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, 2007
OR
[
]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE
SECURITIES EXCHANGE ACT OF 1934
For
The Transition Period from ____ to ____
Commission
|
|
Registrant,
State of Incorporation,
|
|
I.R.S.
Employer
|
File
Number
|
|
Address
of Principal Executive Offices, and Telephone Number
|
|
Identification
No.
|
|
|
|
|
|
1-3525
|
|
AMERICAN
ELECTRIC POWER COMPANY, INC. (A New York Corporation)
|
|
13-4922640
|
0-18135
|
|
AEP
GENERATING COMPANY (An Ohio Corporation)
|
|
31-1033833
|
0-346
|
|
AEP
TEXAS CENTRAL COMPANY (A Texas Corporation)
|
|
74-0550600
|
0-340
|
|
AEP
TEXAS NORTH COMPANY (A Texas Corporation)
|
|
75-0646790
|
1-3457
|
|
APPALACHIAN
POWER COMPANY (A Virginia Corporation)
|
|
54-0124790
|
1-2680
|
|
COLUMBUS
SOUTHERN POWER COMPANY (An Ohio Corporation)
|
|
31-4154203
|
1-3570
|
|
INDIANA
MICHIGAN POWER COMPANY (An Indiana Corporation)
|
|
35-0410455
|
1-6858
|
|
KENTUCKY
POWER COMPANY (A Kentucky Corporation)
|
|
61-0247775
|
1-6543
|
|
OHIO
POWER COMPANY (An Ohio Corporation)
|
|
31-4271000
|
0-343
|
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)
|
|
73-0410895
|
1-3146
|
|
SOUTHWESTERN
ELECTRIC POWER COMPANY (A Delaware Corporation)
|
|
72-0323455
|
|
|
|
|
|
All
Registrants
|
|
1
Riverside Plaza, Columbus, Ohio 43215-2373
|
|
|
|
|
Telephone
(614) 716-1000
|
|
|
Indicate
by check mark whether the registrants (1) have filed all reports
required
to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934
during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been
subject
to such filing requirements for the past 90 days.
|
Yes
X
|
No
|
Indicate
by check mark whether American Electric Power Company, Inc. is a
large
accelerated filer, an accelerated filer, or a non-accelerated filer.
See
definition of ‘accelerated filer and large accelerated filer’ in Rule
12b-2 of the Exchange Act. (Check One)
|
|
Large
accelerated filer X
Accelerated filer
Non-accelerated
filer
|
Indicate
by check mark whether AEP Generating Company, AEP Texas Central Company,
AEP Texas North Company, Appalachian Power Company, Columbus Southern
Power Company, Indiana Michigan Power Company, Kentucky Power Company,
Ohio Power Company, Public Service Company of Oklahoma and Southwestern
Electric Power Company, are large accelerated filers, accelerated
filers,
or non-accelerated filers. See definition of ‘accelerated filer and large
accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check
One)
|
|
Large
accelerated filer
Accelerated filer
Non-accelerated
filer X
|
|
Indicate
by check mark whether the registrants are shell companies (as defined
in
Rule 12b-2 of the Exchange Act.)
|
Yes
|
No X
|
AEP
Generating Company, AEP Texas Central Company, AEP Texas North Company, Columbus
Southern Power Company, Indiana Michigan 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.
|
|
|
Number
of shares of common stock outstanding of the registrants
at
April
30, 2007
|
|
|
|
|
AEP
Generating Company
|
|
|
1,000
|
|
|
|
($1,000
par value)
|
AEP
Texas Central Company
|
|
|
2,211,678
|
|
|
|
($25
par value)
|
AEP
Texas North Company
|
|
|
5,488,560
|
|
|
|
($25
par value)
|
American
Electric Power Company, Inc.
|
|
|
398,766,908
|
|
|
|
($6.50
par value)
|
Appalachian
Power Company
|
|
|
13,499,500
|
|
|
|
(no
par value)
|
Columbus
Southern Power Company
|
|
|
16,410,426
|
|
|
|
(no
par value)
|
Indiana
Michigan Power Company
|
|
|
1,400,000
|
|
|
|
(no
par value)
|
Kentucky
Power Company
|
|
|
1,009,000
|
|
|
|
($50
par value)
|
Ohio
Power Company
|
|
|
27,952,473
|
|
|
|
(no
par value)
|
Public
Service Company of Oklahoma
|
|
|
9,013,000
|
|
|
|
($15
par value)
|
Southwestern
Electric Power Company
|
|
|
7,536,640
|
|
|
|
($18
par value)
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX
TO QUARTERLY REPORTS ON FORM 10-Q
March
31, 2007
|
|
Glossary
of Terms
|
|
|
|
Forward-Looking
Information
|
|
|
|
Part
I. FINANCIAL INFORMATION
|
|
|
|
|
|
Items
1, 2 and 3 - Financial Statements, Management’s Financial Discussion and
Analysis and Quantitative and Qualitative Disclosures About Risk
Management Activities:
|
|
American
Electric Power Company, Inc. and Subsidiary
Companies:
|
|
|
Management’s
Financial Discussion and Analysis of Results of Operations
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
Condensed
Consolidated Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Consolidated Financial
Statements
|
|
|
|
|
AEP
Generating Company:
|
|
|
Management’s
Narrative Financial Discussion and Analysis
|
|
|
Condensed
Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
AEP
Texas Central Company and Subsidiaries:
|
|
|
Management’s
Narrative Financial Discussion and Analysis
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
Condensed
Consolidated Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
AEP
Texas North Company and Subsidiary:
|
|
|
Management’s
Narrative Financial Discussion and Analysis
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
Condensed
Consolidated Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
Appalachian
Power Company and Subsidiaries:
|
|
|
Management’s
Financial Discussion and Analysis
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
Condensed
Consolidated Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
Columbus
Southern Power Company and Subsidiaries:
|
|
|
Management’s
Narrative Financial Discussion and Analysis
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
Condensed
Consolidated Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
Indiana
Michigan Power Company and Subsidiaries:
|
|
|
Management’s
Narrative Financial Discussion and Analysis
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
Condensed
Consolidated Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
Kentucky
Power Company:
|
|
|
Management’s
Narrative Financial Discussion and Analysis
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
Condensed
Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
Ohio
Power Company Consolidated:
|
|
|
Management’s
Financial Discussion and Analysis
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
Condensed
Consolidated Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
Public
Service Company of Oklahoma:
|
|
|
Management’s
Narrative Financial Discussion and Analysis
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
Condensed
Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
Southwestern
Electric Power Company Consolidated:
|
|
|
Management’s
Financial Discussion and Analysis
|
|
|
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|
Condensed
Consolidated Financial Statements
|
|
|
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
Condensed
Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|
|
|
Combined
Management’s Discussion and Analysis of Registrant
Subsidiaries
|
|
|
|
|
Controls
and Procedures
|
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Part
II. OTHER INFORMATION
|
|
|
|
|
Item
1.
|
Legal
Proceedings
|
|
|
Item
1A.
|
Risk
Factors
|
|
|
Item
2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
|
|
Item
5.
|
Other
Information
|
|
|
Item
6.
|
Exhibits:
|
|
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Exhibit
12
|
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Exhibit
31(a)
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Exhibit
31(b)
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Exhibit
31(c)
|
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Exhibit
31(d)
|
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Exhibit
32(a)
|
|
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Exhibit
32(b)
|
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SIGNATURE
|
|
|
This
combined Form 10-Q is separately filed by American Electric Power
Company,
Inc., AEP Generating Company, AEP Texas Central Company, AEP Texas
North
Company, Appalachian Power Company, Columbus Southern Power Company,
Indiana Michigan Power Company, Kentucky Power Company, Ohio Power
Company, Public Service Company of Oklahoma and Southwestern Electric
Power Company. Information contained herein relating to any individual
registrant is filed by such registrant on its own behalf. Each registrant
makes no representation as to information relating to the other
registrants.
|
When
the following terms and abbreviations appear in the text of this report, they
have the meanings indicated below.
ADITC
|
|
Accumulated
Deferred Investment Tax Credits.
|
AEGCo
|
|
AEP
Generating Company, an AEP electric utility subsidiary.
|
AEP
or Parent
|
|
American
Electric Power Company, Inc.
|
AEP
Consolidated
|
|
AEP
and its majority owned consolidated subsidiaries and consolidated
affiliates.
|
AEP
Credit
|
|
AEP
Credit, Inc., a subsidiary of AEP which factors accounts receivable
and
accrued utility revenues for affiliated domestic electric utility
companies.
|
AEP
East companies
|
|
APCo,
CSPCo, I&M, KPCo and OPCo.
|
AEP
System or the System
|
|
American
Electric Power System, an integrated electric utility system, owned
and
operated by AEP’s electric utility subsidiaries.
|
AEP
System Power Pool or
AEP Power Pool
|
|
Members
are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation,
cost of generation and resultant wholesale off-system sales of the
member
companies.
|
AEPSC
|
|
American
Electric Power Service Corporation, a service subsidiary providing
management and professional services to AEP and its
subsidiaries.
|
AEP
West companies
|
|
PSO,
SWEPCo, TCC and TNC.
|
AFUDC
|
|
Allowance
for Funds Used During Construction.
|
ALJ
|
|
Administrative
Law Judge.
|
AOCI
|
|
Accumulated
Other Comprehensive Income (Loss).
|
APCo
|
|
Appalachian
Power Company, an AEP electric utility subsidiary.
|
ARO
|
|
Asset
Retirement Obligations.
|
CAA
|
|
Clean
Air Act.
|
CO2
|
|
Carbon
Dioxide.
|
Cook
Plant
|
|
Donald
C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by
I&M.
|
CSPCo
|
|
Columbus
Southern Power Company, an AEP electric utility
subsidiary.
|
CSW
|
|
Central
and South West Corporation, a subsidiary of AEP (Effective January
21,
2003, the legal name of Central and South West Corporation was changed
to
AEP Utilities, Inc.).
|
CSW
Operating Agreement
|
|
Agreement,
dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing
generating capacity allocation. AEPSC acts as the
agent.
|
CTC
|
|
Competition
Transition Charge.
|
DETM
|
|
Duke
Energy Trading and Marketing L.L.C., a risk management
counterparty.
|
ECAR
|
|
East
Central Area Reliability Council.
|
EDFIT
|
|
Excess
Deferred Federal Income Taxes.
|
ERCOT
|
|
Electric
Reliability Council of Texas.
|
FASB
|
|
Financial
Accounting Standards Board.
|
Federal
EPA
|
|
United
States Environmental Protection Agency.
|
FERC
|
|
Federal
Energy Regulatory Commission.
|
FIN
46
|
|
FASB
Interpretation No. 46, “Consolidation of Variable Interest
Entities.”
|
FIN
48
|
|
FASB
Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” and
FASB Staff Position FIN 48-1, "Definition of Settlement in FASB
Interpretation No. 48."
|
GAAP
|
|
Accounting
Principles Generally Accepted in the United States of
America.
|
HPL
|
|
Houston
Pipeline Company, a former AEP
subsidiary.
|
IGCC
|
|
Integrated
Gasification Combined Cycle, technology that turns coal into a
cleaner-burning gas.
|
IPP
|
|
Independent
Power Producer.
|
IRS
|
|
Internal
Revenue Service.
|
IURC
|
|
Indiana
Utility Regulatory Commission.
|
I&M
|
|
Indiana
Michigan Power Company, an AEP electric utility
subsidiary.
|
JMG
|
|
JMG
Funding LP.
|
KGPCo
|
|
Kingsport
Power Company, an AEP electric distribution subsidiary.
|
KPCo
|
|
Kentucky
Power Company, an AEP electric utility subsidiary.
|
KPSC
|
|
Kentucky
Public Service Commission.
|
kV
|
|
Kilovolt.
|
KWH
|
|
Kilowatthour.
|
LPSC
|
|
Louisiana
Public Service Commission.
|
MISO
|
|
Midwest
Independent Transmission System Operator.
|
MTM
|
|
Mark-to-Market.
|
MW
|
|
Megawatt.
|
MWH
|
|
Megawatthour.
|
NOx
|
|
Nitrogen
oxide.
|
Nonutility
Money Pool
|
|
AEP
System’s Nonutility Money Pool.
|
NRC
|
|
Nuclear
Regulatory Commission.
|
NSR
|
|
New
Source Review.
|
NYMEX
|
|
New
York Mercantile Exchange.
|
OATT
|
|
Open
Access Transmission Tariff.
|
OCC
|
|
Corporation
Commission of the State of Oklahoma.
|
OPCo
|
|
Ohio
Power Company, an AEP electric utility subsidiary.
|
OTC
|
|
Over
the counter.
|
OVEC
|
|
Ohio
Valley Electric Corporation, which is 43.47% owned by
AEP.
|
PJM
|
|
Pennsylvania
- New Jersey - Maryland regional transmission
organization.
|
PSO
|
|
Public
Service Company of Oklahoma, an AEP electric utility
subsidiary.
|
PUCO
|
|
Public
Utilities Commission of Ohio.
|
PUCT
|
|
Public
Utility Commission of Texas.
|
Registrant
Subsidiaries
|
|
AEP
subsidiaries which are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC.
|
REP
|
|
Texas
Retail Electric Provider.
|
Risk
Management Contracts
|
|
Trading
and nontrading derivatives, including those derivatives designated
as cash
flow and fair value hedges.
|
Rockport
Plant
|
|
A
generating plant, consisting of two 1,300 MW coal-fired generating
units
near Rockport, Indiana owned by AEGCo and I&M.
|
RSP
|
|
Rate
Stabilization Plan.
|
RTO
|
|
Regional
Transmission Organization.
|
S&P
|
|
Standard
and Poor’s.
|
SEC
|
|
United
States Securities and Exchange Commission.
|
SECA
|
|
Seams
Elimination Cost Allocation.
|
SFAS
|
|
Statement
of Financial Accounting Standards issued by the Financial Accounting
Standards Board.
|
SFAS
71
|
|
Statement
of Financial Accounting Standards No. 71, “Accounting for the Effects of
Certain Types of Regulation.”
|
SFAS
133
|
|
Statement
of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities.”
|
SFAS
158
|
|
Statement
of Financial Accounting Standards No. 158, “Employers’ Accounting for
Defined Benefit Pension and Other Postretirement
Plans.”
|
SFAS
159
|
|
Statement
of Financial Accounting Standards No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities.”
|
SIA
|
|
System
Integration Agreement.
|
SO2
|
|
Sulfur
Dioxide.
|
SPP
|
|
Southwest
Power Pool.
|
Sweeny
|
|
Sweeny
Cogeneration Limited Partnership, owner and operator of a four unit,
480
MW gas-fired generation facility, owned 50% by AEP.
|
SWEPCo
|
|
Southwestern
Electric Power Company, an AEP electric utility
subsidiary.
|
TCC
|
|
AEP
Texas Central Company, an AEP electric utility subsidiary.
|
TEM
|
|
SUEZ
Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing,
Inc.).
|
Texas
Restructuring Legislation
|
|
Legislation
enacted in 1999 to restructure the electric utility industry in
Texas.
|
TNC
|
|
AEP
Texas North Company, an AEP electric utility subsidiary.
|
Transmission
Equalization
Agreement
|
|
Transmission
Equalization Agreement by and among APCo, CSPCo, I&M, KPCo and OPCo
with AEPSC as agent, promoting the allocation of the cost of
ownership and operation of the transmission system in proportion
to their
demand ratios.
|
True-up
Proceeding
|
|
A
filing made under the Texas Restructuring Legislation to finalize
the
amount of stranded costs and other true-up items and the recovery
of such
amounts.
|
Utility
Money Pool
|
|
AEP
System’s Utility Money Pool.
|
VaR
|
|
Value
at Risk, a method to quantify risk exposure.
|
Virginia
SCC
|
|
Virginia
State Corporation Commission.
|
WPCo
|
|
Wheeling
Power Company, an AEP electric distribution subsidiary.
|
WVPSC
|
|
Public
Service Commission of West
Virginia.
|
FORWARD-LOOKING
INFORMATION
This
report made by AEP and its Registrant Subsidiaries contains forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act
of
1934. Although AEP and each of its Registrant Subsidiaries believe that their
expectations are based on reasonable assumptions, any such statements may be
influenced by factors that could cause actual outcomes and results to be
materially different from those projected. Among the factors that could cause
actual results to differ materially from those in the forward-looking statements
are:
·
|
Electric
load and customer growth.
|
·
|
Weather
conditions, including storms.
|
·
|
Available
sources, costs and transportation for fuels and the creditworthiness
of
fuel suppliers and transporters.
|
·
|
Availability
of generating capacity and the performance of our generating
plants.
|
·
|
Our
ability to recover regulatory assets and stranded costs in connection
with
deregulation.
|
·
|
Our
ability to recover increases in fuel and other energy costs through
regulated or competitive electric rates.
|
·
|
Our
ability to build or acquire generating capacity when needed at acceptable
prices and terms and to recover those costs through applicable rate
cases
or competitive rates.
|
·
|
New
legislation, litigation and government regulation including requirements
for reduced emissions of sulfur, nitrogen, mercury, carbon, soot
or
particulate matter and other substances.
|
·
|
Timing
and resolution of pending and future rate cases, negotiations and
other
regulatory decisions (including rate or other recovery for new
investments, transmission service and environmental
compliance).
|
·
|
Resolution
of litigation (including pending Clean Air Act enforcement actions
and
disputes arising from the bankruptcy of Enron Corp. and related
matters).
|
·
|
Our
ability to constrain operation and maintenance costs.
|
·
|
The
economic climate and growth in our service territory and changes
in market
demand and demographic patterns.
|
·
|
Inflationary
and interest rate trends.
|
·
|
Our
ability to develop and execute a strategy based on a view regarding
prices
of electricity, natural gas and other energy-related
commodities.
|
·
|
Changes
in the creditworthiness of the counterparties with whom we have
contractual arrangements, including participants in the energy trading
market.
|
·
|
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 recent legislation in Virginia,
the
potential for new legislation in Ohio and membership in and integration
into regional transmission organizations.
|
·
|
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.
|
The
registrants expressly disclaim any obligation to update any
forward-looking information.
|
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS
EXECUTIVE
OVERVIEW
Regulatory
Activity
Our
significant regulatory activities in 2007 are updated to include:
·
|
In
March 2007, the Texas District Court judge reversed his earlier
preliminary decision and concluded the sale of assets method used
by TCC
to value its nuclear plant stranded costs was appropriate.
|
·
|
In
March 2007, various intervenors and the PUCT staff filed their
recommendations in TCC’s and TNC’s energy delivery base rate filings.
Though the recommendations varied, the range of recommended increase
was
$8 million to $30 million for TCC and $1 million to $14 million for
TNC.
In April 2007, TCC and TNC filed rebuttal testimony and continue
to pursue
$70 million and $22 million, respectively, in annual base rate increases.
Hearings began in April 2007 and are scheduled to conclude in May
2007.
|
·
|
In
April 2007, the Virginia legislature approved amendments recommended
by
the Governor to the legislature’s recently adopted, comprehensive bill
providing for the re-regulation of electric utilities generation/supply
rates. The effective date of the new amendments is July 1, 2007.
|
·
|
In
March 2007, a Hearing Examiner (HE) in Virginia issued a report
recommending a $76 million increase in APCo’s base rates and $45 million
credit to the fuel factor for off-system sales margins. APCo
continues to pursue an annual base rate increase of $225 million
and a $27
million credit for off-system sales margins. We expect a ruling during
2007.
|
·
|
In
April 2007, the FERC issued an order reversing an initial favorable
ALJ
decision which had found the existing PJM zonal rate design to be
unjust
and determined that it should be replaced. In the April 2007 order,
the
FERC ruled that the existing PJM rate design is just and reasonable.
As a
result of this order, our retail customers will be asked to bear
the full
cost of the existing AEP east transmission zone facilities. We presently
recover approximately 85% of these costs from retail customers. The
FERC
further ruled that the cost of new facilities of 500 kV and above
would be
shared among all PJM participants.
|
·
|
In
March 2007, the OCC staff and various intervenors filed testimony
in PSO’s
base rate case. The recommendations were base rate reductions that
ranged
from $18 million to $52 million. In April 2007, PSO filed rebuttal
testimony and continues to pursue an increase in annual base rates
of $48
million.
|
·
|
Beginning
with the May 2007 billing cycle, CSPCo and OPCo implemented rates
filed
with the PUCO under the 4% provision of their RSPs to increase their
annual generation rates for 2007 by $24 million and $8 million,
respectively, to recover governmentally-mandated costs. These increases
are subject to refund until the PUCO issues a final order in the
matter.
The hearing is scheduled to begin in late May 2007.
|
·
|
In
March 2007, CSPCo filed an application under the 4% provision of
the RSP
to adjust the Power Acquisition Rider (PAR) which was authorized
in 2005
by the PUCO in connection with CSPCo's acquisition of Monongahela
Power
Company's certified territory in Ohio. If approved, CSPCo's revenues
would
increase by $22 million and $38 million for 2007 and 2008,
respectively.
|
·
|
In
April 2007, CSPCo and OPCo filed a joint motion with the PUCO staff
and
other intervenors to withdraw the proposed enhanced reliability
plan.
|
Investment
Activity
Our
significant investment activities in 2007 are updated to include:
·
|
We
completed the 480 MW Darby Electric Generation Station acquisition
in
April 2007.
|
·
|
In
April 2007, we signed a memorandum of understanding with Allegheny
Energy
Inc. to form a joint venture company to build and own certain electric
transmission assets within PJM with the initial focus on a transmission
line between AEP’s Amos power plant in West Virginia and Allegheny’s
proposed Kemptown power plant in Maryland. We expect to execute definitive
agreements for the joint venture with Allegheny Energy Inc. by mid-2007
and anticipate the joint venture will begin activities in the second
half
of 2007.
|
RESULTS
OF OPERATIONS
Our
principal operating business segments and their related business activities
are
as follows:
Utility
Operations
·
|
Generation
of electricity for sale to U.S. retail and wholesale
customers.
|
·
|
Electricity
transmission and distribution in the
U.S.
|
MEMCO
Operations
·
|
Barging
operations that annually transport approximately 34 million tons
of coal
and dry bulk commodities primarily on the Ohio, Illinois and Lower
Mississippi rivers. Approximately 35% of the barging operations
relates to
the transportation of coal, 28% relates to agricultural
products, 21% relates to steel and 16% relates to other
commodities.
|
Generation
and Marketing
·
|
IPPs,
wind farms and marketing and risk management activities primarily in
ERCOT.
|
The
table
below presents our consolidated Income Before Discontinued Operations for the
three months ended March 31, 2007 and 2006 (Earnings and Weighted Average Number
of Basic Shares Outstanding in millions). We reclassified prior year amounts
to
conform to the current year’s segment presentation.
|
|
Three
Months Ended March 31,
|
|
|
|
2007
|
|
2006
|
|
|
|
Earnings
|
|
EPS
(b)
|
|
Earnings
|
|
EPS
(b)
|
|
Utility
Operations
|
|
$
|
253
|
|
$
|
0.63
|
|
$
|
365
|
|
$
|
0.93
|
|
MEMCO
Operations
|
|
|
15
|
|
|
0.04
|
|
|
21
|
|
|
0.05
|
|
Generation
and Marketing
|
|
|
(1
|
)
|
|
-
|
|
|
4
|
|
|
0.01
|
|
All
Other (a)
|
|
|
4
|
|
|
0.01
|
|
|
(12
|
)
|
|
(0.03
|
)
|
Income
Before Discontinued Operations
|
|
$
|
271
|
|
$
|
0.68
|
|
$
|
378
|
|
$
|
0.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average Number of Basic Shares Outstanding
|
|
|
|
|
|
397
|
|
|
|
|
|
394
|
|
(a)
|
All
Other includes:
|
|
·
|
Parent
company’s guarantee revenue received from affiliates, interest income and
interest expense and other nonallocated costs.
|
|
·
|
Other
energy supply related businesses, including the Plaquemine Cogeneration
Facility, which was sold in the fourth quarter of 2006.
|
(b)
|
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 2007 Compared to First Quarter of 2006
Income
Before Discontinued Operations in 2007 decreased $107 million compared to 2006
primarily due to a decrease in Utility Operations segment earnings of $112
million. The decrease in Utility Operations segment earnings primarily relates
to higher operation and maintenance expenses, higher regulatory amortization
expense, lower earnings-sharing payments from Centrica, lower off-system sales
margins and the elimination of SECA revenues. These decreases were partially
offset by higher retail margins related to new rates in the east region and
favorable weather.
Average
basic shares outstanding increased to 397 million in 2007 from 394 million
in
2006 primarily due to the issuance of shares under our incentive compensation
and dividend reinvestment plans. Actual shares outstanding were 398 million
as
of March 31, 2007.
Utility
Operations
Our
Utility Operations segment includes primarily regulated revenues with direct
and
variable offsetting expenses and net reported commodity trading operations.
We
believe that a discussion of the results from our Utility Operations segment
on
a gross margin basis is most appropriate in order to further understand the
key
drivers of the segment. Gross margin represents utility operating revenues
less
the related direct cost of fuel, including consumption of chemicals and
emissions allowances, and purchased power.
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(in
millions)
|
|
Revenues
|
|
$
|
3,033
|
|
$
|
2,966
|
|
Fuel
and Purchased Power
|
|
|
1,119
|
|
|
1,126
|
|
Gross
Margin
|
|
|
1,914
|
|
|
1,840
|
|
Depreciation
and Amortization
|
|
|
383
|
|
|
340
|
|
Other
Operating Expenses
|
|
|
991
|
|
|
836
|
|
Operating
Income
|
|
|
540
|
|
|
664
|
|
Other
Income, Net
|
|
|
18
|
|
|
41
|
|
Interest
Charges and Preferred Stock Dividend Requirements
|
|
|
179
|
|
|
154
|
|
Income
Tax Expense
|
|
|
126
|
|
|
186
|
|
Income
Before Discontinued Operations
|
|
$
|
253
|
|
$
|
365
|
|
Summary
of Selected Sales and Weather Data
For
Utility Operations
For
the Three Months Ended March 31, 2007 and 2006
|
|
2007
|
|
2006
|
|
Energy
Summary
|
|
(in
millions of KWH)
|
|
Retail:
|
|
|
|
|
|
Residential
|
|
|
14,139
|
|
|
12,938
|
|
Commercial
|
|
|
9,359
|
|
|
8,909
|
|
Industrial
|
|
|
13,565
|
|
|
13,222
|
|
Miscellaneous
|
|
|
614
|
|
|
618
|
|
Total
Retail
|
|
|
37,677
|
|
|
35,687
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
|
8,778
|
|
|
10,844
|
|
|
|
|
|
|
|
|
|
Texas
Wires Delivery
|
|
|
5,831
|
|
|
5,546
|
|
Total
KWHs
|
|
|
52,286
|
|
|
52,077
|
|
Cooling
degree days and heating degree days are metrics commonly used in the utility
industry as a measure of the impact of weather on results of operations. In
general, degree day changes in our eastern region have a larger effect on
results of operations than changes in our western region due to the relative
size of the two regions and the associated number of customers within each.
Cooling degree days and heating degree days in our service territory for the
three months ended March 31, 2007 and 2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
2006
|
|
Weather
Summary
|
|
(in
degree days)
|
|
Eastern
Region
|
|
|
|
|
|
Actual
- Heating (a)
|
|
1,816
|
|
1,456
|
|
Normal
- Heating (b)
|
|
1,792
|
|
1,817
|
|
|
|
|
|
|
|
Actual
- Cooling (c)
|
|
14
|
|
1
|
|
Normal
- Cooling (b)
|
|
3
|
|
3
|
|
|
|
|
|
|
|
Western
Region
(d)
|
|
|
|
|
|
Actual
- Heating (a)
|
|
902
|
|
658
|
|
Normal
- Heating (b)
|
|
959
|
|
972
|
|
|
|
|
|
|
|
Actual
- Cooling (c)
|
|
56
|
|
43
|
|
Normal
- Cooling (b)
|
|
18
|
|
17
|
|
(a)
|
Eastern
region and western region heating degree days are calculated on a
55
degree temperature base.
|
(b)
|
Normal
Heating/Cooling represents the thirty-year average of degree
days.
|
(c)
|
Eastern
region and western region cooling degree days are calculated on a
65
degree temperature base.
|
(d)
|
Western
region statistics represent PSO/SWEPCo customer base
only.
|
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Income
from Utility Operations Before Discontinued Operations
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
365
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
139
|
|
|
|
|
Off-system
Sales
|
|
|
(41
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(29
|
)
|
|
|
|
Other
Revenues
|
|
|
5
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(111
|
)
|
|
|
|
Gain
on Dispositions of Assets, Net
|
|
|
(47
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(43
|
)
|
|
|
|
Carrying
Costs Income
|
|
|
(22
|
)
|
|
|
|
Other
Income, Net
|
|
|
2
|
|
|
|
|
Interest
and Other Charges
|
|
|
(25
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(246
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
60
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
253
|
|
Income
from Utility Operations Before Discontinued Operations decreased $112 million
to
$253 million in 2007. The key driver of the decrease was a $246 million increase
in Operating Expenses and Other offset by a $74 million increase in Gross Margin
and a $60 million decrease in Income Tax Expense.
The
major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $139 million primarily due to the
following:
|
|
·
|
A
$35 million increase related to new rates implemented in our Ohio
jurisdictions as approved by the PUCO in our RSPs and a $58 million
increase related to new rates implemented in other east jurisdictions
of
Kentucky, West Virginia and Virginia. See “APCo Virginia Base Rate Case”
in Note 3 for discussion of the Virginia increase implemented subject
to
refund.
|
|
·
|
A
$34 million increase related to increased residential and commercial
usage
and customer growth.
|
|
·
|
A
$40 million increase in usage related to weather. As compared to
the prior
year, our eastern region and western region experienced 25% and
37%
increases, respectively, in heating degree days.
|
These
increases were partially offset by:
|
|
·
|
A
$27 million decrease in financial transmission rights revenue,
net of
congestion, primarily due to fewer transmission constraints within
the PJM
market.
|
·
|
Margins
from Off-system Sales decreased $41 million primarily due to lower
generation availability in the east due to planned outages for
completion
of environmental retrofits and higher retail load offset by higher
margins
from trading activities.
|
·
|
Transmission
Revenues decreased $29 million primarily due to the elimination
of SECA
revenues as of April 1, 2006. See the “Transmission Rate Proceedings at
the FERC” section of Note 3.
|
Utility
Operating Expenses and Other and Income Taxes changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $111 million primarily
due to
increases in generation expenses related to plant outages and removal
costs, distribution expenses associated with service reliability
and storm
restoration primarily in Oklahoma and expenses associated with employee
benefits.
|
·
|
Gain
on Disposition of Assets, Net decreased $47 million primarily related
to
the earnings sharing agreement with Centrica from the sale of our
REPs in
2002. In 2006, we received $70 million from Centrica for earnings
sharing
and in 2007 we received $20 million as the earnings sharing agreement
ended.
|
·
|
Depreciation
and Amortization expense increased $43 million primarily due to increased
Ohio regulatory asset amortization related to recovery of IGCC
preconstruction costs, increased Texas amortization of the
securitized transition assets, increased Virginia regulatory amortization
related to environmental and reliability recovery and higher depreciable
property balances.
|
·
|
Carrying
Costs Income decreased $22 million because TCC started recovering
Texas
stranded costs in October 2006, resulting in lower Texas carrying
costs
income in 2007.
|
·
|
Interest
and Other Charges increased $25 million primarily due to additional
debt
issued in the fourth quarter of 2006 partially offset by an increase
in
allowance for borrowed funds used for construction.
|
·
|
Income
Tax Expense decreased $60 million due to a decrease in pretax
income.
|
MEMCO
Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Income
Before Discontinued Operations from our MEMCO Operations segment decreased
from
$21 million in 2006 to $15 million in 2007. The decrease was primarily related
to a return to normal winter river operating conditions in 2007 compared to
milder and more favorable weather in 2006 and lower spot market rates due to
decreased barging demand caused by lower backhaul imports.
Generation
and Marketing
First
Quarter of 2007 Compared to First Quarter of 2006
Loss
Before Discontinued Operations from our Generation and Marketing segment was
$1
million in 2007 compared to income of $4 million in 2006. The decrease primarily
relates to planned and forced outages at our Oklaunion plant in 2007 that
limited the availability of power under lease.
All
Other
First
Quarter of 2007 Compared to First Quarter of 2006
Income
Before Discontinued Operations from All Other increased from a $12 million
loss
in 2006 to income of $4 million in 2007. In 2006, we had after-tax losses of
$8
million in 2006 from operation of the Plaquemine Cogeneration Facility which
was
sold in the fourth quarter of 2006. In 2007, we had an after-tax gain of $10
million on the sale of investment securities.
AEP
System Income Taxes
Income
Tax Expense decreased $59 million primarily due to a decrease in pretax book
income.
FINANCIAL
CONDITION
We
measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.
Debt
and Equity Capitalization
|
|
March
31, 2007
|
|
December
31, 2006
|
|
|
|
($
in millions)
|
|
Long-term
Debt, including amounts due within one year
|
|
$
|
13,902
|
|
|
58.7
|
%
|
$
|
13,698
|
|
|
59.1
|
%
|
Short-term
Debt
|
|
|
175
|
|
|
0.7
|
|
|
18
|
|
|
0.0
|
|
Total
Debt
|
|
|
14,077
|
|
|
59.4
|
|
|
13,716
|
|
|
59.1
|
|
Common
Equity
|
|
|
9,540
|
|
|
40.3
|
|
|
9,412
|
|
|
40.6
|
|
Preferred
Stock
|
|
|
61
|
|
|
0.3
|
|
|
61
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt and Equity Capitalization
|
|
$
|
23,678
|
|
|
100.0
|
%
|
$
|
23,189
|
|
|
100.0
|
%
|
Our
ratio
of debt to total capital increased from 59.1% to 59.4% in 2007 due to our
increased borrowings.
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, 2007, our available liquidity was approximately $3.1 billion as illustrated
in the table below:
|
|
Amount
|
|
Maturity
|
|
|
|
(in
millions)
|
|
|
|
Commercial
Paper Backup:
|
|
|
|
|
|
Revolving
Credit Facility
|
|
$
|
1,500
|
|
|
March
2011
|
|
Revolving
Credit Facility
|
|
|
1,500
|
|
|
April
2012
|
|
Total
|
|
|
3,000
|
|
|
|
|
Cash
and Cash Equivalents
|
|
|
259
|
|
|
|
|
Total
Liquidity Sources
|
|
|
3,259
|
|
|
|
|
Less:
AEP Commercial Paper Outstanding
|
|
|
150
|
|
|
|
|
Letters of Credit Drawn
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Available Liquidity
|
|
$
|
3,082
|
|
|
|
|
In
2007,
we amended the terms and extended the maturity of our two credit facilities
by
one year to March 2011 and April 2012, respectively. The facilities are
structured as two $1.5 billion credit facilities of which $300 million may
be
issued under each credit facility as letters of credit.
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, 2007, this contractually-defined percentage
was 54.5%. Nonperformance of these covenants could result in an event of default
under these credit agreements. At March 31, 2007, we complied with all of the
covenants contained in these credit agreements. In addition, the acceleration
of
our payment obligations, or the obligations of certain of our major
subsidiaries, prior to maturity under any other agreement or instrument relating
to debt outstanding in excess of $50 million, would cause an event of default
under these credit agreements and permit the lenders to declare the outstanding
amounts payable.
The
two
revolving credit facilities do not permit the lenders to refuse a draw on either
facility if a material adverse change occurs.
Under
a
regulatory order, our utility subsidiaries, other than TCC, cannot incur
additional indebtedness if the issuer’s common equity would constitute less than
30% of its capital. In addition, this order restricts those 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,
2007, all applicable utility subsidiaries complied with this order.
Utility
Money Pool borrowings and external borrowings may not exceed amounts authorized
by regulatory orders. At March 31, 2007, we had not exceeded those authorized
limits.
Credit
Ratings
AEP’s
ratings have not been adjusted by any rating agency during 2007 and AEP is
currently on a stable outlook by the rating agencies. Our current credit ratings
are as follows:
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Moody’s
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S&P
|
|
|
Fitch
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|
|
|
|
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|
|
|
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|
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AEP
Short Term Debt
|
P-2
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A-2
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F-2
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AEP
Senior Unsecured Debt
|
Baa2
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BBB
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BBB
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If
we or
any of our rated subsidiaries receive an upgrade from any of the rating agencies
listed above, our borrowing costs could decrease. If we receive a downgrade
in
our credit ratings by one of the rating agencies listed above, our borrowing
costs could increase and access to borrowed funds could be negatively
affected.
Cash
Flow
Managing
our cash flows is a major factor in maintaining our liquidity
strength.
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(in
millions)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
301
|
|
$
|
401
|
|
Net
Cash Flows From Operating Activities
|
|
|
351
|
|
|
583
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(628
|
)
|
|
(750
|
)
|
Net
Cash Flows From Financing Activities
|
|
|
235
|
|
|
42
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(42
|
)
|
|
(125
|
)
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
259
|
|
$
|
276
|
|
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, 2007,
we had credit facilities totaling $3 billion to support our commercial paper
program.
The
maximum amount of commercial paper outstanding during 2007 was $150 million.
The
weighted-average interest rate of our commercial paper during 2007 was 5.43%.
We
generally use short-term borrowings to fund working capital needs, property
acquisitions and construction until long-term funding is arranged. Sources
of
long-term funding include issuance of common stock or long-term debt and
sale-leaseback or leasing agreements. Utility Money Pool borrowings and external
borrowings may not exceed authorized limits under regulatory orders. See the
discussion below for further detail related to the components of our cash
flows.
Operating
Activities
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(in
millions)
|
|
Net
Income
|
|
$
|
271
|
|
$
|
381
|
|
Less:
Discontinued Operations, Net of Tax
|
|
|
-
|
|
|
(3
|
)
|
Income
Before Discontinued Operations
|
|
|
271
|
|
|
378
|
|
Noncash
Items Included in Earnings
|
|
|
420
|
|
|
323
|
|
Changes
in Assets and Liabilities
|
|
|
(340
|
)
|
|
(118
|
)
|
Net
Cash Flows From Operating Activities
|
|
$
|
351
|
|
$
|
583
|
|
Net
Cash
Flows From Operating Activities decreased in 2007 primarily due to lower fuel
costs recovery.
Net
Cash
Flows From Operating Activities were $351 million in 2007 consisting primarily
of Income
Before Discontinued Operations
of $271 million. Income Before
Discontinued
Operations included noncash expense items primarily for depreciation,
amortization, deferred taxes and deferred investment tax credits. 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, none of which were
significant.
Net
Cash
Flows From Operating Activities were $583 million in 2006. We produced Income
Before Discontinued Operations of $378 million. Income Before Discontinued
Operations included noncash expense items primarily for depreciation,
amortization, 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.
Investing
Activities
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(in
millions)
|
|
Construction
Expenditures
|
|
$
|
(907
|
)
|
$
|
(765
|
)
|
Change
in Other Temporary Cash Investments, Net
|
|
|
(20
|
)
|
|
27
|
|
(Purchases)/Sales
of Investment Securities, Net
|
|
|
236
|
|
|
(89
|
)
|
Proceeds
from Sales of Assets
|
|
|
68
|
|
|
111
|
|
Other
|
|
|
(5
|
)
|
|
(34
|
)
|
Net
Cash Flows Used for Investing Activities
|
|
$
|
(628
|
)
|
$
|
(750
|
)
|
Net
Cash
Flows Used For Investing Activities were $628 million in 2007 primarily due
to
Construction Expenditures for our environmental, distribution and new generation
investment plan. In
our
normal course of business, we purchase investment securities including auction
rate securities and variable rate demand notes with cash available for
short-term investments. Also included in Purchases/Sales of Investment
Securities, Net are purchases and sales of securities within our nuclear
trusts.
Net
Cash
Flows Used For Investing Activities were $750 million in 2006 primarily due
to
Construction Expenditures. Construction Expenditures increased due to our
environmental investment plan.
We
forecast approximately $2.6 billion of construction expenditures for the
remainder of 2007 plus $427 million for announced purchases of gas-fired
generating units. Estimated construction expenditures are subject to periodic
review and modification and may vary based on the ongoing effects of regulatory
constraints, environmental regulations, business opportunities, market
volatility, economic trends, weather, legal reviews and the ability to access
capital. These construction expenditures will be funded through results of
operations and financing activities.
Financing
Activities
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(in
millions)
|
|
Issuance
of Common Stock
|
|
$
|
54
|
|
$
|
5
|
|
Issuance/Retirement
of Debt, Net
|
|
|
355
|
|
|
129
|
|
Dividends
Paid on Common Stock
|
|
|
(155
|
)
|
|
(146
|
)
|
Other
|
|
|
(19
|
)
|
|
54
|
|
Net
Cash Flows From Financing Activities
|
|
$
|
235
|
|
$
|
42
|
|
Net
Cash
Flows From Financing Activities in 2007 were $235 million primarily
due to $150 million of short-term commercial paper borrowings under our credit
facilities and issuing $250 million of debt securities. We paid common stock
dividends of $155 million. See Note 9 for a complete discussion of long-term
debt issuances and retirements.
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. 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.
In
April
2007, OPCo issued $400 million of three-year floating rate notes at an initial
rate of 5.53% due in 2010. The proceeds from this issuance will
contribute to our investment in environmental equipment.
Our
capital investment plans for 2007 will require additional funding from the
capital markets.
Off-balance
Sheet Arrangements
Under
a
limited set of circumstances we enter into off-balance sheet arrangements to
accelerate cash collections, reduce operational expenses and spread risk of
loss
to third parties. Our current guidelines restrict the use of off-balance sheet
financing entities or structures to traditional operating lease arrangements
and
sales of customer accounts receivable that we enter in the normal course of
business. Our significant off-balance sheet arrangements are as
follows:
|
|
|
|
|
|
|
|
|
|
March
31,
2007
|
|
December
31,
2007
|
|
|
|
(in
millions)
|
|
AEP
Credit Accounts Receivable Purchase Commitments
|
|
$
|
549
|
|
$
|
536
|
|
Rockport
Plant Unit 2 Future Minimum Lease Payments
|
|
|
2,364
|
|
|
2,364
|
|
Railcars
Maximum Potential Loss From Lease Agreement
|
|
|
31
|
|
|
31
|
|
For
complete information on each of these off-balance sheet arrangements see the
“Off-balance Sheet Arrangements” section of “Management’s Financial Discussion
and Analysis of Results of Operations” in the 2006 Annual Report.
Summary
Obligation Information
A
summary
of our contractual obligations is included in our 2006 Annual Report and has
not
changed significantly from year-end other than the debt issuances discussed
in
“Cash Flow” and “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 with Centrica from the two
REPs
above a threshold amount through 2006 if the Texas retail market developed
increased earnings opportunities. We received $20 million and $70 million
payments in 2007 and 2006, respectively, for our share in earnings. The payment
we received in 2007 was the final payment under the earnings sharing
agreement.
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 2006 Annual Report. The 2006 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 2006 Annual Report, but
may
have a material impact on our future results of operations, cash flows and
financial condition.
Electric
Transmission Texas LLC Joint Venture
In
January 2007, we signed a participation agreement with MidAmerican Energy
Holdings Company (MidAmerican) to form a joint venture company, Electric
Transmission Texas LLC (ETT), to fund, own and operate electric transmission
assets in ERCOT. ETT filed with the PUCT in January 2007 requesting regulatory
approval to operate as an electric transmission utility in Texas, to transfer
from TCC to ETT approximately $76 million of transmission assets currently
under
construction and to establish a wholesale transmission tariff for ETT. ETT
also
requested approval from the PUCT of initial rates based on an 11.25% return
on
equity. A procedural schedule has been established in the case, with a hearing
scheduled for June. We expect a final order from the PUCT in the third
quarter.
TCC
also
made a regulatory filing at the FERC in February 2007 regarding the transfer
of
certain transmission assets from TCC to ETT. In April, the FERC authorized
the
transfer.
Upon
receipt of all required regulatory approvals, AEP Utilities, Inc., a subsidiary
of AEP, and MEHC Texas Transco LLC, a subsidiary of MidAmerican, each will
acquire a 50 percent equity ownership in ETT. AEP
and
MidAmerican plan for ETT to invest in additional transmission projects in ERCOT.
The joint venture partners anticipate investments in excess of $1 billion of
joint investment in Texas ERCOT Transmission projects could be constructed
by
ETT during the next several years. The joint venture is anticipated to be formed
and begin operations in the second half of 2007, subject to regulatory approval
from the PUCT and the FERC.
In
February 2007, ETT filed an informational proposal with the PUCT that addresses
the Competitive Renewable Energy Zone initiative of the Texas Legislature and
in
April ETT filed detailed testimony and exhibits supporting this proposal. The
proposal outlines opportunities for additional significant investment in
transmission assets in Texas.
We
believe Texas can provide a high degree of regulatory certainty for transmission
investment due to the predetermination of ERCOT’s need based on reliability
requirements and significant Texas economic growth as well as public policy
that
supports “green generation” initiatives, which require substantial transmission
access. In addition, a streamlined annual interim transmission cost of service
review process is available in ERCOT, which reduces regulatory lag. The use
of a joint venture structure will allow us to share the significant capital
requirements for the investments, and also allow us to participate in more
transmission projects than previously anticipated.
AEP
Interstate Project
In
January 2006, we filed a proposal with the FERC and PJM to build a new 765
kV
550-mile transmission line from West Virginia to New Jersey. The 765 kV line
is
designed to reduce PJM congestion costs by substantially improving west-east
transfer capability by approximately 5,000 MW during peak loading conditions
and
reducing transmission line losses by up to 280 MW. The project would also
enhance reliability of the Eastern transmission grid. The projected cost
for the project, as oringally proposed to PJM, is approximately $3 billion.
The project is subject to PJM and state approvals, and FERC approvals
of incentive cost recovery mechanisms. The projected in-service date
assumes eight years for siting and construction. Due to PJM's need to review
and
evaluate the project in conjunction with other proposed projects, the projected
in-service date is now 2015. This assumes approval by the PJM Board in mid-2007,
followed by approval by the FERC on initial rates by the end of 2007.
We
were
the first entity to file with the Department of Energy (DOE) seeking to have
the
route of a proposed transmission project designated as a National Interest
Electric Transmission Corridor (NIETC). The Energy Policy Act of 2005 provides
for NIETC designation for areas experiencing electric energy transmission
capacity constraints or congestion that adversely affects consumers. In August
2006, the DOE issued the “National Interest Electric Transmission Congestion
Study.” In this study, DOE indicated that the mid-Atlantic Coastal area, which
the AEP Interstate Project is designed to reinforce, is one of the two most
critical congestion areas in the nation. In April 2007, the DOE approved
the mid-Atlantic Coastal area as a NIETC which includes the entire proposed
765
kV transmission line.
In
July
2006, pursuant to our request, the FERC provided that the new line is
included in PJM’s formal Regional Transmission Expansion Plan to be finalized in
2007. The conditionally approved incentives include (a) a return on equity
set
at the high end of the “zone of reasonableness”; (b) the timely recovery of the
cost of capital during the construction period; and (c) the ability to defer
and
recover costs incurred during the pre-construction and pre-operating period.
Since the FERC has clarified that the project qualifies for these rate
incentives, we expect to propose rates that will capture the incentives in
a
future FERC rate filing.
In
April
2007, we signed a memorandum of understanding (MOU) with Allegheny Energy
Inc. to form a joint venture company to build and own certain electric
transmission assets within PJM including the first half of the West
Virginia - New Jersey line proposed by AEP in January 2006. Under the
terms of the MOU, the joint venture company will build and own approximately
250
miles of 765kV transmission lines from AEP's Amos station to the Maryland
border. The MOU does not include any provisions for the remainder of the
AEP Interstate Project proposal from Allegheny's Kemptown station to New
Jersey. We expect to execute definitive agreements for the joint venture
with Allegheny Energy Inc. by mid-2007 and anticipate the joint venture will
begin activities in the second half of 2007.
Texas
Restructuring
TCC recovered
its net recoverable stranded generation costs through a securitization
financing and is refunding its net other true-up items through a CTC rate
rider credit under 2006 PUCT orders. TCC appealed the PUCT stranded costs
true-up orders seeking relief in both state and federal court on the grounds
that certain aspects of the orders are contrary to the Texas Restructuring
Legislation, PUCT rulemakings, federal law and fail to fully compensate TCC
for
its net stranded cost and other true-up items. The significant items appealed
by
TCC are:
·
|
The
PUCT ruling that TCC did not comply with the statute and PUCT rules
regarding the required auction of 15% of its Texas jurisdictional
installed capacity, which led to a significant disallowance of capacity
auction true-up revenues,
|
·
|
The
PUCT ruling that TCC acted in a manner that was commercially unreasonable,
because it failed to determine a minimum price at which it would
reject
bids for the sale of its nuclear generating plant and it bundled
out of
the money gas units with the sale of its coal unit, which led to
the
disallowance of a significant portion of TCC’s net stranded generation
plant cost, and
|
·
|
The
two federal matters regarding the allocation of off-system sales
related
to fuel recoveries and the potential tax normalization
violation.
|
Municipal
customers and other intervenors also appealed the PUCT true-up orders seeking
to
further reduce TCC’s true-up recoveries. On February 1, 2007, the Texas District
Court judge hearing the various appeals issued a letter containing his
preliminary determinations. He generally affirmed the PUCT’s April 4, 2006 final
true-up order for TCC with two significant exceptions. The judge determined
that
the PUCT erred when it determined TCC’s stranded cost using the sale of assets
method instead of the Excess Cost Over Market (ECOM) method to value TCC’s
nuclear plant. The judge also determined that the PUCT erred when it concluded
it was required to use the carrying cost rate specified in the true-up order.
However, the District Court did not rule that the carrying cost rate was
inappropriate. He directed that these matters should be remanded to the PUCT
to
determine their specific impact on TCC’s future true-up revenues.
In
March
2007, the District Court judge reversed his earlier preliminary decision and
concluded the sale of assets method to value TCC’s nuclear plant was
appropriate. The District Court judge did not reconsider his preliminary ruling
that the PUCT erred when it concluded it was required to use the carrying cost
rate specified in the true-up order. The District Court judge also determined
the PUCT improperly reduced TCC’s net stranded plant costs from the sale of its
generating units through the commercial unreasonableness disallowance, which
could have a materially favorable effect on TCC. Management cannot predict
the
ultimate outcome of any future court appeals or any future remanded PUCT
proceeding. If the District Court’s carrying cost rate remand ruling is
ultimately upheld on appeal and remanded to the PUCT for reconsideration, the
PUCT could either confirm the existing weighted average carrying cost (WACC)
rate or redetermine a new rate. If the PUCT changes the rate, it could result
in
a material adverse change to TCC’s recoverable carrying costs, results of
operations, cash flows and financial condition. TCC, the PUCT and intervenors
appealed the District Court ruling to the Court of Appeals. Management cannot
predict what actions, if any, the PUCT will take regarding the carrying
costs.
If
TCC
ultimately succeeds in its appeals, it could have a favorable effect on future
results of operations, cash flows and financial condition. If municipal
customers and other intervenors succeed in their appeals, it could have a
substantial adverse effect on future results of operations, cash flows and
financial condition.
SECA
Revenue Subject to Refund
We
ceased
collecting through-and-out transmission service (T&O) revenues in accordance
with FERC orders and implemented SECA rates to mitigate the loss of T&O
revenues from December 1, 2004 through March 31, 2006, when SECA rates expired.
Intervenors objected to the SECA rates, raising various issues. In August 2006,
the ALJ issued an initial decision, finding that the rate design for the
recovery of SECA charges was flawed and that a large portion of the “lost
revenues” reflected in the SECA rates was not recoverable. The ALJ found that
the SECA rates charged were unfair, unjust and discriminatory and that new
compliance filings and refunds should be made.
Since
the
implementation of SECA rates in December 2004, the AEP East companies recorded
approximately $220 million of gross SECA revenues, subject to refund. The AEP
East companies have reached settlements with certain customers related to
approximately $70 million of such revenues. The unsettled gross SECA revenues
total approximately $150 million. If the ALJ’s initial decision is upheld in its
entirety, it would disallow $126 million of the AEP East companies’ unsettled
gross SECA revenues. In the second half of 2006, the AEP East companies provided
a reserve of $37 million in net refunds.
In
September 2006, AEP, together with Exelon and the Dayton Power and Light
Company, filed an extensive post hearing brief and reply brief noting exceptions
to the ALJ’s initial decision and asking the FERC to reverse the decision in
large part. Management believes
that the FERC should reject the initial decision because it is contrary to
prior
related FERC decisions, which are presently subject to rehearing. Furthermore,
management believes the ALJ’s findings on key issues are largely without merit.
Although management believes they have meritorious arguments, management cannot
predict the ultimate outcome of any future FERC proceedings or court appeals.
If
the
FERC adopts the ALJ’s decision, it will have an adverse effect on future results
of operations and cash flows.
Virginia
Restructuring
In
April
2004, Virginia enacted legislation that extended the transition period for
electricity restructuring, including capped rates, through December 31, 2010.
The legislation provides APCo with specified cost recovery opportunities during
the capped rate period, including two optional bundled general base rate changes
and an opportunity for timely recovery, through a separate rate mechanism,
of
certain incremental environmental and reliability costs incurred on and after
July 1, 2004. Under the restructuring law, APCo continues to have an active
fuel
clause recovery mechanism in Virginia and continues to practice deferred fuel
accounting. Also, under the restructuring law, APCo defers incremental
environmental generation costs and incremental T&D reliability costs for
future recovery, to the extent such costs are not being recovered when incurred,
and amortizes a portion of such deferrals commensurate with recovery.
In
April
2007, the Virginia legislature adopted a comprehensive law providing for the
re-regulation of electric utilities’ generation/supply rates. The amendments
shorten the transition period by two years (from 2010 to 2008) after which
rates
for retail generation/supply will return to a form of cost-based regulation.
The
legislation provides for, among other things, biennial rate reviews beginning
in
2009, rate adjustment clauses for the recovery of the costs of (a) transmission
services and new transmission investment, (b) Demand Side Management, load
management, and energy efficiency programs, (c) renewable energy programs,
and
(d) environmental retrofit and new generation investments, significant return
on
equity enhancements for large investments in new generation and a floor on
the
allowed return on equity based on the average earned return on equities’ of
regional vertically integrated electric utilities. Effective July 1, 2007,
utilities will retain a minimum of 25% of the margins from off-system sales
with
the remaining margins from such sales credited against the fuel factor. The
legislation also allows APCo to continue to defer and recover incremental
environmental and reliability costs incurred through December 31, 2008. APCo
expects this new form of cost-based ratemaking should improve its annual return
on equity and cash flow from operations when new ratemaking begins in 2009.
However, with the return of cost-based regulation, APCo’s generation business
will again meet the criteria for application of regulatory accounting principles
under SFAS 71. Results of operations and financial condition could be adversely
affected when APCo is required to re-establish certain net regulatory
liabilities applicable to its generation/supply business. The timing and
earnings effect from such reapplication of SFAS 71 regulatory accounting for
APCo’s Virginia generation/supply business are uncertain at this
time.
New
Generation
In
March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of cost
recovery associated with the IGCC plant: Phase 1, recovery of $24 million in
pre-construction costs during 2006; Phase 2, concurrent recovery of
construction-financing costs; and Phase 3, recovery or refund in distribution
rates of any difference between the market-based standard service offer price
for generation and the cost of operating and maintaining the plant, including
a
return on and return of the ultimate cost to construct the plant, originally
projected to be $1.2 billion, along with fuel, consumables and replacement
power
costs. The proposed recoveries in Phases 1 and 2 would be applied against the
4%
limit on additional generation rate increases CSPCo and OPCo could request
under
their RSPs.
In
April
2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
1
of the cost recovery proposal. In June 2006, the PUCO issued another order
approving a tariff to recover Phase 1 pre-construction costs over no more than
a
twelve-month period effective July 1, 2006. Through March 31, 2007, CSPCo and
OPCo each recorded pre-construction IGCC regulatory assets of $10 million and
each recovered $9 million of those costs. CSPCo and OPCo will recover the
remaining amounts through June 30, 2007. The PUCO indicated that if CSPCo and
OPCo have not commenced a continuous course of construction of the IGCC plant
within five years of the June 2006 PUCO order, all charges collected for
pre-construction costs, associated with items that may be utilized in IGCC
projects at other sites, must be refunded to Ohio ratepayers with interest.
The
PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings
are
held. A date for further rehearings has not been set.
In
August
2006, the Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy
Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order
in the IGCC proceeding. CSPCo and OPCo believe that the PUCO’s authorization to
begin collection of Phase 1 rates is lawful. Management, however, cannot predict
the outcome of these appeals. If the PUCO’s order is found to be unlawful, CSPCo
and OPCo could be required to refund Phase I cost-related
recoveries.
In
January 2006, APCo filed a petition with the WVPSC requesting its approval
of a
Certificate of Public Convenience and Necessity to construct a 629 MW IGCC
plant
adjacent to APCo’s existing Mountaineer Generating Station in Mason County, WV.
In January 2007, at APCo’s request, the WVPSC issued an order delaying the
Commission’s deadline for issuing an order on the certificate to December 2007.
Through March 31, 2007, APCo deferred pre-construction IGCC costs totaling
$10
million. If the plant is not built and these costs are not recoverable, future
results of operations and cash flows would be adversely affected.
In
December 2005, SWEPCo sought proposals for new peaking, intermediate and base
load generation to be online between 2008 and 2011. In May 2006, SWEPCo
announced plans to construct new generation to satisfy the demands of its
customers. SWEPCo will build up to 480 MW of simple-cycle natural gas combustion
turbine peaking generation in Tontitown, Arkansas and will build a 480 MW
combined-cycle natural gas fired plant at its existing Arsenal Hill Power Plant
in Shreveport, Louisiana. SWEPCo also plans to build a new 600 MW base load
coal
plant, of which SWEPCo’s investment will be 73%, in Hempstead County, Arkansas
by 2011 to meet the long-term generation needs of its customers. Preliminary
cost estimates for SWEPCo’s share of the new facilities are approximately $1.4
billion (this total excludes the related transmission investment and AFUDC).
These new facilities are subject to regulatory approvals from SWEPCo’s three
state commissions. The peaking generation facility in Tontitown, Arkansas has
been approved by all three state commissions and Units 3 and 4 are projected
to
be online in July 2007 and the remaining two units by 2008. Construction is
expected to begin in 2007 on the intermediate and base load facilities upon
approval from the state regulatory commissions. Expenditures related to
construction of these facilities are expected to total $349 million in
2007.
In
September 2005, PSO sought proposals for new peaking generation to be online
in
2008, and in December 2005 PSO sought proposals for base load generation to
be
online in 2011. PSO received proposals and evaluated those proposals meeting
the
Request for Proposal criteria with oversight from a neutral third party. In
March 2006, PSO announced plans to add 170 MW of peaking generation to its
Riverside Station plant in Jenks, Oklahoma where PSO will construct and operate
two 85 MW simple-cycle natural gas combustion turbines. Also in March 2006,
PSO
announced plans to add 170 MW of peaking generation to its Southwestern Station
plant in Anadarko, Oklahoma where they will construct and operate two 85 MW
simple-cycle natural gas combustion turbines. Combined preliminary cost
estimates for these additions are approximately $120 million. In
April
2007, the OCC approved a settlement agreement regarding these new peaking units.
The settlement agreement provides for recovery of a purchase fee of $35 million
to be paid by PSO to Lawton Cogeneration, LLC (Lawton) and for all rights to
Lawton’s cogeneration facility for permits, options and engineering studies. PSO
will record the purchase fee as a regulatory asset and recover it through a
rider over a three-year period with a carrying charge of 8.25% beginning in
September 2007. In addition, PSO will recover the traditional costs associated
with plant in service of these new peaking units. Such costs will be recovered
through the rider until cost recovery occurs through base rates or formula
rates
in a subsequent proceeding. PSO must file a rate case within eighteen months
of
the beginning of recovery through the rider unless the OCC approves a
formula-based rate mechanism that provides for recovery of the peaking
units.
In
July
2006, PSO announced plans to enter a joint venture with Oklahoma Gas and
Electric Company (OG&E) and Oklahoma Municipal Power Authority (OMPA) where
OG&E will construct and operate a new 950 MW coal-fueled electricity
generating unit near Red Rock, Oklahoma. PSO will own 50% of the new unit.
PSO,
OG&E and OMPA signed an agreement in February 2007 with Red Rock Power
Partners to begin the first phase of the project. Preliminary cost estimates
for
100% of the new facility are approximately $1.8 billion, and the unit is
expected to be online no later than the first half of 2012. These new facilities
are subject to regulatory approval from the OCC. Construction of all of these
additions is expected to begin in 2007. Expenditures related to construction
of
these facilities are expected to total $125 million in 2007.
In
November 2006, CSPCo agreed to purchase Darby Electric Generating Station
(Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light
Company, for $102 million. CSPCo completed the purchase in April 2007. The
Darby
plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle
power plant with a generating capacity of 480 MW. The purchase of Darby is
an economically efficient way to provide peaking generation to our customers
at
a cost below that of building a new, comparable plant.
In
January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station
(Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG)
for
approximately $325 million and the assumption of liabilities of approximately
$2
million. The transaction is expected to close in May 2007. The Lawrenceburg
plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek
Plant, and is a natural gas, combined cycle power plant with a generating
capacity of 1,096 MW. AEGCo plans to sell the power to CSPCo through a
FERC-approved purchase power contract.
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
regulatory proceedings and our pending litigation see Note 4 - Rate Matters,
Note 6 - Commitments, Guarantees and Contingencies and the “Litigation” section
of “Management’s Financial Discussion and Analysis of Results of Operations” in
the 2006 Annual Report. Additionally, see Note 3 - Rate Matters and Note 4
-
Commitments, Guarantees and Contingencies included herein. Adverse results
in
these proceedings have the potential to materially affect 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
are
implementing a substantial capital investment program and incurring additional
operational costs to comply with new environmental control requirements. The
sources of these requirements include:
·
|
Requirements
under the 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;
and
|
·
|
Requirements
under the Clean Water Act (CWA) to reduce the impacts of water intake
structures on aquatic species at certain of our power
plants.
|
In
addition, we are engaged in litigation with respect to certain environmental
matters, have been notified of potential responsibility for the clean-up of
contaminated sites and incur costs for disposal of spent nuclear fuel and future
decommissioning of our nuclear units. We are also monitoring possible future
requirements to reduce carbon dioxide (CO2)
emissions to address concerns about global climate change. All of these matters
are discussed in the “Environmental Matters” section of “Management’s Financial
Discussion and Analysis of Results of Operations” in the 2006 Annual
Report.
Environmental
Litigation
New
Source Review (NSR) Litigation:
In 1999,
the Federal EPA and a number of states filed complaints alleging that APCo,
CSPCo, I&M, OPCo and other nonaffiliated utilities including the Tennessee
Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company,
Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power
Company, Tampa Electric Company, Virginia Electric Power Company and Duke
Energy, modified certain units at coal-fired generating plants in violation
of
the NSR requirements of the CAA. 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 thereafter against
nonaffiliated utilities including Allegheny Energy, Eastern Kentucky Electric
Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric
Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases
were resolved through consent decrees. The alleged modifications at our power
plants occurred over a twenty-year period. A bench trial on the liability issues
was held during 2005. Briefing has concluded. In June 2006, the judge stayed
the
liability decision pending the issuance of a decision by the U.S. Supreme Court
in the Duke Energy case.
Under
the
CAA, if a plant undertakes a major modification that directly results in an
emissions increase, permitting requirements might be triggered and the plant
may
be required to install additional pollution control technology. This requirement
does not apply to activities such as routine maintenance, replacement of
degraded equipment or failed components, or other repairs needed for the
reliable, safe and efficient operation of the plant.
Courts
that considered whether the activities at issue in these cases are routine
maintenance, repair, or replacement, and therefore are excluded from NSR,
reached different conclusions. Similarly, courts that considered whether the
activities at issue increased emissions from the power plants reached different
results. Appeals on these and other issues were filed in certain appellate
courts, including a petition to appeal to the U.S. Supreme Court that was
granted in the Duke Energy 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 Court denied the
Federal EPA’s request for rehearing, and the Federal EPA and other parties filed
a petition for review by the U.S. Supreme Court. In April 2007, the Supreme
Court denied the petition for review. The Federal EPA also proposed a rule
that
would define “emissions increases” in a way that would exclude most of the
challenged activities from NSR.
On
April
2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’
decision that had supported the statutory construction argument of Duke Energy
in its NSR proceeding. In a unanimous decision, the Court ruled that the Federal
EPA was not obligated to define “major modification” in two different CAA
provisions in the same way. The Court also found that the Fourth Circuit’s
interpretation of “major modification” as applying only to projects that
increased hourly emission rates amounted to an invalidation of the relevant
Federal EPA regulations, which under the CAA can only be challenged in the
Court
of Appeals within 60 days of the Federal EPA rulemaking. The U.S. Supreme Court
did acknowledge, however, that Duke Energy may argue on remand that the Federal
EPA has been inconsistent in its interpretations of the CAA and the regulations
and may not retroactively change 20 years of accepted practice.
In
addition to providing guidance on certain of the merits of the NSR proceedings
brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the
Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the
Duke Energy cases has an impact on the timing of our NSR proceedings. First,
the
court in the case for which a trial on liability issues has been conducted
has
indicated an intent to issue a decision on liability. Second, the bench trial
on
remedy issues, if necessary, is likely to be scheduled to begin in the third
quarter of 2007.
We
are
unable to estimate the loss or range of loss related to any contingent
liability, if any, we might have for civil penalties under the 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 to be
determined by the court. If we do not prevail, we believe we can recover any
capital and operating costs of additional pollution control equipment that
may
be required through regulated rates and market prices for electricity. If we
are
unable to recover such costs or if material penalties are imposed, it would
adversely affect future results of operations, cash flows and possibly financial
condition.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Management’s Financial Discussion
and Analysis of Results of Operations” in the 2006 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
FIN
48
clarifies the accounting for uncertainty in income taxes recognized in an
enterprise’s financial statements by prescribing a recognition threshold
(whether a tax position is more likely than not to be sustained) without which,
the benefit of that position is not recognized in the financial statements.
It
requires a measurement determination for recognized tax positions based on
the
largest amount of benefit that is greater than 50 percent likely of being
realized upon ultimate settlement. FIN 48 also provides guidance on
derecognition, classification, interest and penalties, accounting in interim
periods, disclosure and transition. FIN 48 requires that the cumulative effect
of applying this interpretation be reported and disclosed as an adjustment
to
the opening balance of retained earnings for that fiscal year and presented
separately. We adopted FIN 48 effective January 1, 2007. The effect of this
interpretation on our financial statements was an unfavorable adjustment to
retained earnings of $17 million. See “FIN 48 “Accounting for Uncertainty in
Income Taxes” and FASB Staff Position FIN 48-1 "Definition of Settlement in
FASB Interpretation No. 48"" section of Note 2 and see Note 8 - Income
Taxes.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
As
a
major power producer and marketer of wholesale electricity, coal and emission
allowances, our Utility Operations segment is exposed to certain market risks.
These risks include commodity price risk, interest rate risk and credit risk.
In
addition, we may be exposed to foreign currency exchange risk because
occasionally we procure various services and materials used in our energy
business from foreign suppliers. These risks represent the risk of loss that
may
impact us due to changes in the underlying market prices or rates.
All
Other
includes gas operations which holds forward gas contracts that were not sold
with the gas pipeline and storage assets. These contracts are primarily
financial derivatives, along with physical contracts, which will gradually
liquidate and completely expire in 2011. Our risk objective is to keep these
positions generally risk neutral through maturity.
Our
Generation and Marketing segment holds power sale contracts to commercial and
industrial customers and wholesale power trading and marketing contracts within
ERCOT.
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 determined by the commercial
operations group in accordance with the market risk policy approved by the
Finance Committee of our Board of Directors. Our market risk management staff
independently monitors our risk policies, procedures and risk levels and
provides members of the Commercial Operations Risk Committee (CORC) various
daily, weekly and/or monthly reports regarding compliance with policies, limits
and procedures. The CORC consists of our President - AEP Utilities, Chief
Financial Officer, Senior Vice President of Commercial Operations and Treasurer.
When commercial activities exceed predetermined limits, we modify the positions
to reduce the risk to be within the limits unless specifically approved by
the
CORC.
We
actively participate in the Committee of Chief Risk Officers (CCRO) to develop
standard disclosures for risk management activities around risk management
contracts. The CCRO adopted disclosure standards for risk management contracts
to improve clarity, understanding and consistency of information reported.
We
support the work of the CCRO and embrace the disclosure standards applicable
to
our business activities. The following tables provide information on our risk
management activities.
Mark-to-Market
Risk Management Contract Net Assets (Liabilities)
The
following two tables summarize the various mark-to-market (MTM) positions
included on our condensed balance sheet as of March 31, 2007 and the reasons
for
changes in our total MTM value included on our condensed balance sheet as
compared to December 31, 2006.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
March
31, 2007
(in
millions)
|
Utility
Operations
|
|
Generation
and
Marketing
|
|
All
Other
|
|
Sub-Total
MTM Risk Management Contracts
|
|
PLUS:
MTM of Cash Flow and Fair Value Hedges
|
|
Total
|
|
Current
Assets
|
$
|
319
|
|
$
|
30
|
|
$
|
121
|
|
$
|
470
|
|
$
|
6
|
|
$
|
476
|
|
Noncurrent
Assets
|
|
210
|
|
|
21
|
|
|
110
|
|
|
341
|
|
|
10
|
|
|
351
|
|
Total
Assets
|
|
529
|
|
|
51
|
|
|
231
|
|
|
811
|
|
|
16
|
|
|
827
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
(228
|
)
|
|
(35
|
)
|
|
(120
|
)
|
|
(383
|
)
|
|
(20
|
)
|
|
(403
|
)
|
Noncurrent
Liabilities
|
|
(92
|
)
|
|
(8
|
)
|
|
(117
|
)
|
|
(217
|
)
|
|
(2
|
)
|
|
(219
|
)
|
Total
Liabilities
|
|
(320
|
)
|
|
(43
|
)
|
|
(237
|
)
|
|
(600
|
)
|
|
(22
|
)
|
|
(622
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative
Contract
Net Assets
(Liabilities)
|
$
|
209
|
|
$
|
8
|
|
$
|
(6
|
)
|
$
|
211
|
|
$
|
(6
|
)
|
$
|
205
|
|
MTM
Risk Management Contract Net Assets (Liabilities)
Three
Months Ended March 31, 2007
(in
millions)
|
|
Utility
Operations
|
|
Generation
and
Marketing
|
|
All
Other
|
|
Total
|
|
Total
MTM Risk Management Contract Net Assets (Liabilities) at
December 31, 2006
|
|
$
|
236
|
|
$
|
2
|
|
$
|
(5
|
)
|
$
|
233
|
|
(Gain)
Loss from Contracts Realized/Settled During
the Period and Entered in a Prior Period
|
|
|
(23
|
)
|
|
-
|
|
|
-
|
|
|
(23
|
)
|
Fair
Value of New Contracts at Inception When Entered
During
the Period (a)
|
|
|
1
|
|
|
3
|
|
|
-
|
|
|
4
|
|
Net
Option Premiums Paid/(Received) for Unexercised or
Unexpired Option Contracts Entered During The
Period
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Changes
in Fair Value Due to Valuation Methodology
Changes
on Forward Contracts
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During
the
Period (b)
|
|
|
5
|
|
|
3
|
|
|
(1
|
)
|
|
7
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions
(c)
|
|
|
(10
|
)
|
|
-
|
|
|
-
|
|
|
(10
|
)
|
Total
MTM Risk Management Contract Net Assets
(Liabilities) at March 31, 2007
|
|
$
|
209
|
|
$
|
8
|
|
$
|
(6
|
)
|
|
211
|
|
Net
Cash Flow and Fair Value Hedge Contracts
|
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
Total
MTM Risk Management Contract Net Assets at March 31,
2007
|
|
|
|
|
|
|
|
|
|
|
$
|
205
|
|
(a)
|
Reflects
fair value on long-term contracts which are typically with customers
that
seek fixed pricing to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
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 on the Condensed
Consolidated Statements of Income. These net gains (losses) are recorded
as regulatory assets/liabilities for those subsidiaries that operate
in
regulated jurisdictions.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
(Liabilities)
The
following table presents:
·
|
The
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, to give an indication
of
when these MTM amounts will settle and generate
cash.
|
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets (Liabilities)
Fair
Value of Contracts as of March 31, 2007
(in
millions)
|
|
Remainder
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
After
2011
|
|
Total
|
|
Utility
Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
14
|
|
$
|
1
|
|
$
|
2
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
17
|
|
Prices
Provided by Other External Sources
-
OTC
Broker Quotes (a)
|
|
|
85
|
|
|
50
|
|
|
33
|
|
|
14
|
|
|
-
|
|
|
-
|
|
|
182
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(18
|
)
|
|
(7
|
)
|
|
9
|
|
|
17
|
|
|
4
|
|
|
5
|
|
|
10
|
|
Total
|
|
$
|
81
|
|
$
|
44
|
|
$
|
44
|
|
$
|
31
|
|
$
|
4
|
|
$
|
5
|
|
$
|
209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
and Marketing:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted - Exchange Traded Contracts
|
|
$
|
(5
|
)
|
$
|
(4
|
)
|
$
|
1
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(8
|
)
|
Prices
Provided by Other External Sources
-
OTC Broker Quotes (a)
|
|
|
(3
|
)
|
|
8
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
6
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
3
|
|
|
6
|
|
|
(1
|
)
|
|
-
|
|
|
-
|
|
|
2
|
|
|
10
|
|
Total
|
|
$
|
(5
|
)
|
$
|
10
|
|
$
|
1
|
|
$
|
-
|
|
$
|
-
|
|
$
|
2
|
|
$
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted - Exchange Traded Contracts
|
|
$
|
4
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
4
|
|
Prices
Provided by Other External Sources
-
OTC Broker Quotes (a)
|
|
|
(3
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(3
|
)
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
-
|
|
|
(1
|
)
|
|
(4
|
)
|
|
(4
|
)
|
|
2
|
|
|
-
|
|
|
(7
|
)
|
Total
|
|
$
|
1
|
|
$
|
(1
|
)
|
$
|
(4
|
)
|
$
|
(4
|
)
|
$
|
2
|
|
$
|
-
|
|
$
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
13
|
|
$
|
(3
|
)
|
$
|
3
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
13
|
|
Prices
Provided by Other External Sources
-
OTC Broker Quotes (a)
|
|
|
79
|
|
|
58
|
|
|
34
|
|
|
14
|
|
|
-
|
|
|
-
|
|
|
185
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(15
|
)
|
|
(2
|
)
|
|
4
|
|
|
13
|
|
|
6
|
|
|
7
|
|
|
13
|
|
Total
|
|
$
|
77
|
|
$
|
53
|
|
$
|
41
|
|
$
|
27
|
|
$
|
6
|
|
$
|
7
|
|
$
|
211
|
|
(a)
|
Prices
Provided by Other External Sources - OTC Broker Quotes reflects
information obtained from over-the-counter brokers (OTC), industry
services, or multiple-party online platforms.
|
(b)
|
Prices
Based on Models and Other Valuation Methods is used in the absence
of
pricing information from external sources. Modeled information is
derived
using valuation models developed by the reporting entity, reflecting
when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity is limited, such valuations are classified as
modeled.
|
|
|
|
Contract
values that are measured using models or valuation methods other
than
active quotes or OTC broker quotes (because of the lack of such data
for
all delivery quantities, locations and periods) incorporate in the
model
or other valuation methods, to the extent possible, OTC broker quotes
and
active quotes for deliveries in years and at locations for which
such
quotes are available.
|
The
determination of the point at which a market is no longer liquid for placing
it
in the modeled category in the preceding table varies by market. The following
table reports an estimate of the maximum tenors (contract maturities) of the
liquid portion of each energy market.
Maximum
Tenor of the Liquid Portion of Risk Management Contracts
As
of March 31, 2007
Commodity
|
|
Transaction
Class
|
|
Market/Region
|
|
Tenor
|
|
|
|
|
|
|
(in
Months)
|
Natural
Gas
|
|
Futures
|
|
NYMEX
/ Henry Hub
|
|
60
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
Gulf
Coast, Texas
|
|
19
|
|
|
|
|
|
|
|
|
|
Swaps
|
|
Northeast,
Mid-Continent, Gulf Coast, Texas
|
|
19
|
|
|
|
|
|
|
|
|
|
Exchange
Option Volatility
|
|
NYMEX
/ Henry Hub
|
|
12
|
|
|
|
|
|
|
|
Power
|
|
Futures
|
|
AEP
East - PJM
|
|
33
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
AEP
East
|
|
45
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
AEP
West
|
|
33
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
West
Coast
|
|
33
|
|
|
|
|
|
|
|
|
|
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
operations. We monitor these risks on our future operations and may use various
commodity instruments designated in qualifying cash flow hedge strategies to
mitigate the impact of these fluctuations on the future cash flows. We do not
hedge all commodity price risk.
We
use
interest rate derivative transactions to manage interest rate risk related
to
existing variable rate debt and to manage interest rate exposure on anticipated
borrowings of fixed-rate debt. We do not hedge all interest rate
exposure.
We
use
forward contracts and collars as cash flow hedges to lock in prices on certain
transactions 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 changes in cash flow hedges from December 31, 2006 to March 31, 2007. The
following table also indicates what portion of designated, effective hedges
are
expected to be reclassified into net income in the next 12 months. Only
contracts designated as cash flow hedges are recorded in AOCI. Therefore,
economic hedge contracts which are not designated as effective cash flow hedges
are marked-to-market and are included in the previous risk management tables.
Total
Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow
Hedges
Three
Months Ended March 31, 2007
(in
millions)
|
|
Power
|
|
Interest
Rate and
Foreign
Currency
|
|
Total
|
|
Beginning
Balance in AOCI, December 31, 2006
|
|
$
|
17
|
|
$
|
(23
|
)
|
$
|
(6
|
)
|
Changes
in Fair Value
|
|
|
(15
|
)
|
|
-
|
|
|
(15
|
)
|
Reclassifications
from AOCI to Net Income for
Cash
Flow Hedges Settled
|
|
|
(7
|
)
|
|
-
|
|
|
(7
|
)
|
Ending
Balance in AOCI, March 31, 2007
|
|
$
|
(5
|
)
|
$
|
(23
|
)
|
$
|
(28
|
)
|
|
|
|
|
|
|
|
|
|
|
|
After
Tax Portion Expected to be Reclassified
to Earnings During Next 12 Months
|
|
$
|
(10
|
)
|
$
|
(1
|
)
|
$
|
(11
|
)
|
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 meets 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
parent/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, 2007, our credit
exposure net of credit collateral to sub investment grade counterparties was
approximately 3.10%, expressed in terms of net MTM assets and net receivables.
As of March 31, 2007, the following table approximates our counterparty credit
quality and exposure based on netting across commodities, instruments and legal
entities where applicable (in millions, except number of
counterparties):
Counterparty
Credit Quality
|
|
Exposure
Before Credit Collateral
|
|
Credit
Collateral
|
|
Net
Exposure
|
|
Number
of Counterparties >10% of
Net
Exposure
|
|
Net
Exposure of Counterparties >10%
|
|
Investment
Grade
|
|
$
|
665
|
|
$
|
102
|
|
$
|
563
|
|
|
1
|
|
$
|
72
|
|
Split
Rating
|
|
|
7
|
|
|
2
|
|
|
5
|
|
|
2
|
|
|
4
|
|
Noninvestment
Grade
|
|
|
7
|
|
|
-
|
|
|
7
|
|
|
2
|
|
|
7
|
|
No
External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internal
Investment Grade
|
|
|
15
|
|
|
-
|
|
|
15
|
|
|
3
|
|
|
11
|
|
Internal
Noninvestment Grade
|
|
|
45
|
|
|
33
|
|
|
12
|
|
|
2
|
|
|
8
|
|
Total
as of March 31, 2007
|
|
$
|
739
|
|
$
|
137
|
|
$
|
602
|
|
|
10
|
|
$
|
102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
as of December 31, 2006
|
|
$
|
998
|
|
$
|
161
|
|
$
|
837
|
|
|
9
|
|
$
|
169
|
|
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, 2009. 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, 2007
|
Remainder
|
|
|
|
|
|
2007
|
|
2008
|
|
2009
|
Estimated
Plant Output Hedged
|
93%
|
|
89%
|
|
90%
|
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, 2007, 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, 2007
|
|
|
|
|
Twelve
Months Ended
December
31, 2006
|
(in
millions)
|
|
|
|
|
(in
millions)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$2
|
|
$6
|
|
$2
|
|
$1
|
|
|
|
|
$3
|
|
$10
|
|
$3
|
|
$1
|
The
High
VaR for 2006 occurred in mid-August during a period of high gas and power
volatility. The following day, positions were flattened and the VaR was
significantly reduced.
Interest
Rate Risk
We
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The volatilities and correlations were based
on
three years of daily prices. The risk of potential loss in fair value
attributable to our exposure to interest rates, primarily related to long-term
debt with fixed interest rates, was $873 million at March 31, 2007 and $870
million at December 31, 2006. 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 INCOME
For
the Three Months Ended March 31, 2007 and 2006
(in
millions, except per-share amounts and shares outstanding)
(Unaudited)
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
Utility
Operations
|
|
$
|
2,886
|
|
$
|
2,982
|
|
Other
|
|
|
283
|
|
|
126
|
|
TOTAL
|
|
|
3,169
|
|
|
3,108
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
886
|
|
|
961
|
|
Purchased
Energy for Resale
|
|
|
246
|
|
|
166
|
|
Other
Operation and Maintenance
|
|
|
938
|
|
|
821
|
|
Gain/Loss
on Disposition of Assets, Net
|
|
|
(23
|
)
|
|
(68
|
)
|
Depreciation
and Amortization
|
|
|
391
|
|
|
348
|
|
Taxes
Other Than Income Taxes
|
|
|
186
|
|
|
191
|
|
TOTAL
|
|
|
2,624
|
|
|
2,419
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
545
|
|
|
689
|
|
|
|
|
|
|
|
|
|
Interest
and Investment Income
|
|
|
23
|
|
|
8
|
|
Carrying
Costs Income
|
|
|
8
|
|
|
30
|
|
Allowance
For Equity Funds Used During Construction
|
|
|
8
|
|
|
6
|
|
Gain
on Disposition of Equity Investments, Net
|
|
|
-
|
|
|
3
|
|
|
|
|
|
|
|
|
|
INTEREST
AND OTHER CHARGES
|
|
|
|
|
|
|
|
Interest
Expense
|
|
|
186
|
|
|
168
|
|
Preferred
Stock Dividend Requirements of Subsidiaries
|
|
|
1
|
|
|
1
|
|
TOTAL
|
|
|
187
|
|
|
169
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE, MINORITY
INTEREST
EXPENSE AND EQUITY EARNINGS
|
|
|
397
|
|
|
567
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
130
|
|
|
189
|
|
Minority
Interest Expense
|
|
|
1
|
|
|
-
|
|
Equity
Earnings of Unconsolidated Subsidiaries
|
|
|
5
|
|
|
-
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS
|
|
|
271
|
|
|
378
|
|
|
|
|
|
|
|
|
|
DISCONTINUED
OPERATIONS, Net of Tax
|
|
|
-
|
|
|
3
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
271
|
|
$
|
381
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
|
|
397,314,642
|
|
|
393,653,162
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations
|
|
$
|
0.68
|
|
$
|
0.96
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
0.01
|
|
TOTAL
BASIC EARNINGS PER SHARE
|
|
$
|
0.68
|
|
$
|
0.97
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
|
|
|
398,552,113
|
|
|
395,580,106
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations
|
|
$
|
0.68
|
|
$
|
0.95
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
0.01
|
|
TOTAL
DILUTED EARNINGS PER SHARE
|
|
$
|
0.68
|
|
$
|
0.96
|
|
|
|
|
|
|
|
|
|
CASH
DIVIDENDS PAID PER SHARE
|
|
$
|
0.39
|
|
$
|
0.37
|
|
|
|
|
|
|
|
|
|
See
Condensed Notes to Condensed Consolidated Financial
Statements.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2007 and December 31, 2006
(in
millions)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
259
|
|
$
|
301
|
|
Other
Temporary Cash Investments
|
|
|
197
|
|
|
425
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
757
|
|
|
676
|
|
Accrued
Unbilled Revenues
|
|
|
304
|
|
|
350
|
|
Miscellaneous
|
|
|
59
|
|
|
44
|
|
Allowance
for Uncollectible Accounts
|
|
|
(31
|
)
|
|
(30
|
)
|
Total Accounts Receivable
|
|
|
1,089
|
|
|
1,040
|
|
Fuel,
Materials and Supplies
|
|
|
942
|
|
|
913
|
|
Risk
Management Assets
|
|
|
476
|
|
|
680
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
22
|
|
|
38
|
|
Margin
Deposits
|
|
|
88
|
|
|
120
|
|
Prepayments
and Other
|
|
|
90
|
|
|
71
|
|
TOTAL
|
|
|
3,163
|
|
|
3,588
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
17,736
|
|
|
16,787
|
|
Transmission
|
|
|
7,094
|
|
|
7,018
|
|
Distribution
|
|
|
11,539
|
|
|
11,338
|
|
Other
(including coal mining and nuclear fuel)
|
|
|
3,423
|
|
|
3,405
|
|
Construction
Work in Progress
|
|
|
2,902
|
|
|
3,473
|
|
Total
|
|
|
42,694
|
|
|
42,021
|
|
Accumulated
Depreciation and Amortization
|
|
|
(15,391
|
)
|
|
(15,240
|
)
|
TOTAL
- NET
|
|
|
27,303
|
|
|
26,781
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
2,385
|
|
|
2,477
|
|
Securitized
Transition Assets
|
|
|
2,134
|
|
|
2,158
|
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,263
|
|
|
1,248
|
|
Goodwill
|
|
|
76
|
|
|
76
|
|
Long-term
Risk Management Assets
|
|
|
351
|
|
|
378
|
|
Employee
Benefits and Pension Assets
|
|
|
316
|
|
|
327
|
|
Deferred
Charges and Other
|
|
|
945
|
|
|
910
|
|
TOTAL
|
|
|
7,470
|
|
|
7,574
|
|
|
|
|
|
|
|
|
|
Assets
Held for Sale
|
|
|
-
|
|
|
44
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
37,936
|
|
$
|
37,987
|
|
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, 2007 and December 31, 2006
(Unaudited)
|
|
|
|
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
millions)
|
|
Accounts
Payable
|
$
|
1,263
|
|
$
|
1,360
|
|
Short-term
Debt
|
|
175
|
|
|
18
|
|
Long-term
Debt Due Within One Year
|
|
1,377
|
|
|
1,269
|
|
Risk
Management Liabilities
|
|
403
|
|
|
541
|
|
Customer
Deposits
|
|
315
|
|
|
339
|
|
Accrued
Taxes
|
|
758
|
|
|
781
|
|
Accrued
Interest
|
|
247
|
|
|
186
|
|
Other
|
|
770
|
|
|
962
|
|
TOTAL
|
|
5,308
|
|
|
5,456
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
Long-term
Debt
|
|
12,525
|
|
|
12,429
|
|
Long-term
Risk Management Liabilities
|
|
219
|
|
|
260
|
|
Deferred
Income Taxes
|
|
4,581
|
|
|
4,690
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
2,759
|
|
|
2,910
|
|
Asset
Retirement Obligations
|
|
1,035
|
|
|
1,023
|
|
Employee
Benefits and Pension Obligations
|
|
829
|
|
|
823
|
|
Deferred
Gain on Sale and Leaseback - Rockport Plant Unit 2
|
|
146
|
|
|
148
|
|
Deferred
Credits and Other
|
|
933
|
|
|
775
|
|
TOTAL
|
|
23,027
|
|
|
23,058
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
28,335
|
|
|
28,514
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
61
|
|
|
61
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
Common
Stock Par Value $6.50:
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
Shares
Authorized
|
|
|
600,000,000
|
|
|
600,000,000
|
|
|
|
|
|
|
|
Shares
Issued
|
|
|
419,667,962
|
|
|
418,174,728
|
|
|
|
|
|
|
|
(21,499,992
shares were held in treasury at March 31, 2007 and December 31, 2006)
|
|
2,728
|
|
|
2,718
|
|
Paid-in
Capital
|
|
4,270
|
|
|
4,221
|
|
Retained
Earnings
|
|
2,795
|
|
|
2,696
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
(253
|
)
|
|
(223
|
)
|
TOTAL
|
|
9,540
|
|
|
9,412
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
37,936
|
|
$
|
37,987
|
|
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, 2007 and 2006
(in
millions)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
271
|
|
$
|
381
|
|
Less:
Discontinued Operations, Net of Tax
|
|
|
-
|
|
|
(3
|
)
|
Income
before Discontinued Operations
|
|
|
271
|
|
|
378
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
391
|
|
|
348
|
|
Deferred
Income Taxes
|
|
|
5
|
|
|
7
|
|
Deferred
Investment Tax Credits
|
|
|
(6
|
)
|
|
(7
|
)
|
Carrying
Costs Income
|
|
|
(8
|
)
|
|
(30
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
22
|
|
|
(9
|
)
|
Amortization
of Nuclear Fuel
|
|
|
16
|
|
|
14
|
|
Deferred
Property Taxes
|
|
|
(67
|
)
|
|
(82
|
)
|
Fuel
Over/Under-Recovery, Net
|
|
|
(62
|
)
|
|
103
|
|
Gain
on Sales of Assets and Equity Investments, Net
|
|
|
(23
|
)
|
|
(71
|
)
|
Change
in Other Noncurrent Assets
|
|
|
44
|
|
|
45
|
|
Change
in Other Noncurrent Liabilities
|
|
|
16
|
|
|
10
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(29
|
)
|
|
214
|
|
Fuel,
Materials and Supplies
|
|
|
(3
|
)
|
|
(50
|
)
|
Margin
Deposits
|
|
|
33
|
|
|
50
|
|
Accounts
Payable
|
|
|
(31
|
)
|
|
(115
|
)
|
Accrued
Taxes
|
|
|
32
|
|
|
176
|
|
Customer
Deposits
|
|
|
(23
|
)
|
|
(157
|
)
|
Other
Current Assets
|
|
|
(40
|
)
|
|
19
|
|
Other
Current Liabilities
|
|
|
(187
|
)
|
|
(260
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
351
|
|
|
583
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(907
|
)
|
|
(765
|
)
|
Change
in Other Temporary Cash Investments, Net
|
|
|
(20
|
)
|
|
27
|
|
Purchases
of Investment Securities
|
|
|
(3,693
|
)
|
|
(2,469
|
)
|
Sales
of Investment Securities
|
|
|
3,929
|
|
|
2,380
|
|
Proceeds
from Sales of Assets
|
|
|
68
|
|
|
111
|
|
Other
|
|
|
(5
|
)
|
|
(34
|
)
|
Net
Cash Flows Used For Investing Activities
|
|
|
(628
|
)
|
|
(750
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Common Stock
|
|
|
54
|
|
|
5
|
|
Change
in Short-term Debt, Net
|
|
|
157
|
|
|
216
|
|
Issuance
of Long-term Debt
|
|
|
247
|
|
|
55
|
|
Retirement
of Long-term Debt
|
|
|
(49
|
)
|
|
(142
|
)
|
Dividends
Paid on Common Stock
|
|
|
(155
|
)
|
|
(146
|
)
|
Other
|
|
|
(19
|
)
|
|
54
|
|
Net
Cash Flows From Financing Activities
|
|
|
235
|
|
|
42
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(42
|
)
|
|
(125
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
301
|
|
|
401
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
259
|
|
$
|
276
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
152
|
|
$
|
159
|
|
Net
Cash Paid for Income Taxes
|
|
|
66
|
|
|
13
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
11
|
|
|
20
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
323
|
|
|
246
|
|
|
|
|
|
|
|
|
|
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, 2007 and 2006
(in
millions)
(Unaudited)
|
|
Common
Stock
|
|
|
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
|
|
|
Shares
|
|
Amount
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
|
Total
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
|
418
|
|
$
|
2,718
|
|
$
|
4,221
|
|
$
|
2,696
|
|
$
|
(223
|
)
|
$
|
9,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
|
(17
|
)
|
|
|
|
|
(17
|
)
|
Issuance
of Common Stock
|
|
|
2
|
|
|
10
|
|
|
44
|
|
|
|
|
|
|
|
|
54
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
(155
|
)
|
|
|
|
|
(155
|
)
|
Other
|
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
5
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22
|
)
|
|
(22
|
)
|
|
Securities
Available for Sale, Net of Tax of $4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
|
(8
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
271
|
|
|
|
|
|
271
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
241
|
|
MARCH
31, 2007
|
|
|
420
|
|
$
|
2,728
|
|
$
|
4,270
|
|
$
|
2,795
|
|
$
|
(253
|
)
|
$
|
9,540
|
|
See Condensed Notes to Condensed Consolidated Financial
Statements.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX
TO CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
|
|
1.
|
Significant
Accounting Matters
|
2.
|
New
Accounting Pronouncements
|
3.
|
Rate
Matters
|
4.
|
Commitments,
Guarantees and Contingencies
|
5.
|
Acquisitions,
Dispositions, Discontinued Operations and Assets Held for
Sale
|
6.
|
Benefit
Plans
|
7.
|
Business
Segments
|
8.
|
Income
Taxes
|
9.
|
Financing
Activities
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT
ACCOUNTING MATTERS
General
The
accompanying unaudited condensed consolidated financial statements and footnotes
were prepared in accordance with accounting principles generally accepted in
the
United States of America (GAAP) for interim financial information and with
the
instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.
Accordingly, they do not include all the information and footnotes required
by
GAAP for complete financial statements.
In
the
opinion of management, the unaudited interim financial statements reflect all
normal and recurring accruals and adjustments necessary for a fair presentation
of our results of operations, financial position and cash flows for the interim
periods. The results of operations for the three months ended March 31, 2007
are
not necessarily indicative of results that may be expected for the year ending
December 31, 2007. The accompanying condensed consolidated financial statements
are unaudited and should be read in conjunction with the audited 2006
consolidated financial statements and notes thereto, which are included in
our
Annual Report on Form 10-K for the year ended December 31, 2006 as filed with
the SEC on February 28, 2007.
Components
of Accumulated Other Comprehensive Income (Loss)
(AOCI)
AOCI
is
included on the Condensed Consolidated Balance Sheets in the common
shareholders’ equity section. The following table provides the components that
constitute the balance sheet amount in AOCI:
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
Components
|
|
(in
millions)
|
|
Securities
Available for Sale, Net of Tax
|
|
$
|
10
|
|
$
|
18
|
|
Cash
Flow Hedges, Net of Tax
|
|
|
(28
|
)
|
|
(6
|
)
|
SFAS
158 Adoption, Net of Tax
|
|
|
(235
|
)
|
|
(235
|
)
|
Total
|
|
$
|
(253
|
)
|
$
|
(223
|
)
|
At
March
31, 2007, we expect to reclassify approximately $11 million of net losses from
cash flow hedges in AOCI to Net Income during the next twelve months at the
time
the hedged transactions affect Net Income. The actual amounts that are
reclassified from AOCI to Net Income can differ as a result of market
fluctuations.
At
March
31, 2007, thirty-nine months
is
the maximum length of time that our exposure to variability in future cash
flows
is hedged with contracts designated as cash flow hedges.
Earnings
Per Share (EPS)
The
following table presents our basic and diluted EPS calculations included on
our
Condensed Consolidated Statements of Income:
|
|
Three
Months Ended March 31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
$/share
|
|
|
|
$/share
|
|
Earnings
Applicable to Common Stock
|
|
$
|
271
|
|
|
|
|
$
|
381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Basic Shares Outstanding
|
|
|
397.3
|
|
$
|
0.68
|
|
|
393.7
|
|
$
|
0.97
|
|
Average
Dilutive Effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
0.6
|
|
|
-
|
|
|
1.4
|
|
|
(0.01
|
)
|
Stock
Options
|
|
|
0.5
|
|
|
-
|
|
|
0.3
|
|
|
-
|
|
Restricted
Stock Units
|
|
|
0.1
|
|
|
-
|
|
|
0.1
|
|
|
-
|
|
Restricted
Shares
|
|
|
0.1
|
|
|
-
|
|
|
0.1
|
|
|
-
|
|
Average
Number of Diluted Shares Outstanding
|
|
|
398.6
|
|
$
|
0.68
|
|
|
395.6
|
|
$
|
0.96
|
|
The
assumed conversion of our share-based compensation does not affect net earnings
for purposes of calculating diluted earnings per share as of March 31,
2007.
Options
to purchase 0.1 million and 0.4 million shares of common stock were outstanding
at March 31, 2007 and 2006, respectively, but were not included in the
computation of diluted earnings per share because the options’ exercise prices
were greater than the quarter-end market price of the common shares and,
therefore, the effect would be antidilutive.
Supplementary
Information
|
|
Three
Months Ended
March
31,
|
|
|
|
2007
|
|
2006
|
|
Related
Party Transactions
|
|
(in
millions)
|
|
AEP
Consolidated Purchased Energy:
|
|
|
|
|
|
Ohio
Valley Electric Corporation (43.47% Owned)
|
|
$
|
49
|
|
$
|
55
|
|
Sweeny
Cogeneration Limited Partnership (50% Owned)
|
|
|
30
|
|
|
34
|
|
AEP
Consolidated Other Revenues - Barging and Other
Transportation Services - Ohio Valley Electric Corporation (43.47%
Owned)
|
|
|
9
|
|
|
7
|
|
Reclassifications
Certain
prior period financial statement items have been reclassified to conform to
current period presentation.
On
our
2006 Condensed Consolidated Statement of Income, we reclassified regulatory
credits related to regulatory asset cost deferral on ARO from Depreciation
and
Amortization to Other Operation and Maintenance to offset the ARO accretion
expense. These reclassifications totaled $7 million for the three months ended
March 31, 2006.
In
our
segment information, we reclassified two subsidiary companies, AEP Texas
Commercial & Industrial Retail GP, LLC and AEP Texas Commercial &
Industrial Retail LP, from the Utility Operations segment to the Generation
and
Marketing segment. Combined revenues for these companies totaled $5 million
for
the three months ended March 31, 2006. As a result, on our 2006 Condensed
Consolidated Statement of Income, we reclassified these revenues from Utility
Operations to Other.
These
revisions had no impact on our previously reported results of operations, cash
flows 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 2007 and standards issued but not implemented that we have determined relate
to our operations.
SFAS
157 “Fair Value Measurements” (SFAS 157)
In
September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair
value measurement of assets and liabilities and instruments measured at fair
value that are classified in shareholders’ equity. The statement defines fair
value, establishes a fair value measurement framework and expands fair value
disclosures. It emphasizes that fair value is market-based with the highest
measurement hierarchy being market prices in active markets. The standard
requires fair value measurements be disclosed by hierarchy level and an entity
include its own credit standing in the measurement of its liabilities and
modifies the transaction price presumption.
SFAS
157
is effective for interim and annual periods in fiscal years beginning after
November 15, 2007. We expect that the adoption of this standard will impact
MTM
valuations of certain contracts, but we are unable to quantify the effect.
Although the statement is applied prospectively upon adoption, the effect of
certain transactions is applied retrospectively as of the beginning of the
fiscal year of application, with a cumulative effect adjustment to the
appropriate balance sheet items. We will adopt SFAS 157 effective January 1,
2008.
SFAS
159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS
159)
In
February 2007, the FASB issued SFAS 159, permitting entities to choose to
measure many financial instruments and certain other items at fair value. The
standard also establishes presentation and disclosure requirements designed
to
facilitate comparison between entities that choose different measurement
attributes for similar types of assets and liabilities.
SFAS
159
is effective for annual periods in fiscal years beginning after November 15,
2007. If the fair value option is elected, the effect of the first remeasurement
to fair value is reported as a cumulative effect adjustment to the opening
balance of retained earnings. If we elect the fair value option promulgated
by
this standard, the valuations of certain assets and liabilities may be impacted.
The statement is applied prospectively upon adoption. We will adopt SFAS 159
effective January 1, 2008.
FIN
48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1
"Definition of Settlement in FASB Interpretation No.
48"
In
July
2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in
Income Taxes” and in May 2007, the FASB issued FASB Staff Position FIN 48-1
“Definition of Settlement
in FASB
Interpretation No. 48.” FIN 48 clarifies the accounting for uncertainty in
income taxes recognized in an enterprise’s financial statements by prescribing a
recognition threshold (whether a tax position is more likely than not to
be
sustained) without which, the benefit of that position is not recognized
in the
financial statements. It requires a measurement determination for recognized
tax
positions based on the largest amount of benefit that is greater than 50
percent
likely of being realized upon ultimate settlement. FIN 48 also provides guidance
on derecognition, classification, interest and penalties, accounting in interim
periods, disclosure and transition.
FIN
48
requires that the cumulative effect of applying this interpretation be reported
and disclosed as an adjustment to the opening balance of retained earnings
for
that fiscal year and presented separately. We adopted FIN 48 effective January
1, 2007, with an unfavorable adjustment to retained earnings of $17
million.
Future
Accounting Changes
The
FASB’s standard-setting process is ongoing and until new standards have been
finalized and issued by FASB, we cannot determine the impact on the reporting
of
our operations and financial position that may result from any such future
changes. The FASB is currently working on several projects including business
combinations, revenue recognition, liabilities and equity, derivatives
disclosures, emission allowances, earnings per share calculations, leases,
insurance, subsequent events and related tax impacts. We also expect to see
more
FASB projects as a result of its desire to converge International Accounting
Standards with GAAP. The ultimate pronouncements resulting from these and future
projects could have an impact on our future results of operations and financial
position.
3. RATE
MATTERS
As
discussed in our 2006 Annual Report, our subsidiaries are involved in rate
and
regulatory proceedings at the FERC and their state commissions. The Rate Matters
note within our 2006 Annual Report should be read in conjunction with this
report to gain a complete understanding of material rate matters still pending
that could impact results of operations, cash flows and possibly financial
condition. The following discusses ratemaking developments in 2007 and updates
the 2006 Annual Report.
Ohio
Rate Matters
Ohio
Restructuring and Rate Stabilization Plans
In
January 2007, CSPCo and OPCo filed with the PUCO under the 4% provision of
their
RSPs to increase their annual generation rates for 2007 by $24 million and
$8
million, respectively, to recover governmentally-mandated costs. Pursuant to
the
RSPs, CSPCo and OPCo implemented these proposed increases effective with the
beginning of the May 2007 billing cycle. These increases are subject to refund
until the PUCO issues a final order in the matter. The hearing is scheduled
to
begin in late May 2007.
In
March
2007, CSPCo filed an application under the 4% provision of the RSP to adjust
the
Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in
connection with CSPCo's acquisition of Monongahela Power Company's certified
territory in Ohio. The PAR is intended to recover the difference between CSPCo's
tariffed generation service rates and the cost of power acquired to serve the
former Monongahela Power load. The PAR was set for an initial 17-month period
of
January 2006 through May 2007. The filing would adjust the PAR for the nineteen
month period of June 2007 through December 2008. The filing reflects a true
up
for estimated under-recoveries during the initial period, $8 million as of
March
31, 2007, as well as the power acquisition costs for the upcoming nineteen-month
period. If approved, CSPCo's revenues would increase by $22 million and $38
million for 2007 and 2008, respectively.
In
March
2007, CSPCo and OPCo filed a settlement agreement at the PUCO resolving the
Ohio
Supreme Court's remand of the PUCO’s RSP order. The Supreme Court indicated
concern with the absence of a competitive bid process as an alternative to
the
generation rates set by the RSP. In response, the settling parties agreed
to
have CSPCo and OPCo take bids for Renewable Energy Certificates (RECs). CSPCo
and OPCo will give customers the option to pay a generation rate premium
that
would encourage the development of renewable energy sources by reimbursing
CSPCo
and OPCo for the cost of the RECs and the administrative costs of the program.
This settlement agreement was supported by the Office of Consumers' Counsel,
the
Ohio Partners for Affordable Energy, the Ohio Energy Group and the PUCO staff.
In May 2007, the PUCO adopted the settlement agreement in its
entirety.
CSPCo
and
OPCo are involved in discussions with various stakeholders in Ohio about
potential legislation to address the period following the expiration of the
RSPs
on December 31, 2008. At this time, management is unable to predict whether
CSPCo and OPCo will transition to market pricing, as permitted by the current
Ohio restructuring legislation, extend their RSP rates, with or without
modification, or become subject to a legislative reinstatement of some form
of
cost-based regulation for their generation supply business on January 1, 2009
when the RSP period ends.
Customer
Choice Deferrals
As
provided in the restructuring settlement agreement approved by the PUCO in
2000,
CSPCo and OPCo established regulatory assets for customer choice implementation
costs and related carrying costs in excess of $20 million each for recovery
in
the next general base rate filing which changes distribution rates after
December 31, 2007 for OPCo and December 31, 2008 for CSPCo. Pursuant to the
RSPs, recovery of these amounts for OPCo was further deferred until the next
base rate filing to change distribution rates after the end of the RSP period
of
December 31, 2008. Through March 31, 2007, CSPCo and OPCo incurred $50 million
and $51 million, respectively, of such costs and established regulatory assets
of $25 million each for such costs. CSPCo and OPCo have not recognized $5
million and $6 million, respectively, of equity carrying costs, which are
recognizable when collected. Management believes that the deferred customer
choice implementation costs were prudently incurred to implement customer choice
in Ohio and are probable of recovery in future distribution rates.
IGCC
Plant
In
March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of cost
recovery associated with the IGCC plant: Phase 1, recovery of $24 million in
pre-construction costs during 2006; Phase 2, concurrent recovery of
construction-financing costs; and Phase 3, recovery or refund in distribution
rates of any difference between the market-based standard service offer price
for generation and the cost of operating and maintaining the plant, including
a
return on and return of the ultimate cost to construct the plant, originally
projected to be $1.2 billion, along with fuel, consumables and replacement
power
costs. The proposed recoveries in Phases 1 and 2 would be applied against the
4%
limit on additional generation rate increases CSPCo and OPCo could request
under
their RSPs.
In
April
2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
1
of the cost recovery proposal. In June 2006, the PUCO issued another order
approving a tariff to recover Phase 1 pre-construction costs over no more than
a
twelve-month period effective July 1, 2006. Through March 31, 2007, CSPCo and
OPCo each recorded pre-construction IGCC regulatory assets of $10 million and
each recovered $9 million of those costs. CSPCo and OPCo will recover the
remaining amounts through June 30, 2007. The PUCO indicated that if CSPCo and
OPCo have not commenced a continuous course of construction of the IGCC plant
within five years of the June 2006 PUCO order, all charges collected for
pre-construction costs, associated with items that may be utilized in IGCC
projects at other sites, must be refunded to Ohio ratepayers with interest.
The
PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings
are
held. A date for further rehearings has not been set.
In
August
2006, the Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy
Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order
in the IGCC proceeding. Management believes that the PUCO’s authorization to
begin collection of Phase 1 rates is lawful. Management, however, cannot predict
the outcome of these appeals. If the PUCO’s order is found to be unlawful, CSPCo
and OPCo could be required to refund Phase I cost-related
recoveries.
Distribution
Reliability Plan
In
January 2006, CSPCo and OPCo initiated a proceeding at the PUCO seeking a new
distribution rate rider to fund enhanced distribution reliability programs.
In
the fourth quarter of 2006, as directed by the PUCO, CSPCo and OPCo filed a
proposed enhanced reliability plan. The plan contemplated CSPCo and OPCo
recovering approximately $28 million and $43 million, respectively, in
additional distribution revenue during an eighteen month period beginning July
2007. In January 2007, the OCC filed testimony, which argued that CSPCo and
OPCo
should be required to improve distribution service reliability with funds from
their existing rates.
In
April
2007, CSPCo and OPCo filed a joint motion with the PUCO staff, the Ohio
Consumers’ Counsel, the Appalachian People’s Action Coalition, the Ohio Partners
for Affordable Energy and the Ohio Manufacturers Association to withdraw the
proposed enhanced reliability plan.
Ormet
Effective
January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial
customer with a 520 MW load, under a PUCO encouraged settlement agreement.
The
settlement agreement between CSPCo and OPCo, Ormet, its employees’ union and
certain other interested parties was approved by the PUCO in November 2006.
The
settlement agreement provides for the recovery in 2007 and 2008 by CSPCo and
OPCo of the difference between $43 per MWH to be paid by Ormet for power and
a
PUCO approved market price, if higher. The recovery will be accomplished by
the
amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo)
Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if
that
is not sufficient, an increase in RSP generation rates under the additional
4%
provision of the RSPs. The $43 per MWH price to be paid by Ormet for generation
services is above the industrial RSP generation tariff but below current market
prices. In December 2006, CSPCo and OPCo submitted a market price of $47.69
per
MWH for 2007, which is pending PUCO approval. If the PUCO approves a lower
market price, it could have an adverse effect on results of operations and
cash
flows. If CSPCo and OPCo serve the Ormet load after 2008 without any special
provisions, they could experience incremental costs to acquire additional
capacity to meet their reserve requirements and/or forgo off-system sales
margins, which could have an adverse effect on future results of operations
and
cash flows.
Texas
Rate Matters
TCC
TEXAS RESTRUCTURING
Texas
District Court Appeal Proceedings
TCC
recovered its net recoverable stranded generation costs through a
securitization financing and is refunding its net other true-up items
through a CTC rate rider credit under 2006 PUCT orders. TCC appealed the PUCT
stranded costs true-up orders seeking relief in both state and federal court
on
the grounds that certain aspects of the orders are contrary to the Texas
Restructuring Legislation, PUCT rulemakings, federal law and fail to fully
compensate TCC for its net stranded cost and other true-up items. The
significant items appealed by TCC are:
·
|
The
PUCT ruling that TCC did not comply with the statute and PUCT rules
regarding the required auction of 15% of its Texas jurisdictional
installed capacity, which led to a significant disallowance of capacity
auction true-up revenues,
|
·
|
The
PUCT ruling that TCC acted in a manner that was commercially unreasonable,
because it failed to determine a minimum price at which it would
reject
bids for the sale of its nuclear generating plant and it bundled
out of
the money gas units with the sale of its coal unit, which led to
the
disallowance of a significant portion of TCC’s net stranded generation
plant cost, and
|
·
|
The
two federal matters regarding the allocation of off-system sales
related
to fuel recoveries and the potential tax normalization violation.
See
“TCC
and TNC Deferred Fuel” and“TCC
Deferred Investment Tax Credits and Excess Deferred Federal Income
Taxes”
sections below.
|
Municipal
customers and other intervenors also appealed the PUCT true-up orders seeking
to
further reduce TCC’s true-up recoveries. On February 1, 2007, the Texas District
Court judge hearing the various appeals issued a letter containing his
preliminary determinations. He generally affirmed the PUCT’s April 4, 2006 final
true-up order for TCC with two significant exceptions. The judge determined
that
the PUCT erred when it determined TCC’s stranded cost using the sale of assets
method instead of the Excess Cost Over Market (ECOM) method to value TCC’s
nuclear plant. The judge also determined that the PUCT erred when it concluded
it was required to use the carrying cost rate specified in the true-up order.
However, the District Court did not rule that the carrying cost rate was
inappropriate. The judge directed that these matters should be remanded to
the
PUCT to determine the specific impact on TCC’s future true-up
revenues.
In
March
2007, the District Court judge reversed his earlier preliminary decision and
concluded the sale of assets method to value TCC’s nuclear plant was
appropriate. The District Court judge did not reconsider his preliminary ruling
that the PUCT erred when it concluded it was required to use the carrying cost
rate specified in the true-up order. The District Court judge also determined
the PUCT improperly reduced TCC’s net stranded plant costs from the sale of its
generating units through the commercial unreasonableness disallowance, which
could have a materially favorable effect on TCC. Management cannot predict
the
ultimate outcome of any future court appeals or any future remanded PUCT
proceeding. If the District Court’s carrying cost rate remand ruling is
ultimately upheld on appeal and remanded to the PUCT for reconsideration, the
PUCT could either confirm the existing weighted average carrying cost (WACC)
rate or redetermine a new rate. If the PUCT changes the rate, it could result
in
a material adverse change to TCC’s recoverable carrying costs, results of
operations, cash flows and financial condition. TCC, the PUCT and intervenors
appealed the District Court ruling to the Court of Appeals. Management cannot
predict what actions, if any, the PUCT will take regarding the carrying
costs.
If
TCC
ultimately succeeds in its appeals, it could have a favorable effect on future
results of operations, cash flows and financial condition. If municipal
customers and other intervenors succeed in their appeals, it could have a
substantial adverse effect on future results of operations, cash flows and
financial condition.
OTHER
TEXAS RESTRUCTURING MATTERS
TCC
Deferred Investment Tax Credits and Excess Deferred Federal Income
Taxes
In
TCC’s
2006 true-up and securitization orders, the PUCT reduced net regulatory assets
and the amount to be securitized by $51 million related to the present value
of
ADITC and by $10 million related to EDFIT associated with TCC’s generation
assets for a total reduction of $61 million.
TCC
filed
a request for a private letter ruling with the IRS in June 2005 regarding the
permissibility under the IRS rules and regulations of the ADITC and EDFIT
reduction proposed by the PUCT. The IRS issued its private letter ruling in
May
2006, which stated that the PUCT’s flow-through to customers of the present
value of the ADITC and EDFIT benefits would result in a normalization violation.
To address the matter and avoid a normalization violation, the PUCT agreed
to
allow TCC to defer an amount of the CTC refund totaling $103 million ($61
million in present value of ADITC and EDFIT associated with TCC’s generation
assets plus $42 million of related carrying costs) pending resolution of the
normalization issue. If
it is
ultimately determined that a refund to customers through the true-up process
of
the ADITC and EDFIT, discussed above, is not a normalization violation, then
TCC
will be required to refund the $103 million, plus additional carrying costs.
However, if such refund of ADITC and EDFIT is ultimately determined to cause
a
normalization violation, TCC anticipates it will be permitted to retain the
$61
million present value of ADITC and EDFIT plus carrying costs, favorably
impacting future results of operations.
If
a
normalization violation occurs, it could result in TCC’s repayment to the IRS of
ADITC on all property, including transmission and distribution property, which
approximates $104 million as of March 31, 2007, and a loss of TCC’s right to
claim accelerated tax depreciation in future tax returns. Tax counsel advised
management that a normalization violation should not occur until all remedies
under law have been exhausted and the tax benefits are returned to ratepayers
under a nonappealable order. Management intends to continue its efforts to
avoid
a normalization violation that would adversely affect future results of
operations and cash flows.
TCC
and TNC Deferred Fuel
The
TCC
deferred fuel over-recovery regulatory liability is a component of the other
true-up items net regulatory liability refunded through the CTC rate rider
credit. In 2002, TCC and TNC filed with the PUCT seeking to reconcile fuel
costs
and establish their final deferred fuel balances. In its final fuel
reconciliation orders, the PUCT ordered a reduction in TCC’s and TNC’s
recoverable fuel costs for, among other things, the reallocation of additional
AEP System off-system sales margins under a FERC-approved SIA. Both TCC and
TNC
appealed the PUCT’s rulings regarding a number of issues in the fuel orders in
state court and challenged the jurisdiction of the PUCT over the allocation
of
off-system sales margin allocations in the federal court. Intervenors also
appealed the PUCT’s rulings in state court.
In
2006,
the Federal District Court issued orders precluding the PUCT from enforcing
the
off-system sales reallocation portion of its ruling in the final TNC and TCC
fuel reconciliation proceedings. The Federal court ruled, in both cases, that
the FERC, not the PUCT, has jurisdiction over the allocation. The PUCT appealed
both Federal District Court decisions to the United States Court of Appeals.
In
TNC’s case, the Court of Appeals affirmed the District Court’s decision. The
PUCT has indicated they will appeal this ruling to the United States Supreme
Court. TCC has filed a Motion for Summary Affirmance based on the outcome of
the
TNC appeal. For TCC, the PUCT has conceded the issue concerning the allocation
of off-system sales margins to AEP West companies under the SIA as governed
by
the TNC case. However, the PUCT continues to challenge the allocation of those
margins among AEP West companies under the CSW Operating Agreement. If the
PUCT’s appeals are ultimately unsuccessful, TCC and TNC could record income of
$16 million and $8 million, respectively, related to the reversal of the
previously recorded fuel over-recovery regulatory liabilities.
If
the
PUCT is unsuccessful in the federal court system, it or another interested
party
may file a complaint at the FERC to address the allocation issue. If a complaint
at the FERC results in the PUCT’s decisions being adopted by the FERC, there
could be an adverse effect on results of operations and cash flows. An
unfavorable FERC ruling may result in a retroactive reallocation of off-system
sales margins from AEP East companies to AEP West companies under the then
existing SIA allocation method. If the adjustments were applied retroactively,
the AEP East companies may be unable to recover the amounts reallocated to
the
West companies from their customers due to past frozen rates, past inactive
fuel
clauses and fuel clauses that do not include off-system sales credits. Although
management cannot predict the ultimate outcome of this federal litigation,
management believes that its allocations were in accordance with the then
existing FERC-approved SIA and that it should not have to allocate additional
off-system sales margins to the West companies including TCC and TNC.
In
January 2007, TCC began refunding as part of the CTC rate rider credit described
above, $149 million of its $165 million over-recovered deferred fuel regulatory
liability. The remaining $16 million refund related to the favorable Federal
District Court order has been deferred pending the outcome of the federal court
appeal and would be subject to refund only upon a successful appeal by the
PUCT.
Excess
Earnings
In
2005,
the Texas Court of Appeals issued a decision finding the PUCT’s prior order from
the unbundled cost of service case requiring TCC to refund excess earnings
prior
to and outside of the true-up process was unlawful under the Texas Restructuring
Legislation. TCC refunded $55 million of excess earnings, including interest,
of
which $30 million went to the affiliated REP. In November 2005, the PUCT filed
a
petition for review with the Supreme Court of Texas seeking reversal of the
Texas Court of Appeals’ decision. The Supreme Court of Texas requested briefing,
which has been provided, but it has not decided whether it will hear the case.
If
the
Court of Appeals decision is upheld and the refund mechanism is found to be
unlawful, the impact on TCC would then depend on: (a) how and if TCC is ordered
by the PUCT to refund the excess earnings through the true-up process to
ultimate customers and (b) whether TCC will be able to recover the amounts
previously refunded to the REPs including the REP TCC sold to Centrica.
Management
is unable to predict the ultimate outcome of this litigation and its effect
on
future results of operations and cash flows.
OTHER
TEXAS RATE MATTERS
TCC
and TNC Energy Delivery Base Rate Filings
TCC
and
TNC each filed a base rate case seeking to increase transmission and
distribution energy delivery services (wires) base rates in Texas. TCC and
TNC
requested $81 million and $25 million in annual increases, respectively. Both
requests include a return on common equity of 11.25% and the impact of the
expiration of the CSW merger savings rate credits. In March 2007, various
intervenors and the PUCT staff filed their recommendations. Though the
recommendations varied, the range of recommended increase was $8 million to
$30
million for TCC and $1 million to $14 million for TNC. The recommended return
on
common equity ranged from 9.00% to 9.75%. In April 2007, TCC and TNC filed
rebuttal testimony reducing the requested annual increases to $70 million for
TCC and $22 million for TNC including a reduced requested return on common
equity of 10.75%. Hearings began in April 2007 and are scheduled to conclude
in
May 2007. Management
expects the new base wires rates to become effective, subject to refund, in
the
second quarter of 2007 with a decision from the PUCT expected in the third
quarter of 2007. Management
is unable to predict the ultimate effect of this filing on future results of
operations, cash flows and financial condition.
SWEPCo
Fuel Reconciliation - Texas
In
June
2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas
retail operations. SWEPCo sought, in the proceedings, to include
under-recoveries related to the reconciliation period of $50 million. In January
2007, intervenors filed testimony recommending that SWEPCo’s reconcilable fuel
costs be reduced. The intervenor recommendations ranged from a $10 million
to
$28 million reduction. In February 2007, the PUCT staff filed testimony
recommending that SWEPCo’s reconcilable fuel costs be reduced by $10 million.
SWEPCo does not agree with the intervenor’s or staff’s recommendations and filed
rebuttal testimony in February 2007. Hearings have been held and briefs have
been filed. Results of operations could be adversely affected by $28 million
plus carrying costs if the PUCT adopts all of the intervenor and staff
recommendations. Management is unable to predict the outcome of this proceeding
or its effect on future results of operations and cash flows.
Virginia
Rate Matters
Virginia
Restructuring
In
April
2004, Virginia enacted legislation that extended the transition period for
electricity restructuring, including capped rates, through December 31, 2010.
The legislation provides APCo with specified cost recovery opportunities during
the capped rate period, including two optional bundled general base rate changes
and an opportunity for timely recovery, through a separate rate mechanism,
of
certain incremental environmental and reliability costs incurred on and after
July 1, 2004. Under the restructuring law, APCo continues to have an active
fuel
clause recovery mechanism in Virginia and continues to practice deferred fuel
accounting. Also, under the restructuring law, APCo defers incremental
environmental generation costs and incremental transmission and distribution
reliability costs for future recovery, to the extent such costs are not being
recovered when incurred, and amortizes a portion of such deferrals commensurate
with recovery.
In
April
2007, the Virginia legislature adopted a comprehensive law providing for the
re-regulation of electric utilities’ generation/supply rates. The amendments
shorten the transition period by two years (from 2010 to 2008) after which
rates
for retail generation/supply will return to a form of cost-based regulation.
The
legislation provides for, among other things, biennial rate reviews beginning
in
2009, rate adjustment clauses for the recovery of the costs of (a) transmission
services and new transmission investment, (b) Demand Side Management, load
management, and energy efficiency programs, (c) renewable energy programs,
and
(d) environmental retrofit and new generation investments, significant return
on
equity enhancements for large investments in new generation and, subject to
Virginia SCC approval, certain environmental retrofits, and a floor on the
allowed return on equity based on the average earned return on equities’ of
regional vertically integrated electric utilities. Effective July 1, 2007,
the
amendments allow utilities to retain a minimum of 25% of the margins from
off-system sales with the remaining margins from such sales credited against
fuel factor expenses. The legislation also allows APCo to continue to defer
and
recover incremental environmental and reliability costs incurred through
December 31, 2008. APCo expects this new form of cost-based ratemaking should
improve its annual return on equity and cash flow from operations when new
ratemaking begins in 2009. However, with the return of cost-based regulation,
APCo’s generation business will again meet the criteria for application of
regulatory accounting principles under SFAS 71. Results of operations and
financial condition could be adversely affected when APCo is required to
re-establish certain net regulatory liabilities applicable to its
generation/supply business. The timing and earnings effect from such
reapplication of SFAS 71 regulatory accounting for APCo’s Virginia
generation/supply business are uncertain at this time.
APCo
Virginia Base Rate Case
In
May
2006, APCo filed a request with the Virginia SCC seeking an increase in base
rates of $225 million to recover increasing costs including the cost of its
investment in environmental equipment and a return on equity of 11.5%. In
addition, APCo requested to move off-system sales margins, currently credited
to
customers through base rates, to the fuel factor where they can be trued-up
to
actual. APCo also proposed to share the off-system sales margins with customers
with 40% going to reduce rates and 60% being retained by APCo. This proposed
off-system sales fuel rate credit, which is estimated to be $27 million,
partially offsets the $225 million requested increase in base rates for a net
increase in base rate revenues of $198 million. The major components of the
$225
million base rate request include $73 million for the impact of removing
off-system sales margins from the rate year ending September 30, 2007, $60
million mainly due to projected net environmental plant additions through
September 30, 2007 and $48 million for return on equity.
In
May
2006, the Virginia SCC issued an order, consistent with Virginia law, placing
the net requested base rate increase of $198 million into effect on October
2,
2006, subject to refund. The $198 million base rate increase being collected,
subject to refund, includes recovery of incremental environmental
compliance and transmission and distribution system reliability (E&R)
costs
projected to be incurred during the rate year beginning October 2006. These
incremental E&R costs can be deferred and recovered through the E&R
surcharge mechanism if not recovered through this base rate request. In October
2006, the Virginia SCC staff filed its direct testimony recommending a base
rate
increase of $13 million with a return on equity of 9.9% and no off-system sales
margin sharing. Other intervenors have recommended base rate increases ranging
from $42 million to $112 million. APCo filed rebuttal testimony in November
2006. Hearings were held in December 2006.
In
March
2007, the Hearing Examiner (HE) issued a report recommending a $76 million
increase in APCo’s base rates and $45 million credit to the fuel factor for
off-system sales margins. The HE’s recommendations include a return on equity of
10.1% which would reduce APCo’s revenue requirement by approximately $23
million. The HE also recommended limiting forward looking ratemaking adjustments
to June 30, 2006 as opposed to September 30, 2007, which would reduce APCo’s
revenue requirement by approximately $72 million, of which approximately $60
million relates to incremental E&R costs that can be deferred for future
recovery through the E&R surcharge mechanism. The HE further proposed to
share the off-system sales margins using the twelve months ended June 30, 2006
of $101 million with 50% reducing base rates, 45% reducing fuel rates and 5%
retained by APCo to determine the revenue requirement. APCo’s proposal did not
reduce base rates for off-system sales margins, but reduced fuel rates
approximately $27 million for off-system sales margins. APCo expects a final
order to be issued during 2007.
APCo
is
providing for a possible refund of revenues collected subject to refund
consistent with the HE recommendations. Management is unable to predict the
ultimate effect of this filing on future results of operations, cash flows
and
financial condition.
West
Virginia Rate Matters
APCo
and WPCo ENEC Filing
In
April
2007, the WVPSC issued an order establishing an investigation and hearing of
APCo’s and WPCo’s 2007 Expanded Net Energy Cost (ENEC) compliance filing.
The ENEC is an expanded form of fuel clause mechanism, which includes all
energy-related costs including fuel, purchased power expenses, off-system sales
credits and other energy/transmission items. In the March 2007 ENEC joint
filing, APCo and WPCo filed for an increase of approximately $101 million
including a $72 million increase in ENEC and a $29 million increase in
construction surcharges to become effective July 1, 2007. A hearing on the
compliance filing is scheduled for May 2007.
APCo
IGCC
In
January 2006, APCo filed a petition with the WVPSC requesting its approval
of a
Certificate of Public Convenience and Necessity to construct a 629 MW IGCC
plant
adjacent to APCo’s existing Mountaineer Generating Station in Mason County, WV.
In January 2007, at APCo’s request, the WVPSC issued an order delaying the
Commission’s deadline for issuing an order on the certificate to December 2007.
Through March 31, 2007, APCo deferred pre-construction IGCC costs totaling
$10
million. If the plant is not built and these costs are not recoverable, future
results of operations and cash flows would be adversely affected.
Indiana
Rate Matters
I&M
Depreciation Study Filing
In
February 2007, I&M filed a request with the IURC for approval of revised
book depreciation rates effective January 1, 2007. The filing included a
settlement agreement entered into with the Indiana Office of the Utility
Consumer Counsel that would provide direct benefits to I&M's customers if
new depreciation rates are approved by the IURC. The direct benefits would
include a $5 million credit to fuel costs and an approximate $8 million smart
metering pilot program. In addition, if the agreement is approved, I&M would
initiate a general rate proceeding on or before July 1, 2007 and initiate two
studies, one to investigate a general smart metering program and the other
to
study the market viability of demand side management programs. Based on the
depreciation study included in the filing, I&M recommended a decrease in
pretax annual depreciation expense on an Indiana jurisdictional basis of
approximately $69 million reflecting an NRC-approved 20-year extension of the
Cook Plant licenses for Units 1 and 2 and an extension of the service life
of
the Tanners Creek coal-fired generating units. This petition was not a request
for a change in customers’ electric service rates. As proposed, the book
depreciation reduction would increase earnings but would not impact cash flows
until rates are revised. The IURC held a public hearing in April 2007. I&M
requested expeditious review and approval of its filing, but management cannot
predict the outcome of the request or the timing of any approved depreciation
reduction. If approved as filed, pretax earnings would increase by $64 million
in 2007.
Kentucky
Rate Matters
KPCo
Environmental Surcharge Filing
In
July
2006, KPCo filed for
approval of an
amended environmental compliance plan and revised tariff to implement an
adjusted environmental surcharge. KPCo
estimates the amended environmental compliance plan and revised tariff would
increase revenues over 2006 levels by approximately $2 million in 2007 and
$6
million in 2008 for a total of $8 million of additional revenue at current
cost
projections. In January 2007, the KPSC issued an order approving KPCo’s proposed
plan and surcharge. Future recovery is based upon actual environmental costs
and
is subject to periodic review and approval of those actual costs by the
KPSC.
In
November 2006, the Kentucky Attorney General and the Kentucky Industrial Utility
Consumers (KIUC) filed an appeal with the Kentucky Court of Appeals of the
Franklin Circuit Court’s 2006 order upholding the KPSC’s 2005 Environmental
Surcharge order. In its order, the KPSC approved KPCo’s recovery of its
environmental costs at its Big Sandy Plant and its share of environmental costs
incurred as a result of the AEP Power Pool capacity settlement. The KPSC has
allowed KPCo to recover these FERC-approved allocated costs, via the
environmental surcharge, since the KPSC’s first environmental surcharge order in
1997. KPCo presently recovers $7 million a year in environmental surcharge
revenues.
In
March
2007, the KPSC issued an order, at the request of the Kentucky Attorney General,
stating the environmental surcharge collections authorized in the January 2007
order that are associated with out-of-state generating facilities should be
collected over the six months beginning March 2007, subject to refund, pending
the outcome of the court of appeals process. At this time, management is unable
to predict the outcome of this proceeding and its effect on KPCo’s current
environmental surcharge revenues or on the January 2007 KPSC order increasing
KPCo’s environmental rates.
Oklahoma
Rate Matters
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
eighteen months. In August 2003, the OCC staff filed testimony recommending
PSO
recover $42 million of the reallocated purchased power costs over three years
and PSO reduced its regulatory asset deferral by $2 million. The OCC
subsequently expanded the case to include a full prudence review of PSO’s 2001
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 the
proposed reallocation of off-system sales margins of $27 million to $37 million
and with $9 million attributed to wholesale customers, which they claimed had
not been refunded. In February 2006, the OCC staff filed a report concluding
that the $9 million of reallocated purchased power costs assigned to wholesale
customers had been refunded, thus removing that issue from its
recommendation.
In
2004,
an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO
deviated from the FERC-approved allocation methodology and held that any such
complaints should be addressed at the FERC. The OCC has not ruled on appeals
by
intervenors of the ALJ’s finding. The United States District Court for the
Western District of Texas issued orders in September 2005 regarding a TNC fuel
proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the
PUCT from reallocating off-system sales margins between the AEP East companies
and AEP West companies. The federal court agreed that the FERC has sole
jurisdiction over that allocation. The PUCT appealed the ruling. The United
States Court of Appeals for the Fifth Circuit, issued a decision in December
2006 regarding the TNC fuel proceeding that affirmed the United States District
Court ruling.
PSO
does
not agree with the intervenors’ and the OCC staff’s recommendations and
proposals other than the staff’s original recommendation that PSO be allowed to
recover the $42 million over three years and will defend its right to recover
its under-recovered fuel balance. Management believes that if the position
taken
by the federal courts in the Texas proceeding is applied to PSO’s case, then the
OCC should 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 could file a complaint at the FERC alleging
the allocation of off-system sales margins to 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. However, to date, there has been no claim
asserted at the FERC that AEP deviated from the approved allocation
methodologies, but even if one were asserted, management believes that it would
not prevail.
In
June
2005, the OCC issued an order directing its staff to conduct a prudence review
of PSO’s fuel and purchased power practices for the year 2003. The OCC staff
filed testimony finding no disallowances in the test year data. The Attorney
General of Oklahoma filed testimony stating that they could not determine if
PSO’s gas procurement activities were prudent, but did not include a recommended
disallowance. However, an intervenor filed testimony in June 2006 proposing
the
disallowance of $22 million in fuel costs based on a historical review of
potential hedging opportunities that he alleges existed during the year. A
hearing was held in August 2006 and management expects a recommendation from
the
ALJ in 2007.
In
February 2006, a law was enacted requiring the OCC to conduct prudence reviews
on all generation and fuel procurement processes, practices and costs on either
a two or three-year cycle depending on the number of customers served. PSO
is
subject to the required biennial reviews. In compliance with an OCC order,
PSO
is required to file its testimony by June 15, 2007. This proceeding will cover
the year 2005.
Management
cannot predict the outcome of the pending fuel and purchased power reviews
or
planned future reviews, but believes that PSO’s fuel and purchased power
procurement practices and costs are prudent and properly incurred. If the OCC
disagrees and disallows fuel or purchased power costs including the unrecovered
2002 reallocation of such costs incurred by PSO, it would have an adverse effect
on future results of operations and cash flows.
PSO
Rate Filing
In
November 2006, PSO filed a request to increase base rates $50 million for
Oklahoma jurisdictional customers with a proposed effective date in the second
quarter of 2007. PSO sought a return on equity of 11.75%. PSO also proposed
a
formula rate plan that, if approved as filed, will permit PSO to defer any
unrecovered costs as a result of a revenue deficiency that exceeds 50 basis
points of the allowed return on equity for recovery within twelve months
beginning six months after the test year. The formula would enable PSO to
recover on a timely basis the cost of its new generation, transmission and
distribution construction (including carrying costs during construction),
provide the opportunity to achieve the approved return on equity and avoid
recording a significant AFUDC that would have been recorded during the
construction time period.
In
March
2007, the OCC staff and various intervenors filed testimony. The recommendations
were base rate reductions that ranged from $18 million to $52 million. The
recommended returns on equity ranged from 9.25% to 10.09%. These recommendations
included reductions in depreciation expense of approximately $25 million, which
has no earnings impact. The OCC staff filed testimony supporting a formula
rate
plan, generally similar to the one proposed by PSO. In April 2007, PSO filed
rebuttal testimony regarding various issues raised by the OCC Staff and the
intervenors. As a result of rebuttal testimony, PSO reduced its base rate
request by $2 million. Hearings commenced on May 1, 2007.
Management
is unable to predict the outcome of these proceedings, however, if rates are
not
increased in an amount sufficient to recover expected unavoidable cost increases
future results of operations, cash flows and possibly financial condition could
be adversely affected.
PSO
Lawton and Peaking Generation Settlement Agreement
On
November 26, 2003, pursuant to an application by Lawton Cogeneration, L.L.C.
(Lawton) seeking approval of a Power Supply Agreement (the Agreement) with
PSO
and associated avoided cost payments, the OCC issued an order approving the
Agreement and setting the avoided costs.
In
December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme
Court (the Court). In the appeal, PSO maintained that the OCC exceeded its
authority under state and federal laws to require PSO to enter into the
Agreement. The Court issued a decision on June 21, 2005, affirming portions
of
the OCC’s order and remanding certain provisions. The Court affirmed the OCC’s
finding that Lawton established a legally enforceable obligation and ruled
that
it was within the OCC’s discretion to award a 20-year contract and to base the
capacity payment on a peaking unit. The Court directed the OCC to revisit its
determination of PSO’s avoided energy cost. Hearings were held on the remanded
issues in April and May 2006.
In
April
2007, all parties in the case filed a settlement agreement with the OCC
resolving all issues. The OCC approved the settlement agreement in April 2007.
The settlement agreement provides for a purchase fee of $35 million to be paid
by PSO to Lawton and for Lawton to provide, at PSO’s direction, all rights to
the Lawton Cogeneration Facility for permits, options and engineering studies.
PSO will record the purchase fee as a regulatory asset and recover it through
a
rider over a three-year period with a carrying charge of 8.25% beginning in
September 2007. In addition, PSO will recover through a rider, subject to a
$135
million cost cap, all of the traditional costs associated with plant in
service of its new peaking units to be located at the Southwestern Station
and
Riverside Station at the time these units are placed in service. PSO may
request approval from the OCC for recovery of costs exceeding the cost cap
if
special circumstances occurred necessitating a higher level of costs. Such
costs
will continue to be recovered through the rider until cost recovery occurs
through base rates or formula rates in a subsequent proceeding. PSO must file
a
rate case within eighteen months of the beginning of recovery through the rider
unless the OCC approves a formula-based rate mechanism that provides for
recovery of the peaking units. Once the cost recovery for the new peaking units
begins in mid-2008, PSO expects annual revenues of an estimated $36 million
related to cost recovery of the peaking units and the purchase fee. This
settlement agreement was supported by the OCC Staff, the Attorney General,
the
Oklahoma Industrial Energy Consumers and Lawton Cogeneration,
L.L.C.
Louisiana
Rate Matters
SWEPCo
Louisiana Compliance Filing
In
October 2002, SWEPCo filed with the LPSC detailed financial information
typically utilized in a revenue requirement filing, including a jurisdictional
cost of service. This filing was required by the LPSC as a result of its order
approving the merger between AEP and CSW. Due to multiple delays, in April
2006,
the LPSC and SWEPCo agreed to update the financial information based on a 2005
test year. SWEPCo filed updated financial review schedules in May 2006 showing
a
return on equity of 9.44% compared to the previously authorized return on equity
of 11.1%.
In
July
2006, the LPSC staff’s consultants filed direct testimony recommending a base
rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana
jurisdiction customers, based on a proposed 10% return on equity. The
recommended reduction range is subject to SWEPCo validating certain ongoing
operations and maintenance expense levels. SWEPCo filed rebuttal testimony
in
October 2006 strongly refuting the consultants’ recommendations. In December
2006, the LPSC staff’s consultants filed reply testimony asserting that SWEPCo’s
Louisiana base rates are excessive by $17 million which includes a proposed
return on equity of 9.8%. SWEPCo filed rebuttal testimony in January 2007.
A
decision is not expected until mid or late 2007. At this time, management is
unable to predict the outcome of this proceeding. If a rate reduction is
ultimately ordered, it would adversely impact future results of operations,
cash
flows and possibly financial condition.
FERC
Rate Matters
Transmission
Rate Proceedings at the FERC
The
FERC PJM Regional Transmission Rate Proceeding
At
AEP’s
urging, the FERC instituted an investigation of PJM’s zonal rate regime,
indicating that the present rate regime may need to be replaced through
establishment of regional rates that would compensate AEP and other transmission
owners for the regional transmission facilities they provide to PJM, which
provides service for the benefit of customers throughout PJM. In September
2005,
AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional
transmission rate design proposal with the FERC. This filing proposes and
supports a new PJM rate regime generally referred to as
Highway/Byway.
Parties
to the regional rate proceeding proposed the following rate
regimes:
·
|
AEP/AP
proposed a Highway/Byway rate design in which:
|
|
·
|
The
cost of all transmission facilities in the PJM region operated at
345 kV
or higher would be included in a “Highway” rate that all load serving
entities (LSEs) would pay based on peak demand. The AEP/AP proposal
would
produce about $125 million in additional revenues per year for AEP
from
users in other zones of PJM.
|
|
·
|
The
cost of transmission facilities operating at lower voltages would
be
collected in the zones where those costs are presently charged under
PJM’s
existing rate design.
|
·
|
Two
other utilities, Baltimore Gas & Electric Company (BG&E) and Old
Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate
that
includes transmission facilities above 200 kV, which would produce
lower
revenues for AEP than the AEP/AP proposal.
|
·
|
In
another competing Highway/Byway proposal, a group of LSEs proposed
rates
that would include existing 500 kV and higher voltage facilities
and new
facilities above 200 kV in the Highway rate, which would produce
considerably lower revenues for AEP than the AEP/AP proposal.
|
·
|
In
January 2006, the FERC staff issued testimony and exhibits supporting
a
PJM-wide flat rate or “Postage Stamp” type of rate design that would
include all transmission facilities, which would produce higher
transmission revenues for AEP than the AEP/AP
proposal.
|
All
of
these proposals were challenged by a majority of other transmission owners
in
the PJM region, who favor continuation of the existing PJM rate design which
provides AEP with no compensation for through and out traffic on its east zone
transmission system. Hearings were held in April 2006 and the ALJ issued an
initial decision in July 2006. The ALJ found the existing PJM zonal rate design
to be unjust and determined that it should be replaced. The ALJ found that
the
Highway/Byway rates proposed by AEP/AP and BG&E/ODEC and the Postage Stamp
rate proposed by the FERC staff to be just and reasonable alternatives. The
ALJ
also found FERC staff’s proposed Postage Stamp rate to be just and reasonable
and recommended that it be adopted. The ALJ also found that the effective date
of the rate change should be April 1, 2006 to coincide with SECA rate
elimination. Because the Postage Stamp rate was found to produce greater cost
shifts than other proposals, the judge also recommended that the design be
phased-in. Without a phase-in, the Postage Stamp method would produce more
revenue for AEP than the AEP/AP proposal. The phase-in of Postage Stamp rates
would delay the full impact of that result until about 2012.
AEP
filed
briefs noting exceptions to the initial decision and replies to the exceptions
of other parties. AEP argued that a phase-in should not be required.
Nevertheless, AEP argued that if the FERC adopts the Postage Stamp rate and
a
phase-in plan, the revenue collections curtailed by the phase-in should be
deferred and paid later with interest.
During
2006, the AEP East companies sought to increase retail rates in most of their
states to recover lost T&O and SECA revenues. The status of such state
retail rate proceedings is as follows:
·
|
In
Kentucky, KPCo settled a rate case, which provided for the recovery
of its
share of the transmission revenue reduction in new rates effective
March
30, 2006.
|
·
|
In
Ohio, CSPCo and OPCo recover their FERC-approved OATT that reflects
their
share of the full transmission revenue requirement retroactive to
April 1,
2006 under a May 2006 PUCO order.
|
·
|
In
West Virginia, APCo settled a rate case, which provided for the recovery
of its share of the T&O/SECA transmission revenue reduction beginning
July 28, 2006.
|
·
|
In
Virginia, APCo filed a request for revised rates, which includes
recovery
of its share of the T&O/SECA transmission revenue reduction starting
October 2, 2006, subject to refund.
|
·
|
In
Indiana, I&M is precluded by a rate cap from raising its rates until
July 1, 2007.
|
·
|
In
Michigan, I&M has not filed to seek recovery of the lost transmission
revenues.
|
In
April
2007, the FERC issued an order reversing the ALJ decision. The FERC ruled that
the current PJM rate design is just and reasonable. The FERC further ruled
that
the cost of new facilities of 500 kV and above would be shared among all PJM
participants. As a result of this order, the AEP East companies retail customers
will be asked to bear the full cost of the existing AEP east transmission zone
facilities. However, the AEP East companies customers will also be charged
a
share of the cost of new 500 kV and higher voltage transmission facilities
built
in PJM, of which the vast majority for the foreseeable future will not be needed
by their customers, but will bolster service and reduce costs in other zones
of
PJM. The AEP East companies will need to obtain regulatory approvals for
recovery of any costs of new facilities that are assigned to them as a result
of
this order, if upheld. AEP will request rehearing of this order. Management
cannot estimate at this time what effect, if any, this order will have on their
future construction of new east transmission facilities, results of operations,
cash flows and financial condition.
The
AEP
East companies presently recover from retail customers approximately 85% of
the
reduction in transmission revenues of $128 million a year. Future results of
operations, cash flows and financial condition will continue to be adversely
affected in Indiana and Michigan until these lost transmission revenues are
recovered in retail rates.
SECA
Revenue Subject to Refund
The
AEP
East companies ceased collecting through-and-out transmission service (T&O)
revenues in accordance with FERC orders, and collected SECA rates to mitigate
the loss of T&O revenues from December 1, 2004 through March 31, 2006, when
SECA rates expired. Intervenors objected to the SECA rates, raising various
issues. As a result, the FERC set SECA rate issues for hearing and ordered
that
the SECA rate revenues be collected, subject to refund or surcharge. The AEP
East companies paid SECA rates to other utilities at considerably lesser amounts
than collected. If a refund is ordered, the AEP East companies would also
receive refunds related to the SECA rates they paid to third parties. The AEP
East companies recognized gross SECA revenues as follows:
|
|
Gross
SECA Revenues Recognized
|
|
|
|
(in
millions)
|
|
Year
Ended December 31, 2006 (a)
|
|
$
|
43
|
|
Year
Ended December 31, 2005
|
|
|
163
|
|
Year
Ended December 31, 2004
|
|
|
14
|
|
(a)
|
Represents
revenues through March 31, 2006, when SECA rates expired, and excludes
all
provisions for refund.
|
Approximately
$19 million of these recorded SECA revenues billed by PJM were never collected.
The AEP East companies filed a motion with the FERC to force payment of these
uncollected SECA billings.
In
August
2006, the ALJ issued an initial decision, finding that the rate design for
the
recovery of SECA charges was flawed and that a large portion of the “lost
revenues” reflected in the SECA rates was not recoverable. The ALJ found that
the SECA rates charged were unfair, unjust and discriminatory and that new
compliance filings and refunds should be made. The ALJ also found that the
unpaid SECA rates must be paid in the recommended reduced amount.
Since
the
implementation of SECA rates in December 2004, the AEP East companies recorded
approximately $220 million of gross SECA revenues, subject to refund. The AEP
East companies reached settlements with certain customers related to
approximately $70 million of such revenues. The unsettled gross SECA revenues
total approximately $150 million. If the ALJ’s initial decision is upheld in its
entirety, it would disallow $126 million of the AEP East companies’ unsettled
gross SECA revenues. In the second half of 2006, the AEP East companies provided
reserves of $37 million in net refunds.
In
September 2006, AEP, together with Exelon and DP&L, filed an extensive
post-hearing brief and reply brief noting exceptions to the ALJ’s initial
decision and asking the FERC to reverse the decision in large part. Management
believes that the FERC should reject the initial decision because it is contrary
to prior related FERC decisions, which are presently subject to rehearing.
Furthermore, management believes the ALJ’s findings on key issues are largely
without merit. Although management believes they have meritorious arguments,
management cannot predict the ultimate outcome of any future FERC proceedings
or
court appeals. If
the
FERC adopts the ALJ’s decision, it will have an adverse effect on future results
of operations and cash flows.
4. COMMITMENTS,
GUARANTEES AND CONTINGENCIES
We
are
subject to certain claims and legal actions arising in our ordinary course
of
business. In addition, our business activities are subject to extensive
governmental regulation related to public health and the environment. The
ultimate outcome of such pending or potential litigation against us cannot
be
predicted. For current proceedings not specifically discussed below, management
does not anticipate that the liabilities, if any, arising from such proceedings
would have a material adverse effect on our financial statements. The
Commitments, Guarantees and Contingencies note within our 2006 Annual Report
should be read in conjunction with this report.
GUARANTEES
There
are
certain immaterial liabilities recorded for guarantees in accordance with FASB
Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is
no collateral held in relation to any guarantees in excess of our ownership
percentages. In the event any guarantee is drawn, there is no recourse to third
parties unless specified below.
Letters
Of Credit
We
enter
into standby letters of credit (LOCs) with third parties. These LOCs cover
items
such as gas and electricity risk management contracts, construction contracts,
insurance programs, security deposits, 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, 2007, the maximum future payments for all the LOCs are approximately $27
million with maturities ranging from June 2007 to March 2008.
Guarantees
Of Third-Party Obligations
SWEPCo
As
part
of the process to receive a renewal of a Texas Railroad Commission permit for
lignite mining, SWEPCo provides guarantees of mine reclamation in the amount
of
approximately $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 Mining Company (Sabine), an
entity consolidated under FIN 46. This guarantee ends upon depletion of reserves
and completion of final reclamation. Based on the latest study, we estimate
the
reserves will be depleted in 2029 with final reclamation completed by 2036,
at
an estimated cost of approximately $39 million. As of March 31, 2007, SWEPCo
has
collected approximately $30 million through a rider for final mine closure
costs, of which approximately $13 million is recorded in Deferred Credits and
Other and approximately $17 million is recorded in Asset Retirement Obligations
on our Condensed Consolidated Balance Sheets.
Sabine
charges SWEPCo, its only customer, all its costs. SWEPCo passes these costs
through its fuel clause.
Indemnifications
And Other Guarantees
Contracts
We
enter
into several types of contracts which require indemnifications. Typically these
contracts include, but are not limited to, sale agreements, lease agreements,
purchase agreements and financing agreements. Generally, these agreements may
include, but are not limited to, indemnifications around certain tax,
contractual and environmental matters. With respect to sale agreements, our
exposure generally does not exceed the sale price. The status of certain sales
agreements is discussed in the 2006 Annual Report, “Dispositions” section of
Note 8. These sale agreements include indemnifications with a maximum exposure
related to the collective purchase price, which is approximately $2.2 billion
(approximately $1 billion relates to the BOA litigation, see “Enron Bankruptcy”
section of this note). There are no material liabilities recorded for any
indemnifications.
Master
Operating Lease
We
lease
certain equipment under a master operating lease. Under the lease agreement,
the
lessor is guaranteed receipt of up to 87% of the unamortized balance of the
equipment at the end of the lease term. If the fair market value of the leased
equipment is below the unamortized balance at the end of the lease term, we
are
committed to pay the difference between the fair market value and the
unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At March 31, 2007, the maximum potential loss for these
lease agreements was approximately $56 million ($36 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.
This operating lease agreement allows us to avoid a large initial capital
expenditure and to spread our railcar costs evenly over the expected twenty-year
usage.
Under
the
lease agreement, the lessor is guaranteed that the sale proceeds under the
return-and-sale option discussed above will equal at least a lessee obligation
amount specified in the lease, which declines over the current lease term from
approximately 86% to 77% of the projected fair market value of the equipment.
At
March 31, 2007, the maximum potential loss was approximately $31 million ($20
million, net of tax) assuming the fair market value of the equipment is zero
at
the end of the current lease term. We have other railcar lease arrangements
that
do not utilize this type of financing structure.
CONTINGENCIES
Federal
EPA Complaint and Notice of Violation
The
Federal EPA, certain special interest groups and a number of states allege
that
APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the
Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric
Company, Ohio Edison Company, Southern Indiana Gas & Electric Company,
Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company
and Duke Energy, modified certain units at coal-fired generating plants in
violation of the NSR requirements of the CAA. The Federal EPA filed its
complaints against our subsidiaries in U.S. District Court for the Southern
District of Ohio. The alleged modifications occurred at our generating units
over a twenty-year period. A bench trial on the liability issues was held during
July 2005. In June 2006, the judge stayed the liability decision pending the
issuance of a decision by the U.S. Supreme Court in the Duke Energy
case.
Under
the
CAA, if a plant undertakes a major modification that 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 routine maintenance, replacement of degraded equipment or
failed component 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.
Cases
are
pending that could affect CSPCo’s share of jointly-owned units at Beckjord,
Zimmer, and Stuart Stations. Similar cases have been filed against other
nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric
Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric
Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases
were resolved through consent decrees.
Courts
have reached different conclusions regarding whether the activities at issue
in
these cases are routine maintenance, repair or replacement, and therefore are
excluded from NSR. Similarly, courts have reached different results regarding
whether the activities at issue increased emissions from the power plants.
Appeals on these and other issues were filed in certain appellate courts,
including a petition to appeal to the U.S. Supreme Court that was granted in
the
Duke Energy 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 Court denied the Federal EPA’s
request for rehearing, and the Federal EPA and other parties filed a petition
for review by the U.S. Supreme Court. In April 2007, the Supreme Court denied
the petition for review. The Federal EPA also proposed a rule that would define
“emissions increases” in a way that most of the challenged activities would be
excluded from NSR.
On
April
2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’
decision that had supported the statutory construction argument of Duke Energy
in its NSR proceeding. In a unanimous decision, the Court ruled that the Federal
EPA was not obligated to define “major modification” in two different CAA
provisions in the same way. The Court also found that the Fourth Circuit’s
interpretation of “major modification” as applying only to projects that
increased hourly emission rates amounted to an invalidation of the relevant
Federal EPA regulations, which under the CAA can only be challenged in the
Court
of Appeals within 60 days of the Federal EPA rulemaking. The U.S. Supreme Court
did acknowledge, however, that Duke Energy may argue on remand that the Federal
EPA has been inconsistent in its interpretations of the CAA and the regulations
and may not retroactively change 20 years of accepted practice.
In
addition to providing guidance on certain of the merits of the NSR proceedings
brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the
Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the
Duke Energy cases has an impact on the timing of our NSR proceedings. First,
the
court in the case for which a trial on liability issues has been conducted
has
indicated an intent to issue a decision on liability. Second, the bench trial
on
remedy issues, if necessary, is likely to be scheduled to begin in the third
quarter of 2007.
We
are
unable to estimate the loss or range of loss related to any contingent
liability, if any, we might have for civil penalties under the 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 our future results of operations, cash flows and possibly
financial condition.
SWEPCo
Notice of Enforcement and Notice of Citizen Suit
In
March
2005, two special interest groups, Sierra Club and Public Citizen, filed a
complaint in Federal District Court for the Eastern District of Texas alleging
violations of the CAA at SWEPCo’s Welsh Plant. SWEPCo filed a response to the
complaint in May 2005. A trial in this matter is scheduled for the second
quarter of 2007.
In
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 limiting
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 and to clarify the sulfur content requirement for fuels consumed at the
plant. A permit alteration was issued in March 2007 removing the heat input
references from the Welsh permit and clarifying the sulfur content of fuels
burned at the plant is limited to 0.5% on an as-received basis. The Sierra
Club
and Public Citizen filed a motion to overturn the permit
alteration.
We
are
unable to predict the timing of any future action by TCEQ or the special
interest groups or the effect of such actions on our results of operations,
cash
flows or financial condition.
Carbon
Dioxide (CO2)
Public Nuisance Claims
In
2004,
eight states and the City of New York filed an action in federal district court
for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel
Energy, Southern Company and Tennessee Valley Authority. The Natural Resources
Defense Council, on behalf of three special interest groups, filed a similar
complaint against the same defendants. The actions allege that CO2
emissions from the defendants’ power plants constitute a public nuisance under
federal common law due to impacts of global warming, and sought injunctive
relief in the form of specific emission reduction commitments from the
defendants. The defendants’ motion to dismiss the lawsuits was granted in
September 2005. The dismissal was appealed to the Second Circuit Court of
Appeals. Briefing and oral argument have concluded. On April 2, 2007, the U.S.
Supreme Court issued a decision holding that the Federal EPA has authority
to
regulate emissions of CO2
and
other greenhouse gases under the CAA, which may impact the Second Circuit’s
analysis of these issues. We believe the actions are without merit and intend
to
defend against the claims.
TEM
Litigation
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). Beginning May 1, 2003, OPCo tendered replacement capacity, energy and
ancillary services to TEM pursuant to the PPA that TEM rejected as
nonconforming.
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
August
2005, a federal judge ruled that TEM had breached the contract and awarded
us
damages of $123 million plus prejudgment interest. Any eventual proceeds will
be
recorded as a gain when received.
In
September 2005, TEM posted a $142 million letter of credit as security pending
appeal of the judgment. Both parties filed Notices of Appeal with the United
States Court of Appeals for the Second Circuit, which heard oral argument on
the
appeals in December 2006. We cannot predict the ultimate outcome of this
proceeding.
Enron
Bankruptcy
In
connection with the 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 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 facility. In 2003, the Texas state court granted partial
summary judgment in favor of the BOA Syndicate. HPL appealed this decision.
In
August 2006, the Court of Appeals for the First District of Texas vacated the
trial court’s judgment and dismissed the BOA Syndicate’s case. The BOA Syndicate
did not seek review of this decision. In June 2004, BOA filed an amended
petition in a separate lawsuit in Texas state court seeking to obtain possession
of up to 55 BCF of storage gas in the Bammel storage facility or its fair value.
Following an adverse decision on its motion to obtain possession of this gas,
BOA voluntarily dismissed this action. In October 2004, BOA refiled this action.
HPL’s motion to have the case assigned to the judge who heard the case
originally was granted. HPL intends to defend against any renewed claims by
BOA.
In
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 facility 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 facility and the right to use and cushion gas
consent agreements be transferred to the Southern District of New York and
that
the four counts alleging breach of contract, fraud and negligent
misrepresentation proceed in the Southern District of Texas. BOA objected to
the
Magistrate Judge’s decision. In April 2005, the Judge entered an order
overruling BOA’s objections, denying BOA’s Motion to Dismiss and severing and
transferring the declaratory judgment claims to the Southern District of New
York. HPL and BOA filed motions for summary judgment in the case pending in
the
Southern District of New York. The case in federal court in Texas was set for
trial beginning April 2007 but the Court continued the trial pending a decision
on the motions for summary judgment in the New York case.
In
February 2007, the Judge in the New York action, after hearing oral argument
on
the motions for summary judgment, made a series of oral “informal findings” and
submitted a written memorandum to the parties’ counsel. In the memorandum to
counsel, the Judge stated that he was denying several of AEP’s motions for
partial summary judgment and granting several of BOA motions for summary
judgment. The substantive matters left open for further proceedings include
the
issue of the nature of the gas subject to BOA security interest and the value
of
that interest. The Judge stated that the memorandum to counsel is not an opinion
or an order, and that no opinion or order will be issued until all motions
pending before the Court have been decided. The Judge heard additional arguments
on the summary judgment motions in March 2007. At this time we are unable to
predict how the Judge will rule on the pending motions due to the complexity
of
those issues and the parties’ disagreement over each issue. If the Judge issues
a judgment directing AEP to pay an amount in excess of the gain on the sale
of
HPL described below and if AEP is unsuccessful in having the judgment reversed
or modified, the judgment could have a material adverse effect on the results
of
operations, cash flow, and possibly financial condition.
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, estimated to be $380 million at March 31, 2007 and December
31, 2006, and the recognition of the gain are dependent on the ultimate
resolution of the BOA dispute and the costs, if any, associated with the
resolution of this matter. The deferred gain is included in Deferred Credits
and
Other on our Condensed Consolidated Balance Sheets.
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
2002
and 2003, three putative class action lawsuits were filed against AEP, certain
executives and AEP’s Employee Retirement Income Security Act (ERISA) Plan
Administrator alleging violations of ERISA in the selection of AEP stock as
an
investment alternative and in the allocation of assets to AEP stock. The ERISA
actions were pending in Federal District Court, Columbus, Ohio. In these
actions, the plaintiffs sought recovery of an unstated amount of compensatory
damages, attorney fees and costs. In July 2006, the Court entered judgment
denying plaintiff’s motion for class certification and dismissing all claims
without prejudice. In August 2006, the plaintiffs filed a notice of appeal
to
the United States Court of Appeals for the Sixth Circuit. Briefing of this
appeal was completed in December 2006 and the parties await the scheduling
of
oral argument. We intend to continue to defend against these
claims.
Natural
Gas Markets Lawsuits
In
2002,
the Lieutenant Governor of California filed a lawsuit in Los Angeles County
California Superior Court against 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 were 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 were transferred to the United States District
Court for the District of Nevada but subsequently were remanded to California
state court. In 2005, the judge in Nevada dismissed three of the remaining
cases
(AEP was a defendant in one of these cases), on the basis of the filed rate
doctrine. Plaintiffs in these cases appealed the decisions. We will continue
to
defend each case where an AEP company is a defendant.
FERC
Long-term Contracts
In
2002,
the FERC held a hearing related to a complaint filed by Nevada Power Company
and
Sierra Pacific Power Company (the Nevada utilities). The complaint sought to
break long-term contracts entered during the 2000 and 2001 California energy
price spike which the customers alleged were “high-priced.” The complaint
alleged that we sold power at unjust and unreasonable prices. In
December 2002, a FERC ALJ ruled in our favor and dismissed the complaint filed
by the Nevada utilities. In 2001, the Nevada utilities filed complaints
asserting that the prices for power supplied under those contracts should be
lowered as the market for power was allegedly dysfunctional at the time such
contracts were executed. The ALJ rejected the complaint, held that the markets
for future delivery were not dysfunctional, and that the Nevada utilities failed
to demonstrate that the public interest required that changes be made to the
contracts. In June 2003, the FERC issued an order affirming the ALJ’s decision.
In December 2006, the U.S. Court of Appeals for the Ninth Circuit reversed
the
FERC order and remanded the case to the FERC for further proceedings.
Management
is unable to predict the outcome of these proceedings or their impact on future
results of operations and cash flows. We have asserted claims against certain
companies that sold power to us, which we resold to the Nevada utilities,
seeking to recover a portion of any amounts we may owe to the Nevada
utilities.
5. ACQUISITIONS,
DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR
SALE
ACQUISITIONS
2007
Darby
Electric Generating Station (Utility Operations
segment)
In
November 2006, CSPCo agreed to purchase Darby Electric Generating Station
(Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light
Company, for $102 million and the assumption of liabilities of approximately
$2
million. CSPCo completed the purchase in April 2007. The Darby plant is located
near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with
a
generating capacity of 480 MW.
Lawrenceburg
Generating Station (Utility Operations segment)
In
January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station
(Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG)
for
approximately $325 million and the assumption of liabilities of approximately
$2
million. AEGCo will complete the purchase in May 2007. The Lawrenceburg plant
is
located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and
is a natural gas, combined cycle power plant with a generating capacity of
1,096
MW.
2006
None
DISPOSITIONS
2007
Texas
Plants - Oklaunion Power Station (Utility Operations
segment)
In
February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public
Utilities Board of the City of Brownsville for $42.8 million plus working
capital adjustments. The sale did not have an impact on our results of
operations nor do we expect any remaining litigation to have a significant
effect on our results of operations.
Intercontinental
Exchange, Inc. (ICE) (All Other)
During
March 2007, we sold 130,000 shares of ICE and recognized a $16 million pretax
gain ($10 million, net of tax). We recorded the gains in Interest and Investment
Income on our 2007 Condensed Consolidated Statement of Income. We recorded
our
remaining investment of approximately 138,000 shares in Other Temporary Cash
Investments on our Condensed Consolidated Balance Sheets.
Texas
REPs (Utility Operations Segment)
As
part
of the purchase-and-sale agreement related to the sale of our Texas REPs
in
2002, we retained the right to share in earnings with Centrica from the two
REPs
above a threshold amount through 2006 if the Texas retail market developed
increased earnings opportunities. We received $20 million and $70 million
payments in 2007 and 2006, respectively, for our share in earnings. These
payments are reflected in Gain/Loss on Disposition of Assets, Net on our
Condensed Consolidated Statements of Income. The payment we received in 2007
was
the final payment under the earnings sharing agreement.
2006
Compresion
Bajio S de R.L. de C.V. (All Other)
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 completed the sale in February
2006
for approximately $29 million with no effect on our 2006 results of
operations.
DISCONTINUED
OPERATIONS
We
determined that certain of our operations were discontinued operations and
classified them as such for all periods presented. We recorded no income or
charges related to our discontinued operations during the first quarter of
2007.
During the first quarter of 2006, we had discontinued operations from U.K.
Generation related to a release of accrued liabilities for the London office
lease and tax adjustments from the sale. We recorded pretax income related
to
U.K. Generation of $5 million ($3 million, net of tax) during the first quarter
of 2006.
ASSETS
HELD FOR SALE
Texas
Plants - Oklaunion Power Station (Utility Operations
segment)
In
February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public
Utilities Board of the City of Brownsville. The sale did not have a significant
effect on our results of operations nor do we expect any remaining litigation
to
have a significant effect on our results of operations.
We
classified TCC’s assets related to the Oklaunion Power Station in Assets Held
for Sale on our Condensed Consolidated Balance Sheet at December 31, 2006.
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 except TNC.
Our
Assets Held for Sale were as follows:
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
Texas
Plants
|
|
(in
millions)
|
|
Other
Current Assets
|
|
$
|
-
|
|
$
|
1
|
|
Property,
Plant and Equipment, Net
|
|
|
-
|
|
|
43
|
|
Total
Assets Held for Sale
|
|
$
|
-
|
|
$
|
44
|
|
6. BENEFIT
PLANS
We
adopted SFAS 158 as of December 31, 2006. We recorded a SFAS 71 regulatory
asset
for qualifying SFAS 158 costs of our regulated operations that for ratemaking
purposes will be deferred for future recovery.
Components
of Net Periodic Benefit Cost
The
following table provides the components of our net periodic benefit cost for
the
plans for the three months ended March 31, 2007 and 2006:
|
|
|
|
Other
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$
|
24
|
|
$
|
24
|
|
$
|
10
|
|
$
|
10
|
|
Interest
Cost
|
|
|
59
|
|
|
57
|
|
|
26
|
|
|
25
|
|
Expected
Return on Plan Assets
|
|
|
(85
|
)
|
|
(83
|
)
|
|
(26
|
)
|
|
(23
|
)
|
Amortization
of Transition Obligation
|
|
|
-
|
|
|
-
|
|
|
7
|
|
|
7
|
|
Amortization
of Net Actuarial Loss
|
|
|
15
|
|
|
20
|
|
|
3
|
|
|
5
|
|
Net
Periodic Benefit Cost
|
|
$
|
13
|
|
$
|
18
|
|
$
|
20
|
|
$
|
24
|
|
7. BUSINESS
SEGMENTS
As
outlined in our 2006 Annual Report, our primary business strategy and the core
of our business are to focus on our electric utility operations. Within our
Utility Operations segment, we centrally dispatch all generation assets and
manage our overall utility operations on an integrated basis because of the
substantial impact of cost-based rates and regulatory oversight.
Generation/supply in Ohio and Virginia continue to have commission-determined
transition rates. In April 2007, the Virginia legislature approved amendments
recommended by the Governor providing for the re-regulation of electric utility
generation/supply rates. See “Virginia Restructuring” section of Note
3.
Our
principal operating business segments and their related business activities
are
as follows:
Utility
Operations
·
|
Generation
of electricity for sale to U.S. retail and wholesale
customers.
|
·
|
Electricity
transmission and distribution in the
U.S.
|
MEMCO
Operations
·
|
Barging
operations that annually transport approximately 34 million tons
of coal
and dry bulk commodities primarily on the Ohio, Illinois and Lower
Mississippi rivers. Approximately 35% of the barging operations
relates to
the transportation of coal, 28% relates to agricultural
products, 21% relates to steel and 16% relates to other
commodities.
|
Generation
and Marketing
·
|
IPPs,
wind farms and marketing and risk management activities primarily in
ERCOT.
|
The
remainder of our company’s activities is presented as All Other. While not
considered a business segment, All Other includes:
·
|
Parent
company’s guarantee revenue received from affiliates, interest income and
interest expense and other nonallocated costs.
|
·
|
Other
energy supply related businesses, including the Plaquemine Cogeneration
Facility, which was sold in the fourth quarter of
2006.
|
The
tables below present our reportable segment information for the three months
ended March 31, 2007 and 2006 and balance sheet information as of March 31,
2007
and December 31, 2006. These amounts include certain estimates and allocations
where necessary. We reclassified prior year amounts to conform to the current
year’s segment presentation.
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
Three
Months Ended March 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
2,886
|
|
$
|
117
|
|
$
|
115
|
|
$
|
51
|
|
$
|
-
|
|
$
|
3,169
|
|
|
Other
Operating Segments
|
|
|
147
|
|
|
3
|
|
|
(73
|
)
|
|
(45
|
)
|
|
(32
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
3,033
|
|
$
|
120
|
|
$
|
42
|
|
$
|
6
|
|
$
|
(32
|
)
|
$
|
3,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$
|
253
|
|
$
|
15
|
|
$
|
(1
|
)
|
$
|
4
|
|
$
|
-
|
|
$
|
271
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Three
Months Ended March 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$
|
2,982
|
|
$
|
116
|
|
$
|
13
|
|
$
|
(3
|
)
|
$
|
-
|
|
$
|
3,108
|
|
Other
Operating Segments
|
|
|
(16
|
)
|
|
3
|
|
|
-
|
|
|
22
|
|
|
(9
|
)
|
|
-
|
|
Total
Revenues
|
|
$
|
2,966
|
|
$
|
119
|
|
$
|
13
|
|
$
|
19
|
|
$
|
(9
|
)
|
$
|
3,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued
Operations
|
|
$
|
365
|
|
$
|
21
|
|
$
|
4
|
|
$
|
(12
|
)
|
$
|
-
|
|
$
|
378
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
3
|
|
|
-
|
|
|
3
|
|
Net
Income (Loss)
|
|
$
|
365
|
|
$
|
21
|
|
$
|
4
|
|
$
|
(9
|
)
|
$
|
-
|
|
$
|
381
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
March
31, 2007
|
|
(in
millions)
|
|
Total
Property, Plant and Equipment
|
|
$
|
42,092
|
|
$
|
239
|
|
$
|
565
|
|
$
|
35
|
|
$
|
(237
|
)(c)
|
$
|
42,694
|
|
Accumulated
Depreciation and Amortization
|
|
|
15,244
|
|
|
53
|
|
|
90
|
|
|
7
|
|
|
(3
|
)(c)
|
|
15,391
|
|
Total
Property, Plant and Equipment - Net
|
|
$
|
26,848
|
|
$
|
186
|
|
$
|
475
|
|
$
|
28
|
|
$
|
(234
|
)(c)
|
$
|
27,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
36,789
|
|
$
|
305
|
|
$
|
705
|
|
$
|
11,732
|
|
$
|
(11,595
|
)(b)
|
$
|
37,936
|
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
December
31, 2006
|
|
(in
millions)
|
|
Total
Property, Plant and Equipment
|
|
$
|
41,420
|
|
$
|
239
|
|
$
|
327
|
|
$
|
35
|
|
$
|
-
|
|
$
|
42,021
|
|
Accumulated
Depreciation and Amortization
|
|
|
15,101
|
|
|
51
|
|
|
83
|
|
|
5
|
|
|
-
|
|
|
15,240
|
|
Total
Property, Plant and Equipment - Net
|
|
$
|
26,319
|
|
$
|
188
|
|
$
|
244
|
|
$
|
30
|
|
$
|
-
|
|
$
|
26,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
36,632
|
|
$
|
315
|
|
$
|
342
|
|
$
|
11,460
|
|
$
|
(10,762
|
)(b)
|
$
|
37,987
|
|
Assets
Held for Sale
|
|
|
44
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
44
|
|
(a)
|
All
Other includes:
|
|
·
|
Parent
company’s guarantee revenue received from affiliates, interest income and
interest expense and other nonallocated costs.
|
|
·
|
Other
energy supply related businesses, including the Plaquemine Cogeneration
Facility, which was sold in the fourth quarter of 2006.
|
(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)
|
Reconciling
Adjustments for Total Property, Plant and Equipment and Accumulated
Depreciation and Amortization as of March 31, 2007 represent the
elimination of an intercompany capital lease that began during the
first
quarter of 2007.
|
8. INCOME
TAXES
We
join
in the filing of a consolidated federal income tax return with our subsidiaries
in the American Electric Power (AEP) System. The allocation of the AEP System’s
current consolidated federal income tax to the AEP System companies allocates
the benefit of current tax losses to the AEP System companies giving rise to
such losses in determining their current expense. The tax benefit of the parent
is allocated to our subsidiaries with taxable income. With the exception of
the
loss of the parent company, the method of allocation approximates a separate
return result for each company in the consolidated group.
Audit
Status
AEP
System companies also file income tax returns in various state, local, and
foreign jurisdictions. With few exceptions, we are no longer subject to U.S.
federal, state and local, or non-U.S. income tax examinations by tax authorities
for years before 2000. The IRS and other taxing authorities routinely examine
our tax returns. We believe that we have filed tax returns with positions that
may be challenged by these tax authorities. We are currently under exam in
several state and local jurisdictions. However, management does not believe
that
the ultimate resolution of these audits will materially impact results of
operations.
We
have
settled with the IRS all issues from the audits of our consolidated federal
income tax returns for years prior to 1997. We have effectively settled all
outstanding proposed IRS adjustments for years 1997 through 1999 and through
June 2000 for the CSW pre-merger tax period and anticipate payment for the
agreed adjustments to occur during 2007. Returns for the years 2000 through
2003
are presently being audited by the IRS and we anticipate that the audit will
be
completed by the end of 2007.
The
IRS
has proposed certain significant adjustments to AEP’s foreign tax credit and
interest allocation positions. Management is currently evaluating those proposed
adjustments to determine if it agrees, but if accepted, we do not anticipate
that the adjustments would result in a material change to our financial
position.
FIN
48 Adoption
We
adopted the provisions of FIN 48 on January 1, 2007. As a result of the
implementation of FIN 48, we recognized approximately a $17 million increase
in
the liabilities for unrecognized tax benefits, as well as related interest
expense and penalties, which was accounted for as a reduction to the January
1,
2007 balance of retained earnings.
At
January 1, 2007, the total amount of unrecognized tax benefits under FIN 48
was
$175 million. We believe it is reasonably possible that there will be a $46
million net decrease in unrecognized tax benefits due to the settlement of
audits and the expiration of statute of limitations within 12 months of the
reporting date. The total amount of unrecognized tax benefits that, if
recognized, would affect the effective tax rate is $73 million. There are $66
million of tax positions for which the ultimate deductibility is highly certain
but for which there is uncertainty about the timing of such deductibility.
Because of the impact of deferred tax accounting, other than interest and
penalties, the disallowance of the shorter deductibility period would not affect
the annual effective tax rate but would accelerate the payment of cash to the
taxing authority to an earlier period.
Prior
to
the adoption of FIN 48, we recorded interest and penalty accruals related to
income tax positions in tax accrual accounts. With the adoption of FIN 48,
we
began recognizing interest accruals related to income tax positions in
interest income or expense as applicable, and penalties in operating expenses.
As of January 1, 2007, we accrued approximately $25 million for the payment
of
uncertain interest and penalties.
9. FINANCING
ACTIVITIES
Long-term
Debt
|
|
March
31,
|
|
December
31,
|
|
Type
of Debt
|
|
2007
|
|
2006
|
|
|
|
(in
millions)
|
|
Senior
Unsecured Notes
|
|
$
|
8,903
|
|
$
|
8,653
|
|
Pollution
Control Bonds
|
|
|
1,950
|
|
|
1,950
|
|
First
Mortgage Bonds
|
|
|
90
|
|
|
90
|
|
Defeased
First Mortgage Bonds (a)
|
|
|
27
|
|
|
27
|
|
Notes
Payable
|
|
|
320
|
|
|
337
|
|
Securitization
Bonds
|
|
|
2,303
|
|
|
2,335
|
|
Notes
Payable To Trust
|
|
|
113
|
|
|
113
|
|
Spent
Nuclear Fuel Obligation (b)
|
|
|
251
|
|
|
247
|
|
Other
Long-term Debt
|
|
|
2
|
|
|
2
|
|
Unamortized
Discount (net)
|
|
|
(57
|
)
|
|
(56
|
)
|
Total
Long-term Debt Outstanding
|
|
|
13,902
|
|
|
13,698
|
|
Less
Portion Due Within One Year
|
|
|
1,377
|
|
|
1,269
|
|
Long-term
Portion
|
|
$
|
12,525
|
|
$
|
12,429
|
|
(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 $19 million at both March 31,
2007
and December 31, 2006. Trust Fund Assets related to this obligation
of $23
million and $2 million at March 31, 2007 and December 31, 2006,
respectively, are included in Other Temporary Cash Investments and
$0 and
$21 million at March 31, 2007 and December 31, 2006, respectively,
are
included in Other Noncurrent Assets on our Condensed Consolidated
Balance
Sheets. 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, 2007 and December 31, 2006. Trust fund assets related to this
obligation of $9 million at both March 31, 2007 and December 31,
2006 are
included in Other Temporary Cash Investments on our Condensed Consolidated
Balance Sheet. 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 related to
this
obligation of $276 million and $274 million at March 31, 2007 and
December
31, 2006, respectively, are included in Spent Nuclear Fuel and
Decommissioning Trusts on our Condensed Consolidated Balance
Sheets.
|
Long-term
debt and other securities issued, retired and principal payments made during
the
first three months of 2007 are shown in the tables below.
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
|
(in
millions)
|
|
(%)
|
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
SWEPCo
|
|
Senior
Unsecured Notes
|
|
$
|
250
|
|
5.55
|
|
2017
|
|
Total
Issuances
|
|
|
|
$
|
250
|
(a)
|
|
|
|
|
The above borrowing
arrangement does not contain guarantees, collateral or dividend
restrictions. |
|
|
(a)
|
Amount
indicated on statement of cash flows of $247 million is net of issuance
costs and unamortized premium or
discount.
|
Company
|
|
Type
of Debt
|
|
Principal
Amount Paid
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
|
(in
millions)
|
|
(%)
|
|
|
|
Retirements
and Principal Payments:
|
|
|
|
|
|
|
|
|
|
OPCo
|
|
Notes
Payable
|
|
$
|
1
|
|
6.81
|
|
2008
|
|
OPCo
|
|
Notes
Payable
|
|
|
6
|
|
6.27
|
|
2009
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
2
|
|
4.47
|
|
2011
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
4
|
|
6.36
|
|
2007
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
1
|
|
Variable
|
|
2008
|
|
TCC
|
|
Securitization
Bonds
|
|
|
32
|
|
5.01
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Registrant:
|
|
|
|
|
|
|
|
|
|
|
AEP
Subsidiaries
|
|
Notes
Payable
|
|
|
3
|
|
Variable
|
|
2017
|
|
Total
Retirements
|
|
|
|
$
|
49
|
|
|
|
|
|
In
April
2007, OPCo issued $400 million of three-year floating rate notes at an initial
rate of 5.53% due in 2010. The proceeds from this issuance will
contribute to our investment in environmental equipment.
Short-term
Debt
Short-term
debt is used to fund our corporate borrowing program and fund other short-term
cash needs. Our outstanding short-term debt is as follows:
|
|
March
31, 2007
|
|
|
December
31, 2006
|
|
|
|
Outstanding
Amount
|
|
Interest
Rate
|
|
|
Outstanding
Amount
|
|
Interest
Rate
|
|
Type
of Debt
|
|
(in
millions)
|
|
|
|
|
|
(in
millions)
|
|
|
|
|
Commercial
Paper - AEP
|
|
$
|
150
|
|
|
5.43
|
%
|
(a)
|
$
|
-
|
|
|
-
|
|
Commercial
Paper - JMG (b)
|
|
|
5
|
|
|
5.56
|
%
|
|
|
1
|
|
|
5.56
|
%
|
Line
of Credit - Sabine (c)
|
|
|
20
|
|
|
6.52
|
%
|
|
|
17
|
|
|
6.38
|
%
|
Total
|
|
$
|
175
|
|
|
|
|
|
$
|
18
|
|
|
|
|
(a)
|
Weighted
average rate.
|
(b)
|
This
commercial paper is specifically associated with the Gavin Scrubber
and is
backed by a separate credit facility. This commercial paper does
not
reduce available liquidity under AEP’s credit
facilities.
|
(c)
|
Sabine
is consolidated under FIN 46. This line of credit does not reduce
available liquidity under AEP’s credit
facilities.
|
Credit
Facilities
In
March
2007, we amended the terms of our credit facilities. The amended facilities
are
structured as two $1.5 billion credit facilities, with an option in each to
issue up to $300 million as letters of credit, expiring separately in March
2011
and April 2012.
AEP
GENERATING COMPANY
AEP
GENERATING COMPANY
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
We
engage
in the generation and wholesale sale of electric power to two affiliates,
I&M and KPCo, under long-term agreements. 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 through December 2022. Under
the
terms of its unit power agreement, I&M agreed to purchase all of our
Rockport energy and capacity unless it is sold to other utilities or affiliates.
I&M assigned 30% of its rights to energy and capacity to KPCo.
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.
The
co-owners divide the costs of operating the plant.
Results
of Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Net
Income
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
2.9
|
|
|
|
|
|
|
|
|
|
Change
in Gross Margin:
|
|
|
|
|
|
|
|
Wholesale
Sales
|
|
|
|
|
|
(0.7
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(1.3
|
)
|
|
|
|
Interest
Expense
|
|
|
(0.5
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(1.8
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense (Credit)
|
|
|
|
|
|
1.2
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
1.6
|
|
Net
Income decreased $1.3 million for 2007 compared with 2006. 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 calculated and adjusted monthly
for over/under billings.
Gross
Margin, defined as Operating Revenues less Fuel for Electric Generation,
decreased $0.7 million primarily due to year-end tax adjustments reflected
in
January’s bill.
Other
Operation and Maintenance expenses increased $1.3 million primarily due
to
increased maintenance cost reflecting more planned and forced outages at
the
Rockport Plant in 2007 than 2006.
Interest
Expense increased $0.5 million primarily due to increased rates on short-term
borrowings and increased money pool borrowings.
Income
Taxes
Income
Tax Expense (Credit) decreased $1.2 million primarily due to a decrease
in
pretax book income and changes in certain book/tax differences accounted
for on
a flow-through basis.
Significant
Factors
Lawrenceburg
Generating Station
In
January 2007, we agreed to purchase Lawrenceburg Generating Station
(Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG)
for
approximately $325 million and the assumption of liabilities of approximately
$2
million. The transaction is expected to close in May 2007. The Lawrenceburg
plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek
Plant, and is a natural gas, combined cycle power plant with a generating
capacity of 1,096 MW. This new generation acquisition will be financed
by a
capital contribution from AEP and issuance of debt related to this acquisition.
We plan to sell the power to CSPCo through a FERC-approved purchase power
contract.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in our 2006 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.
Adoption
of New Accounting Pronouncements
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
AEP
GENERATING COMPANY
CONDENSED
STATEMENTS OF INCOME
For
the Three Months Ended March 31, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
|
$
|
77,151
|
|
$
|
78,151
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
Used for Electric Generation
|
|
|
43,649
|
|
|
43,961
|
|
Rent
- Rockport Plant Unit 2
|
|
|
17,071
|
|
|
17,071
|
|
Other
Operation
|
|
|
3,326
|
|
|
3,068
|
|
Maintenance
|
|
|
3,811
|
|
|
2,786
|
|
Depreciation
and Amortization
|
|
|
5,990
|
|
|
5,975
|
|
Taxes
Other Than Income Taxes
|
|
|
1,081
|
|
|
1,070
|
|
TOTAL
|
|
|
74,928
|
|
|
73,931
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
2,223
|
|
|
4,220
|
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
|
(1,252
|
)
|
|
(722
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
971
|
|
|
3,498
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense (Credit)
|
|
|
(620
|
)
|
|
570
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
1,591
|
|
$
|
2,928
|
|
CONDENSED
STATEMENTS OF RETAINED EARNINGS
For
the Three Months Ended March 31, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
BALANCE
AT BEGINNING OF PERIOD
|
|
$
|
30,942
|
|
$
|
26,038
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
27
|
|
|
-
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
|
1,591
|
|
|
2,928
|
|
|
|
|
|
|
|
|
|
Cash
Dividends Declared
|
|
|
-
|
|
|
1,998
|
|
|
|
|
|
|
|
|
|
BALANCE
AT END OF PERIOD
|
|
$
|
32,560
|
|
$
|
26,968
|
|
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, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Accounts
Receivable - Affiliated Companies
|
|
$
|
29,380
|
|
$
|
31,060
|
|
Fuel
|
|
|
28,414
|
|
|
37,701
|
|
Materials
and Supplies
|
|
|
8,024
|
|
|
7,873
|
|
Accrued
Tax Benefits
|
|
|
1,820
|
|
|
3,808
|
|
Prepayments
and Other
|
|
|
38
|
|
|
57
|
|
TOTAL
|
|
|
67,676
|
|
|
80,499
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric
- Production
|
|
|
688,599
|
|
|
686,776
|
|
Other
|
|
|
2,567
|
|
|
2,460
|
|
Construction
Work in Progress
|
|
|
15,931
|
|
|
15,198
|
|
Total
|
|
|
707,097
|
|
|
704,434
|
|
Accumulated
Depreciation and Amortization
|
|
|
405,676
|
|
|
398,422
|
|
TOTAL
- NET
|
|
|
301,421
|
|
|
306,012
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
5,403
|
|
|
5,438
|
|
Deferred
Charges and Other
|
|
|
3,667
|
|
|
1,382
|
|
TOTAL
|
|
|
9,070
|
|
|
6,820
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
378,167
|
|
$
|
393,331
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
GENERATING COMPANY
CONDENSED
BALANCE SHEETS
LIABILITIES
AND SHAREHOLDER’S EQUITY
March
31, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
29,997
|
|
$
|
53,646
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
6
|
|
|
549
|
|
Affiliated
Companies
|
|
|
18,918
|
|
|
27,935
|
|
Accrued
Taxes
|
|
|
7,092
|
|
|
3,685
|
|
Accrued
Rent - Rockport Plant Unit 2
|
|
|
23,427
|
|
|
4,963
|
|
Other
|
|
|
521
|
|
|
1,200
|
|
TOTAL
|
|
|
79,961
|
|
|
91,978
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
44,839
|
|
|
44,837
|
|
Deferred
Income Taxes
|
|
|
19,792
|
|
|
19,749
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
76,069
|
|
|
79,650
|
|
Deferred
Gain on Sale and Leaseback - Rockport Plant Unit 2
|
|
|
87,370
|
|
|
88,762
|
|
Deferred
Credits and Other
|
|
|
13,142
|
|
|
12,979
|
|
TOTAL
|
|
|
241,212
|
|
|
245,977
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
321,173
|
|
|
337,955
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - Par Value - $1,000 Per Share:
Authorized
- 1,000 Shares
Outstanding
- 1,000 Shares
|
|
|
1,000
|
|
|
1,000
|
|
Paid-in
Capital
|
|
|
23,434
|
|
|
23,434
|
|
Retained
Earnings
|
|
|
32,560
|
|
|
30,942
|
|
TOTAL
|
|
|
56,994
|
|
|
55,376
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$
|
378,167
|
|
$
|
393,331
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
1,591
|
|
$
|
2,928
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
5,990
|
|
|
5,975
|
|
Deferred
Income Taxes
|
|
|
(1,205
|
)
|
|
(1,126
|
)
|
Deferred
Investment Tax Credits
|
|
|
(820
|
)
|
|
(827
|
)
|
Amortization
of Deferred Gain on Sale and Leaseback - Rockport Plant Unit
2
|
|
|
(1,392
|
)
|
|
(1,392
|
)
|
Deferred
Property Taxes
|
|
|
(2,516
|
)
|
|
(2,734
|
)
|
Changes
in Other Noncurrent Assets
|
|
|
47
|
|
|
(403
|
)
|
Changes
in Other Noncurrent Liabilities
|
|
|
200
|
|
|
374
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
|
1,680
|
|
|
1,607
|
|
Fuel,
Materials and Supplies
|
|
|
9,136
|
|
|
(1,044
|
)
|
Accounts
Payable
|
|
|
(9,560
|
)
|
|
(2,068
|
)
|
Accrued
Taxes, Net
|
|
|
5,252
|
|
|
6,179
|
|
Accrued
Rent - Rockport Plant Unit 2
|
|
|
18,464
|
|
|
18,464
|
|
Other
Current Assets
|
|
|
(28
|
)
|
|
(35
|
)
|
Other
Current Liabilities
|
|
|
(332
|
)
|
|
(379
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
26,507
|
|
|
25,519
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(2,841
|
)
|
|
(1,693
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
(23,649
|
)
|
|
(21,814
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(17
|
)
|
|
(14
|
)
|
Dividends
Paid on Common Stock
|
|
|
-
|
|
|
(1,998
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(23,666
|
)
|
|
(23,826
|
)
|
|
|
|
|
|
|
|
|
Net
Change in Cash and Cash Equivalents
|
|
|
-
|
|
|
-
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
-
|
|
|
-
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
-
|
|
$
|
-
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
1,398
|
|
$
|
1,109
|
|
Net
Cash Received for Income Taxes
|
|
|
(439
|
)
|
|
-
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1
|
|
|
27
|
|
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,
Guarantees and Contingencies
|
Note
4
|
Acquisitions,
Dispositions and Assets Held for Sale
|
Note
5
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Net
Income
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Off-system
Sales
|
|
|
7
|
|
|
|
|
Texas
Wires
|
|
|
6
|
|
|
|
|
Transmission
Revenues
|
|
|
1
|
|
|
|
|
Other
|
|
|
28
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
2
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(13
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
2
|
|
|
|
|
Carrying
Costs Income
|
|
|
(19
|
)
|
|
|
|
Other
Income
|
|
|
5
|
|
|
|
|
Interest
Expense
|
|
|
(19
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(42
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
4
|
|
Net
Income remained relatively flat in the first quarter of 2007 compared to
the
first quarter of 2006.
The
major
components of our change in Gross Margin, defined as revenues less the
related
direct costs of fuel, including the consumption of emissions allowances,
and
purchased power were as follows:
·
|
Margins
from Off-system Sales increased $7 million primarily due to lower
margins
from optimization activities of $5 million in 2006. An additional
$2
million increase was primarily due to a $4 million provision
for refund
recorded in 2006 related to the pending and subsequent sale of
our portion
of the Oklaunion Plant offset in part by reduced sales margins
upon
completion of the sale.
|
·
|
Texas
Wires revenues increased $6 million primarily due to increased
usage and
favorable weather conditions. As compared to the prior year, heating
degree days more than doubled.
|
·
|
Other
revenues increased $28 million. This increase was due in part
to $36
million of revenue from securitization transition charges primarily
resulting from new financing in October 2006. Securitization
transition
charges represent amounts collected to recover securitization
bond
principal and interest payments related to our securitized transition
assets and are fully offset by amortization and interest expenses.
This
increase was partially offset by a $7 million decrease in third
party
construction project revenues mainly 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 $2 million primarily
due to a
$5 million decrease from lower expenses related to construction
projects
performed for third parties, primarily Lower Colorado River Authority.
This decrease is partially offset by an increase of $2 million
in payments
made for transmission services and approximately $1 million increase
related to the replacement of meters.
|
·
|
Depreciation
and Amortization expense increased $13 million primarily due
to the
recovery and amortization of the securitization assets of $15
million
offset in part by $2 million related to the amortization of the
CTC
liability (see “TCC’s 2006 Securitization Proceeding” and “TCC’s 2006 CTC
Proceeding” sections of Note 4 of the 2006 Annual
Report).
|
·
|
Taxes
Other Than Income Taxes decreased $2 million primarily due to
lower
property-related taxes related to Texas tax legislation and the
sale of
our portion of Oklaunion in February 2007.
|
·
|
Carrying
Costs Income decreased $19 million primarily due to the absence
of
carrying cost on stranded cost recovery.
|
·
|
Other
Income increased $5 million primarily due to larger invested
balances in
the Utility Money Pool.
|
·
|
Interest
Expense increased $19 million primarily due to a $22 million
increase in
long-term debt interest primarily related to the Securitization
Bonds
issued in October 2006, offset in part by the retirement of other
long-term debt.
|
Income
Taxes
Income
Tax Expense remained relatively flat for the first quarter 2007.
Financial
Condition
Credit
Ratings
In
April
2007, Fitch Ratings downgraded our unsecured debt from A- to BBB+ and placed
us
on negative outlook. The negative rating outlook reflects Fitch’s expectation
that credit metrics will continue to be weak for the BBB rating category
absent
a favorable outcome in our pending rate case in Texas. See “TCC and TNC Energy
Delivery Base Rate Filings” in Note 3.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in our 2006 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption
of New Accounting Pronouncements
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
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 $228 million and $232 million at March
31,
2007 and December 31, 2006, respectively. We would not expect to liquidate
our
entire debt portfolio in a one-year holding period; therefore, a near term
change in interest rates should not negatively affect our results of operations
or consolidated financial position.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three Months Ended March 31, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
171,987
|
|
$
|
123,211
|
|
Sales
to AEP Affiliates
|
|
|
1,130
|
|
|
1,598
|
|
Other
|
|
|
3,814
|
|
|
10,479
|
|
TOTAL
|
|
|
176,931
|
|
|
135,288
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
825
|
|
|
1,726
|
|
Purchased
Electricity for Resale
|
|
|
1,509
|
|
|
1,680
|
|
Other
Operation
|
|
|
57,396
|
|
|
58,902
|
|
Maintenance
|
|
|
7,785
|
|
|
7,789
|
|
Depreciation
and Amortization
|
|
|
46,020
|
|
|
33,360
|
|
Taxes
Other Than Income Taxes
|
|
|
18,524
|
|
|
20,363
|
|
TOTAL
|
|
|
132,059
|
|
|
123,820
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
44,872
|
|
|
11,468
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
4,959
|
|
|
505
|
|
Carrying
Costs Income
|
|
|
-
|
|
|
19,423
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
1,159
|
|
|
373
|
|
Interest
Expense
|
|
|
(46,021
|
)
|
|
(26,773
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
4,969
|
|
|
4,996
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
1,431
|
|
|
1,223
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
3,538
|
|
|
3,773
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
60
|
|
|
60
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
3,478
|
|
$
|
3,713
|
|
The
common stock of TCC is owned by a wholly-owned subsidiary of
AEP.
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME
For
the Three Months Ended March 31, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$
|
55,292
|
|
$
|
132,606
|
|
$
|
217,218
|
|
$
|
-
|
|
$
|
405,116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
(2,187
|
)
|
|
|
|
|
(2,187
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(60
|
)
|
|
|
|
|
(60
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
402,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
3,538
|
|
|
|
|
|
3,538
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2007
|
|
$
|
55,292
|
|
$
|
132,606
|
|
$
|
218,509
|
|
$
|
-
|
|
$
|
406,407
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
52
|
|
$
|
779
|
|
Other
Cash Deposits
|
|
|
131,824
|
|
|
104,203
|
|
Advances
to Affiliates
|
|
|
216,953
|
|
|
394,004
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
44,519
|
|
|
31,215
|
|
Affiliated
Companies
|
|
|
6,513
|
|
|
8,613
|
|
Accrued
Unbilled Revenues
|
|
|
17,969
|
|
|
10,093
|
|
Allowance
for Uncollectible Accounts
|
|
|
(45
|
)
|
|
(49
|
)
|
Total Accounts Receivable
|
|
|
68,956
|
|
|
49,872
|
|
Materials
and Supplies
|
|
|
30,526
|
|
|
28,347
|
|
Prepayments
and Other
|
|
|
11,107
|
|
|
5,672
|
|
TOTAL
|
|
|
459,418
|
|
|
582,877
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Transmission
|
|
|
917,708
|
|
|
904,527
|
|
Distribution
|
|
|
1,602,745
|
|
|
1,579,498
|
|
Other
|
|
|
224,856
|
|
|
220,028
|
|
Construction
Work in Progress
|
|
|
166,300
|
|
|
165,979
|
|
Total
|
|
|
2,911,609
|
|
|
2,870,032
|
|
Accumulated
Depreciation and Amortization
|
|
|
636,740
|
|
|
630,239
|
|
TOTAL
- NET
|
|
|
2,274,869
|
|
|
2,239,793
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
187,765
|
|
|
193,111
|
|
Securitized
Transition Assets
|
|
|
2,133,966
|
|
|
2,158,408
|
|
Employee
Benefits and Pension Assets
|
|
|
35,534
|
|
|
35,574
|
|
Deferred
Charges and Other
|
|
|
68,393
|
|
|
69,493
|
|
TOTAL
|
|
|
2,425,658
|
|
|
2,456,586
|
|
|
|
|
|
|
|
|
|
Assets
Held for Sale - Texas Generation Plant
|
|
|
-
|
|
|
44,475
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
5,159,945
|
|
$
|
5,323,731
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
March
31, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Accounts
Payable:
|
|
|
|
|
|
General
|
|
$
|
17,857
|
|
$
|
26,934
|
|
Affiliated
Companies
|
|
|
17,329
|
|
|
21,234
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
138,507
|
|
|
78,227
|
|
Customer
Deposits
|
|
|
17,851
|
|
|
18,742
|
|
Accrued
Taxes
|
|
|
33,474
|
|
|
74,499
|
|
Accrued
Interest
|
|
|
57,625
|
|
|
44,712
|
|
Other
|
|
|
21,138
|
|
|
34,762
|
|
TOTAL
|
|
|
303,781
|
|
|
299,110
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
2,845,020
|
|
|
2,937,387
|
|
Deferred
Income Taxes
|
|
|
1,037,080
|
|
|
1,034,123
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
503,627
|
|
|
598,027
|
|
Deferred
Credits and Other
|
|
|
58,109
|
|
|
44,047
|
|
TOTAL
|
|
|
4,443,836
|
|
|
4,613,584
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,747,617
|
|
|
4,912,694
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
5,921
|
|
|
5,921
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - Par Value - $25 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
|
|
|
218,509
|
|
|
217,218
|
|
TOTAL
|
|
|
406,407
|
|
|
405,116
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
5,159,945
|
|
$
|
5,323,731
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Three Months Ended March 31, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
3,538
|
|
$
|
3,773
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
46,020
|
|
|
33,360
|
|
Deferred
Income Taxes
|
|
|
11,102
|
|
|
2,928
|
|
Carrying
Costs on Stranded Cost Recovery
|
|
|
-
|
|
|
(19,423
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
-
|
|
|
5,125
|
|
Fuel
Over/Under Recovery, Net
|
|
|
(98,665
|
)
|
|
-
|
|
Deferred
Property Taxes
|
|
|
(20,064
|
)
|
|
(25,755
|
)
|
Change
in Other Noncurrent Assets
|
|
|
(753
|
)
|
|
(1,330
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
3,187
|
|
|
1,398
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(19,084
|
)
|
|
121,367
|
|
Fuel,
Materials and Supplies
|
|
|
(2,543
|
)
|
|
(2,569
|
)
|
Accounts
Payable
|
|
|
(3,957
|
)
|
|
(53,124
|
)
|
Customer
Deposits
|
|
|
(891
|
)
|
|
(6,514
|
)
|
Accrued
Taxes, Net
|
|
|
(40,642
|
)
|
|
6,854
|
|
Accrued
Interest
|
|
|
11,019
|
|
|
(16,152
|
)
|
Other
Current Assets
|
|
|
681
|
|
|
2,629
|
|
Other
Current Liabilities
|
|
|
(13,867
|
)
|
|
(7,461
|
)
|
Net
Cash Flows From (Used for) Operating Activities
|
|
|
(124,919
|
)
|
|
45,106
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(59,872
|
)
|
|
(58,645
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
(6,071
|
)
|
|
29,736
|
|
Change
in Advances to Affiliates, Net
|
|
|
177,051
|
|
|
(32,101
|
)
|
Proceeds
from Sale of Assets
|
|
|
45,619
|
|
|
3,837
|
|
Net
Cash Flows From (Used For) Investing Activities
|
|
|
156,727
|
|
|
(57,173
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt - Affiliated
|
|
|
-
|
|
|
125,000
|
|
Change
in Advances from Affiliates, Net
|
|
|
-
|
|
|
(82,080
|
)
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
(32,125
|
)
|
|
(30,641
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(350
|
)
|
|
(152
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(60
|
)
|
|
(60
|
)
|
Net
Cash From (Used For) Financing Activities
|
|
|
(32,535
|
)
|
|
12,067
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(727
|
)
|
|
-
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
779
|
|
|
-
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
52
|
|
$
|
-
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
27,961
|
|
$
|
40,646
|
|
Net
Cash Paid for Income Taxes
|
|
|
32,601
|
|
|
485
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
363
|
|
|
680
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
7,477
|
|
|
9,970
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to TCC’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for
other
registrant subsidiaries. Listed below are the notes that apply to TCC.
|
Footnote
Reference
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Acquisitions,
Dispositions and Assets Held for Sale
|
Note
5
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Net
Income
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Off-system
Sales
|
|
|
3
|
|
|
|
|
Texas
Wires
|
|
|
2
|
|
|
|
|
Transmission
Revenues
|
|
|
1
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(4
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
5
|
|
Net
Income increased $1 million primarily due to an increase in Gross Margin
of $6
million partially offset by an increase in Other Operation and Maintenance
expenses of $4 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:
·
|
Margins
from Off-system Sales increased $3 million primarily due to lower
margins
from optimization activities of $2 million in 2006. An additional
$1
million increase was primarily due to the implementation of the
Power
Purchase Agreement with AEP Energy Partners in January 2007.
Under this
agreement, we recover our costs and capacity charges regardless
of plant
availability. See “Oklaunion PPA between TNC and AEP Energy Partners”
section of Note 1.
|
·
|
Texas
Wires revenues increased $2 million primarily due to increased
usage and
favorable weather conditions. As compared to the prior year,
heating
degree days increased 77%.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $4 million primarily
resulting from planned and forced outages at our Oklaunion Plant
during
the first quarter of 2007.
|
Income
Taxes
Income
Tax Expense increased $1 million primarily due to an increase in pretax
book
income.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in our 2006 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption
of New Accounting Pronouncements
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management assets and liabilities are zero at March 31, 2007 as a result
of our
exit from the generation business. See “Oklaunion PPA between TNC and AEP Energy
Partners” section of Note 1.
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 $12 million at March
31, 2007
and December 31, 2006, respectively. We would not expect to liquidate our
entire
debt portfolio in a one-year holding period; therefore, a near term change
in
interest rates should not negatively affect our results of operations or
financial position.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three Months Ended March 31, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
38,079
|
|
$
|
68,825
|
|
Sales
to AEP Affiliates
|
|
|
24,654
|
|
|
6,025
|
|
Other
|
|
|
230
|
|
|
(184
|
)
|
TOTAL
|
|
|
62,963
|
|
|
74,666
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
6,276
|
|
|
12,115
|
|
Purchased
Electricity for Resale
|
|
|
2,802
|
|
|
14,396
|
|
Other
Operation
|
|
|
19,563
|
|
|
18,478
|
|
Maintenance
|
|
|
7,467
|
|
|
5,201
|
|
Depreciation
and Amortization
|
|
|
10,346
|
|
|
10,301
|
|
Taxes
Other Than Income Taxes
|
|
|
4,841
|
|
|
5,540
|
|
TOTAL
|
|
|
51,295
|
|
|
66,031
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
11,668
|
|
|
8,635
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
133
|
|
|
219
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
52
|
|
|
382
|
|
Interest
Expense
|
|
|
(4,346
|
)
|
|
(4,362
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
7,507
|
|
|
4,874
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
2,230
|
|
|
1,040
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
5,277
|
|
|
3,834
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
26
|
|
|
26
|
|
Gain
on Reacquired Preferred Stock
|
|
|
-
|
|
|
2
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
5,251
|
|
$
|
3,810
|
|
The
common
stock of TNC is owned by a wholly-owned subsidiary of AEP.
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME
For
the Three Months Ended March 31, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$
|
137,214
|
|
$
|
2,351
|
|
$
|
176,950
|
|
$
|
(10,159
|
)
|
$
|
306,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
(557
|
)
|
|
|
|
|
(557
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(26
|
)
|
|
|
|
|
(26
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
305,773
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $378
|
|
|
|
|
|
|
|
|
|
|
|
702
|
|
|
702
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
5,277
|
|
|
|
|
|
5,277
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2007
|
|
$
|
137,214
|
|
$
|
2,351
|
|
$
|
181,644
|
|
$
|
(9,457
|
)
|
$
|
311,752
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
3
|
|
$
|
84
|
|
Other
Cash Deposits
|
|
|
8,958
|
|
|
8,863
|
|
Advances
to Affiliates
|
|
|
-
|
|
|
13,543
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
11,080
|
|
|
21,742
|
|
Affiliated
Companies
|
|
|
13,177
|
|
|
5,634
|
|
Accrued
Unbilled Revenues
|
|
|
2,917
|
|
|
2,292
|
|
Allowance
for Uncollectible Accounts
|
|
|
(18
|
)
|
|
(9
|
)
|
Total Accounts Receivable
|
|
|
27,156
|
|
|
29,659
|
|
Fuel
|
|
|
11,401
|
|
|
8,559
|
|
Materials
and Supplies
|
|
|
9,544
|
|
|
9,319
|
|
Prepayments
and Other
|
|
|
1,879
|
|
|
1,681
|
|
TOTAL
|
|
|
58,941
|
|
|
71,708
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
290,654
|
|
|
290,485
|
|
Transmission
|
|
|
330,272
|
|
|
327,845
|
|
Distribution
|
|
|
506,752
|
|
|
512,265
|
|
Other
|
|
|
160,141
|
|
|
159,451
|
|
Construction
Work in Progress
|
|
|
36,145
|
|
|
38,847
|
|
Total
|
|
|
1,323,964
|
|
|
1,328,893
|
|
Accumulated
Depreciation and Amortization
|
|
|
483,960
|
|
|
486,961
|
|
TOTAL
- NET
|
|
|
840,004
|
|
|
841,932
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
38,356
|
|
|
38,402
|
|
Employee
Benefits and Pension Assets
|
|
|
12,824
|
|
|
12,867
|
|
Deferred
Charges and Other
|
|
|
12,807
|
|
|
2,605
|
|
TOTAL
|
|
|
63,987
|
|
|
53,874
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
962,932
|
|
$
|
967,514
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’
EQUITY
March
31, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
11,185
|
|
$
|
-
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
6,328
|
|
|
4,448
|
|
Affiliated
Companies
|
|
|
34,129
|
|
|
43,993
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
8,151
|
|
|
8,151
|
|
Accrued
Taxes
|
|
|
19,477
|
|
|
21,782
|
|
Other
|
|
|
8,687
|
|
|
14,934
|
|
TOTAL
|
|
|
87,957
|
|
|
93,308
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
268,807
|
|
|
268,785
|
|
Long-term
Risk Management Liabilities
|
|
|
-
|
|
|
1,081
|
|
Deferred
Income Taxes
|
|
|
120,261
|
|
|
124,048
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
132,646
|
|
|
139,429
|
|
Deferred
Credits and Other
|
|
|
39,160
|
|
|
32,158
|
|
TOTAL
|
|
|
560,874
|
|
|
565,501
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
648,831
|
|
|
658,809
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
2,349
|
|
|
2,349
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - Par Value - $25 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
|
|
|
181,644
|
|
|
176,950
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(9,457
|
)
|
|
(10,159
|
)
|
TOTAL
|
|
|
311,752
|
|
|
306,356
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
962,932
|
|
$
|
967,514
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For
the Three Months Ended March 31, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
5,277
|
|
$
|
3,834
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
10,346
|
|
|
10,301
|
|
Deferred
Income Taxes
|
|
|
(1,016
|
)
|
|
(1,323
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
-
|
|
|
1,989
|
|
Deferred
Property Taxes
|
|
|
(10,862
|
)
|
|
(12,360
|
)
|
Change
in Other Noncurrent Assets
|
|
|
1,508
|
|
|
(2,081
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
(5,713
|
)
|
|
652
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
2,503
|
|
|
36,836
|
|
Fuel,
Materials and Supplies
|
|
|
(3,067
|
)
|
|
(2,156
|
)
|
Accounts
Payable
|
|
|
(9,176
|
)
|
|
(36,932
|
)
|
Accrued
Taxes, Net
|
|
|
(302
|
)
|
|
4,059
|
|
Other
Current Assets
|
|
|
(255
|
)
|
|
1,676
|
|
Other
Current Liabilities
|
|
|
(5,975
|
)
|
|
(9,775
|
)
|
Net
Cash Flows Used For Operating Activities
|
|
|
(16,732
|
)
|
|
(5,280
|
)
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(19,793
|
)
|
|
(18,662
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
(95
|
)
|
|
792
|
|
Change
In Advances to Affiliates, Net
|
|
|
13,543
|
|
|
31,240
|
|
Proceeds
from Sale of Assets
|
|
|
11,965
|
|
|
-
|
|
Net
Cash Flows From Investing Activities
|
|
|
5,620
|
|
|
13,370
|
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
11,185
|
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(128
|
)
|
|
(64
|
)
|
Dividends
Paid on Common Stock
|
|
|
-
|
|
|
(8,000
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(26
|
)
|
|
(26
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
11,031
|
|
|
(8,090
|
)
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(81
|
)
|
|
-
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
84
|
|
|
-
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
3
|
|
$
|
-
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
6,150
|
|
$
|
6,113
|
|
Net
Cash Paid for Income Taxes
|
|
|
2,288
|
|
|
-
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
98
|
|
|
224
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
2,509
|
|
|
2,372
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to TNC’s condensed financial statements are combined with the
condensed notes to condensed financial statements for other registrant
subsidiaries. Listed below are the notes that apply to TNC.
|
Footnote
Reference
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
APPALACHIAN
POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Net
Income
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
74
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
29
|
|
|
|
|
Off-system
Sales
|
|
|
(6
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(11
|
)
|
|
|
|
Other
|
|
|
1
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(5
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(11
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
2
|
|
|
|
|
Carrying
Costs Income
|
|
|
(3
|
)
|
|
|
|
Interest
Expense
|
|
|
(2
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(19
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
70
|
|
Net
Income decreased $4 million to $70 million in 2007 primarily due to an
increase
in Operating Expenses and Other of $19 million, partially offset by an
increase
in Gross Margin of $13 million.
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 $29 million in comparison to 2006 primarily
due
to:
|
|
·
|
A
$42 million increase in retail revenues primarily related to
new rates
implemented in relation to our Virginia general rate case, which
are being
collected subject to refund, and recovery of Virginia Environmental
and
Reliability (E&R) costs. See the “APCo Virginia Base Rate Case”
section of Note 3.
|
|
·
|
A
$9 million increase in retail sales primarily due to increased
demand in
the residential class associated with favorable weather conditions.
Heating degree days increased approximately 19%.
|
|
These
increases were partially offset by:
|
|
·
|
A
$14 million decrease in revenues related to financial transmission
rights,
net of congestion, primarily due to fewer transmission constraints
in the
PJM market.
|
|
·
|
A
$9 million decrease in revenues related to the Expanded Net Energy
Cost
(ENEC) mechanism with West Virginia retail customers primarily
due to
pass-through of off-system sales margins. The mechanism
was reinstated in West Virginia effective July 1, 2006 in conjunction
with
our West Virginia rate case.
|
·
|
Margins
from Off-system Sales decreased $6 million primarily due to an
$18 million
decrease in physical sales margins partially offset by a $10
million
increase in margins from optimization activities and a $2 million
increase
in our allocation of off-system sales margins under the SIA.
The change in
allocation methodology of the SIA occurred on April 1, 2006.
|
·
|
Transmission
Revenues decreased $11 million primarily due to the elimination
of SECA
revenues as of April 1, 2006. See the “Transmission Rate Proceedings at
the FERC” section of Note 3.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $5 million mainly
due to a $6
million increase in expenses for overhead line right-of-way clearing,
overhead line repairs and increases in various other operation
and
maintenance expenses totaling $8 million. These increases were
partially
offset by a $9 million decrease in expenses related to the AEP
Transmission Equalization Agreement due to the addition of our
Wyoming-Jacksons Ferry 765 kV line which was energized and placed
into
service in June 2006.
|
·
|
Depreciation
and Amortization expenses increased $11 million primarily due
to the
amortization of carrying charges and depreciation expense that
are being
collected through the E&R surcharges and increased plant in service
related to the Wyoming-Jacksons Ferry 765 kV line, which was
energized and
placed in service in June 2006.
|
·
|
Carrying
Costs Income decreased $3 million related to carrying costs associated
with our E&R case.
|
Income
Taxes
Income
Tax Expense decreased $2 million primarily due to a decrease 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, 2007 and 2006 were as
follows:
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
2,318
|
|
$
|
1,741
|
|
Cash
Flows From (Used For):
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
176,029
|
|
|
210,980
|
|
Investing
Activities
|
|
|
(200,894
|
)
|
|
(194,897
|
)
|
Financing
Activities
|
|
|
24,534
|
|
|
(16,372
|
)
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(331
|
)
|
|
(289
|
)
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,987
|
|
$
|
1,452
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $176 million in 2007. We produced
income of
$70 million during the period and a noncash expense item of $59 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
in
2007.
Net
Cash
Flows From Operating Activities were $211 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.
Investing
Activities
Net
Cash
Flows Used For Investing Activities during 2007 and 2006 primarily reflect
our
construction expenditures of $202 million and $197 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, capital projects for transmission expenditures
were
primarily related to the Wyoming-Jacksons Ferry 765 KV line placed into
service
in June 2006. Environmental upgrades include the installation of selective
catalytic reduction equipment on our plants and the flue gas desulfurization
project at the Amos and Mountaineer plants. In February 2007, environmental
upgrades were completed for the Mountaineer plant. For the remainder of
2007, we
expect construction expenditures to be approximately $460 million.
Financing
Activities
Net
Cash
Flows From Financing Activities were $25 million in 2007. We had a net
increase
of $48 million in borrowings from the Utility Money Pool and paid $15 million
in
dividends on common stock.
Net
Cash
Flows Used For Financing Activities were $16 million in 2006. 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.
Financing
Activity
There
were no material long-term debt issuances and retirements during the first
three
months of 2007.
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 2006 Annual Report and
has not
changed significantly from year-end.
Significant
Factors
New
Generation
In
January 2006, we filed a petition with the WVPSC requesting our approval
of a
Certificate of Public Convenience and Necessity to construct a 629 MW IGCC
plant
adjacent to our existing Mountaineer Generating Station in Mason County,
WV. In
January 2007, at our request, the WVPSC issued an order delaying the
Commission’s deadline for issuing an order on the certificate to December 2007.
Through March 31, 2007, we deferred pre-construction IGCC costs totaling
$10
million. If the plant is not built and these costs are not recoverable,
future
results of operations and cash flows would be adversely affected.
Virginia
Restructuring
In
April
2004, Virginia enacted legislation that extended the transition period for
electricity restructuring, including capped rates, through December 31,
2010.
The legislation provides us with specified cost recovery opportunities
during
the capped rate period, including two optional bundled general base rate
changes
and an opportunity for timely recovery, through a separate rate mechanism,
of
certain incremental environmental and reliability costs incurred on and
after
July 1, 2004. Under the restructuring law, we continue to have an active
fuel
clause recovery mechanism in Virginia and continue to practice deferred
fuel
accounting. Also, under the restructuring law, we defer incremental
environmental generation costs and incremental transmission and distribution
reliability costs for future recovery, to the extent such costs are not
being
recovered when incurred, and amortize a portion of such deferrals commensurate
with recovery.
In
April
2007, the Virginia legislature adopted a comprehensive law
providing for the re-regulation of electric utilities’ generation/supply
rates. The amendments shorten the transition period by two years (from
2010 to 2008) after which rates for retail generation/supply will return
to a
form of cost-based regulation. The legislation provides for, among other
things,
biennial rate reviews beginning in 2009, rate adjustment clauses for the
recovery of the costs of (a) transmission services and new transmission
investment, (b) Demand Side Management, load management, and energy efficiency
programs, (c) renewable energy programs, and (d) environmental retrofit
and new
generation investments, significant return on equity enhancements for large
investments in new generation and, subject to Virginia SCC approval, certain
environmental retrofits, and a floor on the allowed return on equity based
on
the average earned return on equities’ of regional vertically integrated
electric utilities. Effective July 1, 2007, the amendments allow utilities
to
retain a minimum of 25% of the margins from off-system sales with the remaining
margins from such sales credited against fuel factor expenses. The legislation
also allows us to continue to defer and recover incremental environmental
and
reliability costs incurred through December 31, 2008. We expect this new
form of
cost-based ratemaking should improve our annual return on equity and cash
flow
from operations when new ratemaking begins in 2009. However, with the return
of
cost-based regulation, our generation business will again meet the criteria
for
application of regulatory accounting principles under SFAS 71. Results
of
operations and financial condition could be adversely affected when we
are
required to re-establish certain net regulatory liabilities applicable
to our
generation/supply business. The timing and earnings effect from such
reapplication of SFAS 71 regulatory accounting for our Virginia
generation/supply business are uncertain at this time.
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 6 - Commitments, Guarantees and Contingencies in our 2006 Annual Report.
Also, see Note 3 - Rate Matters and Note 4 - Commitments, Guarantees and
Contingencies in the “Condensed Notes to Condensed Financial Statements of
Registrant Subsidiaries” section. Adverse results in these proceedings have the
potential to materially affect 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 2006 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption
of New Accounting Pronouncements
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management assets and liabilities are managed by AEPSC as agent for us.
The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative
Disclosures About Risk Management Activities” section. The following tables
provide information about AEP’s risk management activities’ effect on
us.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included on our condensed consolidated balance sheet as of March 31, 2007
and
the reasons for changes in our total MTM value as compared to December
31, 2006.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of March 31, 2007
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow &
Fair
Value
Hedges
|
|
DETM
Assignment
(a)
|
|
Total
|
|
Current
Assets
|
|
$
|
66,058
|
|
$
|
1,405
|
|
$
|
-
|
|
$
|
67,463
|
|
Noncurrent
Assets
|
|
|
84,718
|
|
|
1,269
|
|
|
-
|
|
|
85,987
|
|
Total
MTM Derivative Contract Assets
|
|
|
150,776
|
|
|
2,674
|
|
|
-
|
|
|
153,450
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(47,767
|
)
|
|
(6,899
|
)
|
|
(3,152
|
)
|
|
(57,818
|
)
|
Noncurrent
Liabilities
|
|
|
(49,833
|
)
|
|
(804
|
)
|
|
(8,358
|
)
|
|
(58,995
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(97,600
|
)
|
|
(7,703
|
)
|
|
(11,510
|
)
|
|
(116,813
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
53,176
|
|
$
|
(5,029
|
)
|
$
|
(11,510
|
)
|
$
|
36,637
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2006 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 2007
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2006
|
|
$
|
52,489
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
(5,389
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
255
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired
Option
Contracts Entered During the Period
|
|
|
(35
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
4,918
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
938
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
53,176
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
(5,029
|
)
|
DETM
Assignment (d)
|
|
|
(11,510
|
)
|
Total
MTM Risk Management Contract Net Assets at March 31, 2007
|
|
$
|
36,637
|
|
(a)
|
Reflects
fair value on long-term contracts which are typically with customers
that
seek fixed pricing to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can
be obtained
for valuation inputs for the entire contract term. The contract
prices are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
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 16 of the 2006 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 to give an indication
of
when these MTM amounts will settle and generate
cash.
|
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets
Fair
Value of Contracts as of March 31, 2007
(in
thousands)
|
|
Remainder
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
After
2011
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
15,650
|
|
$
|
(644
|
)
|
$
|
706
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
15,712
|
|
Prices
Provided by Other External Sources
-
OTC Broker Quotes (a)
|
|
|
3,482
|
|
|
13,908
|
|
|
11,448
|
|
|
4,542
|
|
|
-
|
|
|
-
|
|
|
33,380
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(3,723
|
)
|
|
(2,358
|
)
|
|
1,822
|
|
|
5,482
|
|
|
1,235
|
|
|
1,626
|
|
|
4,084
|
|
Total
|
|
$
|
15,409
|
|
$
|
10,906
|
|
$
|
13,976
|
|
$
|
10,024
|
|
$
|
1,235
|
|
$
|
1,626
|
|
$
|
53,176
|
|
(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.
|
|
|
|
Contract
values that are measured using models or valuation methods other
than
active quotes or OTC broker quotes (because of the lack of such
data for
all delivery quantities, locations and periods) incorporate in
the model
or other valuation methods, to the extent possible, OTC broker
quotes and
active quotes for deliveries in years and at locations for which
such
quotes are available.
|
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 use
various
commodity instruments designated in qualifying cash flow hedge strategies
to
mitigate the impact of these fluctuations on the future cash flows. We
do not
hedge all commodity price risk.
We
use
interest rate derivative transactions to manage interest rate risk related
to
anticipated borrowings of fixed-rate debt. We do not hedge all interest
rate
risk.
We
use
forward contracts and collars as cash flow hedges to lock in prices on
certain
transactions 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, 2006 to March 31, 2007. 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, 2007
(in
thousands)
|
|
Power
|
|
Foreign
Currency
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2006
|
|
$
|
5,332
|
|
$
|
(164
|
)
|
$
|
(7,715
|
)
|
$
|
(2,547
|
)
|
Changes
in Fair Value
|
|
|
(5,612
|
)
|
|
-
|
|
|
-
|
|
|
(5,612
|
)
|
Reclassifications
from AOCI to Net Income for
Cash
Flow Hedges
Settled
|
|
|
(2,221
|
)
|
|
2
|
|
|
347
|
|
|
(1,872
|
)
|
Ending
Balance in AOCI March 31, 2007
|
|
$
|
(2,501
|
)
|
$
|
(162
|
)
|
$
|
(7,368
|
)
|
$
|
(10,031
|
)
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $4,214 thousand loss.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
VaR
Associated with Risk Management Contracts
We
use a
risk measurement model, which calculates Value at Risk (VaR) to measure
our
commodity price risk in the risk management portfolio. The VaR is based
on the
variance-covariance method using historical prices to estimate volatilities
and
correlations and assumes a 95% confidence level and a one-day holding period.
Based on this VaR analysis, at March 31, 2007, 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, 2007
|
|
|
|
|
Twelve
Months Ended
December
31, 2006
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$712
|
|
$2,328
|
|
$1,037
|
|
$282
|
|
|
|
|
$756
|
|
$1,915
|
|
$658
|
|
$358
|
The
High
VaR for the twelve months ended December 31, 2006 occurred in the third
quarter
due to volatility in the ECAR/PJM region.
VaR
Associated with Debt Outstanding
We
utilize a VaR model to measure interest rate market risk exposure. The
interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence
level
and a one-year holding period. The
risk
of potential loss in fair value attributable to our exposure to interest
rates
primarily related to long-term debt with fixed interest rates was $176
million
and $153 million at March 31, 2007 and December 31, 2006, 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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
601,546
|
|
$
|
559,993
|
|
Sales
to AEP Affiliates
|
|
|
61,545
|
|
|
71,772
|
|
Other
|
|
|
2,637
|
|
|
2,676
|
|
TOTAL
|
|
|
665,728
|
|
|
634,441
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
171,186
|
|
|
166,853
|
|
Purchased
Electricity for Resale
|
|
|
35,950
|
|
|
27,616
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
127,601
|
|
|
122,399
|
|
Other
Operation
|
|
|
67,629
|
|
|
69,901
|
|
Maintenance
|
|
|
45,753
|
|
|
37,839
|
|
Depreciation
and Amortization
|
|
|
59,160
|
|
|
48,268
|
|
Taxes
Other Than Income Taxes
|
|
|
21,275
|
|
|
23,092
|
|
TOTAL
|
|
|
528,554
|
|
|
495,968
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
137,174
|
|
|
138,473
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
639
|
|
|
951
|
|
Carrying
Costs Income
|
|
|
3,166
|
|
|
6,011
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
2,777
|
|
|
2,476
|
|
Interest
Expense
|
|
|
(31,823
|
)
|
|
(30,268
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
111,933
|
|
|
117,643
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
41,706
|
|
|
44,049
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
70,227
|
|
|
73,594
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements including Capital Stock Expense
|
|
|
238
|
|
|
238
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
69,989
|
|
$
|
73,356
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$
|
260,458
|
|
$
|
1,024,994
|
|
$
|
805,513
|
|
$
|
(54,791
|
)
|
$
|
2,036,174
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
(2,685
|
)
|
|
|
|
|
(2,685
|
)
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(15,000
|
)
|
|
|
|
|
(15,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(200
|
)
|
|
|
|
|
(200
|
)
|
Capital
Stock Expense
|
|
|
|
|
|
38
|
|
|
(38
|
)
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,018,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $4,030
|
|
|
|
|
|
|
|
|
|
|
|
(7,484
|
)
|
|
(7,484
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
70,227
|
|
|
|
|
|
70,227
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62,743
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2007
|
|
$
|
260,458
|
|
$
|
1,025,032
|
|
$
|
857,817
|
|
$
|
(62,275
|
)
|
$
|
2,081,032
|
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
1,987
|
|
$
|
2,318
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
199,112
|
|
|
180,190
|
|
Affiliated
Companies
|
|
|
85,919
|
|
|
98,237
|
|
Accrued
Unbilled Revenues
|
|
|
29,618
|
|
|
46,281
|
|
Miscellaneous
|
|
|
4,849
|
|
|
3,400
|
|
Allowance
for Uncollectible Accounts
|
|
|
(4,573
|
)
|
|
(4,334
|
)
|
Total Accounts Receivable
|
|
|
314,925
|
|
|
323,774
|
|
Fuel
|
|
|
72,075
|
|
|
77,077
|
|
Materials
and Supplies
|
|
|
69,428
|
|
|
56,235
|
|
Risk
Management Assets
|
|
|
67,463
|
|
|
105,376
|
|
Accrued
Tax Benefits
|
|
|
9,189
|
|
|
3,748
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
17,789
|
|
|
29,526
|
|
Prepayments
and Other
|
|
|
15,682
|
|
|
20,126
|
|
TOTAL
|
|
|
568,538
|
|
|
618,180
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
3,363,911
|
|
|
2,844,803
|
|
Transmission
|
|
|
1,640,046
|
|
|
1,620,512
|
|
Distribution
|
|
|
2,276,327
|
|
|
2,237,887
|
|
Other
|
|
|
342,014
|
|
|
339,450
|
|
Construction
Work in Progress
|
|
|
512,388
|
|
|
957,626
|
|
Total
|
|
|
8,134,686
|
|
|
8,000,278
|
|
Accumulated
Depreciation and Amortization
|
|
|
2,470,106
|
|
|
2,476,290
|
|
TOTAL
- NET
|
|
|
5,664,580
|
|
|
5,523,988
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
612,352
|
|
|
622,153
|
|
Long-term
Risk Management Assets
|
|
|
85,987
|
|
|
88,906
|
|
Deferred
Charges and Other
|
|
|
167,913
|
|
|
163,089
|
|
TOTAL
|
|
|
866,252
|
|
|
874,148
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
7,099,370
|
|
$
|
7,016,316
|
|
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, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
82,860
|
|
$
|
34,975
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
286,892
|
|
|
296,437
|
|
Affiliated
Companies
|
|
|
77,642
|
|
|
105,525
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
324,169
|
|
|
324,191
|
|
Risk
Management Liabilities
|
|
|
57,818
|
|
|
81,114
|
|
Customer
Deposits
|
|
|
54,193
|
|
|
56,364
|
|
Accrued
Taxes
|
|
|
87,864
|
|
|
60,056
|
|
Accrued
Interest
|
|
|
55,787
|
|
|
30,617
|
|
Other
|
|
|
119,509
|
|
|
142,326
|
|
TOTAL
|
|
|
1,146,734
|
|
|
1,131,605
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
2,174,951
|
|
|
2,174,473
|
|
Long-term
Debt - Affiliated
|
|
|
100,000
|
|
|
100,000
|
|
Long-term
Risk Management Liabilities
|
|
|
58,995
|
|
|
64,909
|
|
Deferred
Income Taxes
|
|
|
933,703
|
|
|
957,229
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
307,018
|
|
|
309,724
|
|
Deferred
Credits and Other
|
|
|
279,174
|
|
|
224,439
|
|
TOTAL
|
|
|
3,853,841
|
|
|
3,830,774
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
5,000,575
|
|
|
4,962,379
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
17,763
|
|
|
17,763
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - No Par Value:
|
|
|
|
|
|
|
|
Authorized
- 30,000,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 13,499,500 Shares
|
|
|
260,458
|
|
|
260,458
|
|
Paid-in
Capital
|
|
|
1,025,032
|
|
|
1,024,994
|
|
Retained
Earnings
|
|
|
857,817
|
|
|
805,513
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(62,275
|
)
|
|
(54,791
|
)
|
TOTAL
|
|
|
2,081,032
|
|
|
2,036,174
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
7,099,370
|
|
$
|
7,016,316
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
70,227
|
|
$
|
73,594
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
59,160
|
|
|
48,268
|
|
Deferred
Income Taxes
|
|
|
(3,901
|
)
|
|
(11,423
|
)
|
Carrying
Costs Income
|
|
|
(3,166
|
)
|
|
(6,011
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
(401
|
)
|
|
(5,696
|
)
|
Change
in Other Noncurrent Assets
|
|
|
(12,747
|
)
|
|
4,020
|
|
Change
in Other Noncurrent Liabilities
|
|
|
30,172
|
|
|
5,848
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
8,849
|
|
|
75,278
|
|
Fuel,
Materials and Supplies
|
|
|
(1,034
|
)
|
|
13,028
|
|
Accounts
Payable
|
|
|
(19,891
|
)
|
|
(30,148
|
)
|
Customer
Deposits
|
|
|
(2,171
|
)
|
|
(13,530
|
)
|
Accrued
Taxes, Net
|
|
|
29,539
|
|
|
56,180
|
|
Accrued
Interest
|
|
|
21,608
|
|
|
15,511
|
|
Fuel
Over/Under Recovery, Net
|
|
|
12,987
|
|
|
7,832
|
|
Other
Current Assets
|
|
|
3,899
|
|
|
(1,718
|
)
|
Other
Current Liabilities
|
|
|
(17,101
|
)
|
|
(20,053
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
176,029
|
|
|
210,980
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(202,007
|
)
|
|
(196,561
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
(29
|
)
|
|
-
|
|
Proceeds
from Sales of Assets
|
|
|
1,142
|
|
|
1,664
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(200,894
|
)
|
|
(194,897
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt - Nonaffiliated
|
|
|
-
|
|
|
49,677
|
|
Change
in Advances from Affiliates, Net
|
|
|
47,885
|
|
|
(29,941
|
)
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
(3
|
)
|
|
(100,003
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(1,112
|
)
|
|
(1,483
|
)
|
Funds
From Amended Coal Contract
|
|
|
-
|
|
|
68,078
|
|
Amortization
of Funds From Amended Coal Contract
|
|
|
(7,036
|
)
|
|
-
|
|
Dividends
Paid on Common Stock
|
|
|
(15,000
|
)
|
|
(2,500
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(200
|
)
|
|
(200
|
)
|
Net
Cash Flows From (Used For) Financing Activities
|
|
|
24,534
|
|
|
(16,372
|
)
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(331
|
)
|
|
(289
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
2,318
|
|
|
1,741
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,987
|
|
$
|
1,452
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
7,084
|
|
$
|
14,686
|
|
Net
Cash Paid for Income Taxes
|
|
|
7,775
|
|
|
1,771
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
444
|
|
|
1,184
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
113,021
|
|
|
83,682
|
|
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,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
COLUMBUS
SOUTHERN POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Net
Income
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
51
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
27
|
|
|
|
|
Off-system
Sales
|
|
|
(11
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(7
|
)
|
|
|
|
Other
|
|
|
(4
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(10
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(4
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1
|
)
|
|
|
|
Interest
Expense
|
|
|
2
|
|
|
|
|
Other
|
|
|
1
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
47
|
|
Net
Income decreased $4 million to $47 million in 2007. The key driver of the
decrease was a $12 million increase in Operating Expenses and Other offset
by a
$5 million increase in Gross Margin and a $3 million decrease in Income
Tax
Expense.
The
major
components of our increase in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $27 million primarily due to:
|
|
·
|
An
$11 million increase in residential and commercial revenue
primarily due
to a 27% increase in heating degree days.
|
|
·
|
A
$10 million increase in rate revenues related to a $4 million
increase in
our RSP, a $3 million increase related to rate recovery of storm
costs and
a $3 million increase related to rate recovery of IGCC preconstruction
costs (see “Ohio Rate Matters” section of Note 3). The
increase in rate recovery of storm costs was offset by the amortization
of
deferred expenses in Other Operation and Maintenance. The increase
in rate
recovery of IGCC preconstruction costs was offset by the amortization
of
deferred expenses in Depreciation and
Amortization.
|
|
·
|
A
$7 million increase in industrial revenue due to the addition
of Ormet, a
major industrial customer (see “Ormet” section of Note
3).
|
·
|
Margins
from Off-system Sales decreased $11 million primarily due to
an $8 million
decrease in physical sales margins and a $4 million decrease
in margins
from optimization activities.
|
·
|
Transmission
Revenues decreased $7 million primarily due to the elimination
of SECA
revenues as of April 1, 2006. See the “Transmission Rate Proceedings at
the FERC” section of Note 3.
|
·
|
Other
revenues decreased $4 million primarily due to lower gains on
sales of
emission allowances.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $10 million primarily
due
to:
|
·
|
A
$5 million increase in overhead line expenses due in part to
the
amortization of deferred storm expenses recovered through a cost-recovery
rider. The increase in amortization of deferred storm expenses
was offset
by a corresponding increase in Retail Margins.
|
·
|
A
$3 million increase in our net allocated transmission costs related
to the
Transmission Equalization Agreement as a result of the addition
of APCo’s
Wyoming-Jacksons Ferry 765 kV line, which was energized and placed
in
service in June 2006.
|
·
|
Depreciation
and Amortization increased $4 million primarily due to the
amortization of
IGCC preconstruction costs of $3 million in the first quarter
of 2007. The
increase in amortization of IGCC preconstruction costs was
offset by a
corresponding increase in Retail Margins.
|
·
|
Interest
Expense decreased $2 million primarily due to an increase in
allowance for
borrowed funds used during
construction.
|
Income
Taxes
Income
Tax Expense decreased $3 million primarily due to a decrease in pretax
book
income and state income taxes offset in part by the recording of tax
adjustments.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in our 2006 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption
of New Accounting Pronouncements
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management assets and liabilities are managed by AEPSC as agent for us.
The
related risk management policies and procedures are instituted and administered
by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative
and Qualitative Disclosures About Risk Management Activities” section for
disclosures about risk management activities.
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 $80 million
and $70 million at March 31, 2007 and December 31, 2006, 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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
423,466
|
|
$
|
413,669
|
|
Sales
to AEP Affiliates
|
|
|
23,013
|
|
|
13,769
|
|
Other
|
|
|
1,433
|
|
|
1,330
|
|
TOTAL
|
|
|
447,912
|
|
|
428,768
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
75,862
|
|
|
69,820
|
|
Purchased
Electricity for Resale
|
|
|
31,311
|
|
|
24,765
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
83,541
|
|
|
82,477
|
|
Other
Operation
|
|
|
61,159
|
|
|
55,945
|
|
Maintenance
|
|
|
22,564
|
|
|
17,934
|
|
Depreciation
and Amortization
|
|
|
50,297
|
|
|
45,828
|
|
Taxes
Other Than Income Taxes
|
|
|
40,582
|
|
|
39,502
|
|
TOTAL
|
|
|
365,316
|
|
|
336,271
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
82,596
|
|
|
92,497
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
422
|
|
|
455
|
|
Carrying
Costs Income
|
|
|
1,092
|
|
|
716
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
772
|
|
|
464
|
|
Interest
Expense
|
|
|
(15,281
|
)
|
|
(17,520
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
69,601
|
|
|
76,612
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
22,620
|
|
|
25,275
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
|
46,981 |
|
|
51,337 |
|
|
|
|
|
|
|
|
|
Capital
Stock Expense
|
|
|
39
|
|
|
39
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK |
|
$ |
46,942 |
|
$ |
51,298 |
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$
|
41,026
|
|
$
|
580,192
|
|
$
|
456,787
|
|
$
|
(21,988
|
)
|
$
|
1,056,017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
(3,022
|
)
|
|
|
|
|
(3,022
|
)
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(20,000
|
)
|
|
|
|
|
(20,000
|
)
|
Capital
Stock Expense
|
|
|
|
|
|
39
|
|
|
(39
|
)
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,032,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,841
|
|
|
|
|
|
|
|
|
|
|
|
(5,276
|
)
|
|
(5,276
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
46,981
|
|
|
|
|
|
46,981
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2007
|
|
$
|
41,026
|
|
$
|
580,231
|
|
$
|
480,707
|
|
$
|
(27,264
|
)
|
$
|
1,074,700
|
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
237
|
|
$
|
1,319
|
|
Advances
to Affiliates
|
|
|
922
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
59,380
|
|
|
49,362
|
|
Affiliated
Companies
|
|
|
35,351
|
|
|
62,866
|
|
Accrued
Unbilled Revenues
|
|
|
8,011
|
|
|
11,042
|
|
Miscellaneous
|
|
|
5,626
|
|
|
4,895
|
|
Allowance
for Uncollectible Accounts
|
|
|
(588
|
)
|
|
(546
|
)
|
Total Accounts Receivable
|
|
|
107,780
|
|
|
127,619
|
|
Fuel
|
|
|
31,320
|
|
|
37,348
|
|
Materials
and Supplies
|
|
|
34,575
|
|
|
31,765
|
|
Emission
Allowances
|
|
|
8,971
|
|
|
3,493
|
|
Risk
Management Assets
|
|
|
36,969
|
|
|
66,238
|
|
Accrued
Tax Benefits
|
|
|
-
|
|
|
4,763
|
|
Prepayments
and Other
|
|
|
11,734
|
|
|
16,107
|
|
TOTAL
|
|
|
232,508
|
|
|
288,652
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
1,954,377
|
|
|
1,896,073
|
|
Transmission
|
|
|
481,875
|
|
|
479,119
|
|
Distribution
|
|
|
1,496,080
|
|
|
1,475,758
|
|
Other
|
|
|
190,645
|
|
|
191,103
|
|
Construction
Work in Progress
|
|
|
269,771
|
|
|
294,138
|
|
Total
|
|
|
4,392,748
|
|
|
4,336,191
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,629,386
|
|
|
1,611,043
|
|
TOTAL
- NET
|
|
|
2,763,362
|
|
|
2,725,148
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
277,251
|
|
|
298,304
|
|
Long-term
Risk Management Assets
|
|
|
46,978
|
|
|
56,206
|
|
Deferred
Charges and Other
|
|
|
131,818
|
|
|
152,379
|
|
TOTAL
|
|
|
456,047
|
|
|
506,889
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
3,451,917
|
|
$
|
3,520,689
|
|
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, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
-
|
|
$
|
696
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
97,767
|
|
|
112,431
|
|
Affiliated
Companies
|
|
|
51,552
|
|
|
59,538
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
52,000
|
|
|
-
|
|
Risk
Management Liabilities
|
|
|
31,365
|
|
|
49,285
|
|
Customer
Deposits
|
|
|
37,563
|
|
|
34,991
|
|
Accrued
Taxes
|
|
|
144,223
|
|
|
166,551
|
|
Accrued
Interest
|
|
|
17,698
|
|
|
20,868
|
|
Other
|
|
|
34,767
|
|
|
37,143
|
|
TOTAL
|
|
|
466,935
|
|
|
481,503
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
1,045,422
|
|
|
1,097,322
|
|
Long-term
Debt - Affiliated
|
|
|
100,000
|
|
|
100,000
|
|
Long-term
Risk Management Liabilities
|
|
|
32,396
|
|
|
40,477
|
|
Deferred
Income Taxes
|
|
|
462,516
|
|
|
475,888
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
168,597
|
|
|
179,048
|
|
Deferred
Credits and Other
|
|
|
101,351
|
|
|
90,434
|
|
TOTAL
|
|
|
1,910,282
|
|
|
1,983,169
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,377,217
|
|
|
2,464,672
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - No Par Value:
|
|
|
|
|
|
|
|
Authorized
- 24,000,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 16,410,426 Shares
|
|
|
41,026
|
|
|
41,026
|
|
Paid-in
Capital
|
|
|
580,231
|
|
|
580,192
|
|
Retained
Earnings
|
|
|
480,707
|
|
|
456,787
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(27,264
|
)
|
|
(21,988
|
)
|
TOTAL
|
|
|
1,074,700
|
|
|
1,056,017
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$
|
3,451,917
|
|
$
|
3,520,689
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
46,981
|
|
$
|
51,337
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
50,297
|
|
|
45,828
|
|
Deferred
Income Taxes
|
|
|
(716
|
)
|
|
3,816
|
|
Carrying
Costs Income
|
|
|
(1,092
|
)
|
|
(716
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
4,400
|
|
|
(3,624
|
)
|
Deferred
Property Taxes
|
|
|
18,954
|
|
|
10,884
|
|
Change
in Other Noncurrent Assets
|
|
|
(912
|
)
|
|
(11,325
|
)
|
Change
in Other Noncurrent Liabilities
|
|
|
(15,510
|
)
|
|
5,800
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
19,839
|
|
|
33,295
|
|
Fuel,
Materials and Supplies
|
|
|
3,218
|
|
|
(7,431
|
)
|
Accounts
Payable
|
|
|
(7,659
|
)
|
|
12,540
|
|
Customer
Deposits
|
|
|
2,572
|
|
|
(7,901
|
)
|
Accrued
Taxes, Net
|
|
|
(8,651
|
)
|
|
(7,873
|
)
|
Accrued
Interest
|
|
|
(5,658
|
)
|
|
(4,127
|
)
|
Other
Current Assets
|
|
|
5,694
|
|
|
(728
|
)
|
Other
Current Liabilities
|
|
|
(5,056
|
)
|
|
(6,571
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
106,701
|
|
|
113,204
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(85,641
|
)
|
|
(65,032
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
(20
|
)
|
|
(1,151
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
(922
|
)
|
|
(6,867
|
)
|
Proceeds
from Sale of Assets
|
|
|
189
|
|
|
531
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(86,394
|
)
|
|
(72,519
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
(696
|
)
|
|
(17,609
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(693
|
)
|
|
(759
|
)
|
Dividends
Paid on Common Stock
|
|
|
(20,000
|
)
|
|
(22,500
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(21,389
|
)
|
|
(40,868
|
)
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(1,082
|
)
|
|
(183
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,319
|
|
|
940
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
237
|
|
$
|
757
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
20,132
|
|
$
|
22,320
|
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(2,907
|
)
|
|
2,533
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
275
|
|
|
1,102
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
20,636
|
|
|
12,054
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to CSPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for
other
registrant subsidiaries. Listed below are the notes that apply to CSPCo.
|
Footnote
Reference
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Acquisitions,
Dispositions and Assets Held for Sale
|
Note
5
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
INDIANA
MICHIGAN POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Net
Income
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
58
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(24
|
)
|
|
|
|
FERC
Municipals and Cooperatives
|
|
|
9
|
|
|
|
|
Off-system
Sales
|
|
|
(4
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(2
|
)
|
|
|
|
Other
|
|
|
(7
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(28
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(6
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(7
|
)
|
|
|
|
Other
Income
|
|
|
(1
|
)
|
|
|
|
Interest
Expense
|
|
|
(2
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
29
|
|
Net
Income decreased $29 million to $29 million in 2007. The key driver of the
decrease was a $28 million decrease in Gross Margin.
The
major
components of our decrease in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins decreased $24 million primarily due to a reduction in capacity
settlement revenues of $23 million under the Interconnection Agreement
reflecting our new peak demand in July 2006.
|
·
|
FERC
Municipals and Cooperatives margins increased $9 million due to
the
addition of new municipal contracts including new rates and increased
demand effective July 2006 and January 2007.
|
·
|
Margins
from Off-system Sales decreased $4 million primarily due to an
$11 million
decrease in physical sales margins partially offset by a $6 million
increase in margins from optimization activities.
|
·
|
Transmission
Revenues decreased $2 million primarily due to the elimination
of SECA
revenues as of April 1, 2006. See the “Transmission Rate Proceedings at
the FERC” section of Note 3.
|
·
|
Other
revenues
decreased
$7 million primarily due to decreased River Transportation Division
(RTD)
revenues for barging coal and decreased gains on sales of emission
allowances. RTD related expenses which offset the RTD revenue decrease
are
included in Other Operation on the Condensed Consolidated Statements
of
Income resulting in our earning only a return approved under regulatory
order.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $6 million primarily
due to a
$5 million increase in transmission expense due to our reduced
credits
under the Transmission Equalization Agreement. Our credits decreased
due
to our July 2006 peak and due to APCo’s addition of the Wyoming-Jacksons
Ferry 765 kV line, which was energized and placed in service in
June 2006
thus decreasing our share of the transmission investment
pool.
|
·
|
Depreciation
and Amortization expense increased $7 million primarily due to a $5
million increase in depreciation related to capital additions
and a $2 million increase in amortization related to capitalized
software
development costs.
|
·
|
Interest
Expense increased $2 million primarily due to an increase in outstanding
long-term debt and higher interest
rates.
|
Income
Taxes
Income
Tax Expense decreased $15 million primarily due to a decrease in pretax book
income.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in our 2006 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption
of New Accounting Pronouncements
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management assets and liabilities are managed by AEPSC as agent for us. The
related risk management policies and procedures are instituted and administered
by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative
and Qualitative Disclosures About Risk Management Activities” section for
disclosures about risk management activities.
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 $108 million
and $93 million at March 31, 2007 and December 31, 2006, 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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
405,164
|
|
$
|
403,769
|
|
Sales
to AEP Affiliates
|
|
|
67,429
|
|
|
88,534
|
|
Other
- Affiliated
|
|
|
12,667
|
|
|
15,094
|
|
Other
- Nonaffiliated
|
|
|
7,609
|
|
|
8,382
|
|
TOTAL
|
|
|
492,869
|
|
|
515,779
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
96,117
|
|
|
89,452
|
|
Purchased
Electricity for Resale
|
|
|
17,940
|
|
|
11,010
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
77,513
|
|
|
86,422
|
|
Other
Operation
|
|
|
120,733
|
|
|
111,617
|
|
Maintenance
|
|
|
42,430
|
|
|
45,219
|
|
Depreciation
and Amortization
|
|
|
56,307
|
|
|
49,715
|
|
Taxes
Other Than Income Taxes
|
|
|
17,994
|
|
|
18,906
|
|
TOTAL
|
|
|
429,034
|
|
|
412,341
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
63,835
|
|
|
103,438
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
588
|
|
|
694
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
265
|
|
|
1,924
|
|
Interest
Expense
|
|
|
(19,821
|
)
|
|
(17,533
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
44,867
|
|
|
88,523
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
15,404
|
|
|
30,645
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
29,463
|
|
|
57,878
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
85
|
|
|
85
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
29,378
|
|
$
|
57,793
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$
|
56,584
|
|
$
|
861,290
|
|
$
|
386,616
|
|
$
|
(15,051
|
)
|
$
|
1,289,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
327
|
|
|
|
|
|
327
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(10,000
|
)
|
|
|
|
|
(10,000
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(85
|
)
|
|
|
|
|
(85
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,279,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,850
|
|
|
|
|
|
|
|
|
|
|
|
(5,293
|
)
|
|
(5,293
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
29,463
|
|
|
|
|
|
29,463
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2007
|
|
$
|
56,584
|
|
$
|
861,290
|
|
$
|
406,321
|
|
$
|
(20,344
|
)
|
$
|
1,303,851
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
753
|
|
$
|
1,369
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
86,128
|
|
|
82,102
|
|
Affiliated
Companies
|
|
|
66,155
|
|
|
108,288
|
|
Accrued
Unbilled Revenues
|
|
|
806
|
|
|
2,206
|
|
Miscellaneous
|
|
|
2,571
|
|
|
1,838
|
|
Allowance
for Uncollectible Accounts
|
|
|
(616
|
)
|
|
(601
|
)
|
Total Accounts Receivable
|
|
|
155,044
|
|
|
193,833
|
|
Fuel
|
|
|
47,818
|
|
|
64,669
|
|
Materials
and Supplies
|
|
|
136,373
|
|
|
129,953
|
|
Risk
Management Assets
|
|
|
39,175
|
|
|
69,752
|
|
Accrued
Tax Benefits
|
|
|
8,680
|
|
|
27,378
|
|
Prepayments
and Other
|
|
|
13,500
|
|
|
15,170
|
|
TOTAL
|
|
|
401,343
|
|
|
502,124
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
3,383,343
|
|
|
3,363,813
|
|
Transmission
|
|
|
1,052,730
|
|
|
1,047,264
|
|
Distribution
|
|
|
1,143,815
|
|
|
1,102,033
|
|
Other
(including nuclear fuel and coal mining)
|
|
|
516,972
|
|
|
529,727
|
|
Construction
Work in Progress
|
|
|
144,856
|
|
|
183,893
|
|
Total
|
|
|
6,241,716
|
|
|
6,226,730
|
|
Accumulated
Depreciation, Depletion and Amortization
|
|
|
2,949,796
|
|
|
2,914,131
|
|
TOTAL
- NET
|
|
|
3,291,920
|
|
|
3,312,599
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
292,704
|
|
|
314,805
|
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,262,960
|
|
|
1,248,319
|
|
Long-term
Risk Management Assets
|
|
|
49,470
|
|
|
59,137
|
|
Deferred
Charges and Other
|
|
|
117,384
|
|
|
109,453
|
|
TOTAL
|
|
|
1,722,518
|
|
|
1,731,714
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
5,415,781
|
|
$
|
5,546,437
|
|
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, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
45,759
|
|
$
|
91,173
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
99,223
|
|
|
146,733
|
|
Affiliated
Companies
|
|
|
57,940
|
|
|
65,497
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
50,000
|
|
|
50,000
|
|
Risk
Management Liabilities
|
|
|
33,643
|
|
|
52,083
|
|
Customer
Deposits
|
|
|
31,436
|
|
|
34,946
|
|
Accrued
Taxes
|
|
|
76,087
|
|
|
59,652
|
|
Other
|
|
|
115,714
|
|
|
128,461
|
|
TOTAL
|
|
|
509,802
|
|
|
628,545
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
1,508,695
|
|
|
1,505,135
|
|
Long-term
Risk Management Liabilities
|
|
|
34,243
|
|
|
42,641
|
|
Deferred
Income Taxes
|
|
|
311,584
|
|
|
335,000
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
739,972
|
|
|
753,402
|
|
Asset
Retirement Obligations
|
|
|
820,371
|
|
|
809,853
|
|
Deferred
Credits and Other
|
|
|
179,181
|
|
|
174,340
|
|
TOTAL
|
|
|
3,594,046
|
|
|
3,620,371
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,103,848
|
|
|
4,248,916
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
8,082
|
|
|
8,082
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - No Par Value:
|
|
|
|
|
|
|
|
Authorized
- 2,500,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 1,400,000 Shares
|
|
|
56,584
|
|
|
56,584
|
|
Paid-in
Capital
|
|
|
861,290
|
|
|
861,290
|
|
Retained
Earnings
|
|
|
406,321
|
|
|
386,616
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(20,344
|
)
|
|
(15,051
|
)
|
TOTAL
|
|
|
1,303,851
|
|
|
1,289,439
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
5,415,781
|
|
$
|
5,546,437
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
29,463
|
|
$
|
57,878
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
56,307
|
|
|
49,715
|
|
Deferred
Income Taxes
|
|
|
(3,638
|
)
|
|
3,493
|
|
Amortization
(Deferral) of Incremental Nuclear Refueling Outage Expenses,
Net
|
|
|
12,191
|
|
|
(1,639
|
)
|
Amortization
of Nuclear Fuel
|
|
|
16,372
|
|
|
13,596
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
4,897
|
|
|
(4,060
|
)
|
Deferred
Property Taxes
|
|
|
(10,836
|
)
|
|
(9,839
|
)
|
Change
in Other Noncurrent Assets
|
|
|
5,729
|
|
|
4,381
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(1,971
|
)
|
|
18,839
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
38,789
|
|
|
43,019
|
|
Fuel,
Materials and Supplies
|
|
|
14,985
|
|
|
(7,194
|
)
|
Accounts
Payable
|
|
|
(38,233
|
)
|
|
(7,010
|
)
|
Customer
Deposits
|
|
|
(3,510
|
)
|
|
(8,031
|
)
|
Accrued
Taxes, Net
|
|
|
39,525
|
|
|
42,871
|
|
Accrued
Rent - Rockport Plant Unit 2
|
|
|
18,464
|
|
|
18,464
|
|
Other
Current Assets
|
|
|
1,959
|
|
|
428
|
|
Other
Current Liabilities
|
|
|
(35,720
|
)
|
|
(20,797
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
144,773
|
|
|
194,114
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(62,252
|
)
|
|
(89,411
|
)
|
Purchases
of Investment Securities
|
|
|
(204,874
|
)
|
|
(150,239
|
)
|
Sales
of Investment Securities
|
|
|
183,927
|
|
|
134,258
|
|
Acquisitions
of Nuclear Fuel
|
|
|
(5,366
|
)
|
|
(34,427
|
)
|
Proceeds
from Sales of Assets and Other
|
|
|
248
|
|
|
1,384
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(88,317
|
)
|
|
(138,435
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
(45,414
|
)
|
|
(44,565
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(1,573
|
)
|
|
(1,274
|
)
|
Dividends
Paid on Common Stock
|
|
|
(10,000
|
)
|
|
(10,000
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(85
|
)
|
|
(85
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(57,072
|
)
|
|
(55,924
|
)
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(616
|
)
|
|
(245
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,369
|
|
|
854
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
753
|
|
$
|
609
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
15,048
|
|
$
|
4,776
|
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(2,768
|
)
|
|
1,324
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
369
|
|
|
2,218
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
20,243
|
|
|
27,624
|
|
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,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
KENTUCKY
POWER COMPANY
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Net
Income
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
17
|
|
|
|
|
Off-system
Sales
|
|
|
(2
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(3
|
)
|
|
|
|
Other
|
|
|
(1
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
15
|
|
Net
Income increased $5 million to $15 million in 2007. The key driver of the
increase was an $11 million increase in Gross Margin, offset by an increase
in
Other Operation and Maintenance expenses of $3 million and an increase in
Income
Tax Expense of $3 million.
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 $17 million primarily due to rate relief of $14
million
from the March 2006 approval of the settlement agreement in our
base rate
case.
|
·
|
Transmission
Revenues decreased $3 million primarily due to the elimination
of SECA
revenues as of April 1, 2006. See the “Transmission Rate Proceedings at
the FERC” section of Note 3.
|
Other
Operation and Maintenance
Other
Operation and Maintenance expenses increased $3 million primarily due to
an
increase in our net allocated transmission costs related to the Transmission
Equalization Agreement as a result of the addition of APCo’s Wyoming-Jacksons
Ferry 765 kV line which was energized and placed into service in June 2006.
Other Operation and Maintenance expenses also increased as a result of increased
forced outages at the Big Sandy Plant.
Income
Taxes
Income
Tax Expense increased $3 million primarily due to an increase in pretax book
income.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in our 2006 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption
of New Accounting Pronouncements
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management assets and liabilities are managed by AEPSC as agent for us. The
related risk management policies and procedures are instituted and administered
by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative
and Qualitative Disclosures About Risk Management Activities” section for
disclosures about risk management activities.
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 $19 million
and $13 million at March 31, 2007 and December 31, 2006, 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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
140,486
|
|
$
|
137,620
|
|
Sales
to AEP Affiliates
|
|
|
13,461
|
|
|
13,968
|
|
Other
|
|
|
149
|
|
|
259
|
|
TOTAL
|
|
|
154,096
|
|
|
151,847
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
38,304
|
|
|
43,966
|
|
Purchased
Electricity for Resale
|
|
|
3,305
|
|
|
973
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
43,257
|
|
|
49,526
|
|
Other
Operation
|
|
|
15,886
|
|
|
13,726
|
|
Maintenance
|
|
|
8,210
|
|
|
7,141
|
|
Depreciation
and Amortization
|
|
|
11,796
|
|
|
11,479
|
|
Taxes
Other Than Income Taxes
|
|
|
2,803
|
|
|
2,512
|
|
TOTAL
|
|
|
123,561
|
|
|
129,323
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
30,535
|
|
|
22,524
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
112
|
|
|
166
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
14
|
|
|
101
|
|
Interest
Expense
|
|
|
(7,011
|
)
|
|
(7,296
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
23,650
|
|
|
15,495
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
8,439
|
|
|
5,665
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
15,211
|
|
$
|
9,830
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income
(Loss)
|
|
Total
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$
|
50,450
|
|
$
|
208,750
|
|
$
|
108,899
|
|
$
|
1,552
|
|
$
|
369,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
(786
|
)
|
|
|
|
|
(786
|
)
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
(5,000
|
)
|
|
|
|
|
(5,000
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
363,865
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $1,100
|
|
|
|
|
|
|
|
|
|
|
|
(2,042
|
)
|
|
(2,042
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
15,211
|
|
|
|
|
|
15,211
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2007
|
|
$
|
50,450
|
|
$
|
208,750
|
|
$
|
118,324
|
|
$
|
(490
|
)
|
$
|
377,034
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
KENTUCKY
POWER COMPANY
CONDENSED
BALANCE SHEETS
ASSETS
March
31, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
775
|
|
$
|
702
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
30,027
|
|
|
30,112
|
|
Affiliated
Companies
|
|
|
9,142
|
|
|
10,540
|
|
Accrued
Unbilled Revenues
|
|
|
6,093
|
|
|
3,602
|
|
Miscellaneous
|
|
|
684
|
|
|
327
|
|
Allowance
for Uncollectible Accounts
|
|
|
(242
|
)
|
|
(227
|
)
|
Total Accounts Receivable
|
|
|
45,704
|
|
|
44,354
|
|
Fuel
|
|
|
12,852
|
|
|
16,070
|
|
Materials
and Supplies
|
|
|
10,277
|
|
|
8,726
|
|
Risk
Management Assets
|
|
|
16,110
|
|
|
25,624
|
|
Accrued
Tax Benefits
|
|
|
-
|
|
|
1,021
|
|
Margin
Deposits
|
|
|
1,458
|
|
|
2,923
|
|
Prepayments
and Other
|
|
|
2,637
|
|
|
2,425
|
|
TOTAL
|
|
|
89,813
|
|
|
101,845
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
480,501
|
|
|
478,955
|
|
Transmission
|
|
|
395,646
|
|
|
394,419
|
|
Distribution
|
|
|
480,690
|
|
|
481,083
|
|
Other
|
|
|
60,047
|
|
|
61,089
|
|
Construction
Work in Progress
|
|
|
27,705
|
|
|
29,587
|
|
Total
|
|
|
1,444,589
|
|
|
1,445,133
|
|
Accumulated
Depreciation and Amortization
|
|
|
441,565
|
|
|
442,778
|
|
TOTAL
- NET
|
|
|
1,003,024
|
|
|
1,002,355
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
135,241
|
|
|
136,139
|
|
Long-term
Risk Management Assets
|
|
|
19,313
|
|
|
21,282
|
|
Deferred
Charges and Other
|
|
|
46,953
|
|
|
48,944
|
|
TOTAL
|
|
|
201,507
|
|
|
206,365
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
1,294,344
|
|
$
|
1,310,565
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
KENTUCKY
POWER COMPANY
CONDENSED
BALANCE SHEETS
LIABILITIES
AND SHAREHOLDER’S EQUITY
March
31, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
20,769
|
|
$
|
30,636
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
33,876
|
|
|
31,490
|
|
Affiliated
Companies
|
|
|
17,615
|
|
|
23,658
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
322,554
|
|
|
322,048
|
|
Risk
Management Liabilities
|
|
|
14,167
|
|
|
20,001
|
|
Customer
Deposits
|
|
|
15,273
|
|
|
16,095
|
|
Accrued
Taxes
|
|
|
18,933
|
|
|
18,775
|
|
Other
|
|
|
22,759
|
|
|
26,303
|
|
TOTAL
|
|
|
465,946
|
|
|
489,006
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
104,944
|
|
|
104,920
|
|
Long-term
Debt - Affiliated
|
|
|
20,000
|
|
|
20,000
|
|
Long-term
Risk Management Liabilities
|
|
|
13,464
|
|
|
15,426
|
|
Deferred
Income Taxes
|
|
|
239,776
|
|
|
242,133
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
47,426
|
|
|
49,109
|
|
Deferred
Credits and Other
|
|
|
25,754
|
|
|
20,320
|
|
TOTAL
|
|
|
451,364
|
|
|
451,908
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
917,310
|
|
|
940,914
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
118,324
|
|
|
108,899
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(490
|
)
|
|
1,552
|
|
TOTAL
|
|
|
377,034
|
|
|
369,651
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$
|
1,294,344
|
|
$
|
1,310,565
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
15,211
|
|
$
|
9,830
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
11,796
|
|
|
11,479
|
|
Deferred
Income Taxes
|
|
|
956
|
|
|
2,217
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
1,092
|
|
|
(1,378
|
)
|
Change
in Other Noncurrent Assets
|
|
|
980
|
|
|
2,518
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(78
|
)
|
|
1,845
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(1,350
|
)
|
|
16,149
|
|
Fuel,
Materials and Supplies
|
|
|
3,609
|
|
|
(2,808
|
)
|
Accounts
Payable
|
|
|
(2,557
|
)
|
|
(6,212
|
)
|
Customer
Deposits
|
|
|
(822
|
)
|
|
(3,127
|
)
|
Accrued
Taxes, Net
|
|
|
1,447
|
|
|
2,676
|
|
Other
Current Assets
|
|
|
1,012
|
|
|
2,069
|
|
Other
Current Liabilities
|
|
|
(3,348
|
)
|
|
(1,480
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
27,948
|
|
|
33,778
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(13,001
|
)
|
|
(19,376
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
(5,923
|
)
|
Proceeds
from Sale of Assets
|
|
|
231
|
|
|
301
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(12,770
|
)
|
|
(24,998
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
(9,867
|
)
|
|
(6,040
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(238
|
)
|
|
(343
|
)
|
Dividends
Paid on Common Stock
|
|
|
(5,000
|
)
|
|
(2,500
|
)
|
Net
Cash Flows Used For Financing Activities
|
|
|
(15,105
|
)
|
|
(8,883
|
)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
73
|
|
|
(103
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
702
|
|
|
526
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
775
|
|
$
|
423
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
5,371
|
|
$
|
4,156
|
|
Net
Cash Paid for Income Taxes
|
|
|
738
|
|
|
214
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
139
|
|
|
224
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
2,257
|
|
|
3,079
|
|
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,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
OHIO
POWER COMPANY CONSOLIDATED
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Net
Income
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
95
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
59
|
|
|
|
|
Off-system
Sales
|
|
|
(22
|
)
|
|
|
|
Transmission
Revenues
|
|
|
(9
|
)
|
|
|
|
Other
|
|
|
(10
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(28
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(5
|
)
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1
|
)
|
|
|
|
Interest
Expense
|
|
|
(3
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
79
|
|
Net
Income decreased $16 million to $79 million in 2007. The key driver of the
decrease was a $37 million increase in Operating Expenses and Other offset
by an
$18 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 chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $59 million primarily due to the
following:
|
|
·
|
A
$25 million increase in capacity settlements under the Interconnection
Agreement related to certain of our affiliates’ peaks and the expiration
of our supplemental capacity and energy obligation to Buckeye Power,
Inc.
under the Cardinal Station Agreement.
|
|
·
|
A
$14 million increase in rate revenues related to an $8 million
increase in
our RSP, a $3 million increase related to rate recovery of storm
costs and
a $3 million increase related to rate recovery of IGCC preconstruction
costs (see “Ohio Rate Matters” section of Note 3). The
increase in rate recovery of storm costs was offset by the amortization
of
deferred expenses in Other Operation and Maintenance. The increase
in rate
recovery of IGCC preconstruction costs was offset by the amortization
of
deferred expenses in Depreciation and
Amortization.
|
|
·
|
A
$9 million increase in fuel margins.
|
|
·
|
A
$7 million increase in industrial revenue due to the addition of
Ormet, a
major industrial customer (see “Ormet” section of Note
3).
|
|
·
|
A
$6 million increase in residential revenue primarily due to a 25%
increase
in heating degree days.
|
|
These
increases were partially offset by:
|
|
·
|
A
$9 million decrease in revenues associated with SO2
allowances received in 2006 from Buckeye Power, Inc. under the
Cardinal
Station Allowances Agreement.
|
·
|
Margins
from Off-system Sales decreased $22 million due to a $19 million
decrease
in physical sales margins and a $4 million decrease in margins
from
optimization activities.
|
·
|
Transmission
Revenues decreased $9 million primarily due to the elimination
of SECA
revenues as of April 1, 2006 (see the “Transmission Rate Proceedings at
the FERC” section of Note 3).
|
·
|
Other
revenues decreased $10 million primarily due to a $4 million decrease
related to the expiration of an obligation to sell supplemental
capacity
and energy to Buckeye Power, Inc. under the Cardinal Station Agreement,
a
$3 million decrease in gains on sales of emission allowances and
a $2
million decrease in revenue associated with Cook Coal
Terminal.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $28 million primarily
due to
a $19 million increase in maintenance and removal costs related
to planned
and forced outages at the Gavin, Muskingum, Mitchell and Cardinal
plants
and a $5 million increase due to the prior period adjustment of
liabilities related to sold coal companies.
|
·
|
Depreciation
and Amortization increased $5 million primarily due to the amortization
of
IGCC preconstruction costs of $3 million in the first quarter
of 2007 and
a $1 million increase in depreciation related to environmental
improvements placed in service at the Mitchell plant. The increase
in
amortization of IGCC preconstruction costs was offset by a corresponding
increase in Retail Margins.
|
·
|
Interest
Expense increased $3 million primarily due to a $5 million increase
related to long-term debt issuances since June 2006 and a $3 million
increase related to higher borrowings from the Utility Money Pool
partially offset by a $6 million increase in allowance for borrowed
funds
used during construction.
|
Income
Taxes
Income
Tax Expense decreased $3 million primarily due to a decrease in pretax book
income offset in part by state income taxes.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Current ratings are
as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
A3
|
|
BBB
|
|
BBB+
|
Cash
Flow
Cash
flows for the three months ended March 31, 2007 and 2006 were as
follows:
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
1,625
|
|
$
|
1,240
|
|
Cash
Flows From (Used For):
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
96,864
|
|
|
182,002
|
|
Investing
Activities
|
|
|
(306,826
|
)
|
|
(221,862
|
)
|
Financing
Activities
|
|
|
209,598
|
|
|
39,577
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(364
|
)
|
|
(283
|
)
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,261
|
|
$
|
957
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $97 million in 2007. We produced Net
Income
of $79 million during the period and a noncash expense item of $84 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. Accounts
Receivable, Net had a $38 million outflow due to temporary timing differences
of
rent receivables and an increase in billed revenue for electric customers.
Accounts Payable had a $26 million outflow primarily due to emission allowance
payments in January 2007. Fuel, Materials and Supplies had a $24 million
outflow
primarily due to an increase in coal inventories.
Our
Net
Cash Flows From Operating Activities were $182 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 had a $102 million inflow due to receivables collected
from our affiliates related to power sales, settled litigation and emission
allowances. Accounts Payable had a $60 million outflow due to emission allowance
payments in January 2006 and temporary timing differences for payments to
affiliates.
Investing
Activities
Our
Net
Cash Used For Investing Activities were $307 million and $222 million in
2007
and 2006, respectively. Construction Expenditures were $302 million and $223
million in 2007 and 2006, respectively, primarily related to environmental
upgrades, as well as projects to improve service reliability for transmission
and distribution. Environmental upgrades include the installation of selective
catalytic reduction equipment and the flue gas desulfurization projects at
the
Cardinal, Amos and Mitchell plants. In January 2007, environmental upgrades
were
completed for Unit 2 at the Mitchell plant. For the remainder of 2007, we
expect
construction expenditures to be approximately $530 million.
Financing
Activities
Net
Cash
Flows From Financing Activities were $210 million in 2007 primarily due to
a net
increase of $216 million in borrowings from the Utility Money Pool.
Net
Cash
Flows From Financing Activities were $40 million in 2006 primarily due to
a $35
million capital contribution from AEP.
Financing
Activity
Long-term
debt issuances and retirements during the first three months of 2007
were:
Issuances
None
Retirements
|
|
Principal
Amount
Paid
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Notes
Payable - Nonaffiliated
|
|
$
|
1,463
|
|
6.81
|
|
2008
|
Notes
Payable - Nonaffiliated
|
|
|
6,000
|
|
6.27
|
|
2009
|
In
April
2007, we issued $400 million of three-year floating rate notes at an
initial rate of 5.53% due in 2010. The proceeds from this issuance will
contribute to our investment in environmental equipment.
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 2006 Annual Report and
has not
changed significantly from year-end
other
than the debt issuance discussed in “Financing Activity” 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
and
Note 6 - Commitments, Guarantees and Contingencies in our 2006 Annual Report.
Also, see Note 3 - Rate Matters and Note 4 - Commitments, Guarantees and
Contingencies in the “Condensed Notes to Condensed Financial Statements of
Registrant Subsidiaries”. Adverse results in these proceedings have the
potential to materially affect 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 2006 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption
of New Accounting Pronouncements
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management assets and liabilities are managed by AEPSC as agent for us. The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative
Disclosures About Risk Management Activities” section. The following tables
provide information about AEP’s risk management activities’ effect on
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, 2007
and
the reasons for changes in our total MTM value as compared to December 31,
2006.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of March 31, 2007
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
DETM
Assignment (a)
|
|
Total
|
|
Current
Assets
|
|
$
|
49,092
|
|
$
|
756
|
|
$
|
-
|
|
$
|
49,848
|
|
Noncurrent
Assets
|
|
|
57,316
|
|
|
96
|
|
|
-
|
|
|
57,412
|
|
Total
MTM Derivative Contract Assets
|
|
|
106,408
|
|
|
852
|
|
|
-
|
|
|
107,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(42,532
|
)
|
|
(3,980
|
)
|
|
(2,071
|
)
|
|
(48,583
|
)
|
Noncurrent
Liabilities
|
|
|
(35,731
|
)
|
|
(312
|
)
|
|
(5,493
|
)
|
|
(41,536
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(78,263
|
)
|
|
(4,292
|
)
|
|
(7,564
|
)
|
|
(90,119
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$
|
28,145
|
|
$
|
(3,440
|
)
|
$
|
(7,564
|
)
|
$
|
17,141
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 in the 2006 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 2007
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2006
|
|
$
|
33,042
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
(4,433
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
311
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
(23
|
)
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
(317
|
)
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(435
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
28,145
|
|
Net
Cash Flow Hedge Contracts
|
|
|
(3,440
|
)
|
DETM
Assignment (d)
|
|
|
(7,564
|
)
|
Total
MTM Risk Management Contract Net Assets at March 31, 2007
|
|
$
|
17,141
|
|
(a)
|
Reflects
fair value on long-term contracts which are typically with customers
that
seek fixed pricing to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can
be obtained
for valuation inputs for the entire contract term. The contract
prices are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
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 16 in our 2006 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 to give an indication
of
when these MTM amounts will settle and generate
cash.
|
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets
Fair
Value of Contracts as of March 31, 2007
(in
thousands)
|
|
Remainder
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
After
2011
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded Contracts
|
|
$
|
11,122
|
|
$
|
(399
|
)
|
$
|
464
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
11,187
|
|
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
|
|
(621
|
)
|
|
9,668
|
|
|
7,524
|
|
|
2,985
|
|
|
-
|
|
|
-
|
|
|
19,556
|
|
Prices
Based on Models and Other Valuation Methods (b)
|
|
|
(5,725
|
)
|
|
(3,527
|
)
|
|
1,165
|
|
|
3,608
|
|
|
812
|
|
|
1,069
|
|
|
(2,598
|
)
|
Total
|
|
$
|
4,776
|
|
$
|
5,742
|
|
$
|
9,153
|
|
$
|
6,593
|
|
$
|
812
|
|
$
|
1,069
|
|
$
|
28,145
|
|
(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.
|
|
|
|
Contract
values that are measured using models or valuation methods other
than
active quotes or OTC broker quotes (because of the lack of such
data for
all delivery quantities, locations and periods) incorporate in
the model
or other valuation methods, to the extent possible, OTC broker
quotes and
active quotes for deliveries in years and at locations for which
such
quotes are available.
|
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 use various
commodity instruments designated in qualifying cash flow hedge strategies
to
mitigate the impact of these fluctuations on the future cash flows. We do
not
hedge all commodity price risk.
We
use
interest rate derivative transactions to manage interest rate risk related
to
anticipated borrowings of fixed-rate debt. We do not hedge all interest rate
risk.
We
use
forward contracts and collars as cash flow hedges to lock in prices on certain
transactions 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, 2006 to March 31, 2007. 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, 2007
(in
thousands)
|
|
Power
|
|
Foreign
Currency
|
|
Interest
Rate
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2006
|
|
$
|
4,040
|
|
$
|
(331
|
)
|
$
|
3,553
|
|
$
|
7,262
|
|
Changes
in Fair Value
|
|
|
(4,677
|
)
|
|
-
|
|
|
-
|
|
|
(4,677
|
)
|
Reclassifications
from AOCI to Net Income for
Cash
Flow Hedges Settled
|
|
|
(1,595
|
)
|
|
3
|
|
|
(202
|
)
|
|
(1,794
|
)
|
Ending
Balance in AOCI March 31, 2007
|
|
$
|
(2,232
|
)
|
$
|
(328
|
)
|
$
|
3,351
|
|
$
|
791
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,292 thousand loss.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
VaR
Associated with Risk Management Contracts
We
use a
risk measurement model, which calculates Value at Risk (VaR) to measure our
commodity price risk in the risk management portfolio. The VaR is based on
the
variance-covariance method using historical prices to estimate volatilities
and
correlations and assumes a 95% confidence level and a one-day holding period.
Based on this VaR analysis, at March 31, 2007, 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, 2007
|
|
|
|
|
Twelve
Months Ended December 31, 2006
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$678
|
|
$2,054
|
|
$924
|
|
$255
|
|
|
|
|
$573
|
|
$1,451
|
|
$500
|
|
$271
|
The
High
VaR for the twelve months ended December 31, 2006 occurred in the third quarter
due to volatility in the ECAR/PJM region.
VaR
Associated with Debt Outstanding
We
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence
level
and a one-year holding period. The
risk
of potential loss in fair value attributable to our exposure to interest
rates
primarily related to long-term debt with fixed interest rates was $131 million
and $110 million at March 31, 2007 and December 31, 2006, 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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
492,534
|
|
$
|
544,639
|
|
Sales
to AEP Affiliates
|
|
|
178,894
|
|
|
149,259
|
|
Other
- Affiliated
|
|
|
4,038
|
|
|
3,709
|
|
Other
- Nonaffiliated
|
|
|
3,975
|
|
|
4,999
|
|
TOTAL
|
|
|
679,441
|
|
|
702,606
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
198,293
|
|
|
235,130
|
|
Purchased
Electricity for Resale
|
|
|
24,854
|
|
|
21,714
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
20,966
|
|
|
28,572
|
|
Other
Operation
|
|
|
102,987
|
|
|
86,629
|
|
Maintenance
|
|
|
59,148
|
|
|
47,524
|
|
Depreciation
and Amortization
|
|
|
84,276
|
|
|
78,821
|
|
Taxes
Other Than Income Taxes
|
|
|
48,385
|
|
|
47,153
|
|
TOTAL
|
|
|
538,909
|
|
|
545,543
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
140,532
|
|
|
157,063
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
412
|
|
|
637
|
|
Carrying
Costs Income
|
|
|
3,541
|
|
|
3,383
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
571
|
|
|
738
|
|
Interest
Expense
|
|
|
(25,931
|
)
|
|
(23,414
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
119,125
|
|
|
138,407
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
39,864
|
|
|
43,375
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
79,261
|
|
|
95,032
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
183
|
|
|
183
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
79,078
|
|
$
|
94,849
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$
|
321,201
|
|
$
|
536,639
|
|
$
|
1,207,265
|
|
$
|
(56,763
|
)
|
$
|
2,008,342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
(5,380
|
)
|
|
|
|
|
(5,380
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(183
|
)
|
|
|
|
|
(183
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,002,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $3,485
|
|
|
|
|
|
|
|
|
|
|
|
(6,471
|
)
|
|
(6,471
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
79,261
|
|
|
|
|
|
79,261
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72,790
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2007
|
|
$
|
321,201
|
|
$
|
536,639
|
|
$
|
1,280,963
|
|
$
|
(63,234
|
)
|
$
|
2,075,569
|
|
See Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
1,261
|
|
$
|
1,625
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
114,608
|
|
|
86,116
|
|
Affiliated
Companies
|
|
|
109,029
|
|
|
108,214
|
|
Accrued
Unbilled Revenues
|
|
|
17,082
|
|
|
10,106
|
|
Miscellaneous
|
|
|
3,620
|
|
|
1,819
|
|
Allowance
for Uncollectible Accounts
|
|
|
(838
|
)
|
|
(824
|
)
|
Total Accounts Receivable
|
|
|
243,501
|
|
|
205,431
|
|
Fuel
|
|
|
139,950
|
|
|
120,441
|
|
Materials
and Supplies
|
|
|
78,866
|
|
|
74,840
|
|
Emission
Allowances
|
|
|
12,302
|
|
|
10,388
|
|
Risk
Management Assets
|
|
|
49,848
|
|
|
86,947
|
|
Accrued
Tax Benefits
|
|
|
3,181
|
|
|
22,909
|
|
Prepayments
and Other
|
|
|
28,395
|
|
|
18,416
|
|
TOTAL
|
|
|
557,304
|
|
|
540,997
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
4,747,459
|
|
|
4,413,340
|
|
Transmission
|
|
|
1,038,642
|
|
|
1,030,934
|
|
Distribution
|
|
|
1,336,874
|
|
|
1,322,103
|
|
Other
|
|
|
300,054
|
|
|
299,637
|
|
Construction
Work in Progress
|
|
|
1,226,985
|
|
|
1,339,631
|
|
Total
|
|
|
8,650,014
|
|
|
8,405,645
|
|
Accumulated
Depreciation and Amortization
|
|
|
2,867,416
|
|
|
2,836,584
|
|
TOTAL
- NET
|
|
|
5,782,598
|
|
|
5,569,061
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
387,201
|
|
|
414,180
|
|
Long-term
Risk Management Assets
|
|
|
57,412
|
|
|
70,092
|
|
Deferred
Charges and Other
|
|
|
209,873
|
|
|
224,403
|
|
TOTAL
|
|
|
654,486
|
|
|
708,675
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
6,994,388
|
|
$
|
6,818,733
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
March
31, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
397,127
|
|
$
|
181,281
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
225,809
|
|
|
250,025
|
|
Affiliated
Companies
|
|
|
116,297
|
|
|
145,197
|
|
Short-term
Debt - Nonaffiliated
|
|
|
4,503
|
|
|
1,203
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
17,854
|
|
|
17,854
|
|
Risk
Management Liabilities
|
|
|
48,583
|
|
|
73,386
|
|
Customer
Deposits
|
|
|
31,547
|
|
|
31,465
|
|
Accrued
Taxes
|
|
|
148,057
|
|
|
165,338
|
|
Accrued
Interest
|
|
|
34,561
|
|
|
35,497
|
|
Other
|
|
|
126,845
|
|
|
123,631
|
|
TOTAL
|
|
|
1,151,183
|
|
|
1,024,877
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
2,176,601
|
|
|
2,183,887
|
|
Long-term
Debt - Affiliated
|
|
|
200,000
|
|
|
200,000
|
|
Long-term
Risk Management Liabilities
|
|
|
41,536
|
|
|
52,929
|
|
Deferred
Income Taxes
|
|
|
891,761
|
|
|
911,221
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
173,946
|
|
|
185,895
|
|
Deferred
Credits and Other
|
|
|
249,254
|
|
|
219,127
|
|
TOTAL
|
|
|
3,733,098
|
|
|
3,753,059
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,884,281
|
|
|
4,777,936
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
17,910
|
|
|
15,825
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
16,628
|
|
|
16,630
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - No Par Value:
|
|
|
|
|
|
|
|
Authorized
- 40,000,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 27,952,473 Shares
|
|
|
321,201
|
|
|
321,201
|
|
Paid-in
Capital
|
|
|
536,639
|
|
|
536,639
|
|
Retained
Earnings
|
|
|
1,280,963
|
|
|
1,207,265
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(63,234
|
)
|
|
(56,763
|
)
|
TOTAL
|
|
|
2,075,569
|
|
|
2,008,342
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
6,994,388
|
|
$
|
6,818,733
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
79,261
|
|
$
|
95,032
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
84,276
|
|
|
78,821
|
|
Deferred
Income Taxes
|
|
|
2,851
|
|
|
3,604
|
|
Carrying
Costs Income
|
|
|
(3,541
|
)
|
|
(3,383
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
3,958
|
|
|
(3,616
|
)
|
Deferred
Property Taxes
|
|
|
17,920
|
|
|
17,331
|
|
Change
in Other Noncurrent Assets
|
|
|
(4,406
|
)
|
|
2,455
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(4,434
|
)
|
|
13,855
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(38,070
|
)
|
|
101,866
|
|
Fuel,
Materials and Supplies
|
|
|
(23,535
|
)
|
|
(18,238
|
)
|
Accounts
Payable
|
|
|
(25,807
|
)
|
|
(60,411
|
)
|
Customer
Deposits
|
|
|
82
|
|
|
(12,497
|
)
|
Accrued
Taxes, Net
|
|
|
6,360
|
|
|
3,116
|
|
Accrued
Interest
|
|
|
(2,986
|
)
|
|
(10,998
|
)
|
Other
Current Assets
|
|
|
1,706
|
|
|
(739
|
)
|
Other
Current Liabilities
|
|
|
3,229
|
|
|
(24,196
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
96,864
|
|
|
182,002
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(301,635
|
)
|
|
(222,600
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
(7,988
|
)
|
|
(1,651
|
)
|
Proceeds
from Sale of Assets
|
|
|
2,797
|
|
|
2,389
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(306,826
|
)
|
|
(221,862
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Capital
Contributions from Parent Company
|
|
|
-
|
|
|
35,000
|
|
Change
in Short-term Debt, Net - Nonaffiliated
|
|
|
3,300
|
|
|
636
|
|
Change
in Advances from Affiliates, Net
|
|
|
215,846
|
|
|
10,972
|
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
(7,463
|
)
|
|
(4,713
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(1,902
|
)
|
|
(2,135
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(183
|
)
|
|
(183
|
)
|
Net
Cash Flows From Financing Activities
|
|
|
209,598
|
|
|
39,577
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(364
|
)
|
|
(283
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,625
|
|
|
1,240
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,261
|
|
$
|
957
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
29,646
|
|
$
|
29,152
|
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(8,899
|
)
|
|
922
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
608
|
|
|
927
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
98,653
|
|
|
82,024
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to OPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to OPCo.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Net
Loss
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
(5
|
)
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
5
|
|
|
|
|
Transmission
Revenues
|
|
|
1
|
|
|
|
|
Other
|
|
|
(1
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(27
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(2
|
)
|
|
|
|
Interest
Expense
|
|
|
(2
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(31
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Credit
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
(20
|
)
|
Net
Loss
increased $15 million to $20 million in 2007. The key driver of the increased
loss was a $31 million increase in Operating Expenses and Other, partially
offset by an $11 million increase in Income Tax Credit and a $5 million increase
in Gross Margin.
The
major
component 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 was a $5 million increase in Retail and
Off-system Sales Margins primarily due to a $4 million increase in retail
margins resulting from an increase in heating degree days.
Operating
Expenses and Other increased between years as follows:
·
|
Other
Operation and Maintenance expenses increased $27 million due to:
|
|
·
|
A
$21 million increase in distribution maintenance expense primarily
due to
a January 2007 ice storm.
|
|
·
|
A
$2 million increase in administrative and general expenses, mostly
due to
increased employee-related expenses.
|
·
|
Interest
Expense increased $2 million primarily due to increased
borrowings.
|
Income
Taxes
Income
Tax Credit increased $11 million primarily due to an increase in pretax book
loss and a decrease in state income taxes.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in our 2006 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption
of New Accounting Pronouncements
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management assets and liabilities are managed by AEPSC as agent for us. The
related risk management policies and procedures are instituted and administered
by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative
and Qualitative Disclosures About Risk Management Activities” section for
disclosures about risk management activities.
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 $42 million and $39 million at March 31,
2007
and December 31, 2006, 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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
290,080
|
|
$
|
339,601
|
|
Sales
to AEP Affiliates
|
|
|
24,593
|
|
|
14,068
|
|
Other
|
|
|
640
|
|
|
1,060
|
|
TOTAL
|
|
|
315,313
|
|
|
354,729
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
142,515
|
|
|
213,173
|
|
Purchased
Electricity for Resale
|
|
|
67,409
|
|
|
33,217
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
13,484
|
|
|
21,231
|
|
Other
Operation
|
|
|
41,007
|
|
|
36,756
|
|
Maintenance
|
|
|
43,085
|
|
|
20,307
|
|
Depreciation
and Amortization
|
|
|
22,706
|
|
|
21,132
|
|
Taxes
Other Than Income Taxes
|
|
|
10,294
|
|
|
10,076
|
|
TOTAL
|
|
|
340,500
|
|
|
355,892
|
|
|
|
|
|
|
|
|
|
OPERATING
LOSS
|
|
|
(25,187
|
)
|
|
(1,163
|
)
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
646
|
|
|
569
|
|
Interest
Expense
|
|
|
(11,383
|
)
|
|
(9,135
|
)
|
|
|
|
|
|
|
|
|
LOSS
BEFORE INCOME TAXES
|
|
|
(35,924
|
)
|
|
(9,729
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Credit
|
|
|
(15,498
|
)
|
|
(4,372
|
)
|
|
|
|
|
|
|
|
|
NET
LOSS
|
|
|
(20,426
|
)
|
|
(5,357
|
)
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
53
|
|
|
53
|
|
|
|
|
|
|
|
|
|
LOSS
APPLICABLE TO COMMON STOCK
|
|
$
|
(20,479
|
)
|
$
|
(5,410
|
)
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$
|
157,230
|
|
$
|
230,016
|
|
$
|
199,262
|
|
$
|
(1,070
|
)
|
$
|
585,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
(386
|
)
|
|
|
|
|
(386
|
)
|
Capital
Contribution from Parent Company
|
|
|
|
|
|
20,000
|
|
|
|
|
|
|
|
|
20,000
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(53
|
)
|
|
|
|
|
(53
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
604,999
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $24
|
|
|
|
|
|
|
|
|
|
|
|
45
|
|
|
45
|
|
NET
LOSS
|
|
|
|
|
|
|
|
|
(20,426
|
)
|
|
|
|
|
(20,426
|
)
|
TOTAL
COMPREHENSIVE LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,381
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2007
|
|
$
|
157,230
|
|
$
|
250,016
|
|
$
|
178,397
|
|
$
|
(1,025
|
)
|
$
|
584,618
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
BALANCE SHEETS
ASSETS
March
31, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
1,584
|
|
$
|
1,651
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
51,680
|
|
|
70,319
|
|
Affiliated
Companies
|
|
|
73,191
|
|
|
73,318
|
|
Miscellaneous
|
|
|
13,004
|
|
|
10,270
|
|
Allowance
for Uncollectible Accounts
|
|
|
(89
|
)
|
|
(5
|
)
|
Total Accounts Receivable
|
|
|
137,786
|
|
|
153,902
|
|
Fuel
|
|
|
19,028
|
|
|
20,082
|
|
Materials
and Supplies
|
|
|
52,951
|
|
|
48,375
|
|
Risk
Management Assets
|
|
|
56,139
|
|
|
100,802
|
|
Accrued
Tax Benefits
|
|
|
25,206
|
|
|
4,679
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
-
|
|
|
7,557
|
|
Margin
Deposits
|
|
|
22,705
|
|
|
35,270
|
|
Prepayments
and Other
|
|
|
5,718
|
|
|
5,732
|
|
TOTAL
|
|
|
321,117
|
|
|
378,050
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
1,095,466
|
|
|
1,091,910
|
|
Transmission
|
|
|
505,326
|
|
|
503,638
|
|
Distribution
|
|
|
1,248,077
|
|
|
1,215,236
|
|
Other
|
|
|
237,383
|
|
|
234,227
|
|
Construction
Work in Progress
|
|
|
158,637
|
|
|
141,283
|
|
Total
|
|
|
3,244,889
|
|
|
3,186,294
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,200,212
|
|
|
1,187,107
|
|
TOTAL
- NET
|
|
|
2,044,677
|
|
|
1,999,187
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
138,815
|
|
|
142,905
|
|
Long-term
Risk Management Assets
|
|
|
13,748
|
|
|
17,066
|
|
Employee
Benefits and Pension Assets
|
|
|
29,761
|
|
|
30,161
|
|
Deferred
Charges and Other
|
|
|
34,237
|
|
|
11,677
|
|
TOTAL
|
|
|
216,561
|
|
|
201,809
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
2,582,355
|
|
$
|
2,579,046
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
BALANCE SHEETS
LIABILITIES
AND SHAREHOLDERS’ EQUITY
March
31, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
135,694
|
|
$
|
76,323
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
173,021
|
|
|
165,618
|
|
Affiliated
Companies
|
|
|
68,782
|
|
|
65,134
|
|
Risk
Management Liabilities
|
|
|
46,530
|
|
|
88,469
|
|
Customer
Deposits
|
|
|
41,404
|
|
|
51,335
|
|
Accrued
Taxes
|
|
|
35,144
|
|
|
19,984
|
|
Regulatory
Liability for Over-Recovered Fuel Costs
|
|
|
9,015
|
|
|
-
|
|
Other
|
|
|
29,898
|
|
|
58,651
|
|
TOTAL
|
|
|
539,488
|
|
|
525,514
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
670,042
|
|
|
669,998
|
|
Long-term
Risk Management Liabilities
|
|
|
8,514
|
|
|
11,448
|
|
Deferred
Income Taxes
|
|
|
407,365
|
|
|
414,197
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
306,194
|
|
|
315,584
|
|
Deferred
Credits and Other
|
|
|
60,872
|
|
|
51,605
|
|
TOTAL
|
|
|
1,452,987
|
|
|
1,462,832
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
1,992,475
|
|
|
1,988,346
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
5,262
|
|
|
5,262
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - $15 Par Value Per Share:
|
|
|
|
|
|
|
|
Authorized
- 11,000,000 Shares
|
|
|
|
|
|
|
|
Issued
- 10,482,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 9,013,000 Shares
|
|
|
157,230
|
|
|
157,230
|
|
Paid-in
Capital
|
|
|
250,016
|
|
|
230,016
|
|
Retained
Earnings
|
|
|
178,397
|
|
|
199,262
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(1,025
|
)
|
|
(1,070
|
)
|
TOTAL
|
|
|
584,618
|
|
|
585,438
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
2,582,355
|
|
$
|
2,579,046
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Loss
|
|
$
|
(20,426
|
)
|
$
|
(5,357
|
)
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
22,706
|
|
|
21,132
|
|
Deferred
Income Taxes
|
|
|
1,039
|
|
|
(23,436
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
3,108
|
|
|
9,106
|
|
Deferred
Property Taxes
|
|
|
(24,809
|
)
|
|
(24,295
|
)
|
Change
in Other Noncurrent Assets
|
|
|
4,393
|
|
|
11,118
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(11,269
|
)
|
|
(20,806
|
)
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
16,116
|
|
|
33,852
|
|
Fuel,
Materials and Supplies
|
|
|
(3,513
|
)
|
|
(26
|
)
|
Margin
Deposits
|
|
|
12,565
|
|
|
5,065
|
|
Accounts
Payable
|
|
|
6,941
|
|
|
(77,217
|
)
|
Customer
Deposits
|
|
|
(9,931
|
)
|
|
(13,056
|
)
|
Accrued
Taxes, Net
|
|
|
(4,378
|
)
|
|
34,196
|
|
Fuel
Over/Under Recovery, Net
|
|
|
16,572
|
|
|
74,281
|
|
Other
Current Assets
|
|
|
(139
|
)
|
|
1,021
|
|
Other
Current Liabilities
|
|
|
(26,677
|
)
|
|
(23,048
|
)
|
Net
Cash Flows From (Used for) Operating Activities
|
|
|
(17,702
|
)
|
|
2,530
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(61,301
|
)
|
|
(45,539
|
)
|
Change
in Other Cash Deposits, Net
|
|
|
(29
|
)
|
|
6
|
|
Proceeds
from Sales of Assets
|
|
|
17
|
|
|
-
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(61,313
|
)
|
|
(45,533
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Capital
Contributions from Parent Company
|
|
|
20,000
|
|
|
-
|
|
Change
in Advances from Affiliates, Net
|
|
|
59,371
|
|
|
42,932
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(370
|
)
|
|
(206
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(53
|
)
|
|
(53
|
)
|
Net
Cash Flows From Financing Activities
|
|
|
78,948
|
|
|
42,673
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(67
|
)
|
|
(330
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,651
|
|
|
1,520
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,584
|
|
$
|
1,190
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
12,921
|
|
$
|
8,681
|
|
Net
Cash Paid for Income Taxes
|
|
|
2,623
|
|
|
575
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
283
|
|
|
564
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
19,038
|
|
|
6,052
|
|
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,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
First
Quarter of 2007 Compared to First Quarter of 2006
Reconciliation
of First Quarter of 2006 to First Quarter of 2007
Net
Income
(in
millions)
First
Quarter of 2006
|
|
|
|
|
$
|
18
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
(1
|
)
|
|
|
|
Other
|
|
|
(4
|
)
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(6
|
)
|
|
|
|
Depreciation
and Amortization
|
|
|
(1
|
)
|
|
|
|
Other
Income
|
|
|
1
|
|
|
|
|
Interest
Expense
|
|
|
(3
|
)
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
First
Quarter of 2007
|
|
|
|
|
$
|
10
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income decreased $8 million to $10 million in 2007. The key drivers of the
decrease were a $9 million increase in Operating Expenses and Other and a
$5
million decrease in Gross Margin, offset by a $6 million decrease in Income
Tax
Expense.
The
major
component of our decrease in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power was a $4 million decrease in Other changes
in
gross margin, primarily due to lower gains on sales of emission
allowances.
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $6 million primarily
due to a
$2 million increase in generation operation and maintenance, a
$1 million
increase in transmission expenses due to higher SPP administration
fees
and a $1 million increase in administrative and general expenses,
primarily associated with outside services and employee-related
expenses.
|
·
|
Interest
Expense increased $3 million primarily due to increased long-term
debt.
|
Income
Taxes
Income
Tax Expense decreased $6 million primarily due to a decrease in pretax book
income and state income taxes.
Financial
Condition
Credit
Ratings
The
rating agencies currently have us on stable outlook. Current ratings are
as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
First
Mortgage Bonds
|
A3
|
|
A-
|
|
A
|
Senior
Unsecured Debt
|
Baa1
|
|
BBB
|
|
A-
|
Cash
Flow
Cash
flows for the three months ended March 31, 2007 and 2006 were as
follows:
|
|
2007
|
|
2006
|
|
|
|
(in
thousands)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$
|
2,618
|
|
$
|
3,049
|
|
Cash
Flows From (Used For):
|
|
|
|
|
|
|
|
Operating
Activities
|
|
|
65,590
|
|
|
41,293
|
|
Investing
Activities
|
|
|
(120,639
|
)
|
|
(54,294
|
)
|
Financing
Activities
|
|
|
54,331
|
|
|
12,501
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(718
|
)
|
|
(500
|
)
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,900
|
|
$
|
2,549
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $66 million in 2007. We produced Net
Income
of $10 million during the period and a noncash expense item of $34 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 $36 million inflow from
Accrued Taxes, Net was the result of increased accruals related to property
and
income taxes. The $22 million inflow from Margin Deposits was due to decreased
trading-related deposits resulting from normal trading activities. The $20
million inflow from Accounts Receivable, Net was primarily due to the assignment
of certain ERCOT contracts to an affiliate company.
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.
Investing
Activities
Cash
Flows Used For Investing Activities during 2007 and 2006 were $121 million
and
$54 million, respectively. The $108 million of cash flows for Construction
Expenditures during 2007 were primarily related to new generation facilities.
In
addition, we had a net increase of $9 million in loans to the Utility Money
Pool. The cash flows during 2006 were comprised primarily of Construction
Expenditures related to projects for improved transmission and distribution
service reliability.
Financing
Activities
Cash
Flows From Financing Activities were $54 million during 2007. We issued $250
million of Senior Unsecured Notes. We had a net decrease of $189 million
in
borrowings from the Utility Money Pool.
Cash
Flows From Financing Activities were $13 million during 2006. We had a net
increase of $21 million in borrowings from the Utility Money Pool. We paid
$10
million in common stock dividends.
Financing
Activity
Long-term
debt issuances and retirements during the first three months of 2007
were:
Issuances
|
|
Principal
Amount
Paid
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Senior
Unsecured Notes
|
|
$
|
250,000
|
|
5.55
|
|
2017
|
Retirements
|
|
Principal
Amount
Paid
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Notes
Payable - Nonaffiliated
|
|
$
|
1,645
|
|
4.47
|
|
2011
|
Notes
Payable - Nonaffiliated
|
|
|
4,000
|
|
6.36
|
|
2007
|
Notes
Payable - Nonaffiliated
|
|
|
750
|
|
Variable
|
|
2008
|
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 2006 Annual Report and
has not
changed significantly since year-end other than the debt issuance discussed
in
“Financing Activity” above and Energy and Capacity Purchase Contracts. Effective
January 1, 2007, we transferred a significant amount of ERCOT energy marketing
contracts to AEPEP; thereby decreasing our future obligations in Energy and
Capacity Purchase Contracts. See “ERCOT Contracts Transferred to AEPEP” section
of Note 1.
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 6 - Commitments, Guarantees and Contingencies in our 2006 Annual Report.
Also, see Note 3 - Rate Matters and Note 4 - Commitments, Guarantees and
Contingencies in the “Condensed Notes to Condensed Financial Statements of
Registrant Subsidiaries” section. Adverse results in these proceedings have the
potential to materially affect our results of operations, financial condition
and cash flows.
New
Generation
In
December 2005, we sought proposals for new peaking, intermediate and base
load
generation to be online between 2008 and 2011. In May 2006, we announced
plans
to construct new generation to satisfy the demands of its customers. We will
build up to 480 MW of simple-cycle natural gas combustion turbine peaking
generation in Tontitown, Arkansas and will build a 480 MW combined-cycle
natural
gas fired plant at its existing Arsenal Hill Power Plant in Shreveport,
Louisiana. We also plan to build a new 600 MW base load coal plant, of which
our
investment will be 73%, in Hempstead County, Arkansas by 2011 to meet the
long-term generation needs of its customers. Preliminary cost estimates our
share of the new facilities are approximately $1.4 billion (this total excludes
the related transmission investment and AFUDC). These new facilities are
subject
to regulatory approvals from our three state commissions. The peaking generation
facility in Tontitown, Arkansas has been approved by all three state commissions
and Units 3 and 4 are projected to be online in July 2007 and the remaining
two
units by 2008. Construction is expected to begin in 2007 on the intermediate
and
base load facilities upon approval from the state regulatory commissions.
Expenditures related to construction of these facilities are expected to
total
$349 million in 2007.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of factors relevant to us.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 2006 Annual Report for a discussion
of the estimates and judgments required for regulatory accounting, revenue
recognition, the valuation of long-lived assets, pension and other
postretirement benefits and the impact of new accounting
pronouncements.
Adoption
of New Accounting Pronouncements
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for a discussion of adoption of new accounting
pronouncements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT
ACTIVITIES
Market
Risks
Our
risk
management assets and liabilities are managed by AEPSC as agent for us. The
related
risk
management policies and procedures are instituted and administered by AEPSC.
See
complete discussion within AEP’s “Quantitative and Qualitative Disclosures About
Risk Management Activities” section. The following tables provide information
about AEP’s risk management activities’ effect on 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, 2007
and
the reasons for changes in our total MTM value as compared to December 31,
2006.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of March 31, 2007
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
Cash
Flow Hedges
|
|
Total
|
|
Current
Assets
|
|
$
|
66,352
|
|
$
|
582
|
|
$
|
66,934
|
|
Noncurrent
Assets
|
|
|
16,264
|
|
|
37
|
|
|
16,301
|
|
Total
MTM Derivative Contract Assets
|
|
|
82,616
|
|
|
619
|
|
|
83,235
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(55,257
|
)
|
|
(6
|
)
|
|
(55,263
|
)
|
Noncurrent
Liabilities
|
|
|
(10,158
|
)
|
|
(16
|
)
|
|
(10,174
|
)
|
Total
MTM Derivative Contract Liabilities
|
|
|
(65,415
|
)
|
|
(22
|
)
|
|
(65,437
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$
|
17,201
|
|
$
|
597
|
|
$
|
17,798
|
|
MTM
Risk Management Contract Net Assets
Three
Months Ended March 31, 2007
(in
thousands)
Total
MTM Risk Management Contract Net Assets at December 31,
2006
|
|
$
|
20,166
|
|
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
|
|
(1,013
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
-
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
-
|
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
21
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(1,973
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
17,201
|
|
Net
Cash Flow Hedge Contracts
|
|
|
597
|
|
Total
MTM Risk Management Contract Net Assets at March 31,
2007
|
|
$
|
17,798
|
|
(a)
|
Reflects
fair value on long-term contracts which are typically with customers
that
seek fixed pricing to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can
be obtained
for valuation inputs for the entire contract term. The contract
prices are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
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 to give an indication
of
when these MTM amounts will settle and generate
cash.
|
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets
Fair
Value of Contracts as of March 31, 2007
(in
thousands)
|
|
Remainder
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
After
2011
|
|
Total
|
|
Prices
Actively Quoted - Exchange Traded
Contracts
|
|
$
|
(16,029
|
)
|
$
|
1,742
|
|
$
|
(283
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(14,570
|
)
|
Prices
Provided by Other External
Sources
- OTC Broker Quotes (a)
|
|
|
29,194
|
|
|
4,143
|
|
|
(813
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
32,524
|
|
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
(2,551
|
)
|
|
335
|
|
|
1,461
|
|
|
2
|
|
|
-
|
|
|
-
|
|
|
(753
|
)
|
Total
|
|
$
|
10,614
|
|
$
|
6,220
|
|
$
|
365
|
|
$
|
2
|
|
$
|
-
|
|
$
|
-
|
|
$
|
17,201
|
|
(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.
|
|
|
|
Contract
values that are measured using models or valuation methods other
than
active quotes or OTC broker quotes (because of the lack of such
data for
all delivery quantities, locations and periods) incorporate in
the model
or other valuation methods, to the extent possible, OTC broker
quotes and
active quotes for deliveries in years and at locations for which
such
quotes are available.
|
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 use various
commodity instruments designated in qualifying cash flow hedge strategies
to
mitigate the impact of these fluctuations on the future cash flows. We do
not
hedge all commodity price risk.
We
use
interest rate derivative transactions to manage interest rate risk related
to
anticipated borrowings of fixed-rate debt. We do not hedge all interest rate
risk.
We
use
forward contracts and collars as cash flow hedges to lock in prices on certain
transactions 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, 2006 to March 31, 2007. 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, 2007
(in
thousands)
|
|
Interest
Rate
|
|
Foreign
Currency
|
|
Total
|
|
Beginning
Balance in AOCI December 31, 2006
|
|
$
|
(6,435
|
)
|
$
|
25
|
|
$
|
(6,410
|
)
|
Changes
in Fair Value
|
|
|
(1,019
|
)
|
|
509
|
|
|
(510
|
)
|
Reclassifications
from AOCI to Net Income for
Cash
Flow Hedges Settled
|
|
|
183
|
|
|
-
|
|
|
183
|
|
Ending
Balance in AOCI March 31, 2007
|
|
$
|
(7,271
|
)
|
$
|
534
|
|
$
|
(6,737
|
)
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $249 thousand loss.
Credit
Risk
Our
counterparty credit quality and exposure is generally consistent with that
of
AEP.
VaR
Associated with Risk Management Contracts
We
use a
risk measurement model, which calculates Value at Risk (VaR) to measure our
commodity price risk in the risk management portfolio. The VaR is based on
the
variance-covariance method using historical prices to estimate volatilities
and
correlations and assumes a 95% confidence level and a one-day holding period.
Based on this VaR analysis, at March 31, 2007, 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, 2007
|
|
|
|
|
Twelve
Months Ended December 31, 2006
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$83
|
|
$245
|
|
$100
|
|
$25
|
|
|
|
|
$447
|
|
$2,171
|
|
$794
|
|
$68
|
The
High
VaR for the twelve months ended December 31, 2006 occurred in the fourth
quarter
due to volatility in the ERCOT region.
VaR
Associated with Debt Outstanding
We
also
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence
level
and a one-year holding period. The risk of potential loss in fair value
attributable to our exposure to interest rates primarily related to long-term
debt with fixed interest rates was $43 million and $25 million at March 31,
2007
and December 31, 2006, 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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$
|
327,284
|
|
$
|
293,993
|
|
Sales
to AEP Affiliates
|
|
|
16,415
|
|
|
10,765
|
|
Other
|
|
|
400
|
|
|
374
|
|
TOTAL
|
|
|
344,099
|
|
|
305,132
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
111,987
|
|
|
90,661
|
|
Purchased
Electricity for Resale
|
|
|
52,498
|
|
|
29,218
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
22,917
|
|
|
23,337
|
|
Other
Operation
|
|
|
53,783
|
|
|
49,700
|
|
Maintenance
|
|
|
26,339
|
|
|
24,657
|
|
Depreciation
and Amortization
|
|
|
34,122
|
|
|
32,617
|
|
Taxes
Other Than Income Taxes
|
|
|
15,991
|
|
|
15,982
|
|
TOTAL
|
|
|
317,637
|
|
|
266,172
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
26,462
|
|
|
38,960
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
705
|
|
|
543
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
1,391
|
|
|
185
|
|
Interest
Expense
|
|
|
(15,490
|
)
|
|
(12,771
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES AND MINORITY
INTEREST
EXPENSE
|
|
|
13,068
|
|
|
26,917
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
2,621
|
|
|
8,823
|
|
Minority
Interest Expense
|
|
|
842
|
|
|
222
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
9,605
|
|
|
17,872
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
57
|
|
|
57
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$
|
9,548
|
|
$
|
17,815
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
Total
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$
|
135,660
|
|
$
|
245,003
|
|
$
|
459,338
|
|
$
|
(18,799
|
)
|
$
|
821,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
(1,642
|
)
|
|
|
|
|
(1,642
|
)
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
(57
|
)
|
|
|
|
|
(57
|
)
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
819,503
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $39
|
|
|
|
|
|
|
|
|
|
|
|
(327
|
)
|
|
(327
|
)
|
NET
INCOME
|
|
|
|
|
|
|
|
|
9,605
|
|
|
|
|
|
9,605
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MARCH
31, 2007
|
|
$
|
135,660
|
|
$
|
245,003
|
|
$
|
467,244
|
|
$
|
(19,126
|
)
|
$
|
828,781
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
March
31, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
1,900
|
|
$
|
2,618
|
|
Advances
to Affiliates
|
|
|
8,959
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
Customers
|
|
|
74,382
|
|
|
88,245
|
|
Affiliated
Companies
|
|
|
48,598
|
|
|
59,679
|
|
Miscellaneous
|
|
|
13,077
|
|
|
8,595
|
|
Allowance
for Uncollectible Accounts
|
|
|
(137
|
)
|
|
(130
|
)
|
Total Accounts Receivable
|
|
|
135,920
|
|
|
156,389
|
|
Fuel
|
|
|
73,479
|
|
|
69,426
|
|
Materials
and Supplies
|
|
|
46,101
|
|
|
46,001
|
|
Risk
Management Assets
|
|
|
66,934
|
|
|
120,036
|
|
Margin
Deposits
|
|
|
19,353
|
|
|
41,579
|
|
Prepayments
and Other
|
|
|
28,581
|
|
|
18,256
|
|
TOTAL
|
|
|
381,227
|
|
|
454,305
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
Production
|
|
|
1,586,238
|
|
|
1,576,200
|
|
Transmission
|
|
|
690,384
|
|
|
668,008
|
|
Distribution
|
|
|
1,262,203
|
|
|
1,228,948
|
|
Other
|
|
|
611,255
|
|
|
595,429
|
|
Construction
Work in Progress
|
|
|
301,251
|
|
|
259,662
|
|
Total
|
|
|
4,451,331
|
|
|
4,328,247
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,868,974
|
|
|
1,834,145
|
|
TOTAL
- NET
|
|
|
2,582,357
|
|
|
2,494,102
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
153,080
|
|
|
156,420
|
|
Long-term
Risk Management Assets
|
|
|
16,301
|
|
|
20,531
|
|
Employee
Benefits and Pension Assets
|
|
|
25,302
|
|
|
26,029
|
|
Deferred
Charges and Other
|
|
|
68,855
|
|
|
39,581
|
|
TOTAL
|
|
|
263,538
|
|
|
242,561
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
3,227,122
|
|
$
|
3,190,968
|
|
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, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$
|
-
|
|
$
|
188,965
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
General
|
|
|
155,206
|
|
|
140,424
|
|
Affiliated
Companies
|
|
|
72,448
|
|
|
68,680
|
|
Short-term
Debt - Nonaffiliated
|
|
|
20,433
|
|
|
17,143
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
97,768
|
|
|
102,312
|
|
Risk
Management Liabilities
|
|
|
55,263
|
|
|
109,578
|
|
Customer
Deposits
|
|
|
36,798
|
|
|
48,277
|
|
Accrued
Taxes
|
|
|
64,418
|
|
|
31,591
|
|
Regulatory
Liability for Over-Recovered Fuel Costs
|
|
|
33,791
|
|
|
26,012
|
|
Other
|
|
|
66,871
|
|
|
85,086
|
|
TOTAL
|
|
|
602,996
|
|
|
818,068
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt - Nonaffiliated
|
|
|
822,519
|
|
|
576,694
|
|
Long-term
Debt - Affiliated
|
|
|
50,000
|
|
|
50,000
|
|
Long-term
Risk Management Liabilities
|
|
|
10,174
|
|
|
14,083
|
|
Deferred
Income Taxes
|
|
|
362,321
|
|
|
374,548
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
347,951
|
|
|
346,774
|
|
Deferred
Credits and Other
|
|
|
196,064
|
|
|
183,087
|
|
TOTAL
|
|
|
1,789,029
|
|
|
1,545,186
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,392,025
|
|
|
2,363,254
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
1,619
|
|
|
1,815
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
4,697
|
|
|
4,697
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
Common
Stock - Par Value - $18 Per Share:
|
|
|
|
|
|
|
|
Authorized
- 7,600,000 Shares
|
|
|
|
|
|
|
|
Outstanding
- 7,536,640 Shares
|
|
|
135,660
|
|
|
135,660
|
|
Paid-in
Capital
|
|
|
245,003
|
|
|
245,003
|
|
Retained
Earnings
|
|
|
467,244
|
|
|
459,338
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(19,126
|
)
|
|
(18,799
|
)
|
TOTAL
|
|
|
828,781
|
|
|
821,202
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
3,227,122
|
|
$
|
3,190,968
|
|
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, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
9,605
|
|
$
|
17,872
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
34,122
|
|
|
32,617
|
|
Deferred
Income Taxes
|
|
|
(6,677
|
)
|
|
(9,101
|
)
|
Mark-to-Market
of Risk Management Contracts
|
|
|
2,965
|
|
|
10,468
|
|
Deferred
Property Taxes
|
|
|
(28,815
|
)
|
|
(28,997
|
)
|
Change
in Other Noncurrent Assets
|
|
|
(3,198
|
)
|
|
9,458
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(178
|
)
|
|
(19,121
|
)
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
20,469
|
|
|
26,848
|
|
Fuel,
Materials and Supplies
|
|
|
(4,141
|
)
|
|
(17,521
|
)
|
Margin
Deposits
|
|
|
22,226
|
|
|
7,915
|
|
Accounts
Payable
|
|
|
13,806
|
|
|
(15,304
|
)
|
Customer
Deposits
|
|
|
(11,479
|
)
|
|
(15,861
|
)
|
Accrued
Taxes, Net
|
|
|
36,113
|
|
|
45,238
|
|
Fuel
Over/Under Recovery, Net
|
|
|
4,212
|
|
|
15,216
|
|
Other
Current Assets
|
|
|
(2,868
|
)
|
|
2,821
|
|
Other
Current Liabilities
|
|
|
(20,572
|
)
|
|
(21,255
|
)
|
Net
Cash Flows From Operating Activities
|
|
|
65,590
|
|
|
41,293
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(107,613
|
)
|
|
(54,238
|
)
|
Change
in Advances to Affiliates, Net
|
|
|
(8,959
|
)
|
|
-
|
|
Other
|
|
|
(4,067
|
)
|
|
(56
|
)
|
Net
Cash Flows Used For Investing Activities
|
|
|
(120,639
|
)
|
|
(54,294
|
)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt - Nonaffiliated
|
|
|
247,548
|
|
|
-
|
|
Change
in Short-term Debt, Net - Nonaffiliated
|
|
|
3,290
|
|
|
4,394
|
|
Change
in Advances from Affiliates, Net
|
|
|
(188,965
|
)
|
|
20,988
|
|
Retirement
of Long-term Debt - Nonaffiliated
|
|
|
(6,395
|
)
|
|
(2,457
|
)
|
Principal
Payments for Capital Lease Obligations
|
|
|
(1,090
|
)
|
|
(367
|
)
|
Dividends
Paid on Common Stock
|
|
|
-
|
|
|
(10,000
|
)
|
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(57
|
)
|
|
(57
|
)
|
Net
Cash Flows From Financing Activities
|
|
|
54,331
|
|
|
12,501
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(718
|
)
|
|
(500
|
)
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
2,618
|
|
|
3,049
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,900
|
|
$
|
2,549
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$
|
16,747
|
|
$
|
11,892
|
|
Net
Cash Paid for Income Taxes
|
|
|
580
|
|
|
1,282
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
3,192
|
|
|
3,412
|
|
Construction
Expenditures Included in Accounts Payable at March 31,
|
|
|
32,460
|
|
|
12,800
|
|
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,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
CONDENSED
NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to condensed financial statements that follow are
a
combined presentation for the Registrant Subsidiaries. The following
list
indicates the registrants to which the footnotes apply:
|
|
|
|
1.
|
Significant
Accounting Matters
|
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.
|
Commitments,
Guarantees and Contingencies
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
5.
|
Acquisitions,
Dispositions and Assets Held for Sale
|
AEGCo,
CSPCo, TCC
|
6.
|
Benefit
Plans
|
APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
7.
|
Business
Segments
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
8.
|
Income
Taxes
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
9.
|
Financing
Activities
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC,
TNC
|
1. SIGNIFICANT
ACCOUNTING MATTERS
General
The
accompanying unaudited condensed financial statements and footnotes were
prepared in accordance with accounting principles generally accepted in the
United States of America (GAAP) for interim financial information and with
the
instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.
Accordingly, they do not include all the information and footnotes required
by
GAAP for complete financial statements.
In
the
opinion of management, the unaudited interim financial statements reflect
all
normal and recurring accruals and adjustments necessary for a fair presentation
of the results of operations, financial position and cash flows for the interim
periods for each Registrant Subsidiary. The results of operations for the
three
months March 31, 2007 are not necessarily indicative of results that may
be
expected for the year ending December 31, 2007. The accompanying condensed
financial statements are unaudited and should be read in conjunction with
the
audited 2006 financial statements and notes thereto, which are included in
the
Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December
31, 2006 as filed with the SEC on February 28, 2007.
Components
of Accumulated Other Comprehensive Income (Loss)
(AOCI)
AOCI
is
included on the balance sheets in the common shareholder’s equity section. AOCI
for Registrant Subsidiaries as of March 31, 2007 and December 31, 2006 is
shown
in the following table.
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
Components
|
|
(in
thousands)
|
|
Cash
Flow Hedges:
|
|
|
|
|
|
APCo
|
|
$
|
(10,031
|
)
|
$
|
(2,547
|
)
|
CSPCo
|
|
|
(1,878
|
)
|
|
3,398
|
|
I&M
|
|
|
(14,255
|
)
|
|
(8,962
|
)
|
KPCo
|
|
|
(490
|
)
|
|
1,552
|
|
OPCo
|
|
|
791
|
|
|
7,262
|
|
PSO
|
|
|
(1,025
|
)
|
|
(1,070
|
)
|
SWEPCo
|
|
|
(6,737
|
)
|
|
(6,410
|
)
|
TNC
|
|
|
-
|
|
|
(702
|
)
|
|
|
|
|
|
|
|
|
SFAS
158 Adoption:
|
|
|
|
|
|
|
|
APCo
|
|
$
|
(52,244
|
)
|
$
|
(52,244
|
)
|
CSPCo
|
|
|
(25,386
|
)
|
|
(25,386
|
)
|
I&M
|
|
|
(6,089
|
)
|
|
(6,089
|
)
|
OPCo
|
|
|
(64,025
|
)
|
|
(64,025
|
)
|
SWEPCo
|
|
|
(12,389
|
)
|
|
(12,389
|
)
|
TNC
|
|
|
(9,457
|
)
|
|
(9,457
|
)
|
Related
Party Transactions
Oklaunion
PPA between TNC and AEP Energy Partners
On
January 1, 2007, TNC began a 20-year Power Purchase & Sale Agreement (PPA)
with an affiliate, AEP Energy Partners (AEPEP), whereby TNC agrees to sell
AEPEP
100% of TNC’s capacity and associated energy from its undivided interest
(54.69%) in the Oklaunion plant. AEPEP is to pay TNC for the capacity and
associated energy delivered to the delivery point, the sum of fuel, operation
and maintenance, depreciation, capacity and all taxes other than federal
income
taxes applicable. A portion of the payment is fixed and is payable regardless
of
the level of output. There are no penalties if TNC fails to maintain a minimum
availability level or exceeds a maximum heat rate level. The PPA was approved
by
the FERC on July 12, 2006.
TNC
recorded revenue of $23.4 million from AEPEP in the first quarter of 2007,
which
is included in Sales to AEP Affiliates on its 2007 Condensed Consolidated
Statement of Income.
ERCOT
Contracts Transferred to AEPEP
Effective
January 1, 2007, PSO and SWEPCo transferred certain existing ERCOT energy
marketing contracts to AEPEP and entered into intercompany financial and
physical purchase and sale agreements with AEPEP. This was done to lock in
PSO
and SWEPCo’s margins on ERCOT trading and marketing contracts and to transfer
the future associated commodity price and credit risk to AEPEP. The contracts
will mature over the next three years.
PSO
and
SWEPCo have historically presented third party ERCOT trading and marketing
activity on a net basis in Revenues - Electric Generation, Transmission and
Distribution. The applicable ERCOT third party trading and marketing contracts
that were not transferred to AEPEP will remain until maturity on PSO and
SWEPCo
and will be presented on a net basis in Sales to AEP Affiliates on PSO’s and
SWEPCo’s Statements of Income.
The
following table indicates the sales to AEPEP and the amounts reclassified
from
third party to affiliate:
|
|
For
the Three Months Ended March 31, 2007
|
|
Company
|
|
Net
Settlement
With
AEPEP
|
|
Third
Party Amounts
Reclassified
to Affiliate
|
|
Net
Amount
included
in Sales
to
AEP Affiliates
|
|
|
|
(in
thousands)
|
|
PSO
|
|
$
|
43,150
|
|
$
|
(35,837
|
)
|
$
|
7,313
|
|
SWEPCo
|
|
|
46,876
|
|
|
(38,259
|
)
|
|
8,617
|
|
The
following table indicates the affiliated portion of risk management assets
and
liabilities reflected on PSO’s and SWEPCo’s balance sheets associated with these
contracts:
|
|
As
of March 31, 2007
|
|
|
|
PSO
|
|
SWEPCo
|
|
Current
|
|
(in
thousands)
|
|
Risk
Management Assets
|
|
$
|
-
|
|
$
|
-
|
|
Risk
Management Liabilities
|
|
|
(8,282
|
)
|
|
(9,758
|
)
|
|
|
|
|
|
|
|
|
Noncurrent
|
|
|
|
|
|
|
|
Long-term
Risk Management Assets
|
|
$
|
584
|
|
$
|
688
|
|
Long-term
Risk Management Liabilities
|
|
|
(2,097
|
)
|
|
(2,471
|
)
|
Texas
Restructuring - SPP - Affecting TNC and SWEPCo
In
August
2006, the PUCT adopted a rule extending the delay in implementation of customer
choice in the SPP area of Texas until no sooner than January 1, 2011. SWEPCo’s
and approximately 3% of TNC’s businesses were in SPP. A petition was filed in
May 2006 requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a
subsidiary of AEP C&I Company, LLC) customers and TNC’s facilities and
certificated service territory located in the SPP area to SWEPCo. In January
2007, the final regulatory approval was received for the transfers. The
transfers were effective February 2007 and were recorded at net book value
of
$11.6 million. The Arkansas Public Service Commission’s approval requires SWEPCo
to amend its fuel recovery tariff so that Arkansas customers do not pay the
incremental cost of serving the additional load.
Reclassifications
Certain
prior period financial statement items have been reclassified to conform
to
current period presentation. These revisions had no impact on the Registrant
Subsidiaries’ previously reported results of operations or changes in
shareholders’ equity.
On
their
statements of income, the Registrant Subsidiaries reclassified regulatory
credits related to regulatory asset cost deferral on ARO from Depreciation
and
Amortization to Other Operation and Maintenance to offset the ARO accretion
expense. The following table shows the credits reclassified by the Registrant
Subsidiaries in 2006:
|
|
Three
Months Ended
|
|
|
|
|
|
Company
|
|
(in
thousands)
|
|
AEGCo
|
|
$
|
27
|
|
APCo
|
|
|
296
|
|
I&M
|
|
|
5,589
|
|
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 2007 and standards issued but not implemented that we have determined
relate
to our operations.
SFAS
157 “Fair Value Measurements” (SFAS 157)
In
September 2006, the FASB issued SFAS 157, enhancing existing guidance for
fair
value measurement of assets and liabilities and instruments measured at fair
value that are classified in shareholders’ equity. The statement defines fair
value, establishes a fair value measurement framework and expands fair value
disclosures. It emphasizes that fair value is market-based with the highest
measurement hierarchy being market prices in active markets. The standard
requires fair value measurements be disclosed by hierarchy level and an entity
include its own credit standing in the measurement of its liabilities and
modifies the transaction price presumption.
SFAS
157
is effective for interim and annual periods in fiscal years beginning after
November 15, 2007. Management expects that the adoption of this standard
will
impact MTM valuations of certain contracts, but is unable to quantify the
effect. Although the statement is applied prospectively upon adoption, the
effect of certain transactions is applied retrospectively as of the beginning
of
the fiscal year of application, with a cumulative effect adjustment to the
appropriate balance sheet items. The Registrant Subsidiaries will adopt SFAS
157
effective January 1, 2008.
SFAS
159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS
159)
In
February 2007, the FASB issued SFAS 159, permitting entities to choose to
measure many financial instruments and certain other items at fair value.
The
standard also establishes presentation and disclosure requirements designed
to
facilitate comparison between entities that choose different measurement
attributes for similar types of assets and liabilities.
SFAS
159
is effective for annual periods in fiscal years beginning after November
15,
2007. If the fair value option is elected, the effect of the first remeasurement
to fair value is reported as a cumulative effect adjustment to the opening
balance of retained earnings. In the event we elect the fair value option
promulgated by this standard, the valuations of certain assets and liabilities
may be impacted. The statement is applied prospectively upon adoption. The
Registrant Subsidiaries will adopt SFAS 159 effective January 1,
2008.
FIN
48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1
"Definition of Settlement in FASB Interpretation No.
48"
In
July
2006, the FASB issued FASB Interpretation No. 48 "Accounting for Uncertainty
in
Income Taxes" and in May 2007, the FASB issued FASB Staff Position FIN 48-1
"Definition of Settlement in FASB Interpretation No. 48." FIN 48
clarifies the
accounting for uncertainty in income taxes recognized in an enterprise’s
financial statements by prescribing a recognition threshold (whether a tax
position is more likely than not to be sustained) without which, the benefit
of
that position is not recognized in the financial statements. It requires
a
measurement determination for recognized tax positions based on the largest
amount of benefit that is greater than 50 percent likely of being realized
upon
ultimate settlement. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure and transition.
FIN
48
requires that the cumulative effect of applying this interpretation be reported
and disclosed as an adjustment to the opening balance of retained earnings
for
that fiscal year and presented separately. The Registrant Subsidiaries adopted
FIN 48 effective January 1, 2007. The impact of this interpretation was an
unfavorable (favorable) adjustment to retained earnings as follows:
Company
|
|
(in
thousands)
|
|
AEGCo
|
|
$
|
(27
|
)
|
APCo
|
|
|
2,685
|
|
CSPCo
|
|
|
3,022
|
|
I&M
|
|
|
(327
|
)
|
KPCo
|
|
|
786
|
|
OPCo
|
|
|
5,380
|
|
PSO
|
|
|
386
|
|
SWEPCo
|
|
|
1,642
|
|
TCC
|
|
|
2,187
|
|
TNC
|
|
|
557
|
|
Future
Accounting Changes
The
FASB’s standard-setting process is ongoing and until new standards have been
finalized and issued by FASB, we cannot determine the impact on the reporting
of
our operations and financial position that may result from any such future
changes. The FASB is currently working on several projects including business
combinations, revenue recognition, liabilities and equity, derivatives
disclosures, emission allowances, leases, insurance, subsequent events and
related tax impacts. We also expect to see more FASB projects as a result
of its
desire to converge International Accounting Standards with GAAP. The ultimate
pronouncements resulting from these and future projects could have an impact
on
future results of operations and financial position.
3. RATE
MATTERS
The
Registrant subsidiaries are involved in rate and regulatory proceedings at
the
FERC and their state commissions. The Rate Matters note within the 2006 Annual
Report should be read in conjunction with this report to gain a complete
understanding of material rate matters still pending that could impact results
of operations, cash flows and possibly financial condition. The following
discusses ratemaking developments in 2007 and updates the 2006 Annual
Report.
Ohio
Rate Matters
Ohio
Restructuring and Rate Stabilization Plans - Affecting CSPCo and
OPCo
In
January 2007, CSPCo and OPCo filed with the PUCO under the 4% provision of
their
RSPs to increase their annual generation rates for 2007 by $24 million and
$8
million, respectively, to recover governmentally-mandated costs. Pursuant
to the
RSPs, CSPCo and OPCo implemented these proposed increases effective with
the
beginning of the May 2007 billing cycle. These increases are subject to refund
until the PUCO issues a final order in the matter. The hearing is scheduled
to
begin in late May 2007.
In
March
2007, CSPCo filed an application under the 4% provision of the RSP to adjust
the
Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in
connection with CSPCo's acquisition of Monongahela Power Company's certified
territory in Ohio. The PAR is intended to recover the difference between
CSPCo's
tariffed generation service rates and the cost of power acquired to serve
the
former Monongahela Power load. The PAR was set for an initial 17-month period
of
January 2006 through May 2007. The filing would adjust the PAR for the nineteen
month period of June 2007 through December 2008. The filing reflects a true
up
for estimated under-recoveries during the initial period, $8 million as of
March
31, 2007, as well as the power acquisition costs for the upcoming nineteen-month
period. If approved, CSPCo's revenues would increase by $22 million and $38
million for 2007 and 2008, respectively.
In
March
2007, CSPCo and OPCo filed a settlement agreement at the PUCO resolving
the Ohio
Supreme Court's remand of the PUCO’s RSP order. The Supreme Court indicated
concern with the absence of a competitive bid process as an alternative
to the
generation rates set by the RSP. In response, the settling parties agreed
to
have CSPCo and OPCo take bids for Renewable Energy Certificates (RECs).
CSPCo
and OPCo will give customers the option to pay a generation rate premium
that
would encourage the development of renewable energy sources by reimbursing
CSPCo
and OPCo for the cost of the RECs and the administrative costs of the program.
This settlement agreement was supported by the Office of Consumers' Counsel,
the
Ohio Partners for Affordable Energy, the Ohio Energy Group and the PUCO
staff.
In May 2007, the PUCO adopted the settlement agreement in its
entirety.
CSPCo
and
OPCo are involved in discussions with various stakeholders in Ohio about
potential legislation to address the period following the expiration of the
RSPs
on December 31, 2008. At this time, management is unable to predict whether
CSPCo and OPCo will transition to market pricing, as permitted by the current
Ohio restructuring legislation, extend their RSP rates, with or without
modification, or become subject to a legislative reinstatement of some form
of
cost-based regulation for their generation supply business on January 1,
2009
when the RSP period ends.
Customer
Choice Deferrals - Affecting CSPCo and OPCo
As
provided in the restructuring settlement agreement approved by the PUCO in
2000,
CSPCo and OPCo established regulatory assets for customer choice implementation
costs and related carrying costs in excess of $20 million each for recovery
in
the next general base rate filing which changes distribution rates after
December 31, 2007 for OPCo and December 31, 2008 for CSPCo. Pursuant to the
RSPs, recovery of these amounts for OPCo was further deferred until the next
base rate filing to change distribution rates after the end of the RSP period
of
December 31, 2008. Through March 31, 2007, CSPCo and OPCo incurred $50 million
and $51 million, respectively, of such costs and established regulatory assets
of $25 million each for such costs. CSPCo and OPCo have not recognized $5
million and $6 million, respectively, of equity carrying costs, which are
recognizable when collected. Management believes that the deferred customer
choice implementation costs were prudently incurred to implement customer
choice
in Ohio and are probable of recovery in future distribution rates.
IGCC
Plant - Affecting CSPCo and OPCo
In
March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of cost
recovery associated with the IGCC plant: Phase 1, recovery of $24 million
in
pre-construction costs during 2006; Phase 2, concurrent recovery of
construction-financing costs; and Phase 3, recovery or refund in distribution
rates of any difference between the market-based standard service offer price
for generation and the cost of operating and maintaining the plant, including
a
return on and return of the ultimate cost to construct the plant, originally
projected to be $1.2 billion, along with fuel, consumables and replacement
power
costs. The proposed recoveries in Phases 1 and 2 would be applied against
the 4%
limit on additional generation rate increases CSPCo and OPCo could request
under
their RSPs.
In
April
2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
1
of the cost recovery proposal. In June 2006, the PUCO issued another order
approving a tariff to recover Phase 1 pre-construction costs over no more
than a
twelve-month period effective July 1, 2006. Through March 31, 2007, CSPCo
and
OPCo each recorded pre-construction IGCC regulatory assets of $10 million
and
each recovered $9 million of those costs. CSPCo and OPCo will recover the
remaining amounts through June 30, 2007. The PUCO indicated that if CSPCo
and
OPCo have not commenced a continuous course of construction of the IGCC plant
within five years of the June 2006 PUCO order, all charges collected for
pre-construction costs, associated with items that may be utilized in IGCC
projects at other sites, must be refunded to Ohio ratepayers with interest.
The
PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings
are
held. A date for further rehearings has not been set.
In
August
2006, the Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy
Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order
in the IGCC proceeding. Management believes that the PUCO’s authorization to
begin collection of Phase 1 rates is lawful. Management, however, cannot
predict
the outcome of these appeals. If the PUCO’s order is found to be unlawful, CSPCo
and OPCo could be required to refund Phase I cost-related
recoveries.
Distribution
Reliability Plan - Affecting CSPCo and OPCo
In
January 2006, CSPCo and OPCo initiated a proceeding at the PUCO seeking a
new
distribution rate rider to fund enhanced distribution reliability programs.
In
the fourth quarter of 2006, as directed by the PUCO, CSPCo and OPCo filed
a
proposed enhanced reliability plan. The plan contemplated CSPCo and OPCo
recovering approximately $28 million and $43 million, respectively, in
additional distribution revenue during an eighteen month period beginning
July
2007. In January 2007, the OCC filed testimony, which argued that CSPCo and
OPCo
should be required to improve distribution service reliability with funds
from
their existing rates.
In
April
2007, CSPCo and OPCo filed a joint motion with the PUCO staff, the Ohio
Consumers’ Counsel, the Appalachian People’s Action Coalition, the Ohio Partners
for Affordable Energy and the Ohio Manufacturers Association to withdraw
the
proposed enhanced reliability plan.
Ormet
- Affecting CSPCo and OPCo
Effective
January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial
customer with a 520 MW load, under a PUCO encouraged settlement agreement.
The
settlement agreement between CSPCo and OPCo, Ormet, its employees’ union and
certain other interested parties was approved by the PUCO in November 2006.
The
settlement agreement provides for the recovery in 2007 and 2008 by CSPCo
and
OPCo of the difference between $43 per MWH to be paid by Ormet for power
and a
PUCO approved market price, if higher. The recovery will be accomplished
by the
amortization of a $57 million ($15 million for CSPCo and $42 million for
OPCo)
Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if
that
is not sufficient, an increase in RSP generation rates under the additional
4%
provision of the RSPs. The $43 per MWH price to be paid by Ormet for generation
services is above the industrial RSP generation tariff but below current
market
prices. In December 2006, CSPCo and OPCo submitted a market price of $47.69
per
MWH for 2007, which is pending PUCO approval. If the PUCO approves a lower
market price, it could have an adverse effect on results of operations and
cash
flows. If CSPCo and OPCo serve the Ormet load after 2008 without any special
provisions, they could experience incremental costs to acquire additional
capacity to meet their reserve requirements and/or forgo off-system sales
margins, which could have an adverse effect on future results of operations
and
cash flows.
Texas
Rate Matters
TCC
TEXAS RESTRUCTURING - Affecting TCC
Texas
District Court Appeal Proceedings
TCC recovered
its net recoverable stranded generation costs through a securitization
financing and is refunding its net other true-up items through a CTC rate
rider
credit under 2006 PUCT orders. TCC appealed the PUCT stranded costs true-up
orders seeking relief in both state and federal court on the grounds that
certain aspects of the orders are contrary to the Texas Restructuring
Legislation, PUCT rulemakings, federal law and fail to fully compensate TCC
for
its net stranded cost and other true-up items. The significant items appealed
by
TCC are:
·
|
The
PUCT ruling that TCC did not comply with the statute and PUCT rules
regarding the required auction of 15% of its Texas jurisdictional
installed capacity, which led to a significant disallowance of
capacity
auction true-up revenues,
|
·
|
The
PUCT ruling that TCC acted in a manner that was commercially unreasonable,
because it failed to determine a minimum price at which it would
reject
bids for the sale of its nuclear generating plant and it bundled
out of
the money gas units with the sale of its coal unit, which led to
the
disallowance of a significant portion of TCC’s net stranded generation
plant cost, and
|
·
|
The
two federal matters regarding the allocation of off-system sales
related
to fuel recoveries and the potential tax normalization violation.
See
“TCC
and TNC Deferred Fuel” and“TCC
Deferred Investment Tax Credits and Excess Deferred Federal Income
Taxes”
sections below.
|
Municipal
customers and other intervenors also appealed the PUCT true-up orders seeking
to
further reduce TCC’s true-up recoveries. On February 1, 2007, the Texas District
Court judge hearing the various appeals issued a letter containing his
preliminary determinations. He generally affirmed the PUCT’s April 4, 2006 final
true-up order for TCC with two significant exceptions. The judge determined
that
the PUCT erred when it determined TCC’s stranded cost using the sale of assets
method instead of the Excess Cost Over Market (ECOM) method to value TCC’s
nuclear plant. The judge also determined that the PUCT erred when it concluded
it was required to use the carrying cost rate specified in the true-up order.
However, the District Court did not rule that the carrying cost rate was
inappropriate. The judge directed that these matters should be remanded to
the
PUCT to determine the specific impact on TCC’s future true-up
revenues.
In
March
2007, the District Court judge reversed his earlier preliminary decision
and
concluded the sale of assets method to value TCC’s nuclear plant was
appropriate. The District Court judge did not reconsider his preliminary
ruling
that the PUCT erred when it concluded it was required to use the carrying
cost
rate specified in the true-up order. The District Court judge also determined
the PUCT improperly reduced TCC’s net stranded plant costs from the sale of its
generating units through the commercial unreasonableness disallowance, which
could have a materially favorable effect on TCC. Management cannot predict
the ultimate outcome of any future court appeals or any future remanded PUCT
proceeding. If the District Court’s carrying cost rate remand ruling is
ultimately upheld on appeal and remanded to the PUCT for reconsideration,
the
PUCT could either confirm the existing weighted average carrying cost (WACC)
rate or redetermine a new rate. If the PUCT changes the rate, it could result
in
a material adverse change to TCC’s recoverable carrying costs, results of
operations, cash flows and financial condition. TCC, the PUCT and
intervenors appealed the District Court ruling to the Court of Appeals.
Management cannot predict what actions, if any, the PUCT will take regarding
the
carrying costs.
If
TCC
ultimately succeeds in its appeals, it could have a favorable effect on future
results of operations, cash flows and financial condition. If municipal
customers and other intervenors succeed in their appeals, it could have a
substantial adverse effect on future results of operations, cash flows and
financial condition.
OTHER
TEXAS RESTRUCTURING MATTERS
TCC
Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes
-
Affecting TCC
In
TCC’s
2006 true-up and securitization orders, the PUCT reduced net regulatory assets
and the amount to be securitized by $51 million related to the present value
of
ADITC and by $10 million related to EDFIT associated with TCC’s generation
assets for a total reduction of $61 million.
TCC
filed
a request for a private letter ruling with the IRS in June 2005 regarding
the
permissibility under the IRS rules and regulations of the ADITC and EDFIT
reduction proposed by the PUCT. The IRS issued its private letter ruling
in May
2006, which stated that the PUCT’s flow-through to customers of the present
value of the ADITC and EDFIT benefits would result in a normalization violation.
To address the matter and avoid a normalization violation, the PUCT agreed
to
allow TCC to defer an amount of the CTC refund totaling $103 million ($61
million in present value of ADITC and EDFIT associated with TCC’s generation
assets plus $42 million of related carrying costs) pending resolution of
the
normalization issue. If it is ultimately determined that a refund to customers
through the true-up process of the ADITC and EDFIT, discussed above, is not
a
normalization violation, then TCC will be required to refund the $103 million,
plus additional carrying costs. However, if such refund of ADITC and EDFIT
is
ultimately determined to cause a normalization violation, TCC anticipates
it
will be permitted to retain the $61 million present value of ADITC and EDFIT
plus carrying costs, favorably impacting future results of
operations.
If
a
normalization violation occurs, it could result in TCC’s repayment to the IRS of
ADITC on all property, including transmission and distribution property,
which
approximates $104 million as of March 31, 2007, and a loss of TCC’s right to
claim accelerated tax depreciation in future tax returns. Tax counsel advised
management that a normalization violation should not occur until all remedies
under law have been exhausted and the tax benefits are returned to ratepayers
under a nonappealable order. Management intends to continue its efforts to
avoid
a normalization violation that would adversely affect future results of
operations and cash flows.
TCC
and TNC Deferred Fuel - Affecting TCC and TNC
The
TCC
deferred fuel over-recovery regulatory liability is a component of the other
true-up items net regulatory liability refunded through the CTC rate rider
credit. In 2002, TCC and TNC filed with the PUCT seeking to reconcile fuel
costs
and establish their final deferred fuel balances. In its final fuel
reconciliation orders, the PUCT ordered a reduction in TCC’s and TNC’s
recoverable fuel costs for, among other things, the reallocation of additional
AEP System off-system sales margins under a FERC-approved SIA. Both TCC and
TNC
appealed the PUCT’s rulings regarding a number of issues in the fuel orders in
state court and challenged the jurisdiction of the PUCT over the allocation
of
off-system sales margin allocations in the federal court. Intervenors also
appealed the PUCT’s rulings in state court.
In
2006,
the Federal District Court issued orders precluding the PUCT from enforcing
the
off-system sales reallocation portion of its ruling in the final TNC and
TCC
fuel reconciliation proceedings. The Federal court ruled, in both cases,
that
the FERC, not the PUCT, has jurisdiction over the allocation. The PUCT appealed
both Federal District Court decisions to the United States Court of Appeals.
In
TNC’s case, the Court of Appeals affirmed the District Court’s decision. The
PUCT has indicated they will appeal this ruling to the United States Supreme
Court. TCC has filed a Motion for Summary Affirmance based on the outcome
of the
TNC appeal. For TCC, the PUCT has conceded the issue concerning the allocation
of off-system sales margins to AEP West companies under the SIA as governed
by
the TNC case. However, the PUCT continues to challenge the allocation of
those
margins among AEP West companies under the CSW Operating Agreement. If the
PUCT’s appeals are ultimately unsuccessful, TCC and TNC could record income of
$16 million and $8 million, respectively, related to the reversal of the
previously recorded fuel over-recovery regulatory liabilities.
If
the
PUCT is unsuccessful in the federal court system, it or another interested
party
may file a complaint at the FERC to address the allocation issue. If a complaint
at the FERC results in the PUCT’s decisions being adopted by the FERC, there
could be an adverse effect on results of operations and cash flows. An
unfavorable FERC ruling may result in a retroactive reallocation of off-system
sales margins from AEP East companies to AEP West companies under the then
existing SIA allocation method. If the adjustments were applied retroactively,
the AEP East companies may be unable to recover the amounts reallocated to
the
West companies from their customers due to past frozen rates, past inactive
fuel
clauses and fuel clauses that do not include off-system sales credits. Although
management cannot predict the ultimate outcome of this federal litigation,
management believes that its allocations were in accordance with the then
existing FERC-approved SIA and that it should not have to allocate additional
off-system sales margins to the West companies including TCC and TNC.
In
January 2007, TCC began refunding as part of the CTC rate rider credit described
above, $149 million of its $165 million over-recovered deferred fuel regulatory
liability. The remaining $16 million refund related to the favorable Federal
District Court order has been deferred pending the outcome of the federal
court
appeal and would be subject to refund only upon a successful appeal by the
PUCT.
Excess
Earnings - Affecting TCC
In
2005,
the Texas Court of Appeals issued a decision finding the PUCT’s prior order from
the unbundled cost of service case requiring TCC to refund excess earnings
prior
to and outside of the true-up process was unlawful under the Texas Restructuring
Legislation. TCC refunded $55 million of excess earnings, including interest,
of
which $30 million went to the affiliated REP. In November 2005, the PUCT
filed a
petition for review with the Supreme Court of Texas seeking reversal of the
Texas Court of Appeals’ decision. The Supreme Court of Texas requested briefing,
which has been provided, but it has not decided whether it will hear the
case.
If
the
Court of Appeals decision is upheld and the refund mechanism is found to
be
unlawful, the impact on TCC would then depend on: (a) how and if TCC is ordered
by the PUCT to refund the excess earnings through the true-up process to
ultimate customers and (b) whether TCC will be able to recover the amounts
previously refunded to the REPs including the REP TCC sold to Centrica.
Management
is unable to predict the ultimate outcome of this litigation and its effect
on
future results of operations and cash flows.
OTHER
TEXAS RATE MATTERS
TCC
and TNC Energy Delivery Base Rate Filings - Affecting TCC and
TNC
TCC
and
TNC each filed a base rate case seeking to increase transmission and
distribution energy delivery services (wires) base rates in Texas. TCC and
TNC
requested $81 million and $25 million in annual increases, respectively.
Both
requests include a return on common equity of 11.25% and the impact of the
expiration of the CSW merger savings rate credits. In March 2007, various
intervenors and the PUCT staff filed their recommendations. Though the
recommendations varied, the range of recommended increase was $8 million
to $30
million for TCC and $1 million to $14 million for TNC. The recommended return
on
common equity ranged from 9.00% to 9.75%. In April 2007, TCC and TNC filed
rebuttal testimony reducing the requested annual increases to $70 million
for
TCC and $22 million for TNC including a reduced requested return on common
equity of 10.75%. Hearings began in April 2007 and are scheduled to be concluded
in May 2007. Management
expects the new base wires rates to become effective, subject to refund,
in the
second quarter of 2007 with a decision from the PUCT expected in the third
quarter of 2007. Management
is unable to predict the ultimate effect of this filing on future results
of
operations, cash flows and financial condition.
SWEPCo
Fuel Reconciliation - Texas - Affecting SWEPCo
In
June
2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its
Texas
retail operations. SWEPCo sought, in the proceedings, to include
under-recoveries related to the reconciliation period of $50 million. In
January
2007, intervenors filed testimony recommending that SWEPCo’s reconcilable fuel
costs be reduced. The intervenor recommendations ranged from a $10 million
to
$28 million reduction. In February 2007, the PUCT staff filed testimony
recommending that SWEPCo’s reconcilable fuel costs be reduced by $10 million.
SWEPCo does not agree with the intervenor’s or staff’s recommendations and filed
rebuttal testimony in February 2007. Hearings have been held and briefs have
been filed. Results of operations could be adversely affected by $28 million
plus carrying costs if the PUCT adopts all of the intervenor and staff
recommendations. Management is unable to predict the outcome of this proceeding
or its effect on future results of operations and cash flows.
Virginia
Rate Matters
Virginia
Restructuring - Affecting APCo
In
April
2004, Virginia enacted legislation that extended the transition period for
electricity restructuring, including capped rates, through December 31, 2010.
The legislation provides APCo with specified cost recovery opportunities
during
the capped rate period, including two optional bundled general base rate
changes
and an opportunity for timely recovery, through a separate rate mechanism,
of
certain incremental environmental and reliability costs incurred on and after
July 1, 2004. Under the restructuring law, APCo continues to have an active
fuel
clause recovery mechanism in Virginia and continues to practice deferred
fuel
accounting. Also, under the restructuring law, APCo defers incremental
environmental generation costs and incremental transmission and distribution
reliability costs for future recovery, to the extent such costs are not being
recovered when incurred, and amortizes a portion of such deferrals commensurate
with recovery.
In
April
2007, the Virginia legislature adopted a comprehensive law providing for
the
re-regulation of electric utilities’ generation/supply rates. The amendments
shorten the transition period by two years (from 2010 to 2008) after which
rates
for retail generation/supply will return to a form of cost-based regulation.
The
legislation provides for, among other things, biennial rate reviews beginning
in
2009, rate adjustment clauses for the recovery of the costs of (a) transmission
services and new transmission investment, (b) Demand Side Management, load
management, and energy efficiency programs, (c) renewable energy programs,
and
(d) environmental retrofit and new generation investments, significant return
on
equity enhancements for large investments in new generation and, subject
to
Virginia SCC approval, certain environmental retrofits, and a floor on the
allowed return on equity based on the average earned return on equities’ of
regional vertically integrated electric utilities. Effective July 1, 2007,
the
amendments allow utilities to retain a minimum of 25% of the margins from
off-system sales with the remaining margins from such sales credited against
fuel factor expenses. The legislation also allows APCo to continue to defer
and
recover incremental environmental and reliability costs incurred through
December 31, 2008. APCo expects this new form of cost-based ratemaking should
improve its annual return on equity and cash flow from operations when new
ratemaking begins in 2009. However, with the return of cost-based regulation,
APCo’s generation business will again meet the criteria for application of
regulatory accounting principles under SFAS 71. Results of operations and
financial condition could be adversely affected when APCo is required to
re-establish certain net regulatory liabilities applicable to its
generation/supply business. The timing and earnings effect from such
reapplication of SFAS 71 regulatory accounting for APCo’s Virginia
generation/supply business are uncertain at this time.
APCo
Virginia Base Rate Case - Affecting APCo
In
May
2006, APCo filed a request with the Virginia SCC seeking an increase in base
rates of $225 million to recover increasing costs including the cost of its
investment in environmental equipment and a return on equity of 11.5%. In
addition, APCo requested to move off-system sales margins, currently credited
to
customers through base rates, to the fuel factor where they can be trued-up
to
actual. APCo also proposed to share the off-system sales margins with customers
with 40% going to reduce rates and 60% being retained by APCo. This proposed
off-system sales fuel rate credit, which is estimated to be $27 million,
partially offsets the $225 million requested increase in base rates for a
net
increase in base rate revenues of $198 million. The major components of the
$225
million base rate request include $73 million for the impact of removing
off-system sales margins from the rate year ending September 30, 2007, $60
million mainly due to projected net environmental plant additions through
September 30, 2007 and $48 million for return on equity.
In
May
2006, the Virginia SCC issued an order, consistent with Virginia law, placing
the net requested base rate increase of $198 million into effect on October
2,
2006, subject to refund. The $198 million base rate increase being collected,
subject to refund, includes recovery of incremental environmental
compliance and transmission and distribution system reliability (E&R)
costs
projected to be incurred during the rate year beginning October 2006. These
incremental E&R costs can be deferred and recovered through the E&R
surcharge mechanism if not recovered through this base rate request. In October
2006, the Virginia SCC staff filed its direct testimony recommending a base
rate
increase of $13 million with a return on equity of 9.9% and no off-system
sales
margin sharing. Other intervenors have recommended base rate increases ranging
from $42 million to $112 million. APCo filed rebuttal testimony in November
2006. Hearings were held in December 2006.
In
March
2007, the Hearing Examiner (HE) issued a report recommending a $76 million
increase in APCo’s base rates and $45 million credit to the fuel factor for
off-system sales margins. The HE’s recommendations include a return on equity of
10.1% which would reduce APCo’s revenue requirement by approximately $23
million. The HE also recommended limiting forward looking ratemaking adjustments
to June 30, 2006 as opposed to September 30, 2007, which would reduce APCo’s
revenue requirement by approximately $72 million, of which approximately
$60
million relates to incremental E&R costs that can be deferred for future
recovery through the E&R surcharge mechanism. The HE further proposed to
share the off-system sales margins using the twelve months ended June 30,
2006
of $101 million with 50% reducing base rates, 45% reducing fuel rates and
5%
retained by APCo to determine the revenue requirement. APCo’s proposal did not
reduce base rates for off-system sales margins, but reduced fuel rates
approximately $27 million for off-system sales margins. APCo expects a
final order to be issued during 2007.
APCo
is
providing for a possible refund of revenues collected subject to refund
consistent with the HE recommendations. Management is unable to predict the
ultimate effect of this filing on future results of operations, cash flows
and
financial condition.
West
Virginia Rate Matters
APCo
Expanded Net Energy Cost (ENEC) Filing - Affecting
APCo
In
April
2007, the WVPSC issued an order establishing an investigation and hearing
of
APCo’s and WPCo’s 2007 ENEC joint compliance filing. The ENEC is an
expanded form of fuel clause mechanism, which includes all energy-related
costs
including fuel, purchased power expenses, off-system sales credits and other
energy/transmission items. In the March 2007 ENEC joint compliance filing,
APCo filed for an increase of approximately $91 million including a $65 million
increase in ENEC and a $26 million increase in construction surcharges to
become
effective July 1, 2007. A hearing on the joint compliance filing is scheduled
for May 2007.
APCo
IGCC - Affecting APCo
In
January 2006, APCo filed a petition with the WVPSC requesting its approval
of a
Certificate of Public Convenience and Necessity to construct a 629 MW IGCC
plant
adjacent to APCo’s existing Mountaineer Generating Station in Mason County, WV.
In January 2007, at APCo’s request, the WVPSC issued an order delaying the
Commission’s deadline for issuing an order on the certificate to December 2007.
Through March 31, 2007, APCo deferred pre-construction IGCC costs totaling
$10
million. If the plant is not built and these costs are not recoverable, future
results of operations and cash flows would be adversely affected.
Indiana
Rate Matters
I&M
Depreciation Study Filing - Affecting I&M
In
February 2007, I&M filed a request with the IURC for approval of revised
book depreciation rates effective January 1, 2007. The filing included a
settlement agreement entered into with the Indiana Office of the Utility
Consumer Counsel that would provide direct benefits to I&M's customers if
new depreciation rates are approved by the IURC. The direct benefits would
include a $5 million credit to fuel costs and an approximate $8 million smart
metering pilot program. In addition, if the agreement is approved, I&M would
initiate a general rate proceeding on or before July 1, 2007 and initiate
two
studies, one to investigate a general smart metering program and the other
to
study the market viability of demand side management programs. Based on the
depreciation study included in the filing, I&M recommended a decrease in
pretax annual depreciation expense on an Indiana jurisdictional basis of
approximately $69 million reflecting an NRC-approved 20-year extension of
the
Cook Plant licenses for Units 1 and 2 and an extension of the service life
of
the Tanners Creek coal-fired generating units. This petition was not a request
for a change in customers’ electric service rates. As proposed, the book
depreciation reduction would increase earnings but would not impact cash
flows
until rates are revised. The IURC held a public hearing in April 2007. I&M
requested expeditious review and approval of its filing, but management cannot
predict the outcome of the request or the timing of any approved depreciation
reduction. If approved as filed, pretax earnings would increase by $64 million
in 2007.
Kentucky
Rate Matters
KPCo
Environmental Surcharge Filing - Affecting KPCo
In
July
2006, KPCo filed for
approval of an
amended environmental compliance plan and revised tariff to implement an
adjusted environmental surcharge. KPCo
estimates the amended environmental compliance plan and revised tariff would
increase revenues over 2006 levels by approximately $2 million in 2007 and
$6
million in 2008 for a total of $8 million of additional revenue at current
cost
projections. In January 2007, the KPSC issued an order approving KPCo’s proposed
plan and surcharge. Future recovery is based upon actual environmental costs
and
is subject to periodic review and approval of those actual costs by the
KPSC.
In
November 2006, the Kentucky Attorney General and the Kentucky Industrial
Utility
Consumers (KIUC) filed an appeal with the Kentucky Court of Appeals of the
Franklin Circuit Court’s 2006 order upholding the KPSC’s 2005 Environmental
Surcharge order. In its order, the KPSC approved KPCo’s recovery of its
environmental costs at its Big Sandy Plant and its share of environmental
costs
incurred as a result of the AEP Power Pool capacity settlement. The KPSC
has
allowed KPCo to recover these FERC-approved allocated costs, via the
environmental surcharge, since the KPSC’s first environmental surcharge order in
1997. KPCo presently recovers $7 million a year in environmental surcharge
revenues.
In
March
2007, the KPSC issued an order, at the request of the Kentucky Attorney General,
stating the environmental surcharge collections authorized in the January
2007
order that are associated with out-of-state generating facilities should
be
collected over the six months beginning March 2007, subject to refund, pending
the outcome of the court of appeals process. At this time, management is
unable
to predict the outcome of this proceeding and its effect on KPCo’s current
environmental surcharge revenues or on the January 2007 KPSC order increasing
KPCo’s environmental rates.
Oklahoma
Rate Matters
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
eighteen months. In August 2003, the OCC staff filed testimony recommending
PSO
recover $42 million of the reallocated purchased power costs over three years
and PSO reduced its regulatory asset deferral by $2 million. The OCC
subsequently expanded the case to include a full prudence review of PSO’s 2001
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
the
proposed reallocation of off-system sales margins of $27 million to $37 million
and with $9 million attributed to wholesale customers, which they claimed
had
not been refunded. In February 2006, the OCC staff filed a report concluding
that the $9 million of reallocated purchased power costs assigned to wholesale
customers had been refunded, thus removing that issue from its
recommendation.
In
2004,
an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO
deviated from the FERC-approved allocation methodology and held that any
such
complaints should be addressed at the FERC. The OCC has not ruled on appeals
by
intervenors of the ALJ’s finding. The United States District Court for the
Western District of Texas issued orders in September 2005 regarding a TNC
fuel
proceeding and in August 2006 regarding a TCC fuel proceeding, preempting
the
PUCT from reallocating off-system sales margins between the AEP East companies
and AEP West companies. The federal court agreed that the FERC has sole
jurisdiction over that allocation. The PUCT appealed the ruling. The United
States Court of Appeals for the Fifth Circuit, issued a decision in December
2006 regarding the TNC fuel proceeding that affirmed the United States District
Court ruling.
PSO
does
not agree with the intervenors’ and the OCC staff’s recommendations and
proposals other than the staff’s original recommendation that PSO be allowed to
recover the $42 million over three years and will defend its right to recover
its under-recovered fuel balance. Management believes that if the position
taken
by the federal courts in the Texas proceeding is applied to PSO’s case, then the
OCC should 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 could file a complaint at the FERC alleging
the allocation of off-system sales margins to 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. However, to date, there has been no claim
asserted at the FERC that AEP deviated from the approved allocation
methodologies, but even if one were asserted, management believes that it
would
not prevail.
In
June
2005, the OCC issued an order directing its staff to conduct a prudence review
of PSO’s fuel and purchased power practices for the year 2003. The OCC staff
filed testimony finding no disallowances in the test year data. The Attorney
General of Oklahoma filed testimony stating that they could not determine
if
PSO’s gas procurement activities were prudent, but did not include a recommended
disallowance. However, an intervenor filed testimony in June 2006 proposing
the
disallowance of $22 million in fuel costs based on a historical review of
potential hedging opportunities that he alleges existed during the year.
A
hearing was held in August 2006 and management expects a recommendation from
the
ALJ in 2007.
In
February 2006, a law was enacted requiring the OCC to conduct prudence reviews
on all generation and fuel procurement processes, practices and costs on
either
a two or three-year cycle depending on the number of customers served. PSO
is
subject to the required biennial reviews. In compliance with an OCC order,
PSO
is required to file its testimony by June 15, 2007. This proceeding will
cover
the year 2005.
Management
cannot predict the outcome of the pending fuel and purchased power reviews
or
planned future reviews, but believes that PSO’s fuel and purchased power
procurement practices and costs are prudent and properly incurred. If the
OCC
disagrees and disallows fuel or purchased power costs including the unrecovered
2002 reallocation of such costs incurred by PSO, it would have an adverse
effect
on future results of operations and cash flows.
PSO
Rate Filing - Affecting PSO
In
November 2006, PSO filed a request to increase base rates $50 million for
Oklahoma jurisdictional customers with a proposed effective date in the second
quarter of 2007. PSO sought a return on equity of 11.75%. PSO also proposed
a
formula rate plan that, if approved as filed, will permit PSO to defer any
unrecovered costs as a result of a revenue deficiency that exceeds 50 basis
points of the allowed return on equity for recovery within twelve months
beginning six months after the test year. The formula would enable PSO to
recover on a timely basis the cost of its new generation, transmission and
distribution construction (including carrying costs during construction),
provide the opportunity to achieve the approved return on equity and avoid
recording a significant AFUDC that would have been recorded during the
construction time period.
In
March
2007, the OCC staff and various intervenors filed testimony. The recommendations
were base rate reductions that ranged from $18 million to $52 million. The
recommended returns on equity ranged from 9.25% to 10.09%. These recommendations
included reductions in depreciation expense of approximately $25 million,
which
has no earnings impact. The OCC staff filed testimony supporting a formula
rate
plan, generally similar to the one proposed by PSO. In April 2007, PSO filed
rebuttal testimony regarding various issues raised by the OCC Staff and the
intervenors. As a result of rebuttal testimony, PSO reduced its base rate
request by $2 million. Hearings commenced on May 1, 2007.
Management
is unable to predict the outcome of these proceedings, however, if rates
are not
increased in an amount sufficient to recover expected unavoidable cost increases
future results of operations, cash flows and possibly financial condition
could
be adversely affected.
PSO
Lawton and Peaking Generation Settlement Agreement - Affecting
PSO
On
November 26, 2003, pursuant to an application by Lawton Cogeneration, L.L.C.
(Lawton) seeking approval of a Power Supply Agreement (the Agreement) with
PSO
and associated avoided cost payments, the OCC issued an order approving the
Agreement and setting the avoided costs. The order did not address recovery
by
PSO of the resultant purchased power costs.
In
December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme
Court (the Court). In the appeal, PSO maintained that the OCC exceeded its
authority under state and federal laws to require PSO to enter into the
Agreement. The Court issued a decision on June 21, 2005, affirming portions
of
the OCC’s order and remanding certain provisions. The Court affirmed the OCC’s
finding that Lawton established a legally enforceable obligation and ruled
that
it was within the OCC’s discretion to award a 20-year contract and to base the
capacity payment on a peaking unit. The Court directed the OCC to revisit
its
determination of PSO’s avoided energy cost. Hearings were held on the remanded
issues in April and May 2006.
In
April
2007, all parties in the case filed a settlement agreement with the OCC
resolving all issues. The OCC approved the settlement agreement in April
2007.
The settlement agreement provides for a purchase fee of $35 million to be
paid
by PSO to Lawton and for Lawton to provide, at PSO’s direction, all rights to
the Lawton Cogeneration Facility for permits, options and engineering studies.
PSO will record the purchase fee as a regulatory asset and recover it through
a
rider over a three-year period with a carrying charge of 8.25% beginning
in
September 2007. In addition, PSO will recover through a rider, subject to
a $135
million cost cap, all of the traditional costs associated with plant in
service of its new peaking units to be located at the Southwestern Station
and
Riverside Station at the time these units are placed in service. PSO may
request
approval from the OCC for recovery of costs exceeding the cost cap if special
circumstances occurred necessitating a higher level of costs. Such costs
will
continue to be recovered through the rider until cost recovery occurs through
base rates or formula rates in a subsequent proceeding. PSO must file a rate
case within eighteen months of the beginning of recovery through the rider
unless the OCC approves a formula-based rate mechanism that provides for
recovery of the peaking units. Once the cost recovery for the new peaking
units
begins in mid-2008, PSO expects annual revenues of an estimated $36 million
related to cost recovery of the peaking units and the purchase fee. This
settlement agreement was supported by the OCC Staff, the Attorney General,
the
Oklahoma Industrial Energy Consumers and Lawton Cogeneration,
L.L.C.
Louisiana
Rate Matters
SWEPCo
Louisiana Compliance Filing - Affecting SWEPCo
In
October 2002, SWEPCo filed with the LPSC detailed financial information
typically utilized in a revenue requirement filing, including a jurisdictional
cost of service. This filing was required by the LPSC as a result of its
order
approving the merger between AEP and CSW. Due to multiple delays, in April
2006,
the LPSC and SWEPCo agreed to update the financial information based on a
2005
test year. SWEPCo filed updated financial review schedules in May 2006 showing
a
return on equity of 9.44% compared to the previously authorized return on
equity
of 11.1%.
In
July
2006, the LPSC staff’s consultants filed direct testimony recommending a base
rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana
jurisdiction customers, based on a proposed 10% return on equity. The
recommended reduction range is subject to SWEPCo validating certain ongoing
operations and maintenance expense levels. SWEPCo filed rebuttal testimony
in
October 2006 strongly refuting the consultants’ recommendations. In December
2006, the LPSC staff’s consultants filed reply testimony asserting that SWEPCo’s
Louisiana base rates are excessive by $17 million which includes a proposed
return on equity of 9.8%. SWEPCo filed rebuttal testimony in January 2007.
A
decision is not expected until mid or late 2007. At this time, management
is
unable to predict the outcome of this proceeding. If a rate reduction is
ultimately ordered, it would adversely impact future results of operations,
cash
flows and possibly financial condition.
FERC
Rate Matters
Transmission
Rate Proceedings at the FERC - Affecting APCo, CSPCo, I&M, KPCo and OPCo
The
FERC PJM Regional Transmission Rate Proceeding
At
AEP’s
urging, the FERC instituted an investigation of PJM’s zonal rate regime,
indicating that the present rate regime may need to be replaced through
establishment of regional rates that would compensate AEP and other transmission
owners for the regional transmission facilities they provide to PJM, which
provides service for the benefit of customers throughout PJM. In September
2005,
AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional
transmission rate design proposal with the FERC. This filing proposes and
supports a new PJM rate regime generally referred to as
Highway/Byway.
Parties
to the regional rate proceeding proposed the following rate
regimes:
·
|
AEP/AP
proposed a Highway/Byway rate design in which:
|
|
·
|
The
cost of all transmission facilities in the PJM region operated
at 345 kV
or higher would be included in a “Highway” rate that all load serving
entities (LSEs) would pay based on peak demand. The AEP/AP proposal
would
produce about $125 million in additional revenues per year for
AEP from
users in other zones of PJM.
|
|
·
|
The
cost of transmission facilities operating at lower voltages would
be
collected in the zones where those costs are presently charged
under PJM’s
existing rate design.
|
·
|
Two
other utilities, Baltimore Gas & Electric Company (BG&E) and Old
Dominion Electric Cooperative (ODEC), proposed a Highway/Byway
rate that
includes transmission facilities above 200 kV, which would produce
lower
revenues for AEP than the AEP/AP proposal.
|
·
|
In
another competing Highway/Byway proposal, a group of LSEs proposed
rates
that would include existing 500 kV and higher voltage facilities
and new
facilities above 200 kV in the Highway rate, which would produce
considerably lower revenues for AEP than the AEP/AP proposal.
|
·
|
In
January 2006, the FERC staff issued testimony and exhibits supporting
a
PJM-wide flat rate or “Postage Stamp” type of rate design that would
include all transmission facilities, which would produce higher
transmission revenues for AEP than the AEP/AP
proposal.
|
All
of
these proposals were challenged by a majority of other transmission owners
in
the PJM region, who favor continuation of the existing PJM rate design which
provides AEP with no compensation for through and out traffic on its east
zone
transmission system. Hearings were held in April 2006 and the ALJ issued
an
initial decision in July 2006. The ALJ found the existing PJM zonal rate
design
to be unjust and determined that it should be replaced. The ALJ found that
the
Highway/Byway rates proposed by AEP/AP and BG&E/ODEC and the Postage Stamp
rate proposed by the FERC staff to be just and reasonable alternatives. The
ALJ
also found FERC staff’s proposed Postage Stamp rate to be just and reasonable
and recommended that it be adopted. The ALJ also found that the effective
date
of the rate change should be April 1, 2006 to coincide with SECA rate
elimination. Because the Postage Stamp rate was found to produce greater
cost
shifts than other proposals, the judge also recommended that the design be
phased-in. Without a phase-in, the Postage Stamp method would produce more
revenue for AEP than the AEP/AP proposal. The phase-in of Postage Stamp rates
would delay the full impact of that result until about 2012.
AEP
filed
briefs noting exceptions to the initial decision and replies to the exceptions
of other parties. AEP argued that a phase-in should not be required.
Nevertheless, AEP argued that if the FERC adopts the Postage Stamp rate and
a
phase-in plan, the revenue collections curtailed by the phase-in should be
deferred and paid later with interest.
During
2006, the AEP East companies sought to increase retail rates in most of their
states to recover lost T&O and SECA revenues. The status of such state
retail rate proceedings is as follows:
·
|
In
Kentucky, KPCo settled a rate case, which provided for the recovery
of its
share of the transmission revenue reduction in new rates effective
March
30, 2006.
|
·
|
In
Ohio, CSPCo and OPCo recover their FERC-approved OATT that reflects
their
share of the full transmission revenue requirement retroactive
to April 1,
2006 under a May 2006 PUCO order.
|
·
|
In
West Virginia, APCo settled a rate case, which provided for the
recovery
of its share of the T&O/SECA transmission revenue reduction beginning
July 28, 2006.
|
·
|
In
Virginia, APCo filed a request for revised rates, which includes
recovery
of its share of the T&O/SECA transmission revenue reduction starting
October 2, 2006, subject to refund.
|
·
|
In
Indiana, I&M is precluded by a rate cap from raising its rates until
July 1, 2007.
|
·
|
In
Michigan, I&M has not filed to seek recovery of the lost transmission
revenues.
|
In
April
2007, the FERC issued an order reversing the ALJ decision. The FERC ruled
that
the current PJM rate design is just and reasonable. The FERC further ruled
that
the cost of new facilities of 500 kV and above would be shared among all
PJM
participants. As a result of this order, the AEP East companies retail customers
will be asked to bear the full cost of the existing AEP east transmission
zone
facilities. However, the AEP East companies customers will also be charged
a
share of the cost of new 500 kV and higher voltage transmission facilities
built
in PJM, of which the vast majority for the foreseeable future will not be
needed
by their customers, but will bolster service and reduce costs in other zones
of
PJM. The AEP East companies will need to obtain regulatory approvals for
recovery of any costs of new facilities that are assigned to them as a result
of
this order, if upheld. AEP will request rehearing of this order. Management
cannot estimate at this time what effect, if any, this order will have on
their
future construction of new east transmission facilities, results of operations,
cash flows and financial condition.
The
AEP
East companies presently recover from retail customers approximately 85%
of the
reduction in transmission revenues of $128 million a year. Future results
of
operations, cash flows and financial condition will continue to be adversely
affected in Indiana and Michigan until these lost transmission revenues are
recovered in retail rates.
SECA
Revenue Subject to Refund
The
AEP
East companies ceased collecting through-and-out transmission service (T&O)
revenues in accordance with FERC orders, and collected SECA rates to mitigate
the loss of T&O revenues from December 1, 2004 through March 31, 2006, when
SECA rates expired. Intervenors objected to the SECA rates, raising various
issues. As a result, the FERC set SECA rate issues for hearing and ordered
that
the SECA rate revenues be collected, subject to refund or surcharge. The
AEP
East companies paid SECA rates to other utilities at considerably lesser
amounts
than collected. If a refund is ordered, the AEP East companies would also
receive refunds related to the SECA rates they paid to third parties. The
AEP
East companies recognized gross SECA revenues as follows:
|
|
Year
Ended December 31,
|
|
|
|
2006
(a)
|
|
2005
|
|
2004
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
13.4
|
|
$
|
52.4
|
|
$
|
4.4
|
|
CSPCo
|
|
|
7.9
|
|
|
28.4
|
|
|
2.5
|
|
I&M
|
|
|
8.1
|
|
|
30.4
|
|
|
2.8
|
|
KPCo
|
|
|
3.2
|
|
|
12.4
|
|
|
1.0
|
|
OPCo
|
|
|
10.4
|
|
|
39.4
|
|
|
3.5
|
|
(a)
|
Represents
revenues through March 31, 2006, when SECA rates expired, and excludes
all
provisions for refund.
|
Approximately
$19 million of these recorded SECA revenues billed by PJM were never collected.
The AEP East companies filed a motion with the FERC to force payment of these
uncollected SECA billings.
In
August
2006, the ALJ issued an initial decision, finding that the rate design for
the
recovery of SECA charges was flawed and that a large portion of the “lost
revenues” reflected in the SECA rates was not recoverable. The ALJ found that
the SECA rates charged were unfair, unjust and discriminatory and that new
compliance filings and refunds should be made. The ALJ also found that the
unpaid SECA rates must be paid in the recommended reduced amount.
Since
the
implementation of SECA rates in December 2004, the AEP East companies recorded
approximately $220 million of gross SECA revenues, subject to refund. The
AEP
East companies reached settlements with certain customers related to
approximately $70 million of such revenues. The unsettled gross SECA revenues
total approximately $150 million. If the ALJ’s initial decision is upheld in its
entirety, it would disallow $126 million of the AEP East companies’ unsettled
gross SECA revenues.
The
AEP
East companies provided for net refunds as shown in the following
table:
|
|
Year
Ended December 31,
|
|
|
|
2006
|
|
2005
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
11.0
|
|
$
|
1.0
|
|
CSPCo
|
|
|
6.1
|
|
|
0.6
|
|
I&M
|
|
|
6.4
|
|
|
0.6
|
|
KPCo
|
|
|
2.6
|
|
|
0.2
|
|
OPCo
|
|
|
8.3
|
|
|
0.8
|
|
In
September 2006, AEP, together with Exelon and DP&L, filed an extensive
post-hearing brief and reply brief noting exceptions to the ALJ’s initial
decision and asking the FERC to reverse the decision in large part. Management
believes that the FERC should reject the initial decision because it is contrary
to prior related FERC decisions, which are presently subject to rehearing.
Furthermore, management believes the ALJ’s findings on key issues are largely
without merit. Although management believes they have meritorious arguments,
management cannot predict the ultimate outcome of any future FERC proceedings
or
court appeals. If
the
FERC adopts the ALJ’s decision, it will have an adverse effect on future results
of operations and cash flows.
4. COMMITMENTS,
GUARANTEES AND CONTINGENCIES
The
Registrant Subsidiaries are subject to certain claims and legal actions arising
in their ordinary course of business. In addition, their business activities
are
subject to extensive governmental regulation related to public health and
the
environment. The ultimate outcome of such pending or potential litigation
cannot
be predicted. For current proceedings not specifically discussed below,
management does not anticipate that the liabilities, if any, arising from
such
proceedings would have a material adverse effect on the financial statements.
The Commitments, Guarantees and Contingencies note within the 2006 Annual
Report
should be read in conjunction with this report.
GUARANTEES
There
are
certain immaterial liabilities recorded for guarantees in accordance with
FASB
Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is
no collateral held in relation to any guarantees. In the event any guarantee
is
drawn, there is no recourse to third parties unless specified
below.
Letters
of Credit
Certain
Registrant Subsidiaries enter into standby letters of credit (LOCs) with
third
parties. These LOCs cover items such as insurance programs, security deposits,
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,
2007, the maximum future payments of the LOCs include $1 million and $4 million
for I&M and SWEPCo, respectively, with maturities ranging from June 2007 to
March 2008.
Guarantees
of Third-Party Obligations
SWEPCo
As
part
of the process to receive a renewal of a Texas Railroad Commission permit
for
lignite mining, SWEPCo provides guarantees of mine reclamation in the amount
of
approximately $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 Mining Company (Sabine),
an
entity consolidated under FIN 46. This guarantee ends upon depletion of reserves
and completion of final reclamation. Based on the latest study, it is estimated
the reserves will be depleted in 2029 with final reclamation completed by
2036,
at an estimated cost of approximately $39 million. As of March 31, 2007,
SWEPCo
collected approximately $30 million through a rider for final mine closure
costs, which is recorded in Deferred Credits and Other on SWEPCo’s Condensed
Consolidated Balance Sheets.
Sabine
charges SWEPCo, its only customer, all its costs. SWEPCo passes these costs
through its fuel clause.
Indemnifications
and Other Guarantees
Contracts
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, 2007, Registrant Subsidiaries entered into sale agreements
including indemnifications with a maximum exposure that was not significant
for
any individual Registrant Subsidiary except TCC. TCC sale agreements include
indemnifications with a maximum exposure of $456 million related to the sale
price of its generation assets. See “Texas Plants - South Texas Project”, “Texas
Plants - TCC Generation Assets” and “Texas Plants - Oklaunion Power Station”
sections of Note 8 of the 2006 Annual Report. There are no material liabilities
recorded for any indemnifications.
AEP
East
companies, PSO and SWEPCo are jointly and severally liable for activity
conducted by AEPSC on behalf of AEP East companies, PSO and SWEPCo related
to
power purchase and sale activity conducted pursuant to the SIA.
Master
Operating Lease
Certain
Registrant Subsidiaries lease certain equipment under a master operating
lease.
Under the lease agreement, the lessor is guaranteed to receive up to 87%
of the
unamortized balance of the equipment at the end of the lease term. If the
fair
market value of the leased equipment is below the unamortized balance at
the end
of the lease term, the subsidiary has committed to pay the difference between
the fair market value and the unamortized balance, with the total guarantee
not
to exceed 87% of the unamortized balance. At March 31, 2007, the maximum
potential loss by subsidiary for these lease agreements assuming the fair
market
value of the equipment is zero at the end of the lease term is as
follows:
|
|
Maximum
Potential Loss
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
7
|
|
CSPCo
|
|
|
4
|
|
I&M
|
|
|
5
|
|
KPCo
|
|
|
2
|
|
OPCo
|
|
|
7
|
|
PSO
|
|
|
5
|
|
SWEPCo
|
|
|
6
|
|
TCC
|
|
|
6
|
|
TNC
|
|
|
3
|
|
CONTINGENCIES
Federal
EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and
OPCo
The
Federal EPA, certain special interest groups and a number of states allege
that
APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the
Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric
Company, Ohio Edison Company, Southern Indiana Gas & Electric Company,
Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company
and Duke Energy, modified certain units at coal-fired generating plants in
violation of the NSR requirements of the CAA. The Federal EPA filed its
complaints against AEP subsidiaries in U.S. District Court for the Southern
District of Ohio. The alleged modifications occurred at our generating units
over a twenty-year period. A bench trial on the liability issues was held
during
July 2005. In June 2006, the judge stayed the liability decision pending
the
issuance of a decision by the U.S. Supreme Court in the Duke Energy
case.
Under
the
CAA, if a plant undertakes a major modification that results in an emissions
increase, permitting requirements might be triggered and the plant may be
required to install additional pollution control technology. This requirement
does not apply to activities such as routine maintenance, replacement of
degraded equipment or failed components or other repairs needed for the
reliable, safe and efficient operation of the plant. The CAA authorizes civil
penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation
at each generating unit. In 2001, the District Court ruled claims for civil
penalties based on activities that occurred more than five years before the
filing date of the complaints cannot be imposed. There is no time limit on
claims for injunctive relief.
The
Federal EPA and eight northeastern states each filed an additional complaint
containing additional allegations against the Amos and Conesville plants.
APCo
and CSPCo filed an answer to the northeastern states’ complaint and the Federal
EPA’s complaint, denying the allegations and stating their defenses. Cases are
also pending that could affect CSPCo’s share of jointly-owned units at Beckjord
(12.5% owned), Zimmer (25.4% owned), and Stuart (26% owned) Stations. Similar
cases have been filed against other nonaffiliated utilities, including Allegheny
Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise
Group,
Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara
Mohawk. Several of these cases were resolved through consent
decrees.
Courts
have reached different conclusions regarding whether the activities at issue
in
these cases are routine maintenance, repair, or replacement, and therefore
are
excluded from NSR. Similarly, courts have reached different results regarding
whether the activities at issue increased emissions from the power plants.
Appeals on these and other issues were filed in certain appellate courts,
including a petition to appeal to the U.S. Supreme Court that was granted
in the
Duke Energy 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 Court denied the Federal
EPA’s
request for rehearing, and the Federal EPA and other parties filed a petition
for review by the U.S. Supreme Court. In April 2007, the Supreme Court denied
the petition for review. The Federal EPA also proposed a rule that would
define
“emissions increases” in a way that most of the challenged activities would be
excluded from NSR.
On
April
2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’
decision that had supported the statutory construction argument of Duke Energy
in its NSR proceeding. In a unanimous decision, the Court ruled that the
Federal
EPA was not obligated to define “major modification” in two different CAA
provisions in the same way. The Court also found that the Fourth Circuit’s
interpretation of “major modification” as applying only to projects that
increased hourly emission rates amounted to an invalidation of the relevant
Federal EPA regulations, which under the CAA can only be challenged in the
Court
of Appeals within 60 days of the Federal EPA rulemaking. The U.S. Supreme
Court
did acknowledge, however, that Duke Energy may argue on remand that the Federal
EPA has been inconsistent in its interpretations of the CAA and the regulations
and may not retroactively change 20 years of accepted practice.
In
addition to providing guidance on certain of the merits of the NSR proceedings
brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the
Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the
Duke Energy cases has an impact on the timing of our NSR proceedings. First,
the
court in the case for which a trial on liability issues has been conducted
has
indicated an intent to issue a decision on liability. Second, the bench trial
on
remedy issues, if necessary, is likely to be scheduled to begin in the third
quarter of 2007.
Management
is
unable to estimate the loss or range of loss related to any contingent
liability, if any, 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
March
2005, two special interest groups, Sierra Club and Public Citizen, filed
a
complaint in Federal District Court for the Eastern District of Texas alleging
violations of the CAA at SWEPCo’s Welsh Plant. SWEPCo filed a response to the
complaint in May 2005. A trial in this matter is scheduled for the second
quarter of 2007.
In
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 and to clarify the sulfur content requirement for fuels consumed
at the plant. A permit alteration was issued in March 2007 removing the heat
input references from the Welsh permit and clarifying the sulfur content
of
fuels burned at the plant is limited to 0.5% on an as-received basis. The
Sierra
Club and Public Citizen filed a motion to overturn the permit
alteration.
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, cash
flows or financial condition.
Carbon
Dioxide (CO2)
Public Nuisance Claims - Affecting AEP East Companies and AEP West
Companies
In
2004,
eight states and the City of New York filed an action in federal district
court
for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel
Energy, Southern Company and Tennessee Valley Authority. The Natural Resources
Defense Council, on behalf of three special interest groups, filed a similar
complaint against the same defendants. The actions allege that CO2
emissions
from the defendant’s power plants constitute a public nuisance under federal
common law due to impacts of global warming, and sought injunctive relief
in the
form of specific emission reduction commitments from the defendants. The
defendants’ motion to dismiss the lawsuits was granted in September 2005. The
dismissal was appealed to the Second Circuit Court of Appeals. Briefing and
oral
argument have concluded. On April 2, 2007, the U.S. Supreme Court issued
a
decision holding that the Federal EPA has authority to regulate emissions
of
CO2
and
other greenhouse gases under the CAA, which may impact the Second Circuit’s
analysis of these issues. Management believes the actions are without merit
and
intends to defend against the claims.
TEM
Litigation - Affecting OPCo
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). Beginning May 1, 2003, OPCo tendered replacement capacity, energy
and
ancillary services to TEM pursuant to the PPA that TEM rejected as
nonconforming.
In
September 2003, TEM and OPCo separately filed declaratory judgment actions
in
the United States District Court for the Southern District of New York. OPCo
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 OPCo’s breaches. The
corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited
guaranty.
In
August
2005, a federal judge ruled that TEM had breached the contract and awarded
damages to OPCo of $123 million plus prejudgment interest. Any eventual proceeds
will be recorded as a gain when received.
In
September 2005, TEM posted a $142 million letter of credit as security pending
appeal of the judgment. Both parties filed Notices of Appeal with the United
States Court of Appeals for the Second Circuit, which heard oral argument
on the
appeals in December 2006. Management cannot predict the ultimate outcome
of this
proceeding.
Coal
Transportation Dispute - Affecting PSO, TCC and TNC
PSO,
TCC,
TNC, the Oklahoma Municipal Power Authority and the Public Utilities Board
of
the City of Brownsville, Texas, as joint owners of a generating station,
disputed transportation costs for coal received between July 2000 and the
present time. The joint plant remitted less than the amount billed and the
dispute is pending before the Surface Transportation Board. Based upon a
weighted average probability analysis of possible outcomes, PSO, as operator
of
the plant, recorded provisions for possible loss in 2004, 2005, 2006 and
the
first quarter of 2007. The provision was deferred as a regulatory asset under
PSO’s fuel mechanism and immaterially affected income for TCC and TNC for their
respective ownership shares. Management continues to work toward mitigating
the
disputed amounts to the extent possible.
Coal
Transportation Rate Dispute - Affecting PSO
In
1985,
the Burlington Northern Railroad Co. (now BNSF) entered into a coal
transportation agreement with PSO. The agreement contained a base rate subject
to adjustment, a rate floor, a reopener provision and an arbitration provision.
In 1992, PSO reopened the pricing provision. The parties failed to reach
an
agreement and the matter was arbitrated, with the arbitration panel establishing
a lowered rate as of July 1, 1992 (the 1992 Rate), and modifying the rate
adjustment formula. The decision did not mention the rate floor. From April
1996
through the contract termination in December 2001, the 1992 Rate exceeded
the
adjusted rate, determined according to the decision. PSO paid the adjusted
rate
and contended that the panel eliminated the rate floor. BNSF invoiced at
the
1992 Rate and contended that the 1992 Rate was the new rate floor. At the
end of
1991, PSO terminated the contract by paying a termination fee, as required
by
the agreement. BNSF contends that the termination fee should have been
calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment
of approximately $9.5 million, including interest.
This
matter was submitted to an arbitration board. In April 2006, the arbitration
board filed its decision, denying BNSF’s underpayments claim. PSO filed a
request for an order confirming the arbitration award and a request for entry
of
judgment on the award with the U.S. District Court for the Northern District
of
Oklahoma. On July 14, 2006, the U.S. District Court issued an order confirming
the arbitration award. On July 24, 2006, BNSF filed a Motion to Reconsider
the
July 14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion
to Vacate and Correct the Arbitration Award with the U.S. District Court.
In
February 2007, the U.S. District Court granted BNSF’s Motion to Reconsider. PSO
filed a substantive response to BNSF’s motion and BNSF filed a reply. Management
continues to work toward mitigating the disputed amounts to the extent
possible.
Claims
by the City of Brownsville, Texas Against TCC - Affecting
TCC
On
April
27, 2007, the City of Brownsville, Texas served its Fifth Amended Answer
and
Cross-Claims in litigation pending in the District Court of Dallas County,
Texas. The cross-claims seek recovery against TCC based on allegations
of breach
of contract, breach of fiduciary duty, unjust enrichment, constructive
trust,
conversion, breach of the Texas theft liability act and fraud allegedly
occurring in connection with a transaction in which Brownsville purchased
TCC’s
interest in the Oklaunion electric generating station. Management believes
that
the claims are without merit and intends to defend against them
vigorously.
FERC
Long-term Contracts - Affecting AEP East Companies and AEP West
Companies
In
2002,
the FERC held a hearing related to a complaint filed by Nevada Power Company
and
Sierra Pacific Power Company (the Nevada utilities). The complaint sought
to
break long-term contracts entered during the 2000 and 2001 California energy
price spike which the customers alleged were “high-priced.” The complaint
alleged that AEP subsidiaries sold power at unjust and unreasonable prices.
In
December 2002, a FERC ALJ ruled in AEP’s favor and dismissed the complaint filed
by the Nevada utilities. In 2001, the Nevada utilities filed complaints
asserting that the prices for power supplied under those contracts should
be
lowered because the market for power was allegedly dysfunctional at the time
such contracts were executed. The ALJ rejected the complaint, held that the
markets for future delivery were not dysfunctional, and that the Nevada
utilities failed to demonstrate that the public interest required that changes
be made to the contracts. In June 2003, the FERC issued an order affirming
the
ALJ’s decision. In December 2006, the U.S. Court of Appeals for the Ninth
Circuit reversed the FERC order and remanded the case to the FERC for further
proceedings. Management is unable to predict the outcome of these proceedings
or
their impact on future results of operations and cash flows. We have asserted
claims against certain companies that sold power to us, which we resold to
the
Nevada utilities, seeking to recover a portion of any amounts we may owe
to the
Nevada utilities.
5. ACQUISITIONS,
DISPOSITIONS AND ASSETS HELD FOR SALE
ACQUISITIONS
2007
Darby
Electric Generating Station - Affecting CSPCo
In
November 2006, CSPCo agreed to purchase Darby Electric Generating Station
(Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light
Company, for $102 million and the assumption of liabilities of approximately
$2
million. CSPCo completed the purchase in April 2007. The Darby plant is located
near Mount Sterling, Ohio and is a natural gas, simple cycle power plant
with a
generating capacity of 480 MW.
Lawrenceburg
Generating Station - Affecting AEGCo
In
January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station
(Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG)
for
approximately $325 million and the assumption of liabilities of approximately
$2
million. AEGCo will complete the purchase in May 2007. The Lawrenceburg plant
is
located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and
is a natural gas, combined cycle power plant with a generating capacity of
1,096
MW.
2006
None
DISPOSITIONS
2007
Texas
Plants - Oklaunion Power Station - Affecting TCC
In
February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the
Public
Utilities Board of the City of Brownsville for $42.8 million plus adjustments.
The sale did not have a significant effect on TCC’s results of operations. See
"Claims by the City of Brownsville, Texas Against TCC" section of Note 4.
2006
None
ASSETS
HELD FOR SALE
Texas
Plants - Oklaunion Power Station - Affecting TCC
In
February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the
Public
Utilities Board of the City of Brownsville. The sale did not have a significant
effect on TCC’s results of operations nor does TCC expect any remaining
litigation to have a significant effect on its results of operations.
TCC’s
assets related to the Oklaunion Power Station were classified in Assets Held
for
Sale - Texas Generation Plant on TCC’s Condensed Consolidated Balance Sheet at
December 31, 2006. 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 except
TNC.
The
Assets Held for Sale were as follows:
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
Texas
Plants (TCC)
|
|
(in
millions)
|
|
Assets:
|
|
|
|
|
|
Other
Current Assets
|
|
$
|
-
|
|
$
|
1
|
|
Property,
Plant and Equipment, Net
|
|
|
-
|
|
|
43
|
|
Total
Assets Held for Sale - Texas Generation Plant
|
|
$
|
-
|
|
$
|
44
|
|
6. BENEFIT
PLANS
APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP
sponsored qualified pension plans and nonqualified pension plans. A substantial
majority of employees are covered by either one qualified plan or both a
qualified and a nonqualified pension plan. In addition, APCo, CSPCo, I&M,
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.
APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC adopted SFAS 158 as of
December 31, 2006. They recorded a SFAS 71 regulatory asset for their qualifying
SFAS 158 costs of regulated operations that for ratemaking purposes will
be
deferred for future recovery.
Components
of Net Periodic Benefit Cost
The
following table provides the components of AEP’s net periodic benefit cost for
the plans for the three months ended March 31, 2007 and 2006:
|
|
|
|
Other
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension
Plans
|
|
Benefit
Plans
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(in
millions)
|
|
Service
Cost
|
|
$
|
24
|
|
$
|
24
|
|
$
|
10
|
|
$
|
10
|
|
Interest
Cost
|
|
|
59
|
|
|
57
|
|
|
26
|
|
|
25
|
|
Expected
Return on Plan Assets
|
|
|
(85
|
)
|
|
(83
|
)
|
|
(26
|
)
|
|
(23
|
)
|
Amortization
of Transition Obligation
|
|
|
-
|
|
|
-
|
|
|
7
|
|
|
7
|
|
Amortization
of Net Actuarial Loss
|
|
|
15
|
|
|
20
|
|
|
3
|
|
|
5
|
|
Net
Periodic Benefit Cost
|
|
$
|
13
|
|
$
|
18
|
|
$
|
20
|
|
$
|
24
|
|
The
following table provides the net periodic benefit cost (credit) for the plans
by
Registrant Subsidiary for the three months ended March 31, 2007 and
2006:
|
|
Pension
Plans
|
|
Other
Postretirement
Benefit
Plans
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
Company
|
|
(in
thousands)
|
|
APCo
|
|
$
|
842
|
|
$
|
1,468
|
|
$
|
3,560
|
|
$
|
4,489
|
|
CSPCo
|
|
|
(257
|
)
|
|
205
|
|
|
1,491
|
|
|
1,805
|
|
I&M
|
|
|
1,900
|
|
|
2,331
|
|
|
2,530
|
|
|
2,953
|
|
KPCo
|
|
|
255
|
|
|
358
|
|
|
426
|
|
|
513
|
|
OPCo
|
|
|
245
|
|
|
826
|
|
|
2,802
|
|
|
3,396
|
|
PSO
|
|
|
424
|
|
|
977
|
|
|
1,431
|
|
|
1,588
|
|
SWEPCo
|
|
|
746
|
|
|
1,225
|
|
|
1,419
|
|
|
1,578
|
|
TCC
|
|
|
101
|
|
|
773
|
|
|
1,575
|
|
|
1,696
|
|
TNC
|
|
|
70
|
|
|
325
|
|
|
631
|
|
|
715
|
|
7. 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, and TCC
and
TNC, which are transmission and distribution businesses. 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 cost-based rates and regulatory oversight on the business process, cost
structures and operating results.
8. INCOME
TAXES
We
join
in the filing of a consolidated federal income tax return with our subsidiaries
in the American Electric Power (AEP) System. The allocation of the AEP System’s
current consolidated federal income tax to the AEP System companies allocates
the benefit of current tax losses to the AEP System companies giving rise
to
such losses in determining their current expense. The tax benefit of the
parent
is allocated to our subsidiaries with taxable income. With the exception
of the
loss of the parent company, the method of allocation approximates a separate
return result for each company in the consolidated group.
Audit
Status
AEP
System companies also file income tax returns in various state, local, and
foreign jurisdictions. With few exceptions, we are no longer subject to U.S.
federal, state and local, or non-U.S. income tax examinations by tax authorities
for years before 2000. The IRS and other taxing authorities routinely examine
our tax returns. We believe that we have filed tax returns with positions
that
may be challenged by these tax authorities. We are currently under exam in
several state and local jurisdictions. However, management does not believe
that
the ultimate resolution of these audits will materially impact results of
operations.
We
have
settled with the IRS all issues from the audits of our consolidated federal
income tax returns for years prior to 1997. We have effectively settled all
outstanding proposed IRS adjustments for years 1997 through 1999 and through
June 2000 for the CSW pre-merger tax period and anticipate payment for the
agreed adjustments to occur during 2007. Returns for the years 2000 through
2003
are presently being audited by the IRS and we anticipate that the audit will
be
completed by the end of 2007.
The
IRS
has proposed certain significant adjustments to AEP’s foreign tax credit and
interest allocation positions. Management is currently evaluating those proposed
adjustments to determine if it agrees, but if accepted, we do not anticipate
the
adjustments would result in a material change to our financial
position.
FIN
48 Adoption
We
adopted the provisions of FIN 48 on January 1, 2007. As a result of the
implementation of FIN 48, the approximate increase (decrease) in the liabilities
for unrecognized tax benefits, as well as related interest expense and
penalties, which was accounted for as a reduction to the January 1, 2007
balance
of retained earnings was recognized by each Registrant Subsidiary as
follows:
Company
|
|
(in
thousands)
|
|
AEGCo
|
|
$
|
(27
|
)
|
APCo
|
|
|
2,685
|
|
CSPCo
|
|
|
3,022
|
|
I&M
|
|
|
(327
|
)
|
KPCo
|
|
|
786
|
|
OPCo
|
|
|
5,380
|
|
PSO
|
|
|
386
|
|
SWEPCo
|
|
|
1,642
|
|
TCC
|
|
|
2,187
|
|
TNC
|
|
|
557
|
|
At
January 1, 2007, the total amount of unrecognized tax benefits under FIN
48 for
each Registrant Subsidiary was as follows:
Company
|
|
(in
millions)
|
|
AEGCo
|
|
$
|
0.1
|
|
APCo
|
|
|
21.7
|
|
CSPCo
|
|
|
25.0
|
|
I&M
|
|
|
18.2
|
|
KPCo
|
|
|
3.4
|
|
OPCo
|
|
|
49.8
|
|
PSO
|
|
|
8.9
|
|
SWEPCo
|
|
|
7.1
|
|
TCC
|
|
|
20.7
|
|
TNC
|
|
|
6.9
|
|
We
believe it is reasonably possible that there will be a net decrease in
unrecognized tax benefits due to the settlement of audits and the expiration
of
statute of limitations within 12 months of the reporting date for each
Registrant Subsidiary as follows:
Company
|
|
(in
millions)
|
|
AEGCo
|
|
$
|
0.5
|
|
APCo
|
|
|
5.5
|
|
CSPCo
|
|
|
9.3
|
|
I&M
|
|
|
6.0
|
|
KPCo
|
|
|
1.4
|
|
OPCo
|
|
|
9.0
|
|
PSO
|
|
|
4.4
|
|
SWEPCo
|
|
|
2.8
|
|
TCC
|
|
|
3.4
|
|
TNC
|
|
|
1.6
|
|
At
January 1, 2007, the total amount of unrecognized tax benefits that, if
recognized, would affect the effective tax rate for each Registrant Subsidiary
was as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
5.4
|
|
CSPCo
|
|
|
13.8
|
|
I&M
|
|
|
5.4
|
|
KPCo
|
|
|
0.6
|
|
OPCo
|
|
|
23.4
|
|
PSO
|
|
|
1.2
|
|
SWEPCo
|
|
|
1.2
|
|
TCC
|
|
|
9.3
|
|
TNC
|
|
|
2.6
|
|
At
January 1, 2007, tax positions for each Registrant Subsidiary, for which
the
ultimate deductibility is highly certain but for which there is uncertainty
about the timing of such deductibility was as follows:
Company
|
|
(in
millions)
|
|
AEGCo
|
|
$
|
0.1
|
|
APCo
|
|
|
13.7
|
|
CSPCo
|
|
|
3.9
|
|
I&M
|
|
|
10.3
|
|
KPCo
|
|
|
2.5
|
|
OPCo
|
|
|
14.2
|
|
PSO
|
|
|
7.1
|
|
SWEPCo
|
|
|
5.1
|
|
TCC
|
|
|
6.4
|
|
TNC
|
|
|
2.9
|
|
Because
of the impact of deferred tax accounting, other than interest and penalties,
the
disallowance of the shorter deductibility period would not affect the annual
effective tax rate but would accelerate the payment of cash to the taxing
authority to an earlier period.
Prior
to
the adoption of FIN 48, we recorded interest and penalty accruals related
to
income tax positions in tax accrual accounts. With the adoption of FIN 48,
we
began recognizing interest accruals related to income tax positions in interest
income or expense as applicable, and penalties in operating expenses. As
of
January 1, 2007, each Registrant Subsidiary accrued for the payment of uncertain
interest and penalties as follows:
Company
|
|
(in
millions)
|
|
AEGCo
|
|
$
|
0.1
|
|
APCo
|
|
|
4.6
|
|
CSPCo
|
|
|
1.7
|
|
I&M
|
|
|
2.8
|
|
KPCo
|
|
|
1.2
|
|
OPCo
|
|
|
4.3
|
|
PSO
|
|
|
2.7
|
|
SWEPCo
|
|
|
2.0
|
|
TCC
|
|
|
2.5
|
|
TNC
|
|
|
1.0
|
|
9. FINANCING
ACTIVITIES
Long-term
Debt
Long-term
debt and other securities issued, retired and principal payments made during
the
first three months of 2007 were:
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
SWEPCo
|
|
Senior
Unsecured Notes
|
|
$
|
250,000
|
|
5.55
|
|
2017
|
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Retirements
and
Principal Payments:
|
|
|
|
|
|
|
|
|
|
OPCo
|
|
Notes
Payable
|
|
$
|
1,463
|
|
6.81
|
|
2008
|
OPCo
|
|
Notes
Payable
|
|
|
6,000
|
|
6.27
|
|
2009
|
SWEPCo
|
|
Notes
Payable
|
|
|
1,645
|
|
4.47
|
|
2011
|
SWEPCo
|
|
Notes
Payable
|
|
|
4,000
|
|
6.36
|
|
2007
|
SWEPCo
|
|
Notes
Payable
|
|
|
750
|
|
Variable
|
|
2008
|
TCC
|
|
Securitization
Bonds
|
|
|
32,125
|
|
5.01
|
|
2008
|
In
April
2007, OPCo issued $400 million of three-year floating rate notes at an initial
rate of 5.53% due in 2010. The proceeds from this issuance will contribute
to
our investment in environmental equipment.
Lines
of Credit and Short-term Debt - 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 amount of outstanding loans (borrowings) to/from
the
Utility Money Pool as of March 31, 2007 and December 31, 2006 are included
in
Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance
sheets. The Utility Money Pool participants’ money pool activity and their
corresponding authorized borrowing limits for the three months ended March
31,
2007 are described in the following table:
|
|
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,
2007
|
|
Authorized
Short-Term
Borrowing Limit
|
|
Company
|
|
(in
thousands)
|
|
AEGCo
|
|
$
|
75,425
|
|
$
|
-
|
|
$
|
44,340
|
|
$
|
-
|
|
$
|
(29,997
|
)
|
$
|
125,000
|
(a)
|
APCo
|
|
|
109,259
|
|
|
-
|
|
|
71,378
|
|
|
-
|
|
|
(82,860
|
)
|
|
600,000
|
|
CSPCo
|
|
|
15,693
|
|
|
35,270
|
|
|
6,204
|
|
|
14,543
|
|
|
922
|
|
|
350,000
|
|
I&M
|
|
|
100,374
|
|
|
-
|
|
|
66,570
|
|
|
-
|
|
|
(45,759
|
)
|
|
500,000
|
|
KPCo
|
|
|
46,317
|
|
|
-
|
|
|
30,845
|
|
|
-
|
|
|
(20,769
|
)
|
|
200,000
|
|
OPCo
|
|
|
444,153
|
|
|
-
|
|
|
333,467
|
|
|
-
|
|
|
(397,127
|
)
|
|
600,000
|
|
PSO
|
|
|
135,694
|
|
|
-
|
|
|
76,776
|
|
|
-
|
|
|
(135,694
|
)
|
|
300,000
|
|
SWEPCo
|
|
|
240,786
|
|
|
48,979
|
|
|
215,207
|
|
|
30,267
|
|
|
8,959
|
|
|
350,000
|
|
TCC
|
|
|
-
|
|
|
394,180
|
|
|
-
|
|
|
295,542
|
|
|
216,953
|
|
|
600,000
|
|
TNC
(b)
|
|
|
35,191
|
|
|
3,200
|
|
|
22,179
|
|
|
2,365
|
|
|
(24,487
|
)
|
|
250,000
|
|
(a)
|
In
April 2007, limit increased by $285 million under regulatory
orders.
|
(b)
|
Does
not include short-term lending activity of TNC’s wholly-owned subsidiary,
AEP Texas North Generation Company LLC (TNGC), who is a participant
in the
Nonutility Money Pool. As of March 31, 2007, TNGC had $13.3 million
in
outstanding loans to the Nonutility Money
Pool.
|
The
maximum and minimum interest rates for funds either borrowed from or loaned
to
the Utility Money Pool were as follows:
|
|
Three
Months Ended March 31,
|
|
|
|
2007
|
|
2006
|
|
Maximum
Interest Rate
|
|
|
5.43
|
%
|
|
4.85
|
%
|
Minimum
Interest Rate
|
|
|
5.30
|
%
|
|
4.37
|
%
|
The
average interest rates for funds borrowed from and loaned to the Utility
Money
Pool for the three months ended March 31, 2007 and 2006 are summarized for
all
Registrant Subsidiaries in the following table:
|
|
Average
Interest Rate for Funds
Borrowed
from the Utility Money
Pool
for
Three
Months Ended March 31,
|
|
Average
Interest Rate for Funds
Loaned
to the Utility Money
Pool
for
Three
Months Ended March 31,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
Company
|
|
(in
percentage)
|
|
AEGCo
|
|
|
5.34
|
|
|
4.57
|
|
|
-
|
|
|
-
|
|
APCo
|
|
|
5.34
|
|
|
4.60
|
|
|
-
|
|
|
-
|
|
CSPCo
|
|
|
5.35
|
|
|
4.58
|
|
|
5.33
|
|
|
4.66
|
|
I&M
|
|
|
5.34
|
|
|
4.59
|
|
|
-
|
|
|
-
|
|
KPCo
|
|
|
5.34
|
|
|
4.54
|
|
|
-
|
|
|
4.75
|
|
OPCo
|
|
|
5.34
|
|
|
4.60
|
|
|
-
|
|
|
-
|
|
PSO
|
|
|
5.34
|
|
|
4.63
|
|
|
-
|
|
|
-
|
|
SWEPCo
|
|
|
5.35
|
|
|
4.60
|
|
|
5.34
|
|
|
-
|
|
TCC
|
|
|
-
|
|
|
4.47
|
|
|
5.34
|
|
|
4.68
|
|
TNC
(a)
|
|
|
5.34
|
|
|
4.57
|
|
|
5.34
|
|
|
4.54
|
|
(a)
|
Does
not include short-term lending activity for TNGC, who is a participant
in
the Nonutility Money Pool. For the three months ended March 31,
2007, the
average interest rate for funds loaned to the Nonutility Money
Pool by
TNGC was 5.31%.
|
The
Registrant Subsidiaries’ outstanding short-term debt was as
follows:
|
|
|
|
March
31, 2007
|
|
|
December
31, 2006
|
|
|
|
Type
of Debt
|
|
Outstanding
Amount
|
|
Interest
Rate
|
|
|
Outstanding
Amount
|
|
Interest
Rate
|
|
Company
|
|
|
|
(in
millions)
|
|
|
|
|
|
(in
millions)
|
|
|
|
|
OPCo
|
|
Commercial
Paper - JMG
|
|
$
|
5
|
|
|
5.56
|
%
|
|
$
|
1
|
|
|
5.56
|
%
|
SWEPCo
|
|
Line
of Credit - Sabine
|
|
|
20
|
|
|
6.52
|
%
|
|
|
17
|
|
|
6.38
|
%
|
The
following is a combined presentation of certain components of the registrants’
management’s discussion and analysis. The information in this section completes
the information necessary for management’s discussion and analysis of financial
condition and results of operations and is meant to be read with (i)
Management’s Financial Discussion and Analysis, (ii) financial statements and
(iii) footnotes of each individual registrant. The combined Management’s
Discussion and Analysis of Registrant Subsidiaries section of the 2006 Annual
Report should also be read in conjunction with this report.
Significant
Factors
Ohio
New Generation
In
March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of cost
recovery associated with the IGCC plant: Phase 1, recovery of $24 million
in
pre-construction costs during 2006; Phase 2, concurrent recovery of
construction-financing costs; and Phase 3, recovery or refund in distribution
rates of any difference between the market-based standard service offer price
for generation and the cost of operating and maintaining the plant, including
a
return on and return of the ultimate cost to construct the plant, originally
projected to be $1.2 billion, along with fuel, consumables and replacement
power
costs. The proposed recoveries in Phases 1 and 2 would be applied against
the 4%
limit on additional generation rate increases CSPCo and OPCo could request
under
their RSPs.
In
April
2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
1
of the cost recovery proposal. In June 2006, the PUCO issued another order
approving a tariff to recover Phase 1 pre-construction costs over no more
than a
twelve-month period effective July 1, 2006. Through March 31, 2007, CSPCo
and
OPCo each recorded pre-construction IGCC regulatory assets of $10 million
and
each recovered $9 million of those costs. CSPCo and OPCo will recover the
remaining amounts through June 30, 2007. The PUCO indicated that if CSPCo
and
OPCo have not commenced a continuous course of construction of the IGCC plant
within five years of the June 2006 PUCO order, all charges collected for
pre-construction costs, associated with items that may be utilized in IGCC
projects at other sites, must be refunded to Ohio ratepayers with interest.
The
PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings
are
held. A date for further rehearings has not been set.
In
August
2006, the Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy
Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order
in the IGCC proceeding. CSPCo and OPCo believe that the PUCO’s authorization to
begin collection of Phase 1 rates is lawful. Management, however, cannot
predict
the outcome of these appeals. If the PUCO’s order is found to be unlawful, CSPCo
and OPCo could be required to refund Phase I cost-related
recoveries.
SECA
Revenue Subject to Refund
The
AEP
East Companies ceased collecting through-and-out transmission service (T&O)
revenues in accordance with FERC orders and implemented SECA rates to mitigate
the loss of T&O revenues from December 1, 2004 through March 31, 2006, when
SECA rates expired. Intervenors objected to the SECA rates, raising various
issues. In August 2006, the ALJ issued an initial decision, finding that
the
rate design for the recovery of SECA charges was flawed and that a large
portion
of the “lost revenues” reflected in the SECA rates was not recoverable. The ALJ
found that the SECA rates charged were unfair, unjust and discriminatory
and
that new compliance filings and refunds should be made.
Since
the
implementation of SECA rates in December 2004, the AEP East companies recorded
approximately $220 million of gross SECA revenues, subject to refund. The
AEP
East companies have reached settlements with certain customers related to
approximately $70 million of such revenues. The unsettled gross SECA revenues
total approximately $150 million. If the ALJ’s initial decision is upheld in its
entirety, it would disallow $126 million of the AEP East companies’ unsettled
gross SECA revenues. In the second half of 2006, the AEP East companies provided
a reserve of $37 million in net refunds.
In
September 2006, AEP, together with Exelon and the Dayton Power and Light
Company, filed an extensive post hearing brief and reply brief noting exceptions
to the ALJ’s initial decision and asking the FERC to reverse the decision in
large part. Management
believes
that the FERC should reject the initial decision because it is contrary to
prior
related FERC decisions, which are presently subject to rehearing. Furthermore,
management believes the ALJ’s findings on key issues are largely without merit.
Although management believes they have meritorious arguments, management
cannot
predict the ultimate outcome of any future FERC proceedings or court appeals.
If
the
FERC adopts the ALJ’s decision, it will have an adverse effect on future results
of operations and cash flows.
Environmental
Matters
The
Registrant Subsidiaries are implementing a substantial capital investment
program and incurring additional operational costs to comply with new
environmental control requirements. The sources of these requirements
include:
·
|
Requirements
under the 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;
and
|
·
|
Requirements
under the Clean Water Act (CWA) to reduce the impacts of water
intake
structures on aquatic species at certain power
plants.
|
In
addition, the Registrant Subsidiaries are engaged in litigation with respect
to
certain environmental matters, have been notified of potential responsibility
for the clean-up of contaminated sites and incur costs for disposal of spent
nuclear fuel and future decommissioning of I&M’s nuclear units. Management
also monitors possible future requirements to reduce carbon dioxide
(CO2)
emissions to address concerns about global climate change.
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, OPCo and other nonaffiliated utilities including the Tennessee
Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company,
Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power
Company, Tampa Electric Company, Virginia Electric Power Company and Duke
Energy, modified certain units at coal-fired generating plants in violation
of
the NSR requirements of the CAA. 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 thereafter against
nonaffiliated utilities including Allegheny Energy, Eastern Kentucky Electric
Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric
Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases
were resolved through consent decrees. The alleged modifications at the
Registrant Subsidiaries’ power plants occurred over a twenty-year period. A
bench trial on the liability issues was held during 2005. Briefing has
concluded. In June 2006, the judge stayed the liability decision pending
the
issuance of a decision by the U.S. Supreme Court in the Duke Energy
case.
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 have reached
different results. Appeals on these and other issues were filed in certain
appellate courts, including a petition to appeal to the U.S. Supreme Court
that
was granted in the Duke Energy 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 Court denied the
Federal EPA’s request for rehearing, and the Federal EPA and other parties filed
a petition for review by the U.S. Supreme Court. In April 2007, the Supreme
Court denied the petition for review. The Federal EPA also proposed a rule
that
would define “emissions increases” in a way that would exclude most of the
challenged activities from NSR.
On
April
2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’
decision that had supported the statutory construction argument of Duke Energy
in its NSR proceeding. In a unanimous decision, the Court ruled that the
Federal
EPA was not obligated to define “major modification” in two different CAA
provisions in the same way. The Court also found that the Fourth Circuit’s
interpretation of “major modification” as applying only to projects that
increased hourly emission rates amounted to an invalidation of the relevant
Federal EPA regulations, which under the CAA can only be challenged in the
Court
of Appeals within 60 days of the Federal EPA rulemaking. The U.S. Supreme
Court
did acknowledge, however, that Duke Energy may argue on remand that the Federal
EPA has been inconsistent in its interpretations of the CAA and the regulations
and may not retroactively change 20 years of accepted practice.
In
addition to providing guidance on certain of the merits of the NSR proceedings
brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the
Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the
Duke Energy cases has an impact on the timing of our NSR proceedings. First,
the
court in the case for which a trial on liability issues has been conducted
has
indicated an intent to issue a decision on liability. Second, the bench trial
on
remedy issues, if necessary, is likely to be scheduled to begin in the third
quarter of 2007.
Management
is unable to estimate the loss or range of loss related to any contingent
liability, if any, 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 to be determined by the court. If the Registrant
Subsidiaries do not prevail, management believes the Registrant Subsidiaries
can
recover any capital and operating costs of additional pollution control
equipment that may be required through regulated rates and market prices
for
electricity. If the Registrant Subsidiaries are unable to recover such costs
or
if material penalties are imposed, it would adversely affect future results
of
operations, cash flows and possibly financial condition.
Adoption
of New Accounting Pronouncements
FIN
48 clarifies the accounting for uncertainty in income taxes recognized in
an enterprise’s financial statements by prescribing a recognition threshold
(whether a tax position is more likely than not to be sustained) without
which,
the benefit of that position is not recognized in the financial statements.
It
requires a measurement determination for recognized tax positions based on
the
largest amount of benefit that is greater than 50 percent likely of being
realized upon ultimate settlement. FIN 48 also provides guidance on
derecognition, classification, interest and penalties, accounting in interim
periods, disclosure and transition. FIN 48 requires that the cumulative effect
of applying this interpretation be reported and disclosed as an adjustment
to
the opening balance of retained earnings for that fiscal year and presented
separately. The Registrant Subsidiaries adopted FIN 48 effective January
1,
2007. See “FIN 48 “Accounting for Uncertainty in Income Taxes”” section of Note
2 and see Note 8 - Income Taxes. The impact of this interpretation was an
unfavorable (favorable) adjustment to retained earnings as follows:
Company
|
|
(in
thousands)
|
|
AEGCo
|
|
$
|
(27
|
)
|
APCo
|
|
|
2,685
|
|
CSPCo
|
|
|
3,022
|
|
I&M
|
|
|
(327
|
)
|
KPCo
|
|
|
786
|
|
OPCo
|
|
|
5,380
|
|
PSO
|
|
|
386
|
|
SWEPCo
|
|
|
1,642
|
|
TCC
|
|
|
2,187
|
|
TNC
|
|
|
557
|
|
CONTROLS
AND PROCEDURES
During
the first quarter of 2007, 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, 2007 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.
The
only
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 2007 that materially affected, or is reasonably likely
to
materially affect, the Registrants’ internal controls over financial reporting,
relates to the Southwest Power Pool’s (SPP) implementation of an Energy
Imbalance Service Market. In connection with this market implementation,
two of
AEP’s subsidiaries (Public Service Company of Oklahoma and Southwestern Electric
Power Company) implemented or modified a number of business processes and
controls to facilitate participation in, and resultant settlement within,
the
SPP Energy Imbalance Service Market.
PART
II. OTHER INFORMATION
Item
1. Legal
Proceedings
For
a
discussion of material legal proceedings, see Note 4, Commitments,
Guarantees and Contingencies, incorporated
herein by reference.
Item
1A. Risk
Factors
Our
Annual Report on Form 10-K for the year ended December 31, 2006 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 2006 Annual Report on Form 10-K.
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.)
APCo
filed a request with the Virginia SCC in May 2006 seeking a net increase
in base
rates of $198 million to recover increasing costs, including a return on
equity
of 11.5%. APCo also requested to apply its off-system sales margins (currently
credited to customers through base rates) to the fuel factor where they can
be
adjusted annually. APCo also requested to retain a portion of the off-system
sales margins. In May 2006, the Virginia SCC issued an order placing the
net
requested base rate increase into effect as of October 2, 2006, subject to
refund. In October 2006, the Virginia SCC staff filed direct testimony
recommending a base rate increase of $13 million with a return on equity
of 9.9%
and no off-system sales margin sharing. Other intervenors have recommended
base
rate increases ranging from $42 million to $112 million. APCo has filed rebuttal
testimony and hearings were held in December 2006. In March 2007, the Hearing
Examiner released a report recommending a base rate increase of $31 million
with
a return on equity of 10.1% and a 5% retention of off-system sales margin
sharing. If the Virginia SCC denies the
requested rate recovery, it could adversely impact future results of operations,
cash flows and financial condition.
Our
request for rate recovery of additional costs may not be approved in
Texas. (Applies
to AEP, TCC and TNC.)
TCC
and
TNC have filed requests with the PUCT to increase their transmission and
distribution rates. The rate requests include the amounts charged for the
delivery of electricity over TCC´s and TNC´s transmission and distribution
lines. TCC is seeking approval of an $81 million increase, which includes
the
expiration of $20 million in billing credits that the PUCT required in approving
the merger of CSW into AEP. The credits have been in place since 2000. TNC
is
seeking approval of a $25 million increase, which includes the expiration
of $6
million in billing credits. TCC and TNC are requesting a return on equity
of
11.25% with a capital structure of approximately 60% debt/40% equity. As
part of
rebuttal testimony filed in April 2007, TCC and TNC reduced their base rate
request by $11 million and $3 million, respectively, and reduced their return
on
equity by 0.5%. If the PUCT denies the
requested rate recovery, it could adversely impact future results of operations,
cash flows and financial condition.
Our
request for rate recovery of additional costs may not be approved in
Oklahoma. (Applies
to AEP and PSO.)
PSO
filed
a request with the OCC in November 2006 seeking approval of a $50 million
overall increase in base rates, an annually adjusted rate mechanism to recover
the expected significant investment PSO will be making in new facilities,
several new and restructured tariffs to allow PSO to begin to reduce the
relationship between its revenues and its sales volumes, and to implement
some
demand side management tariffs. PSO´s planned investments over the next five
years include new generation facilities ($1.12 billion), new and refurbished
transmission substations and lines ($302 million) and new distribution lines
and
equipment ($582 million). In April 2007, PSO filed rebuttal testimony regarding
various issues raised by the OCC Staff and the intervenors. As part of rebuttal
testimony, PSO reduced its base rate request by $2 million. If the OCC denies
the
requested rate recovery, it could adversely impact future results of operations,
cash flows and financial condition.
The
amount we charged third parties for using our transmission facilities has
been
reduced, is subject to refund and may not be completely restored in the
future. (Applies
to AEP and the AEP
East companies.)
In
July
2003, the FERC issued an order directing PJM and MISO to make compliance
filings
for their respective tariffs to eliminate the transaction-based charges for
through and out (T&O) transmission service on transactions where the energy
is delivered within those RTOs. 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 seams elimination cost allocation (SECA) transition
rates
beginning in December 2004 and extending through March 2006. Intervenors
objected to this decision; therefore the SECA fees we collected ($220
million) are
subject to refund. Approximately
$19 million of the SECA revenues that we billed were never collected. AEP
filed
a motion with the FERC to force payment of these SECA billings.
A
hearing
was held in May 2006 to determine whether any of the SECA revenues should
be
refunded. In August 2006, the ALJ issued an initial decision, finding that
the
rate design for the recovery of SECA charges was flawed and that a large
portion
of the “lost revenues” reflected in the SECA rates was not recoverable. The ALJ
found that the SECA rates charged were unfair, unjust and discriminatory,
and
that new compliance filings and refunds should be made. The ALJ also found
that
unpaid SECA rates must be paid in the recommended reduced amount. The FERC
has
not ruled on the matter. If the FERC upholds the decision of the ALJ, up
to $126
million of collected SECA rates could be refunded by the AEP East companies.
We
have recorded provisions in the aggregate amount of $37 million related to
the
potential refund of SECA rates pending settlement negotiations with various
intervenors.
SECA
transition rates expired on March 31, 2006
and did
not fully compensate AEP East companies for ongoing lost T&O
revenues.
As a
result of rate relief in certain jurisdictions, however, approximately 85%
of
the ongoing
lost T&O revenues
are now
being recovered from native load customers of AEP East companies in those
jurisdictions.
The
portion attributable to Virginia is being collected subject to
refund.
In
addition to seeking retail rate recovery from native load customers in 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 the filers’ the AEP East companies
respective transmission assets. A
majority of PJM members have filed in opposition to the proposal. Hearings
were
held in April 2006. An ALJ recommended a rate design that would result in
greater recovery for AEP than the proposal AEP had submitted. The ALJ also
recommended, however, that the design be phased-in, which could limit the
amount
of recovery for AEP. In April 2007, the FERC issued an order reversing the
ALJ
decision. The FERC ruled that the current PJM rate design is just and
reasonable. The FERC further ruled that the cost of new facilities of 500
kV and
above would be shared among all PJM participants. Management cannot estimate
at
this time what affect, if any, this order will have on our future construction
of new east transmission facilities, results of operations, cash flows and
financial condition.
We
are exposed to losses resulting from the bankruptcy of Enron
Corp.
(Applies to AEP.)
On
June
1, 2001, we purchased HPL from Enron Corp. (Enron). Later that year, Enron
and
its subsidiaries filed bankruptcy proceedings in the U.S. Bankruptcy Court
for
the Southern District of New York. Various HPL-related contingencies and
indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.
In
connection with the 2001 acquisition of HPL, we entered into an agreement
with
BAM Lease Company, which granted HPL the exclusive right to use approximately
65
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 (together with BOA, BOA Syndicate) and Enron entered
into an
agreement granting HPL the exclusive use of 65 BCF of cushion gas. Additionally,
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, HPL was informed by the BOA Syndicate of a purported default
by Enron under the terms of the financing arrangement. We purchased 10 BCF
of
gas from Enron and are currently litigating the rights to the remaining 55
BCF
of cushion gas.
In
February 2004, in connection with BOA’s dispute, Enron filed Notices of
Rejection regarding the cushion gas use agreement and other incidental
agreements. We have objected to Enron’s attempted rejection of these agreements.
In 2005, we sold HPL, including the Bammel gas storage facility. We indemnified
the purchaser for damages, if any, arising from the litigation with BOA.
Management
is unable to predict the final resolution of these disputes, however the
impact
on results of operations, cash flows and financial condition could be
material.
Risks
Relating To State Restructuring
In
Ohio, our costs may not be recovered and rates may be reduced.
(Applies
to AEP, OPCo and CSPCo.)
In
January 2005, the PUCO approved RSPs for CSPCo and OPCo. The RSPs provide,
among
other things, for CSPCo and OPCo to raise their generation rates on an annual
basis through 2008 by 3% and 7%, respectively. The RSPs also provide for
possible additional annual generation rate increases of up to an average
of 4%
per year for specified costs. The RSPs also provide that CSPCo and OPCo can
recover certain environmental carrying costs, PJM-related administrative
costs
and certain congestion costs. In 2006, CSPCo and OPCo collected an additional
estimated $244 million in gross margin as a result of the RSPs. This amount
is
expected to increase in 2007 and 2008.
In
2005,
the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that
challenged the validity of the RSPs under Ohio’s electricity restructuring law.
In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP orders for CSPCo and
OPCo and remanded the case to the PUCO for further proceedings.
In
August
2006, the PUCO directed CSPCo and OPCo to file a plan providing an option
for
customer participation in the electric market through competitive bids or
other
reasonable means. The PUCO also held that the RSPs shall remain effective.
Accordingly, CSPCo and OPCo continued collecting RSP revenues. In September
2006, CSPCo and OPCo submitted their proposals to provide additional options
for
customer participation in the electric market.
In
March
2007, CSPCo and OPCo filed a settlement agreement at the PUCO resolving the
Ohio
Supreme Court's remand of the PUCO’s RSP order. Management expects the PUCO will
approve this settlement agreement.
Some
laws and regulations governing restructuring in Virginia have not yet been
interpreted or adopted and could harm our business, operating results and
financial condition.
(Applies to AEP and APCo.)
Virginia
restructuring legislation was enacted in 1999 providing for retail choice
of
generation suppliers to be phased in over two years beginning January 1,
2002. It required jurisdictional utilities to unbundle their power supply
and
energy delivery rates and to file functional separation plans by January
1,
2002. APCo filed its plan with the Virginia SCC and, following Virginia SCC
approval of a settlement agreement, now operates in Virginia as a functionally
separated electric utility charging unbundled rates for its retail sales
of
electricity. The settlement agreement addressed functional separation, leaving
decisions related to legal separation for later Virginia SCC consideration.
While the electric restructuring law in Virginia established the general
framework governing the retail electric market, it required the Virginia
SCC to
issue rules and determinations implementing the law.
In
April
2007, Virginia enacted a law providing for cost-based regulation of electric
utilities’ generation/supply rates. With the return of cost-based regulation,
APCo’s generation business will again meet the criteria for application of
regulatory accounting principles under SFAS 71. Results of operations and
financial condition could be adversely affected if and when APCo is required
to
re-establish certain net regulatory liabilities applicable to its
generation/supply business. The timing and one-time earnings effect from
such
reapplication of SFAS 71 regulatory accounting for APCo’s Virginia
generation/supply business are uncertain at this time.
There
is uncertainty as to our recovery of stranded costs resulting from industry
restructuring in Texas.
(Applies to AEP and TCC.)
Restructuring
legislation in Texas required utilities with stranded costs to use market-based
methods to value certain generating assets for determining stranded costs.
We
elected to use the sale of assets method to determine the market value of
TCC’s
generation assets for stranded cost purposes. In general terms, the amount
of
stranded costs under this market valuation methodology is the amount by which
the book value of generating assets, including regulatory assets and liabilities
that were not securitized, exceeds the market value of the generation assets,
as
measured by the net proceeds from the sale of the assets. In
May
2005, TCC filed its stranded cost quantification application with the PUCT
seeking recovery of $2.4 billion of net stranded generation costs and other
recoverable true-up items. A final order was issued in April 2006. In the
final
order, the PUCT determined TCC’s net stranded generation costs and other
recoverable true-up items to be approximately $1.475 billion. We have appealed
the PUCT’s final order seeking additional recovery consistent with the Texas
Restructuring Legislation and related rules, other parties have appealed
the
PUCT’s final order as unwarranted or too large. In a preliminary ruling filed
in
February 2007, the Texas state district court (District Court) adjudicating
the
appeal of the final order in the true-up proceeding found that the PUCT erred
in
several respects, including the method used to determine stranded costs and
the
awarding of certain carrying costs. Following the preliminary ruling, the
court
granted a rehearing of the issue regarding the method to determine stranded
costs.
In
March
2007, the District Court judge reversed the earlier preliminary decision
concluding the sale of assets method to value TCC’s nuclear plant was
appropriate. It is expected that the parties and intervenors will appeal
various
portions of the District Court ruling along with other items to the Texas
Court
of Appeals. Management cannot predict the ultimate outcome of any future
court
appeals or any future remanded PUCT proceeding.
Risks
Related to Owning and Operating Generation Assets and Selling Power
Our
costs of compliance with environmental laws are significant and the cost
of
compliance with future environmental laws could harm our cash flow and
profitability. (Applies
to AEP and each Registrant Subsidiary other than TCC and TNC.)
Our
operations are subject to extensive federal, state and local environmental
statutes, rules and regulations relating to air quality, water quality, waste
management, natural resources and health and safety. Compliance with these
legal
requirements requires us to commit significant capital toward environmental
monitoring, installation of pollution control equipment, emission fees and
permits at all of our facilities. These expenditures have been significant
in
the past, and we expect that they will increase in the future. On April 2,
2007,
the U.S. Supreme Court issued a decision holding that the Federal EPA has
authority to regulate emissions of CO2
and
other
greenhouse gases under the CAA. Costs of compliance with environmental
regulations could adversely affect our results of operations and financial
position, especially if emission and/or discharge limits are tightened, more
extensive permitting requirements are imposed, additional substances become
regulated and the number and types of assets we operate increase. All of
our
estimates are subject to significant uncertainties about the outcome of several
interrelated assumptions and variables, including timing of implementation,
required levels of reductions, allocation requirements of the new rules and
our
selected compliance alternatives. As a result, we cannot estimate our compliance
costs with certainty. The actual costs to comply could differ significantly
from
our estimates. All of the costs are incremental to our current investment
base
and operating cost structure.
If
Federal and/or State requirements are imposed on electric utility companies
mandating further emission reductions, including limitations on
CO2
emissions,
such requirements could make some of our electric generating units uneconomical
to maintain or operate. (Applies
to AEP and each Registrant Subsidiary other than TCC and TNC.)
Emissions
of nitrogen and sulfur oxides, mercury and particulates from fossil fueled
generating plants are potentially subject to increased regulations, controls
and
mitigation expenses. Environmental advocacy groups, other organizations and
some
agencies in the United States are focusing considerable attention on
CO2
emissions from power generation facilities and their potential role in climate
change. Although several bills have been introduced in Congress that would
compel CO2
emission
reductions, none have advanced through the legislature. On April 2, 2007,
the
U.S. Supreme Court issued a decision holding that the Federal EPA has authority
to regulate emissions of CO2
and
other greenhouse gases under the CAA. Future changes in environmental
regulations governing these pollutants could make some of our electric
generating units uneconomical to maintain or operate. In addition, any legal
obligation that would require us to substantially reduce our emissions beyond
present levels could require extensive mitigation efforts and, in the case
of
CO2
legislation, would raise uncertainty about the future viability of fossil
fuels,
particularly coal, as an energy source for new and existing electric generation
facilities. While mandatory requirements for further emission reductions
from
our fossil fleet do not appear to be imminent, we continue to monitor regulatory
and legislative developments in this area.
Governmental
authorities may assess penalties on us if it is determined that we have not
complied with environmental laws and regulations. (Applies
to AEP and each Registrant Subsidiary other than TCC and TNC.)
If
we
fail to comply with environmental laws and regulations, even if caused by
factors beyond our control, that failure may result in the assessment of
civil
or criminal penalties and fines against us. Recent lawsuits by the Federal
EPA
and various states filed against us highlight the environmental risks faced
by
generating facilities, in general, and coal-fired generating facilities,
in
particular.
Since
1999, we have been involved in litigation regarding generating plant emissions
under the CAA. The Federal EPA and a number of states alleged that we and
other
unaffiliated utilities modified certain units at coal-fired generating plants
in
violation of the CAA. The Federal EPA filed complaints against certain AEP
subsidiaries in U.S. District Court for the Southern District of Ohio. A
separate lawsuit initiated by certain special interest groups was consolidated
with the Federal EPA case. The alleged modification of the generating units
occurred over a 20-year period. A
bench
trial on the liability issues was held during July 2005. Briefing has concluded
and the court has indicated an intent to issue a decision on
liability.
Additionally, in July 2004 attorneys general of eight states and others sued
AEP
and other utilities alleging that CO2
emissions from power generating facilities constitute a public nuisance under
federal common law. The trial court dismissed the suits and plaintiffs have
appealed the dismissal. While we believe the claims are without merit, the
costs
associated with reducing CO2
emissions could harm our business and our results of operations and financial
position.
If
these
or other future actions are resolved against us, substantial modifications
of
our existing coal-fired power plants could be required. In addition, we could
be
required to invest significantly in additional emission control equipment,
accelerate the timing of capital expenditures, pay penalties and/or halt
operations. Moreover, our results of operations and financial position could
be
reduced due to the timing of recovery of these investments and the expense
of
ongoing litigation.
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, 2007 of
equity
securities that are registered by AEP (or its publicly-traded subsidiaries)
pursuant to Section 12 of the Exchange Act:
ISSUER
PURCHASES OF EQUITY SECURITIES
Period
|
|
Total
Number
of
Shares
Purchased
|
|
Average
Price
Paid
per Share
|
|
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans
or
Programs
|
|
Maximum
Number (or Approximate Dollar Value) of Shares that May Yet Be
Purchased
Under the Plans or Programs
|
|
01/01/07
- 01/31/07
|
|
|
30
|
(a)
|
$
|
79
|
|
|
|
-
|
|
$
|
-
|
|
02/01/07
- 02/28/07
|
|
|
-
|
|
|
-
|
|
|
|
-
|
|
|
-
|
|
03/01/07
- 03/31/07
|
|
|
-
|
|
|
-
|
|
|
|
-
|
|
|
-
|
|
(a)
|
OPCo
repurchased 30 shares of its 4.40% cumulative preferred stock,
in a
privately-negotiated transaction outside of an announced
program.
|
Item
5. Other
Information
NONE
Item
6. Exhibits
AEP,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
12
-
Computation of Consolidated Ratio of Earnings to Fixed Charges.
AEP
31(a)
-
Certification of AEP Chief Executive Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31(c)
-
Certification of AEP Chief Financial Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
31(b)
-
Certification of Registrant Subsidiaries’ Chief Executive Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
31(d)
-
Certification of Registrant Subsidiaries’ Chief Financial Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
AEP,
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and
TNC
32(a)
-
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter
63
of Title 18 of the United States Code.
32(b)
-
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter
63
of Title 18 of the United States Code.
Pursuant
to the requirements of the Securities Exchange Act of 1934, each registrant
has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized. The signature for each undersigned company shall be deemed
to
relate only to matters having reference to such company and any subsidiaries
thereof.
AMERICAN
ELECTRIC POWER COMPANY, INC.
By: /s/Joseph
M. Buonaiuto
Joseph
M.
Buonaiuto
Controller
and Chief
Accounting Officer
AEP
GENERATING COMPANY
AEP
TEXAS
CENTRAL COMPANY
AEP
TEXAS
NORTH COMPANY
APPALACHIAN
POWER COMPANY
COLUMBUS
SOUTHERN POWER COMPANY
INDIANA
MICHIGAN POWER COMPANY
KENTUCKY
POWER COMPANY
OHIO
POWER COMPANY
PUBLIC
SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN
ELECTRIC POWER COMPANY
By: /s/Joseph
M. Buonaiuto
Joseph
M.
Buonaiuto
Controller
and Chief
Accounting Officer
Date:
May
4, 2007