale to be less
than $1
million, while intervenors and PUCT staff filed testimony recommending that
$77
million of stranded costs be allocated to TCC’s wholesale jurisdiction. TCC
cannot predict the ultimate amount the PUCT will allocate to the wholesale
jurisdiction that TCC will not be able to securitize or recover.
Consistent
with certain prior securitization determinations, the PUCT may deduct the
cost-of-money benefit of accumulated deferred federal income taxes (ADFIT)
from
the securitization request. Then, the future cost-of-money benefit would
be
transferred to a separate regulatory asset recoverable in normal delivery
rates
outside of the securitization process, which would affect the timing of cash
recovery. TCC estimates the total cost-of-money benefit to be $328 million,
which TCC plans to include in its estimated CTC request. Intervenors filed
testimony recommending an increase in this amount, along with the retrospective
ADFIT amounts, by as much as $175 million.
In
addition, the intervenors raised three issues totaling $138 million which
were
addressed by the PUCT in prior proceedings - the appropriate interest rate
for
both stranded cost and deferred fuel and the treatment of excess earnings
refunds. Other issues raised by the intervenors dealt with the amounts to
be
securitized versus refunded to customers through the CTC, customer class
allocation issues and debt defeasance strategies.
The
difference between the recorded securitizable true-up regulatory asset of
$1.5
billion at March 31, 2006 and TCC’s securitization request of $1.8 billion is
detailed in the table below:
|
|
(in
millions)
|
|
Stranded
Generation Plant Costs
|
|
$
|
969
|
|
Net
Generation-related Regulatory Asset
|
|
|
249
|
|
Excess
Earnings
|
|
|
(49
|
)
|
Recorded
Securitizable Net Stranded Generation Plant Costs
|
|
|
1,169
|
|
Recorded
Debt Carrying Costs on Recorded Net Stranded Generation Plant
Costs
|
|
|
284
|
|
Recorded
Securitizable True-up Regulatory Asset
|
|
|
1,453
|
|
Unrecorded
But Recoverable Equity Carrying Costs
|
|
|
212
|
|
Unrecorded
Estimated April 2006 - August 2006 Debt Carrying Costs
|
|
|
40
|
|
Unrecorded
Securitization Issuance Costs
|
|
|
24
|
|
Unrecorded
Excess Earnings, Related Return and Other
|
|
|
75
|
|
Securitization
Request
|
|
$
|
1,804
|
|
Deferred
Investment Tax Credits and Excess Deferred Federal Income
Taxes
In
TCC’s
true-up order, the PUCT reduced net stranded generation plant costs by $51
million related to the present value of accumulated deferred investment tax
credits (ADITC) and by $10 million related to excess deferred federal income
taxes (EDFIT) associated with TCC’s generating assets. TCC testified that the
sharing of these tax benefits with customers may be a violation of the Internal
Revenue Code’s normalization provisions. The federal tax statutes require public
utilities to “normalize” or synchronize the tax benefits derived from ADITC and
EDFIT with the financial and regulatory life of the regulated plant assets
that
give rise to the benefit. The normalization rules prohibit returning the
benefits to ratepayers faster than the underlying assets are recovered for
rate
purposes. Once these assets are no longer regulated, the normalization
provisions do not permit these benefits to be returned to ratepayers. In
the
true-up order, the PUCT agreed to consider revisiting this issue if the IRS
ruled that the flow-through of ADITC and EDFIT constituted a normalization
violation. 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 final, nonappealable rate order. Although
ADITC and EDFIT are recorded as a liability on TCC’s books, such amounts are not
reflected as a reduction of TCC’s recorded securitizable true-up regulatory
asset in the above reconciliation.
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. On April
21, 2006 the IRS informed TCC that they are ruling against the PUCT treatment
and consider the flow-through of ADITC and EDFIT a normalization
violation.
In
a
motion for rehearing, TCC asked the PUCT to reconsider its treatment of ADITC
and EDFIT in light of the position of the IRS. In its order on rehearing,
the
PUCT declined to change its treatment. The PUCT withdrew the language stating
it
would revisit the issue if their treatment was ruled a normalization violation
by the IRS and replaced it with an additional explanation of the basis for
its
original decision. In a motion for a second rehearing filed April 24, 2006,
TCC
informed the PUCT that the IRS intended to rule adversely on the private
letter
ruling request.
If
a
normalization violation occurs, it could result in the repayment of TCC’s ADITC
on all property, including transmission and distribution, which approximates
$105 million as of March 31, 2006 and also a loss of the accelerated tax
depreciation election in the future. Management intends to continue working
with
the PUCT to avoid a normalization violation that would adversely affect TCC’s
future results of operations and cash flows.
CTC
Proceeding for Other True-up Items
TCC
incurs carrying costs on the net negative other true-up regulatory liability
balances until fully refunded. The principal components of the CTC rate
reduction 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. TCC anticipates
filing to implement a negative CTC (as a rate reduction) for its net other
true-up items in the second quarter of 2006.
The
difference between the components of TCC’s recorded net regulatory liabilities -
other true-up items as of March 31, 2006 and its planned CTC proceeding request
are detailed below:
|
|
(in
millions)
|
|
Wholesale
Capacity Auction True-up
|
|
$
|
61
|
|
Carrying
Costs on Wholesale Capacity Auction True-up
|
|
|
17
|
|
Retail
Clawback
|
|
|
(61
|
)
|
Deferred
Over-recovered Fuel Balance
|
|
|
(177
|
)
|
Recorded
Net Regulatory Liabilities - Other True-up Items
|
|
|
(160
|
)
|
ADFIT
Benefit
|
|
|
(328
|
)
|
Unrecorded
Carrying Costs and Other
|
|
|
(3
|
)
|
Estimated
CTC Request
|
|
$
|
(491
|
)
|
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. TCC has a similar
appeal outstanding and believes that the same ruling should result. The impact
of the favorable Federal District court order, if upheld on appeal, could
result
in reductions to the over-recovered fuel balances of $8 million for TNC and
$14
million for TCC. The PUCT appealed the Federal Court decision to the United
States Court of Appeals for the Fifth Circuit. If the PUCT is unsuccessful
in
the federal court system, it may file a complaint at the FERC to address
the
allocation issue. Management is 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 and is successful, it could result in an adverse effect
on
results of operations and cash flows for the AEP East companies. An unfavorable
FERC ruling may result in a reallocation of off-system sales margins from
AEP
East companies to AEP West companies. 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 from its unbundled cost
of
service rate proceeding. The recorded embedded debt component of the carrying
cost rate is 8.12%. Through March 2006, TCC recorded $301 million of
debt-related carrying costs ($284 million on stranded generation plant costs
impacting the securitization proceeding and $17 million on wholesale capacity
auction true-up impacting the CTC proceeding). The remaining equity component
of
$166 million will be recognized in income as collected. TCC will continue
to
accrue a debt-related carrying cost until its net true-up regulatory asset
is
fully recovered. Equity carrying costs are recognized in income as
collected.
In
January 2006, the PUCT approved publication of a proposed rule that would
reduce
the 11.79% overall carrying cost rate on nonsecuritized true-up amounts to
the
most recently approved weighted average cost of debt, which would be 5.70%
for
TCC. The effective date of the change is proposed to be (i) January 1, 2002
for
utilities that have not received a final true-up order or (ii) the date the
rule
is adopted for utilities that have received a final order. There will be
a
45-day comment period from the date of adoption. TCC received an order in
the
True-up Proceeding in February 2006 and an order on rehearing in April 2006
(which is subject to rehearing). TCC asserted in comments filed in the
rulemaking proceeding that the rule change should not have retroactive
application. However, TCC cannot predict if the rule will be adopted, or
if it
will be adopted in its present prospective form for utilities that have received
their final true-up order. If adopted retroactively, it would have an adverse
effect on future results of operations and cash flows.
Summary
TCC’s
recorded securitizable true-up regulatory asset at March 31, 2006 of $1.5
billion, net of regulatory liabilities - other true-up items of $160 million,
accurately reflects the PUCT’s order in TCC’s True-up Proceeding. TCC performed
a probability of recovery impairment test on its net true-up regulatory asset
taking into account the treatment ordered by the PUCT and determined that
the
projected cash flows from the net transition charges would be more than
sufficient to recover TCC’s recorded net true-up regulatory asset since the
equity portion of the carrying costs are not recorded until collected. As
a
result, TCC has not recorded any additional impairment. Barring any future
disallowances to TCC’s net recoverable true-up regulatory asset in its true-up
or subsequent proceedings, TCC expects to amortize its total net true-up
regulatory asset commensurate with recovery over periods established by the
PUCT
in future securitization and CTC proceedings. If TCC determines in future
securitization and CTC proceedings that it is probable it cannot recover
a
portion of the recorded net true-up regulatory asset and is able to estimate
the
amount of such nonrecovery, it would record a provision for such amount which
could have an adverse effect on its future results of operations, cash flows
and
possibly financial condition. TCC intends to pursue rehearing and appeals
to
vigorously seek relief as necessary in both federal and state court where
it
believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation,
PUCT rulemakings and federal law. It is expected that municipal customers
and
other intervenors will also pursue vigorously court appeals 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,
requested rehearings or court appeals. If municipal customers and other
intervenors succeed in their expected appeals, it could have a material adverse
effect on TCC’s future results of operations, cash flows and financial
condition.
Texas
Restructuring - SPP
In
April
2006, the PUCT proposed a possible delay in 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.
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 the IGCC Plant (see “IGCC Plant” section of this note below). OPCo’s
potential for the 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 the IGCC plant. The RSPs also provide
that the Ohio companies can recover in 2006, 2007 and 2008 estimated 2004
and
2005 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 $8 million for CSPCo and $20 million
for
OPCo in the first quarter of 2006 from all the RSP recoveries less the
amortization of RSP deferrals net of the recognition of equity carrying charges
from 2004 and 2005.
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 Dayton Power & Light Company'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 another Ohio
Supreme Court decision involving First Energy Corporation's Ohio electric
companies, the Court held that the PUCO-approved RSPs for First Energy
Corporation's Ohio Electric Companies did not comply with the statutory
provision regarding the availability of a competitive bid alternative for
customers. The Ohio companies believe their RSPs are factually different
from First Energy Corporation's Ohio electric companies' RSPs and comply
with
the applicable statute. However, if the Ohio Supreme Court reverses the
PUCO’s authorization of the POLR charge, CSPCo and OPCo’s future earnings will
be adversely affected. In addition, if the RSP order were determined on appeal
to be illegal in its entirety under the Ohio Electric Restructuring
Act of 1999, it would have an initial adverse effect on results of operations,
cash flows and possibly financial condition. Although the Ohio companies
believe
that the RSP plan is legal and intend to defend vigorously the PUCO’s order,
management cannot predict the ultimate outcome of the pending
litigation.
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, 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. 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
March 31, 2006, CSPCo and OPCo each deferred $5 million of pre-construction
IGCC
costs.
On
April
10, 2006, the PUCO issued an order finding that the PUCO has the jurisdiction
to
approve the proposed cost recovery and authorizing the Ohio companies to
implement Phase 1 of the cost recovery proposal. The Ohio companies filed
a
tariff to recover Phase 1 pre-construction costs over a twelve-month period.
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.
Transmission
Rate Filing
In
February 2006, the Ohio companies filed a request with the PUCO for a two-step
increase in their transmission rates. In the filing, the first increase would
be
effective April 1, 2006 to reflect their share of the loss of SECA revenues
and
the second increase would be effective the later of August 2006 or the first
day
of the month following the date when AEP’s Wyoming-Jacksons Ferry transmission
line enters service, currently expected to occur on June 30, 2006. The Ohio
companies anticipate, if approved, the filing will result in increased revenues
for CSPCo and OPCo of $32 million and $42 million, respectively, in 2006
and
increasing in 2007 to $46 million and $59 million for CSPCo and OPCo,
respectively. This filing intends to recover the new OATT rates resulting
from
the settlement of the March 2005 filing with the FERC requesting increased
OATT
rates in a three-step increase. In March 2006, the PUCO suspended the effective
date of the new rates to provide its staff additional time to conduct its
review
of the application. In their application, the Ohio companies requested
permission to defer for future recovery their unrecovered transmission costs
as
a result of the loss of SECA revenues starting April 1, 2006 if the PUCO
did not
issue an order in this case in time to implement the increase on April 1,
2006.
If the PUCO does not approve the future recovery of the unrecovered transmission
costs effective April 1, 2006 when the SECA revenues ceased, results of
operations and cash flows will be adversely affected.
Storm
Cost Recovery Filing
In
March
2006, the Ohio companies filed an application with the PUCO to implement
tariff
riders to recover a portion of previously-expensed 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.
PUCO
Staff Report on Service Reliability
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 April
2006, the staff of the PUCO submitted a commission-ordered investigative
report
on the Ohio companies’ compliance with the stipulation agreement. In the report,
the staff asserted that the Ohio companies failed to fulfill all the terms
of
the stipulation agreement. The staff recommended various consequences for
the
PUCO’s consideration, including the potential for civil forfeitures, monthly
payments until the terms of the stipulation agreement have been met and
providing credits to customers. The staff also suggested that the PUCO could
explore possible improvements in the Ohio companies’ management of the
reliability process. Finally, the staff recommended that the Ohio companies
file, in a companion docket, a comprehensive plan to improve their system
reliability. The PUCO ordered the Ohio companies to respond to the staff's
recommendations concerning consequences by May 23, 2006, after which the
PUCO
will determine how to proceed. In the companion docket, the PUCO directed
the Ohio companies to prepare a plan to enhance service reliability. A
timeline for submission of that plan has not been set. The PUCO indicated
that it will set a procedural schedule in the future. Although the
Ohio companies believe that they have substantially met the terms and
expectations of the stipulation agreement, they cannot predict the outcome
of
these proceedings. If the PUCO adopts the staff’s recommendations, the Ohio
companies’ results of operations and cash flows could be adversely affected.
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 $40 million. The agreements provide for the deferral of these
costs
as regulatory assets until the next distribution base rate cases. Through
March
31, 2006, CSPCo incurred $50 million and deferred $26 million and OPCo incurred
$51 million and deferred $27 million of such costs for probable future recovery
in distribution rates. Through March 31, 2006, CSPCo and OPCo have not recorded
$4 million each of equity carrying costs, which are not recognized until
collected. Recovery of these regulatory assets is subject to PUCO review
in
future Ohio filings for new distribution rates. Pursuant to the RSPs, recovery
of these amounts is deferred until the next distribution rate filing to change
rates after December 31, 2008. 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 have 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 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 but no decision has been
issued. A bench trial on remedy issues is scheduled for January
2007.
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 have been 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 have been filed in certain appellate courts,
including a petition to appeal to the U.S. Supreme Court 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 and the Federal EPA filed a petition for rehearing in that case.
The
Federal EPA also recently proposed a rule that would define “emissions
increases” in a way that most of the challenged activities would be excluded
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 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.
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 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 defendant’s 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 has been completed and the case is scheduled to be argued this summer.
Management believes the actions are without merit and intends to defend
vigorously 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. AEP has 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, have emitted NOX,
SO2
and
particulate matter that have 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 vigorously 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 nonregulated merchant power generation facility (Facility)
near
Plaquemine, Louisiana and leased the Facility to AEP. AEP has subleased the
Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated
“qualifying cogeneration facility” for purposes of PURPA.
Dow
uses
a portion of the energy produced by the Facility and sells the excess energy.
OPCo has 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
(expected to be approximately 220 MW through May 31, 2006 and 270 MW
thereafter). 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
United States 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 (i) was suspending performance of
its
obligations under the PPA; (ii) would seek a declaration from the District
Court
that the PPA was terminated; and (iii) would pursue against 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 had breached the contract and awarded damages to OPCo of $123
million plus prejudgment interest. In August 2005, both parties filed motions
with the trial court seeking reconsideration of the judgment. OPCo asked
the
court to modify the judgment to (i) award a termination payment to OPCo under
the terms of the PPA; (ii) grant OPCo’s attorneys’ fees; and (iii) 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. 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 and to the extent
claimed
termination value damages are not fully recovered from TEM.
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 certain wholesale
customers located in Nevada. 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 two Nevada utilities. In 2001, the 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 utilities' complaint, held
that
the markets for future delivery were not dysfunctional, and that the 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 utilities’ request for a rehearing was denied. The 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
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
March 31, 2006, the maximum future payments of the LOCs include $1 million
and
$4 million for I&M and SWEPCo, respectively, each with a maturity of 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 $55
million with maturity dates ranging from July 2006 to February
2012.
As
part
of the process to receive a renewal of a Texas Railroad Commission permit
for
lignite mining, SWEPCo provided 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. At March 31, 2006, the
cost to
reclaim the mine in 2035 is estimated to be approximately $39 million. This
guarantee ends upon depletion of reserves estimated at 2035 plus 6 years
to
complete reclamation.
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 March 31, 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.
Registrant
Subsidiaries are jointly and severally liable for activity conducted by AEPSC
on
behalf of AEP East companies and AEP West companies and for activity conducted
by any Registrant Subsidiary pursuant to the system integration
agreement.
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 March 31, 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
|
|
|
3
|
|
I&M
|
|
|
4
|
|
KPCo
|
|
|
2
|
|
OPCo
|
|
|
6
|
|
PSO
|
|
|
5
|
|
SWEPCo
|
|
|
5
|
|
TCC
|
|
|
6
|
|
TNC
|
|
|
3
|
|
7. COMPANY-WIDE
STAFFING AND BUDGET REVIEW
In
2005,
primarily in the second quarter, the Registrant Subsidiaries recorded severance
benefits expense (primarily in Other Operation) resulting from a company-wide
staffing and budget review. The expense included the allocation of approximately
$19 million of severance benefits associated with AEPSC employees among the
Registrant Subsidiaries. AEGCo has no employees but received allocated
expenses.
Remaining
accruals, reflected primarily in Current Liabilities - Other, ranged from
$8
thousand to $1.1 million as of December 31, 2005. Payments and accrual
adjustments recorded during the first quarter of 2006 were immaterial.
Settlement of the remaining accruals, ranging from $5 thousand to $600 thousand
as of March 31, 2006, are expected by the end of the second quarter of
2006.
8. 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) but
subject to a right of first refusal by the Oklahoma Municipal Power Authority
and the Public Utilities Board of the City of Brownfield (the nonaffiliated
co-owners). By May 2004, TCC received notice from the nonaffiliated co-owners
of
the Oklaunion Power Station, 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.
These agreements were challenged in Dallas County, Texas State District Court
by
Golden Spread. Golden Spread alleges that the Public Utilities Board
of the City of Brownsfield 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 co-owners’
exercise of their rights of first refusal void. The court entered a judgment
in
favor of Golden Spread on October 10, 2005. TCC and the nonaffiliated co-owners
filed an appeal to the Fifth State Court of Appeals in Dallas. The case was
briefed and argued before the court and is awaiting a decision. 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 have been classified as Assets Held for Sale
-
Texas Generation Plants on TCC’s Condensed Consolidated Balance Sheets at March
31, 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 March 31, 2006 and December 31, 2005 are as
follows:
Texas
Plants (TCC)
|
|
March
31, 2006
|
|
December
31, 2005
|
|
Assets:
|
|
(in
millions)
|
|
Other
Current Assets
|
|
$
|
1
|
|
$
|
1
|
|
Property,
Plant and Equipment, Net
|
|
|
43
|
|
|
43
|
|
Total
Assets Held for Sale - Texas Generation Plants
|
|
$
|
44
|
|
$
|
44
|
|
|
|
|
|
|
|
|
|
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 months ended March 31, 2006 and 2005:
|
|
Pension
Plans
|
|
Other
Postretirement
Benefit
Plans
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$
|
24
|
|
$
|
23
|
|
$
|
10
|
|
$
|
11
|
|
Interest
Cost
|
|
|
57
|
|
|
56
|
|
|
25
|
|
|
27
|
|
Expected
Return on Plan Assets
|
|
|
(83
|
)
|
|
(77
|
)
|
|
(23
|
)
|
|
(23
|
)
|
Amortization
of Transition Obligation
|
|
|
-
|
|
|
-
|
|
|
7
|
|
|
7
|
|
Amortization
of Net Actuarial Loss
|
|
|
20
|
|
|
13
|
|
|
5
|
|
|
7
|
|
Net
Periodic Benefit Cost
|
|
$
|
18
|
|
$
|
15
|
|
$
|
24
|
|
$
|
29
|
|
The
following table provides the net periodic benefit cost (credit) for the plans
by
Registrant Subsidiaries for the three months ended March 31, 2006 and
2005:
|
|
Pension
Plans
|
|
Other
Postretirement
Benefit
Plans
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
APCo
|
|
$
|
1,468
|
|
$
|
1,848
|
|
$
|
4,489
|
|
$
|
5,345
|
|
CSPCo
|
|
|
205
|
|
|
534
|
|
|
1,805
|
|
|
2,222
|
|
I&M
|
|
|
2,331
|
|
|
2,365
|
|
|
2,953
|
|
|
3,631
|
|
KPCo
|
|
|
358
|
|
|
376
|
|
|
513
|
|
|
603
|
|
OPCo
|
|
|
826
|
|
|
1,206
|
|
|
3,396
|
|
|
3,827
|
|
PSO
|
|
|
977
|
|
|
72
|
|
|
1,588
|
|
|
1,869
|
|
SWEPCo
|
|
|
1,225
|
|
|
364
|
|
|
1,578
|
|
|
1,837
|
|
TCC
|
|
|
773
|
|
|
(219
|
)
|
|
1,696
|
|
|
2,008
|
|
TNC
|
|
|
325
|
|
|
41
|
|
|
715
|
|
|
877
|
|
10. 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.
11. FINANCING
ACTIVITIES
Long-term
Debt
Long-term
debt and other securities issued, retired and principal payments made during
the
first three 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
|
In
April
2006, APCo issued $250 million, 5.55% senior notes due in 2011 and $250 million,
6.375% senior notes due in 2036. The proceeds were used for general corporate
purposes including funding the construction program, repaying advances from
affiliates and replenishing working capital.
In
April
2006, OPCo incurred obligations of $65 million relating to variable rate
pollution control bonds due in 2036. The proceeds will be used to finance
the
cost of solid waste disposal facilities at the Mitchell Generating
Station.
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
Debt
|
|
|
3
|
|
13.718
|
|
2026
|
OPCo
|
|
Notes
Payable
|
|
|
1,463
|
|
6.81
|
|
2008
|
OPCo
|
|
Notes
Payable
|
|
|
3,250
|
|
6.27
|
|
2009
|
SWEPCo
|
|
Notes
Payable
|
|
|
1,707
|
|
4.47
|
|
2011
|
SWEPCo
|
|
Notes
Payable
|
|
|
750
|
|
Variable
|
|
2008
|
TCC
|
|
Securitization
Bonds
|
|
|
30,641
|
|
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
|
|
|
|
|
|
|
|
|
|
|
Retirements:
|
|
|
|
|
|
|
|
|
|
NONE
|
|
|
|
|
|
|
|
|
|
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 three months
ended March 31, 2006 are described in the following table:
Three
Months Ended March 31, 2006:
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 March 31,
2006
|
|
Authorized
Short-Term Borrowing Limit
|
|
|
|
(in
thousands)
|
|
AEGCo
|
|
$
|
58,209
|
|
$
|
-
|
|
$
|
23,516
|
|
$
|
-
|
|
$
|
(13,317
|
)
|
$
|
125,000
|
|
APCo
|
|
|
283,872
|
|
|
-
|
|
|
201,590
|
|
|
-
|
|
|
(164,192
|
)
|
|
600,000
|
|
CSPCo
|
|
|
48,337
|
|
|
24,779
|
|
|
18,021
|
|
|
14,168
|
|
|
6,867
|
|
|
350,000
|
|
I&M
|
|
|
128,071
|
|
|
-
|
|
|
92,774
|
|
|
-
|
|
|
(49,137
|
)
|
|
500,000
|
|
KPCo
|
|
|
20,659
|
|
|
5,923
|
|
|
9,175
|
|
|
1,583
|
|
|
5,923
|
|
|
200,000
|
|
OPCo
|
|
|
181,450
|
|
|
-
|
|
|
104,183
|
|
|
-
|
|
|
(81,043
|
)
|
|
600,000
|
|
PSO
|
|
|
118,815
|
|
|
-
|
|
|
66,273
|
|
|
-
|
|
|
(118,815
|
)
|
|
300,000
|
|
SWEPCo
|
|
|
58,124
|
|
|
-
|
|
|
37,848
|
|
|
-
|
|
|
(49,198
|
)
|
|
350,000
|
|
TCC
|
|
|
117,429
|
|
|
49,193
|
|
|
87,094
|
|
|
32,347
|
|
|
32,101
|
|
|
600,000
|
|
TNC
|
|
|
14,513
|
|
|
34,574
|
|
|
5,000
|
|
|
13,339
|
|
|
3,046
|
|
|
250,000
|
|
The
maximum and minimum interest rates for funds either borrowed from or loaned
to
the Utility Money Pool for the three months ended March 31, 2006 and 2005
were
4.85% and 4.37% and 2.96% and 1.63%, respectively. The average interest rates
for funds borrowed from and loaned to the Utility Money Pool for the three
months ended March 31, 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
Three Months Ended March 31, 2006
|
|
Average
Interest Rate
for
Funds Borrowed
from
the
Utility
Money Pool
for
Three
Months Ended
March
31, 2005
|
|
Average
Interest Rate
for
Funds Loaned to
the
Utility Money Pool
for
Three Months Ended March 31, 2006
|
|
Average
Interest Rate
for
Funds Loaned to
the
Utility Money Pool
for
Three Months Ended March 31, 2005
|
|
|
|
|
(in
percentage)
|
|
AEGCo
|
|
|
4.57
|
|
2.00
|
|
-
|
|
-
|
|
APCo
|
|
|
4.60
|
|
1.96
|
|
-
|
|
2.15
|
|
CSPCo
|
|
|
4.58
|
|
-
|
|
4.66
|
|
2.10
|
|
I&M
|
|
|
4.59
|
|
2.14
|
|
-
|
|
2.12
|
|
KPCo
|
|
|
4.54
|
|
-
|
|
4.75
|
|
2.15
|
|
OPCo
|
|
|
4.60
|
|
-
|
|
-
|
|
2.14
|
|
PSO
|
|
|
4.63
|
|
2.11
|
|
-
|
|
-
|
|
SWEPCo
|
|
|
4.60
|
|
-
|
|
-
|
|
2.13
|
|
TCC
|
|
|
4.47
|
|
2.27
|
|
4.68
|
|
2.12
|
|
TNC
|
|
|
4.57
|
|
-
|
|
4.54
|
|
2.14
|
|
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 be read in conjunction with this report.
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 Clean Air Act (CAA) to reduce emissions of sulfur dioxide
(SO2),
nitrogen oxide (NOx),
particulate matter (PM), and mercury from fossil fuel-fired power
plants;
|
·
|
Requirements
under the Clean Water Act (CWA) to reduce the impacts of water
intake
structures on aquatic species at certain power plants;
and
|
·
|
Possible
future requirements to reduce carbon dioxide (CO2)
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.
Clean
Air Act Requirements
The
CAA
establishes a comprehensive program to protect and improve the nation’s air
quality, and control mobile and stationary sources of air emissions. The
major
CAA programs affecting power plants are briefly described below. Many of
these
programs are implemented and administered by the states, which can impose
additional or more stringent requirements.
National
Ambient Air Quality Standards:
The CAA
requires the Federal EPA to periodically review the available scientific
data
for six criteria pollutants and establish a concentration level in the ambient
air for those substances that is adequate to protect the public health and
welfare with an extra margin for safety. These concentration levels are known
as
“national ambient air quality standards” or NAAQS.
Each
state identifies those areas within its boundaries that meet the NAAQS
(attainment areas) and those that do not (nonattainment areas). Each state
must
then develop a state implementation plan (SIP) to bring nonattainment areas
into
compliance with the NAAQS and maintain good air quality in attainment areas.
All
SIPs are then submitted to the Federal EPA for approval. If a state fails
to
develop adequate plans, the Federal EPA must develop and implement a plan.
In
addition, as the Federal EPA reviews the NAAQS, the attainment status of
areas
can change, and states may be required to develop new SIPs. The Federal EPA
recently proposed a new PM NAAQS and is conducting periodic reviews for
additional criteria pollutants.
In
1997,
the Federal EPA established new NAAQS that required further reductions in
SO2
and
NOx
emissions. In 2005, the Federal EPA issued a final model federal rule, the
Clean
Air Interstate Rule (CAIR), that assists states developing new SIPs to meet
the
new NAAQS. CAIR reduces regional emissions of SO2
and
NOx
from
power plants in the Eastern U.S. (29 states and the District of Columbia).
CAIR
requires power plants within these states to reduce emissions of SO2
by 50
percent by 2010, and by 65 percent by 2015. NOx
emissions will be subject to additional limits beginning in 2009, and will
be
reduced by a total of 70 percent from current levels by 2015. Reductions
of both
SO2
and
NOx
would be
achieved through a cap-and-trade program. The Federal EPA reconsidered and
affirmed certain aspects of the final CAIR, and the rule has been challenged
in
the courts. States must develop and submit SIPs to implement CAIR by November
2006. Nearly all of the states in which the Registrant Subsidiaries’ power
plants are located will be covered by CAIR. Oklahoma is not affected, while
Texas and Arkansas will be covered only by certain parts of CAIR. A SIP that
complies with CAIR will also establish compliance with other CAA requirements,
including certain visibility goals.
Hazardous
Air Pollutants:
As a
result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous
air pollutant (HAP) emissions from the electric utility sector and submitted
a
report to Congress, identifying mercury emissions from coal-fired power plants
as warranting further study. In March 2005, the Federal EPA issued a final
Clean
Air Mercury Rule (CAMR) setting mercury standards for new coal-fired power
plants and requiring all states to issue new SIPs including mercury requirements
for existing coal-fired power plants. The Federal EPA issued a model federal
rule based on a cap-and-trade program for mercury emissions from existing
coal-fired power plants that would reduce mercury emissions to 38 tons per
year
from all existing plants in 2010, and to 15 tons per year in 2018. The national
cap of 38 tons per year in 2010 is intended to reflect the level of reduction
in
mercury emissions that will be achieved as a result of installing controls
to
reduce SO2
and
NOx
emissions in order to comply with CAIR. The Federal EPA is currently
reconsidering certain aspects of the final CAMR, and the rule has been
challenged in the courts. States must develop and submit their SIPs to implement
CAMR by November 2006.
The
Acid Rain Program:
The 1990
Amendments to the CAA included a cap-and-trade emission reduction program
for
SO2
emissions from power plants, implemented in two phases. By 2000, the program
established a nationwide cap on power plant SO2
emissions of 8.9 million tons per year. The 1990 Amendments also contained
requirements for power plants to reduce NOx
emissions through the use of available combustion controls.
The
success of the SO2
cap-and-trade program encouraged the Federal EPA and the states to use it
as a
model for other emission reduction programs, including CAIR and CAMR. The
Registrant Subsidiaries meet their obligations under the Acid Rain Program
through the installation of controls, use of alternate fuels, and participation
in the emissions allowance markets. CAIR uses the SO2
allowances originally allocated through the Acid Rain Program as the basis
for
its SO2
cap-and-trade system.
Regional
Haze:
The CAA
also establishes visibility goals for certain federally designated areas,
including national parks, and requires states to submit SIPs that will
demonstrate reasonable progress toward preventing impairment and remedying
any
existing impairment of visibility in these areas. This is commonly called
the
“Regional Haze” program. In June 2005, the Federal EPA issued its final Clean
Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit
technology (BART) requirements will be applied to facilities built between
1962
and 1977 that emit more than 250 tons per year of certain pollutants in specific
industrial categories, including power plants. The final rule contains a
demonstration that for power plants subject to CAIR, CAIR will result in
more
visibility improvements than BART would provide. Thus, states are allowed
to
substitute CAIR requirements in their Regional Haze SIPs for controls that
would
otherwise be required by BART. For BART-eligible facilities located in states
not subject to CAIR requirements for SO2
and
NOx,
some
additional controls will be required. The final rule has been challenged
in the
courts.
Estimated
Air Quality Environmental Investments
As
discussed in the 2005 Annual Report, the CAIR and CAMR programs described
above
will require significant additional investments, some of which are estimable.
However, many of the rules described above are the subject of reconsideration
by
the Federal EPA, have been challenged in the courts and have not yet been
incorporated into SIPs. As a result, these rules may be further modified.
Management’s estimates, disclosed in the 2005 Annual Report, are subject to
significant uncertainties, and will be affected by any changes in the outcome
of
several interrelated variables and assumptions, including: the timing of
implementation, required levels of reductions, methods for allocation of
allowances and selected compliance alternatives. In short, management cannot
estimate compliance costs with certainty.
The
Registrant Subsidiaries will seek recovery of expenditures for pollution
control
technologies, replacement or additional generation and associated operating
costs from customers through regulated rates (in regulated jurisdictions).
The
Registrant Subsidiaries should be able to recover these expenditures through
market prices in deregulated jurisdictions. If not, those costs could adversely
affect future results of operations, cash flows and possibly financial
condition.
Potential
Regulation of CO2
Emissions
At
the
Third Conference of the Parties to the United Nations Framework Convention
on
Climate Change held in Kyoto, Japan in December 1997, more than 160 countries,
including the U.S., negotiated a treaty requiring legally-binding reductions
in
emissions of greenhouse gases, chiefly CO2,
which
many scientists believe are contributing to global climate change. The U.S.
signed the Kyoto Protocol in November 1998, but the treaty was not submitted
to
the Senate for its advice and consent. In March 2001, President Bush announced
his opposition to the treaty. During 2004, enough countries ratified the
treaty
for it to become enforceable against the ratifying countries in February
2005.
Several bills have been introduced in Congress seeking regulation of greenhouse
gas emissions, including CO2
emissions from power plants, but none has passed either house of
Congress.
The
Federal EPA stated that it does not have authority under the CAA to regulate
greenhouse gas emissions that may affect global climate trends. This decision
was challenged in the courts and upheld. A petition to appeal to the U.S.
Supreme Court has been filed. While mandatory requirements to reduce
CO2
emissions at our power plants do not appear to be imminent, we participate
in a
number of voluntary programs to monitor, mitigate, and reduce greenhouse
gas
emissions.
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 special interest 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 have been 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 been completed, but no decision
has been issued. A bench trial on remedy issues is scheduled for January
2007.
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 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 also recently proposed a rule
that
would define “emissions increases” in a way that most of the challenged
activities would be excluded 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.
Other
Environmental Concerns
Management
performs environmental reviews and audits on a regular basis for the purpose
of
identifying, evaluating and addressing environmental concerns and issues.
In
addition to the matters discussed above, the Registrant Subsidiaries are
managing other environmental concerns, which are not believed to be material
or
potentially material at this time. If they become significant or if any new
matters arise that could be material, they could have a material adverse
effect
on 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, the trend in the Registrant Subsidiaries’
quarter-over-quarter net income (loss) is not materially different. See Note
2 -
New Accounting Pronouncements in the Condensed Notes to Condensed Financial
Statements of Registrant Subsidiaries for further discussion.
During
the first 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
March 31, 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 first 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. No new risk factors have
been
identified during the quarter ended March 31, 2006.
General
Risks of Our Regulated Operations
Our
request for rate recovery of additional costs may not be approved in
Virginia. (Applies
to AEP and APCo.)
On
July
1, 2005, APCo filed a request with the Virginia SCC seeking approval for
the
recovery of $62 million in incremental costs through June 30, 2006. The $62
million request included incurred and projected costs of environmental controls,
transmission costs (including line construction) and other system reliability
work. In October 2005, the Virginia SCC ruled that it does not have the
authority to approve the recovery of projected costs. In November 2005, APCo
filed supplemental testimony in which it updated the actual costs through
September 2005 and reduced its requested recovery to $21 million. The staff
of
the Virginia SCC made filings to dismiss the transmission system reliability
costs from consideration for recovery, arguing that the FERC, and not the
Virginia SCC, has jurisdiction over the unbundled transmission component
of
APCo's retail rates. Through March 31, 2006, APCo deferred $26 million of
recorded costs that are subject to this proceeding. The staff of the Virginia
SCC issued testimony that would reduce APCo’s recovery of current and future
costs to $20 million. Hearings concluded in March 2006. At the hearings,
the
staff amended its testimony to recommend a $24 million increase in APCo’s
ongoing rates. If the Virginia SCC reverses its decision and adopts the staff’s
recommendation or denies recovery of any of APCo’s deferred costs, it would
adversely impact future results of operations and cash flows.
Our
request for rate recovery of additional costs may not be approved in West
Virginia. (Applies
to AEP and APCo.)
In
August
2005, APCo and WPCo collectively filed an application (amended in January
2006)
with the WVPSC seeking an initial increase in their retail base rates of
approximately $74 million. Most of the requested base rate increase is
attributable to reactivating the currently suspended ENEC mechanism that
provides recovery of power supply costs, including fuel and purchased power,
while the rest is primarily related to recovery of costs associated with
the
Ceredo Generating Station and service reliability improvements. The first
supplemental increase of $9 million, requested to be effective at the same
time
as the base rate change, provides for recovery of the capital costs of the
Wyoming-Jackson's Ferry 765kV line. The remaining proposed supplemental
increases are $44 million, $10 million and $38 million, to be effective on
January 1, 2007, 2008 and 2009, respectively, and provide for recovery of
environmental expenditures. APCo has a regulatory liability of $52 million
of
pre-suspension, previously over-recovered ENEC costs which, along with a
carrying cost, it is proposing to apply in the future to any future
under-recoveries of ENEC costs through the reactivated ENEC mechanism. The
WVPSC
granted a joint motion that requested hearings begin in April 2006, that
new
rates go into effect on July 28, 2006 and that deferral accounting for over-
or
under-recovery of the ENEC begin July 1, 2006. In April 2006, the parties
filed
a settlement agreement with the WVPSC. The WVPSC has not approved the settlement
agreement and therefore, we are unable to predict the ultimate effect of
this
filing on future revenues, results of operations and cash flows.
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.
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 temporary
replacement SECA transition rates beginning in December 2004 and extending
through March 2006. Intervenors objected to this decision and SECA fees of
$174
million were collected subject to refund while FERC considers the issue.
Hearings are scheduled for May 2006.
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.
A rate
request is pending in West Virginia that addresses the reduction in these
transmission revenues. In February 2006, CSPCo and OPCo filed with the PUCO
to
increase their transmission rates to reflect the loss of their share of SECA
revenues.
At this
time, management is unable to predict whether any resultant increase in rates
applicable to AEP’s internal load will be recoverable on a timely basis from
state retail customers.
In
addition to seeking retail rate recovery from the applicable states, AEP
and
another member of PJM have filed an application with the FERC seeking
compensation from other unaffiliated members of PJM for the costs associated
with those members’ use of our respective transmission assets. A
majority of PJM members have filed in opposition to the proposal. Hearings
were
held in April 2006. AEP management cannot at this time estimate the outcome
of
the proceeding.
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 non-regulated 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. If the power agreement is held to be unenforceable,
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 March 31, 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
(a)
|
|
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
|
|
01/01/06
- 01/31/06
|
|
|
-
|
|
$
|
-
|
|
|
-
|
|
$
|
-
|
|
02/01/06
- 02/28/06
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
03/01/06
- 03/31/06
|
|
|
80
|
|
|
78.00
|
|
|
-
|
|
|
-
|
|
Total
|
|
|
80
|
|
$
|
78.00
|
|
|
-
|
|
$
|
-
|
|
(a)
|
TNC
repurchased 80 shares of its 4.40% cumulative preferred stock,
in a
privately-negotiated transaction outside of an announced
program.
|
Item
5. Other
Information
On
April
6, 2006, AEP entered into (i) an Amended and Restated $1.5 billion Credit
Agreement, dated as of April 6, 2006 (the “2010 Credit Agreement”) among AEP, a
group of banks and JPMorgan Chase Bank, N.A., as Administrative Agent, and
(ii)
an Amended and Restated $1.5 billion Credit Agreement, dated as of April
6, 2006
(the “2011 Credit Agreement” and, together the 2010 Credit Agreement, the
“Credit Agreements”) among AEP, a group of banks and Barclays Bank PLC, as
Administrative Agent. The Credit Agreements are available for working capital
and other general corporate purposes of AEP.
AEP
also has the ability to issue letters of credit against the Credit Agreements
in
an amount up to $200 million per Credit Agreement. The 2010 Credit Agreement
expires on March 30, 2010 and the 2011 Credit Agreement expires on April
6,
2011.
Borrowings
under the Credit Agreements are available upon customary terms and conditions
for facilities of this type. AEP also is required to maintain its percentage
of
debt to total capitalization at a level that does not exceed 67.5%.
The
2010
Credit Agreement amends and restates a $1.5 billion credit agreement previously
maturing in March 2010, and the 2011 Credit Agreement amends and restates
a $1
billion credit agreement previously maturing in May 2007.
Item
6. Exhibits
AEP,
PSO, SWEPCo
10(a)
-
Restated and Amended Operating Agreement among PSO, SWEPCo and AEPSC. Issued
on
February 10, 2006, effective May 1, 2006
10(b)
-
Restated and Amended Operating Agreement among PSO, SWEPCo and AEPSC. Issued
on
February 10, 2006, effective May 1, 2006
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:
May
5, 2006