Unassociated Document
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE
SECURITIES EXCHANGE ACT OF 1934
For
The
Quarterly Period Ended September 30, 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
|
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
|
1-6543
|
|
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 Appalachian Power Company, Columbus Southern
Power
Company, Indiana Michigan Power Company, Ohio Power Company, Public
Service Company of Oklahoma and Southwestern Electric Power Company,
are
large accelerated filers, accelerated filers, 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
|
Columbus
Southern Power Company, Indiana Michigan 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
October
31, 2007
|
|
|
|
|
American
Electric Power Company, Inc.
|
|
|
400,006,022
|
|
|
|
($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)
|
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
September
30, 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
|
|
|
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
|
|
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
|
|
|
|
Part
II. OTHER INFORMATION
|
|
|
Item
1.
|
Legal
Proceedings
|
|
Item
1A.
|
Risk
Factors
|
|
Item
2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
|
Item
4.
|
Submission
of Matters to a Vote of Security Holders
|
|
Item
5.
|
Other
Information
|
|
Item
6.
|
Exhibits:
|
|
|
|
|
|
Exhibit
12
|
|
|
|
|
|
Exhibit
31(a)
|
|
|
|
|
|
Exhibit
31(b)
|
|
|
|
|
|
Exhibit
31(c)
|
|
|
|
|
|
Exhibit
31(d)
|
|
|
|
|
|
Exhibit
32(a)
|
|
|
|
|
|
Exhibit
32(b)
|
|
|
|
|
|
|
SIGNATURE
|
|
This
combined Form 10-Q is separately filed by American Electric Power
Company,
Inc., Appalachian Power Company, Columbus Southern Power Company,
Indiana
Michigan Power Company, Ohio Power Company, Public Service Company
of
Oklahoma and Southwestern Electric Power Company. Information
contained herein relating to any individual registrant is filed by
such
registrant on its own behalf. Each registrant makes no representation
as
to information relating to the other
registrants.
|
When
the following terms and abbreviations appear in the text of this report, they
have the meanings indicated below.
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.
|
AEP
West companies
|
|
PSO,
SWEPCo, TCC and TNC.
|
AEPEP
|
|
AEP
Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale
marketing and trading, asset management and commercial and industrial
sales in the deregulated Texas market.
|
AEPSC
|
|
American
Electric Power Service Corporation, a service subsidiary providing
management and professional services to AEP and its
subsidiaries.
|
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.).
|
CTC
|
|
Competition
Transition Charge.
|
DETM
|
|
Duke
Energy Trading and Marketing L.L.C., a risk management
counterparty.
|
DOJ
|
|
United
States Department of Justice.
|
E&R
|
|
Environmental
compliance and transmission and distribution system
reliability.
|
EDFIT
|
|
Excess
Deferred Federal Income Taxes.
|
EITF
|
|
Financial
Accounting Standards Board’s Emerging Issues Task
Force.
|
ERCOT
|
|
Electric
Reliability Council of Texas.
|
FASB
|
|
Financial
Accounting Standards Board.
|
Federal
EPA
|
|
United
States Environmental Protection Agency.
|
FERC
|
|
Federal
Energy Regulatory Commission.
|
FIN
|
|
FASB
Interpretation No.
|
FIN
46
|
|
FIN
46, “Consolidation of Variable Interest Entities.”
|
FIN
48
|
|
FIN
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.
|
IRS
|
|
Internal
Revenue Service.
|
IURC
|
|
Indiana
Utility Regulatory Commission.
|
I&M
|
|
Indiana
Michigan Power Company, an AEP electric utility
subsidiary.
|
JMG
|
|
JMG
Funding LP.
|
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.
|
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; APCo, CSPCo, I&M, OPCo, PSO,
SWEPCo.
|
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
|
|
Ohio
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
157
|
|
Statement
of Financial Accounting Standards No. 157, “Fair Value
Measurements.”
|
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.
|
Stall
Unit
|
|
J.
Lamar Stall Unit at Arsenal Hill Plant.
|
Sweeny
|
|
Sweeny
Cogeneration Limited Partnership, owner and operator of a four unit,
480
MW gas-fired generation facility, owned 50% by AEP.
|
SWEPCo
|
|
Southwestern
Electric Power Company, an AEP electric utility
subsidiary.
|
TCC
|
|
AEP
Texas Central Company, an AEP electric utility
subsidiary.
|
TEM
|
|
SUEZ
Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing,
Inc.).
|
Texas
Restructuring Legislation
|
|
Legislation
enacted in 1999 to restructure the electric utility industry in
Texas.
|
TNC
|
|
AEP
Texas North Company, an AEP electric utility
subsidiary.
|
True-up
Proceeding
|
|
A
filing made under the Texas Restructuring Legislation to finalize
the
amount of stranded costs and other true-up items and the recovery
of such
amounts.
|
Turk
Plant
|
|
John
W. Turk Jr. Plant.
|
Utility
Money Pool
|
|
AEP
System’s Utility Money Pool.
|
VaR
|
|
Value
at Risk, a method to quantify risk exposure.
|
Virginia
SCC
|
|
Virginia
State Corporation Commission.
|
WPCo
|
|
Wheeling
Power Company, an AEP electric distribution subsidiary.
|
WVPSC
|
|
Public
Service Commission of West
Virginia.
|
FORWARD-LOOKING
INFORMATION
This
report made by AEP and its Registrant Subsidiaries contains forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act
of
1934. Although AEP and each of its Registrant Subsidiaries believe
that their expectations are based on reasonable assumptions, any such statements
may be influenced by factors that could cause actual outcomes and results to
be
materially different from those projected. Among the factors that
could cause actual results to differ materially from those in the
forward-looking statements are:
·
|
Electric
load and customer growth.
|
·
|
Weather
conditions, including storms.
|
·
|
Available
sources and costs of, and transportation for, fuels and the
creditworthiness and performance of fuel suppliers and
transporters.
|
·
|
Availability
of generating capacity and the performance of our generating
plants.
|
·
|
Our
ability to recover regulatory assets and stranded costs in connection
with
deregulation.
|
·
|
Our
ability to recover increases in fuel and other energy costs through
regulated or competitive electric rates.
|
·
|
Our
ability to build or acquire generating capacity (including our ability
to
obtain any necessary regulatory approvals and permits) when needed
at
acceptable prices and terms and to recover those costs 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 the potential for new legislation
in Ohio
and membership in and integration into RTOs.
|
·
|
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
The
status of base rate filings ongoing or finalized this year with implemented
rates are:
Operating
Company
|
|
Jurisdiction
|
|
Revised
Annual Rate Increase Request
|
|
Implemented
Annual Rate Increase
|
|
Projected
or
Effective
Date of Rate Increase
|
|
Date
of
Final
Order
|
|
|
|
|
|
(in
millions)
|
|
|
|
|
|
APCo
|
|
Virginia
|
|
$
|
198
|
(a)
|
$
|
24
|
(a)
|
October
2006
|
|
May
2007
|
|
OPCo
|
|
Ohio
|
|
|
8
|
|
|
4
|
(b)
|
May
2007
|
|
October
2007
|
|
CSPCo
|
|
Ohio
|
|
|
24
|
|
|
19
|
(b)
|
May
2007
|
|
October
2007
|
|
TCC
|
|
Texas
|
|
|
70
|
|
|
47
|
|
June
2007
|
|
October
2007
|
|
TNC
|
|
Texas
|
|
|
22
|
|
|
14
|
|
June
2007
|
|
May
2007
|
|
PSO
|
|
Oklahoma
|
|
|
48
|
|
|
10
|
(c)
|
July
2007
|
|
October
2007
|
|
OPCo
|
|
Ohio
|
|
|
12
|
|
|
NA
|
|
January
2008
|
|
NA
|
|
CSPCo
|
|
Ohio
|
|
|
35
|
|
|
NA
|
|
January
2008
|
|
NA
|
|
(a)
|
The
difference between the requested and implemented amounts of annual
rate
increase is partially offset by approximately $35 million of incremental
E&R costs which APCo has reflected as a regulatory
asset. APCo will file for recovery through the E&R
surcharge mechanism in 2008. APCo also implemented, beginning
September 1, 2007 subject to refund, a net $50 million reduction
in
credits to customers for off-system sales margins as part of its
July 2007
fuel clause filing under the new re-regulation
legislation.
|
(b)
|
Management
plans to seek rehearing of the PUCO decision.
|
(c)
|
Implemented
$9 million in July 2007, increased to $10 million upon OCC order
in
October 2007.
|
In
Virginia, APCo filed the following non-base rate requests in July 2007 with
the
Virginia SCC:
Operating
Company
|
|
Jurisdiction
|
|
Cost
Type
|
|
Request
|
|
Implemented
Annual Rate Increase
|
|
Projected
or Effective Date of Rate Increase
|
|
Date
of
Final
Order
|
|
|
|
|
|
|
(in
millions)
|
|
|
|
|
APCo
|
|
Virginia
|
|
Incremental
E&R
|
|
$
|
60
|
|
$
|
NA
|
|
December
2007
|
|
NA
|
APCo
|
|
Virginia
|
|
Fuel,
Off-system Sales
|
|
|
33
|
|
|
33
|
(a)
|
September
2007
|
|
(a)
|
(a)
|
Subject
to refund. Proceeding is
on-going.
|
Ohio
Restructuring
As
permitted by the current Ohio restructuring legislation, CSPCo and OPCo can
implement market-based rates effective January 2009, following the expiration
of
its RSPs on December 31, 2008. In August 2007, legislation was
introduced that would significantly reduce the likelihood of CSPCo’s and OPCo’s
ability to charge market-based rates for generation at the expiration of their
RSPs. In place of market-based rates, it is more likely that some
form of cost-based rates or hybrid-based rates would be required. The
legislation passed through the Ohio Senate and still must be considered by
the
Ohio House of Representatives. Management continues to analyze the
proposed legislation and is working with various stakeholders to achieve a
principled, fair and well-considered approach to electric supply
pricing. At this time, management is unable to predict whether CSPCo
and OPCo will transition to market pricing, 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.
SWEPCo
and PSO Construction Costs
SWEPCo
has incurred pre-construction and equipment procurement costs of $206 million
and $15 million related to its Turk and Stall plant construction projects,
respectively. In September 2007, the PUCT staff recommended that
SWEPCo’s application to build the Turk Plant be denied suggesting the
construction of the plant would adversely impact the development of competition
in the SPP zone. In the filings to date, both the APSC and LPSC
staffs have supported the Turk Plant project. Neither the PUCT, the
APSC nor the LPSC have issued final orders regarding the Turk
Plant.
PSO
has
deferred pre-construction costs of $20 million related to its Red Rock
Generating Facility construction project. In October 2007, the
OCC issued a final order denying PSO’s application for pre-approval of the Red
Rock project stating PSO failed to fully study other
alternatives. PSO has cancelled the project and intends to seek
recovery of the $20 million.
Michigan
Depreciation Study Filing
In
September 2007, the Michigan Public Service Commission (MPSC) approved a
settlement agreement authorizing I&M to implement new book depreciation
rates. Based on the depreciation study included in the settlement,
I&M agreed to decrease pretax annual depreciation expense, on a Michigan
jurisdictional basis, by approximately $10 million. This petition was
not a request for a change in retail customers’ electric service
rates. In
addition and as a result of the new MPSC-approved rates, I&M will decrease
pretax annual depreciation expense, on a FERC jurisdictional basis, by
approximately $11 million which will reduce wholesale rates for customers
representing approximately half the load beginning in November 2007 and reduce
wholesale rates for the remaining customers in June 2008.
Dividend
Increase
In
October 2007, our Board of Directors approved a five percent increase in our
quarterly dividend to $0.41 per share from $0.39 per share.
Investment
Activity
In
September 2007, AEGCo purchased the partially completed 580 MW Dresden Plant
from Dominion Resources, Inc. for $85 million and the assumption of liabilities
of $2 million. Management estimates that approximately $180 million
in additional costs (excluding AFUDC) will be required to finish the
construction of the plant.
In
October 2007, we sold our 50% equity interest in the Sweeny Cogeneration Plant
(Sweeny) to ConocoPhillips for approximately $80 million, including working
capital and the buyer’s assumption of project debt. In addition to
the sale of our interest in Sweeny, we agreed to separately sell our purchase
power contract for our share of power generated by Sweeny through 2014 for
$11
million to ConocoPhillips. ConocoPhillips also agreed to assume certain related
third-party power obligations. In the fourth quarter of 2007, we
estimate that we will realize a total of $57 million in pretax gains related
to
the sales of our investment in the Sweeny Plant and the related purchase power
contracts.
Environmental
Litigation
In
October 2007, we announced that we had reached a settlement agreement with
the
Federal EPA, the DOJ, various states and special interest
groups. Under the New Source Review (NSR) settlement agreement, we
agreed to invest in additional environmental controls for our plants before
2019. We will also pay a $15 million civil penalty and provide $36
million for environmental projects coordinated with the federal government
and
$24 million to the states for environmental mitigation. In the third
quarter of 2007, we expensed $77 million (before tax) related to the penalty
and
the environmental mitigation projects.
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, 30% relates to agricultural
products, 18% relates to steel and 17% relates to other
commodities.
|
Generation
and Marketing
·
|
IPPs,
wind farms and marketing and risk management activities primarily
in
ERCOT. Our 50% interest in the Sweeny Cogeneration Plant was
sold in October 2007.
|
The
table
below presents our consolidated Income Before Discontinued Operations and
Extraordinary Loss for the three and nine months ended September 30, 2007 and
2006. We reclassified prior year amounts to conform to the current
year’s segment presentation.
|
|
Three
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Utility
Operations
|
|
$ |
388
|
|
|
$ |
378
|
|
|
$ |
879
|
|
|
$ |
902
|
|
MEMCO
Operations
|
|
|
18
|
|
|
|
19
|
|
|
|
40
|
|
|
|
54
|
|
Generation
and Marketing
|
|
|
3
|
|
|
|
4
|
|
|
|
17
|
|
|
|
10
|
|
All
Other (a)
|
|
|
(2 |
) |
|
|
(136 |
) |
|
|
(1 |
) |
|
|
(151 |
) |
Income
Before Discontinued Operations
and
Extraordinary Loss
|
|
$ |
407
|
|
|
$ |
265
|
|
|
$ |
935
|
|
|
$ |
815
|
|
(a)
|
All
Other includes:
|
|
·
|
Parent’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.
|
Third
Quarter of 2007 Compared to Third Quarter of 2006
Income
Before Discontinued Operations and Extraordinary Loss in 2007
increased $142 million compared to 2006 primarily due to a $136 million
after-tax impairment of the Plaquemine Cogeneration Facility recorded in August
2006.
Average
basic shares outstanding for the three-month period increased to 399
million in 2007 from 394 million in 2006 primarily due to the issuance of shares
under our incentive compensation plans. At September 30, 2007, actual
shares outstanding were 400 million.
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Income
Before Discontinued Operations and Extraordinary Loss in 2007 increased $120
million compared to 2006 primarily due to a $136 million after-tax impairment
of
the Plaquemine Cogeneration Facility recorded in 2006. This increase
was partially offset by a decrease in earnings of $23 million from our Utility
Operations segment. The decrease in Utility Operations segment
earnings primarily relates to higher operation and maintenance expenses due
to
the NSR settlement, higher regulatory amortization expense, higher interest
expense and lower earnings-sharing payments from Centrica received in March
2007, representing the last payment under an earnings-sharing
agreement. These decreases in earnings were partially offset by rate
increases, increased residential and commercial usage and customer growth and
favorable weather.
Average
basic shares outstanding for the nine-month period increased to 398 million
in 2007 from 394 million in 2006 primarily due to the issuance of shares under
our incentive compensation plans. At September 30, 2007, actual
shares outstanding were 400 million.
Utility
Operations
Our
Utility Operations segment includes primarily regulated revenues with direct
and
variable offsetting expenses and net reported commodity trading
operations. We believe that a discussion of the results from our
Utility Operations segment on a gross margin basis is most appropriate in order
to further understand the key drivers of the segment. Gross margin
represents utility operating revenues less the related direct cost of fuel,
including consumption of chemicals and emissions allowances and purchased
power.
Utility
Operations Income Summary
For
the Three and Nine Months Ended September 30, 2007 and
2006
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Revenues
|
|
$ |
3,600
|
|
|
$ |
3,437
|
|
|
$ |
9,587
|
|
|
$ |
9,199
|
|
Fuel
and Purchased Power
|
|
|
1,413
|
|
|
|
1,384
|
|
|
|
3,641
|
|
|
|
3,633
|
|
Gross
Margin
|
|
|
2,187
|
|
|
|
2,053
|
|
|
|
5,946
|
|
|
|
5,566
|
|
Depreciation
and Amortization
|
|
|
374
|
|
|
|
374
|
|
|
|
1,122
|
|
|
|
1,060
|
|
Other
Operating Expenses
|
|
|
1,037
|
|
|
|
962
|
|
|
|
2,985
|
|
|
|
2,781
|
|
Operating
Income
|
|
|
776
|
|
|
|
717
|
|
|
|
1,839
|
|
|
|
1,725
|
|
Other
Income, Net
|
|
|
27
|
|
|
|
18
|
|
|
|
72
|
|
|
|
103
|
|
Interest
Charges and Preferred Stock Dividend Requirements
|
|
|
213
|
|
|
|
160
|
|
|
|
599
|
|
|
|
475
|
|
Income
Tax Expense
|
|
|
202
|
|
|
|
197
|
|
|
|
433
|
|
|
|
451
|
|
Income
Before Discontinued Operations and Extraordinary
Loss
|
|
$ |
388
|
|
|
$ |
378
|
|
|
$ |
879
|
|
|
$ |
902
|
|
Summary
of Selected Sales and Weather Data
For
Utility Operations
For
the Three and Nine Months Ended September 30, 2007 and
2006
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
Energy/Delivery
Summary
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions of KWH)
|
|
Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
13,749
|
|
|
|
13,482
|
|
|
|
38,015
|
|
|
|
36,010
|
|
Commercial
|
|
|
11,164
|
|
|
|
10,799
|
|
|
|
30,750
|
|
|
|
29,149
|
|
Industrial
|
|
|
14,697
|
|
|
|
13,468
|
|
|
|
43,110
|
|
|
|
40,405
|
|
Miscellaneous
|
|
|
686
|
|
|
|
719
|
|
|
|
1,932
|
|
|
|
1,991
|
|
Total
Retail
|
|
|
40,296
|
|
|
|
38,468
|
|
|
|
113,807
|
|
|
|
107,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
|
13,493
|
|
|
|
13,464
|
|
|
|
31,648
|
|
|
|
35,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivery
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
Wires – Energy delivered to customers served
by
AEP’s Texas Wires Companies
|
|
|
7,721
|
|
|
|
7,877
|
|
|
|
20,297
|
|
|
|
20,338
|
|
Total
KWHs
|
|
|
61,510
|
|
|
|
59,809
|
|
|
|
165,752
|
|
|
|
163,025
|
|
Cooling
degree days and heating degree days are metrics commonly used in the utility
industry as a measure of the impact of weather on results of
operations. In general, degree day changes in our eastern region have
a larger effect on results of operations than changes in our western region
due
to the relative size of the two regions and the associated number of customers
within each.
Summary
of Heating and Cooling Degree Days for Utility Operations
For
the Three and Nine Months Ended September 30, 2007 and
2006
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
degree days)
|
|
Weather
Summary
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern
Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Heating (a)
|
|
|
2
|
|
|
|
10
|
|
|
|
2,041
|
|
|
|
1,573
|
|
Normal
– Heating (b)
|
|
|
7
|
|
|
|
7
|
|
|
|
1,973
|
|
|
|
1,999
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Cooling (c)
|
|
|
808
|
|
|
|
685
|
|
|
|
1,189
|
|
|
|
914
|
|
Normal
– Cooling (b)
|
|
|
685
|
|
|
|
688
|
|
|
|
963
|
|
|
|
970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western
Region (d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Heating (a)
|
|
|
0
|
|
|
|
0
|
|
|
|
994
|
|
|
|
664
|
|
Normal
– Heating (b)
|
|
|
2
|
|
|
|
2
|
|
|
|
993
|
|
|
|
1,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Cooling (c)
|
|
|
1,406
|
|
|
|
1,468
|
|
|
|
2,084
|
|
|
|
2,325
|
|
Normal
– Cooling (b)
|
|
|
1,411
|
|
|
|
1,410
|
|
|
|
2,084
|
|
|
|
2,079
|
|
(a)
|
Eastern
region and western region heating degree days are calculated on a
55
degree temperature base.
|
(b)
|
Normal
Heating/Cooling represents the thirty-year average of degree
days.
|
(c)
|
Eastern
region and western region cooling degree days are calculated on a
65
degree temperature base.
|
(d)
|
Western
region statistics represent PSO/SWEPCo customer base
only.
|
Third
Quarter of 2007 Compared to Third Quarter of 2006
Reconciliation
of Third Quarter of 2006 to Third Quarter of 2007
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss
(in
millions)
Third
Quarter of 2006
|
|
|
|
|
$ |
378
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
155
|
|
|
|
|
|
Off-system
Sales
|
|
|
36
|
|
|
|
|
|
Transmission
Revenues, Net
|
|
|
(58 |
) |
|
|
|
|
Other
Revenues
|
|
|
1
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
134
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(69 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(6 |
) |
|
|
|
|
Carrying
Costs Income
|
|
|
11
|
|
|
|
|
|
Other
Income, Net
|
|
|
(2 |
) |
|
|
|
|
Interest
and Other Charges
|
|
|
(53 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(119 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
Third
Quarter of 2007
|
|
|
|
|
|
$ |
388
|
|
Income
from Utility Operations Before Discontinued Operations and Extraordinary Loss
increased $10 million to $388 million in 2007. The key driver of the
increase was a $134 million increase in Gross Margin partially offset by a
$119
million increase in Operating Expenses and Other and a $5 million increase
in
Income Tax Expense.
The
major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $155 million primarily due to the
following:
|
|
·
|
A
$29 million increase at APCo related to the Virginia base rate case
and
the West Virginia construction surcharge.
|
|
·
|
A
$29 million increase related to Ormet, a new industrial customer
in Ohio,
effective January 1, 2007. See “Ormet” section of Note
3.
|
|
·
|
A
$23 million increase related to increased residential and commercial
usage
and customer growth.
|
|
·
|
A
$16 million increase in usage related to weather. As compared
to the prior year, our eastern region experienced an 18% increase
in
cooling degree days partially offset by a 4% decrease in cooling
degree
days in our western region.
|
|
·
|
A
$15 million increase related to new rates implemented in our Ohio
jurisdictions as approved by the PUCO in our RSPs.
|
|
·
|
A
$15 million increase related to new rates in Texas.
|
|
·
|
A
$14 million increase related to increased sales to municipal, cooperative
and other customers primarily resulting from new power supply
contracts.
|
|
These
increases were partially offset by:
|
|
·
|
A
$15 million decrease in financial transmission rights revenue, net
of
congestion, primarily due to fewer transmission constraints within
the PJM
market. Financial
transmission rights are financial instruments which entitle the holder
to
receive compensation for transmission charges that arise when the
PJM
market is congested.
|
·
|
Margins
from Off-system Sales increased $36 million primarily due to favorable
fuel reconciliations in our western territory, benefits from our
eastern
natural gas fleet, higher power prices, and higher sales volumes
in the
east.
|
·
|
Transmission
Revenues, Net decreased $58 million primarily due to PJM’s revision of its
pricing methodology for transmission line losses to marginal-loss
pricing
effective June 1, 2007. See “PJM Marginal-Loss Pricing” section
of Note 3.
|
·
|
Other
Revenues were essentially flat as a result of higher securitization
revenue at TCC from the $1.7 billion securitization in October 2006
partially offset by lower gains on sale of emission
allowances. Securitization revenue represents amounts collected
to recover securitization bond principal and interest payments related
to
TCC’s securitized transition assets and are fully offset by amortization
and interest expenses.
|
Utility
Operating Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $69 million primarily
due to
the NSR settlement partially offset by an abandonment of digital
turbine
control equipment at the Cook Plant recorded in the prior
year. See “Federal EPA Complaint and Notice of Violation”
section in Note 4.
|
·
|
Depreciation
and Amortization expense was flat as a result of increased Texas
amortization of the securitized transition assets and overall higher
depreciable property balances, offset by lower depreciation expense
at
I&M and APCo. The decrease at I&M relates to the lower
depreciation rates approved by the IURC in June 2007. The
decrease at APCo relates to the lower depreciation rates approved
by the
Virginia SCC in May 2007 and adjustments in the prior period related
to
the 2006 Virginia E&R case.
|
·
|
Carrying
Costs Income increased $11 million primarily due to higher carrying
cost
income related to APCo’s Virginia E&R cost deferrals offset by TCC’s
start in recovering stranded costs in October 2006, thus eliminating
future TCC carrying costs income.
|
·
|
Interest
and Other Charges increased $53 million primarily due to additional
debt
issued in the twelve months ended September 30, 2007 including TCC
securitization bonds as well as higher rates on variable rate
debt.
|
·
|
Income
Tax Expense increased $5 million due to an increase in pretax
income.
|
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Reconciliation
of Nine Months Ended September 30, 2006 to Nine Months Ended September 30,
2007
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss
(in
millions)
Nine
Months Ended September 30, 2006
|
|
|
|
|
$ |
902
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
383
|
|
|
|
|
|
Off-system
Sales
|
|
|
49
|
|
|
|
|
|
Transmission
Revenues, Net
|
|
|
(87 |
) |
|
|
|
|
Other
Revenues
|
|
|
35
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
380
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(154 |
) |
|
|
|
|
Gain
on Dispositions of Assets, Net
|
|
|
(47 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(62 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(3 |
) |
|
|
|
|
Carrying
Costs Income
|
|
|
(28 |
) |
|
|
|
|
Other
Income, Net
|
|
|
(3 |
) |
|
|
|
|
Interest
and Other Charges
|
|
|
(124 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(421 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
$ |
879
|
|
Income
from Utility Operations Before Discontinued Operations and Extraordinary Loss
decreased $23 million to $879 million in 2007. The key driver of the
decrease was a $421 million increase in Operating Expenses and Other, offset
by
a $380 million increase in Gross Margin and an $18 million decrease in Income
Tax Expense.
The
major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $383 million primarily due to the
following:
|
|
·
|
An
$84 million increase related to new rates implemented in our Ohio
jurisdictions as approved by the PUCO in our RSPs, a $51 million
increase
related to new rates implemented in our other east jurisdictions
of
Virginia, West Virginia and Kentucky and a $23 million increase related
to
new rates in Texas and a $9 million increase related to new rates
in
Oklahoma.
|
|
·
|
A
$93 million increase related to increased residential and commercial
usage
and customer growth.
|
|
·
|
An
$83 million increase in usage related to weather. As compared
to the prior year, our eastern region and western region experienced
30%
and 50% increases, respectively, in heating degree days. Also,
our eastern region experienced a 30% increase in cooling degree days
which
was offset by a 10% decrease in cooling degree days in our western
region.
|
|
·
|
A
$66 million increase related to Ormet, a new industrial customer
in Ohio,
effective January 1, 2007. See “Ormet” section of Note
3.
|
|
·
|
A
$35 million increase related to increased sales to municipal, cooperative
and other wholesale customers primarily resulting from new power
supply
contracts.
|
|
These
increases were partially offset by:
|
|
·
|
A
$63 million decrease in financial transmission rights revenue, net
of
congestion, primarily due to fewer transmission constraints within
the PJM
market.
|
|
·
|
A
$25 million decrease due to a second quarter 2007 provision related
to a
SWEPCo Texas fuel reconciliation proceeding. See “SWEPCo Fuel
Reconciliation – Texas” section of Note 3.
|
|
·
|
A
$14 million decrease related to increased PJM ancillary
costs.
|
·
|
Margins
from Off-system Sales increased $49 million primarily due to strong
trading performance and favorable fuel reconciliations in our western
territory.
|
·
|
Transmission
Revenues, Net decreased $87 million primarily due to PJM’s revision of its
pricing methodology for transmission line losses to marginal-loss
pricing
effective June 1, 2007. See “PJM Marginal-Loss Pricing” section
of Note 3.
|
·
|
Other
Revenues increased $35 million primarily due to higher securitization
revenue at TCC resulting from the $1.7 billion securitization in
October
2006. Securitization revenue represents amounts collected to
recover securitization bond principal and interest payments related
to
TCC’s securitized transition assets and are fully offset by amortization
and interest expenses.
|
Utility
Operating Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $154 million primarily
due to
a $77 million expense resulting from the NSR settlement. The
remaining increases relate to generation expenses from plant outages
and
base operations and distribution expenses associated with service
reliability and storm restoration primarily in
Oklahoma.
|
·
|
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 expired.
|
·
|
Depreciation
and Amortization expense increased $62 million primarily due to increased
Ohio regulatory asset amortization related to recovery of IGCC
pre-construction costs, increased Texas amortization of the securitized
transition assets and higher depreciable property balances, partially
offset by commission-approved lower depreciation rates in Indiana
and
Virginia.
|
·
|
Carrying
Costs Income decreased $28 million primarily due to TCC’s start in
recovering stranded costs in October 2006, thus eliminating future
TCC
carrying costs income, offset by higher carrying costs income related
to
APCo’s Virginia E&R cost deferrals.
|
·
|
Interest
and Other Charges increased $124 million primarily due to additional
debt
issued in the twelve months ended September 30, 2007 including TCC
securitization bonds as well as higher rates on variable rate
debt.
|
·
|
Income
Tax Expense decreased $18 million due to a decrease in pretax
income.
|
MEMCO
Operations
Third
Quarter of 2007 Compared to Third Quarter of 2006
Income
Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations
segment decreased from $19 million in 2006 to $18 million in
2007. Operating expenses increased $2 million mainly due to the
increased fleet size, rising fuel costs and wage increases.
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Income
Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations
segment decreased from $54 million in 2006 to $40 million in
2007. MEMCO operated approximately 11% more barges in the first nine
months of 2007 than 2006; however, revenue remained flat as reduced imports,
primarily steel and cement continued to depress freight rates and reduce
northbound loadings. Operating expenses were up for the first nine
months of 2007 compared to 2006 primarily due to the cost of the increased
fleet
size, rising fuel costs and wage increases.
Generation
and Marketing
Third
Quarter of 2007 Compared to Third Quarter of 2006
Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment slightly decreased from $4 million in 2006 to $3 million
in
2007. The decrease was primarily due to increased purchased power and
operating expenses. The decrease was partially offset by increases in
revenues primarily due to certain existing ERCOT energy contracts, which were
transferred from our Utility Operations segment on January 1, 2007, and
favorable marketing contracts with municipalities and cooperatives in
ERCOT.
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment increased from $10 million in 2006 to $17 million in
2007. Revenues increased primarily due to certain existing ERCOT
energy contracts, which were transferred from our Utility Operations segment
on
January 1, 2007, and favorable marketing contracts with municipalities and
cooperatives in ERCOT. The increase in revenues was partially offset
by increased purchased power and operating expenses.
All
Other
Third
Quarter of 2007 Compared to Third Quarter of 2006
Loss
Before Discontinued Operations and Extraordinary Loss from All Other decreased
from $136 million in 2006 to $2 million in 2007. The decrease was
primarily due to a $136 million after-tax impairment of the Plaquemine
Cogeneration Facility recorded in August 2006.
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Loss
Before Discontinued Operations and Extraordinary Loss from All Other decreased
from $151 million in 2006 to $1 million in 2007. In 2006, we recorded
a $136 million after-tax impairment 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 increased $72 million in the third quarter of 2007 compared to
the
third quarter of 2006 primarily due to an increase in pretax book
income.
Income
Tax Expense increased $49 million for the nine months ended September 30, 2007
compared to the nine months ended September 30, 2006 primarily due to an
increase in pretax book income.
FINANCIAL
CONDITION
We
measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.
Debt
and Equity Capitalization
|
|
September
30, 2007
|
|
|
December
31, 2006
|
|
|
|
($
in millions)
|
|
Long-term
Debt, Including Amounts Due
Within One Year
|
|
$ |
14,776
|
|
|
|
58.3 |
% |
|
$ |
13,698
|
|
|
|
59.1 |
% |
Short-term
Debt
|
|
|
587
|
|
|
|
2.3
|
|
|
|
18
|
|
|
|
0.0
|
|
Total
Debt
|
|
|
15,363
|
|
|
|
60.6
|
|
|
|
13,716
|
|
|
|
59.1
|
|
Common
Equity
|
|
|
9,909
|
|
|
|
39.1
|
|
|
|
9,412
|
|
|
|
40.6
|
|
Preferred
Stock
|
|
|
61
|
|
|
|
0.3
|
|
|
|
61
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt and Equity Capitalization
|
|
$ |
25,333
|
|
|
|
100.0 |
% |
|
$ |
23,189
|
|
|
|
100.0 |
% |
Our
ratio
of debt to total capital increased, as planned, from 59.1% to 60.6% in 2007
due
to our increased borrowings to support our construction program.
Liquidity
Liquidity,
or access to cash, is an important factor in determining our financial
stability. We are committed to maintaining adequate
liquidity.
Credit
Facilities
We
manage
our liquidity by maintaining adequate external financing
commitments. At September 30, 2007, our available liquidity was
approximately $2.6 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
|
|
|
|
196
|
|
|
Total
Liquidity Sources
|
|
|
|
3,196
|
|
|
Less:
AEP Commercial Paper Outstanding
|
|
|
|
559
|
|
|
|
Letters
of Credit Drawn
|
|
|
|
69
|
|
|
|
|
|
|
|
|
|
Net
Available Liquidity
|
|
|
$
|
2,568
|
|
|
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.
Sale
of Receivables
In
October 2007, we renewed our sale of receivables agreement. The sale
of receivables agreement provides a commitment of $650 million from a bank
conduit to purchase receivables. Under the agreement, the commitment
will increase to $700 million for the months of August and September to
accommodate seasonal demand. This agreement expires in October
2008.
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 in our revolving credit agreements. At
September 30, 2007, this contractually-defined percentage was
56.3%. Nonperformance of these covenants could result in an event of
default under these credit agreements. At September 30, 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 September 30, 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 September 30, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Moody’s
|
|
|
S&P
|
|
|
Fitch
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AEP
Short Term Debt
|
P-2
|
|
|
A-2
|
|
|
F-2
|
AEP
Senior Unsecured Debt
|
Baa2
|
|
|
BBB
|
|
|
BBB
|
If
we or
any of our rated subsidiaries receive an upgrade from any of the rating agencies
listed above, our borrowing costs could decrease. If we receive a
downgrade in our credit ratings by one of the rating agencies listed above,
our
borrowing costs could increase and access to borrowed funds could be negatively
affected.
Cash
Flow
Managing
our cash flows is a major factor in maintaining our liquidity
strength.
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$ |
301
|
|
|
$ |
401
|
|
Net
Cash Flows From Operating Activities
|
|
|
1,630
|
|
|
|
2,196
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(2,935 |
) |
|
|
(2,457
|
) |
Net
Cash Flows From Financing Activities
|
|
|
1,200
|
|
|
|
119
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(105 |
) |
|
|
(142
|
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
196
|
|
|
$ |
259
|
|
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 September 30, 2007, we had credit facilities totaling
$3 billion to support our commercial paper program. The maximum
amount of commercial paper outstanding during 2007 was $865
million. The weighted-average interest rate of our commercial paper
for the nine months ended September 30, 2007 was 5.6%. 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
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Net
Income
|
|
$ |
858
|
|
|
$ |
821
|
|
Less: Discontinued
Operations, Net of Tax
|
|
|
(2 |
) |
|
|
(6 |
) |
Income
Before Discontinued Operations
|
|
|
856
|
|
|
|
815
|
|
Depreciation
and Amortization
|
|
|
1,144
|
|
|
|
1,084
|
|
Other
|
|
|
(370 |
) |
|
|
297
|
|
Net
Cash Flows From Operating Activities
|
|
$ |
1,630
|
|
|
$ |
2,196
|
|
Net
Cash
Flows From Operating Activities decreased in 2007 primarily due to lower fuel
costs recovery, higher tax payments in 2007 in conjunction with the filing
of
the 2006 tax return and increased customer accounts receivable reflecting
September 2007 weather’s impact on sales and new contracts in the Generation and
Marketing segment.
Net
Cash
Flows From Operating Activities were $1.6 billion in 2007. We produced Income
Before Discontinued Operations of $856 million adjusted for noncash expense
items, primarily depreciation and amortization. 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 of which
relates to the Texas CTC refund of fuel over-recovery.
Net
Cash
Flows From Operating Activities were $2.2 billion in 2006. We
produced Income Before Discontinued Operations of $815 million adjusted for
noncash expense items, primarily depreciation and amortization. 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 is a $235 million decrease in cash related to customer deposits
held for trading activities generally due to lower gas and power market
prices.
Investing
Activities
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Construction
Expenditures
|
|
$ |
(2,595 |
) |
|
$ |
(2,428
|
) |
Acquisition
of Darby, Dresden and Lawrenceburg Plants
|
|
|
(512 |
) |
|
|
-
|
|
Proceeds
from Sales of Assets
|
|
|
78
|
|
|
|
120
|
|
Other
|
|
|
94
|
|
|
|
(149
|
) |
Net
Cash Flows Used For Investing Activities
|
|
$ |
(2,935 |
) |
|
$ |
(2,457
|
) |
Net
Cash
Flows Used For Investing Activities were $2.9 billion in 2007 primarily due
to
Construction Expenditures for our environmental, distribution and new generation
investment plan and purchases of gas-fired generating units.
Net
Cash
Flows Used For Investing Activities were $2.5 billion in 2006 primarily due
to
Construction Expenditures for our environmental investment plan, consistent
with
our budgeted cash flows.
We
forecast approximately $1 billion of construction expenditures for the remainder
of 2007. 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 with cash
from operations and financing activities.
Financing
Activities
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Issuance/Retirement
of Debt, Net
|
|
$ |
1,623
|
|
|
$ |
529
|
|
Dividends
Paid on Common Stock
|
|
|
(467 |
) |
|
|
(437
|
) |
Other
|
|
|
44
|
|
|
|
27
|
|
Net
Cash Flows From Financing Activities
|
|
$ |
1,200
|
|
|
$ |
119
|
|
Net
Cash
Flows From Financing Activities in 2007 were $1.2 billion primarily due to
issuing $1.9 billion of debt securities including $1 billion of new debt for
plant acquisitions and construction and increasing short-term commercial paper
borrowings. We paid common stock dividends of $467
million. See Note 9 for a complete discussion of long-term debt
issuances and retirements.
Net
Cash
Flows From Financing Activities in 2006 were $119 million. During
2006, we issued $115 million of obligations relating to pollution control bonds,
issued $1 billion of senior unsecured notes and retired $396 million of notes
for a net increase in notes outstanding of $604 million and retired $100 million
of first mortgage bonds and $52 million of securitization bonds.
We
expect
to issue debt in the capital markets of approximately $675 million to fund
our
capital investment plans for the remainder of 2007.
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 internal guidelines restrict the use of
off-balance sheet financing entities or structures to traditional operating
lease arrangements and sales of customer accounts receivable that we enter
in
the normal course of business. Our significant off-balance sheet
arrangements are as follows:
|
|
September
30,
2007
|
|
|
December
31,
2006
|
|
|
|
(in
millions)
|
|
AEP
Credit Accounts Receivable Purchase Commitments
|
|
$ |
530
|
|
|
$ |
536
|
|
Rockport
Plant Unit 2 Future Minimum Lease Payments
|
|
|
2,290
|
|
|
|
2,364
|
|
Railcars
Maximum Potential Loss From Lease Agreement
|
|
|
30
|
|
|
|
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 and the obligations resulting from
the settlement agreement regarding alleged violations of the NSR provisions
of
the CAA. See “Federal EPA Complaint and Notice of Violations” section
of Note 4. We also entered into additional contractual commitments
related to the construction of the proposed Turk Plant announced in August
2006. See “Turk Plant” in the “Arkansas Rate Matters” section of Note
3.
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.
Ohio
Restructuring
As
permitted by the current Ohio restructuring legislation, CSPCo and OPCo can
implement market-based rates effective January 2009, following the expiration
of
its RSPs on December 31, 2008. In August 2007, legislation was
introduced that would significantly reduce the likelihood of CSPCo’s and OPCo’s
ability to charge market-based rates for generation at the expiration of their
RSPs. In place of market-based rates, it is more likely that some
form of cost-based rates or hybrid-based rates would be required. The
legislation passed through the Ohio Senate and still must be considered by
the
Ohio House of Representatives. Management continues to analyze the
proposed legislation and is working with various stakeholders to achieve a
principled, fair and well-considered approach to electric supply
pricing. At this time, management is unable to predict whether CSPCo
and OPCo will transition to market pricing, 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.
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 and related orders seeking relief in both state and federal court on
the
grounds that certain aspects of the orders are contrary to the Texas
Restructuring Legislation, PUCT rulemakings and federal law and fail to fully
compensate TCC for its net stranded cost and other true-up items.
Municipal
customers and other intervenors also appealed the PUCT true-up and related
orders seeking to further reduce TCC’s true-up recoveries. In March
2007, the Texas District Court judge hearing the appeal of the true-up order
affirmed the PUCT’s April 4, 2006 final true-up order for TCC with two
significant exceptions. The judge determined that the PUCT erred by
applying an invalid rule to determine the carrying cost rate for the true-up
of
stranded costs. However, the District Court did not rule that the
carrying cost rate was inappropriate. If the District Court’s ruling
on the carrying cost rate 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 determine a new rate. If the
PUCT reduces the rate, it could result in a material adverse change to TCC’s
recoverable carrying costs, results of operations, cash flows and financial
condition.
The
District Court judge also determined the PUCT improperly reduced TCC’s net
stranded plant costs for commercial unreasonableness. If upheld on
appeal, this ruling could have a materially favorable effect on TCC’s results of
operations and cash flows.
TCC,
the
PUCT and intervenors appealed the District Court true-up order rulings to the
Texas Court of Appeals. Management cannot predict the outcome of
these true-up and related proceedings. If TCC ultimately succeeds in
its appeals in both state and federal court, 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, or if TCC
has a tax normalization violation as discussed in the “TCC Deferred Investment
Tax Credits and Excess Deferred Federal Income Taxes” section of Note 3, it
could have a substantial adverse effect on future results of operations, cash
flows and financial condition.
Virginia
Restructuring
In
April
2007, the Virginia legislature adopted a comprehensive law providing for the
re-regulation of electric utilities’ generation and supply
rates. These amendments shorten the transition period by two years
(from 2010 to 2008) after which rates for retail generation and supply will
return to cost-based regulation in lieu of market-based rates. 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 investments, (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 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
with a true-up to actual. The legislation also allows APCo to
continue to defer and recover incremental environmental and reliability costs
incurred through December 31, 2008. The new re-regulation legislation
should result in significant positive effects on APCo’s future earnings and cash
flows from the mandated enhanced future returns on equity, the reduction of
regulatory lag from the opportunities to adjust base rates on a biennial basis
and the new opportunities to request timely recovery of certain new costs not
included in base rates.
SECA
Revenue Subject to Refund
Effective
December 1, 2004, AEP and other transmission owners in the region covered by
PJM
and MISO eliminated transaction-based through-and-out transmission service
(T&O) charges in accordance with FERC orders and collected load-based
charges, referred to as RTO SECA, to mitigate the loss of T&O revenues on a
temporary basis through March 31, 2006. 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 they
collected. If a refund is ordered, the AEP East companies would also
receive refunds related to the SECA rates they paid to third
parties. The AEP East companies recognized gross SECA revenues of
$220 million. Approximately $10 million of these recorded SECA revenues billed
by PJM were not collected. The AEP East companies filed a motion with
the FERC to force payment of these uncollected SECA billings.
In
August
2006, a FERC ALJ issued an initial decision, finding that the rate design for
the recovery of SECA charges was flawed and that a large portion of the “lost
revenues” reflected in the SECA rates 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.
In
2006,
the AEP East companies provided reserves of $37 million in net refunds for
current and future SECA settlements with all of the AEP East companies’ SECA
customers. The AEP East companies reached settlements with certain
SECA customers related to approximately $69 million of such revenues for a
net
refund of $3 million. The AEP East companies are in the process of
completing two settlements-in-principle on an additional $36 million of SECA
revenues and expect to make net refunds of $4 million when those settlements
are
approved. Thus, completed and in-process settlements cover $105
million of SECA revenues and will consume about $7 million of the reserves
for
refunds, leaving approximately $115 million of contested SECA revenues and
$30
million of refund reserves. If the ALJ’s initial decision were upheld
in its entirety, it would disallow approximately $90 million of the AEP East
companies' remaining $115 million of unsettled gross SECA
revenues. Based on recent settlement experience and the expectation
that most of the $115 million of unsettled SECA revenues will be settled,
management believes that the remaining reserve of $30 million will be adequate
to cover all remaining settlements.
In
September 2006, AEP, together with Exelon Corporation 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 contradicts prior related FERC decisions,
which are presently subject to rehearing. Furthermore, management
believes the ALJ’s findings on key issues are largely without
merit. As directed by the FERC, management is working to settle the
remaining $115 million of unsettled revenues within the remaining reserve
balance. Although management believes it has meritorious arguments
and can settle with the remaining customers within the amount provided,
management cannot predict the ultimate outcome of ongoing settlement talks
and,
if necessary, any future FERC proceedings or court appeals. If the
FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of
the remaining unsettled claims within the amount provided, it will have an
adverse effect on future results of operations, cash flows and financial
condition.
PJM
Marginal-Loss Pricing
On
June
1, 2007, in response to a 2006 FERC order, PJM revised its methodology for
considering transmission line losses in generation dispatch and the calculation
of locational marginal prices. Marginal-loss dispatch
recognizes the varying delivery costs of transmitting electricity from
individual generator locations to the places where customers consume the
energy. Prior to the implementation of marginal-loss dispatch, PJM
used average losses in dispatch and in the calculation of locational marginal
prices. Locational marginal prices in PJM now include the real-time
impact of transmission losses from individual sources to loads. Due
to the implementation of marginal-loss pricing, for the period June 1, 2007
through September 30, 2007, AEP experienced an increase in the cost of
delivering energy from the generating plant locations to customer load zones
partially offset by cost recoveries and increased off-system sales resulting
in
a net loss of approximately $25 million. AEP has initiated
discussions with PJM regarding the impact it is experiencing from the change
in
methodology and will pursue through the appropriate stakeholder processes a
modification of such methodology. Management believes these
additional costs should be recoverable through retail and/or cost-based
wholesale rates and is seeking recovery in current and future fuel or base
rate
filings as appropriate in each of its eastern zone states. In the
interim, these costs will have an adverse effect on future results of operations
and cash flows. Management is unable to predict whether full recovery
will ultimately be approved.
New
Generation
AEP
is in
various stages of construction of the following generation
facilities. Certain plants are pending regulatory
approval:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
Operation
|
Operating
|
|
Project
|
|
|
|
Projected
|
|
|
|
|
|
|
|
|
MW
|
|
Date
|
Company
|
|
Name
|
|
Location
|
|
Cost
(a)
|
|
CWIP
|
|
Fuel
Type
|
|
Plant
Type
|
|
Capacity
|
|
(Projected)
|
|
|
|
|
|
|
(in
millions)
|
|
(in
millions)
|
|
|
|
|
|
|
|
|
SWEPCo
|
|
Mattison
|
|
Arkansas
|
|
$
|
122
|
(b)
|
$
|
52
|
|
Gas
|
|
Simple-cycle
|
|
340
|
(b)
|
2007
|
PSO
|
|
Southwestern
|
|
Oklahoma
|
|
|
59
|
(c)
|
|
45
|
|
Gas
|
|
Simple-cycle
|
|
170
|
|
2008
|
PSO
|
|
Riverside
|
|
Oklahoma
|
|
|
58
|
(c)
|
|
45
|
|
Gas
|
|
Simple-cycle
|
|
170
|
|
2008
|
AEGCo
|
|
Dresden
|
(d)
|
Ohio
|
|
|
265
|
(d)
|
|
88
|
|
Gas
|
|
Combined-cycle
|
|
580
|
|
2009
|
SWEPCo
|
|
Stall
|
|
Louisiana
|
|
|
375
|
|
|
15
|
|
Gas
|
|
Combined-cycle
|
|
480
|
|
2010
|
SWEPCo
|
|
Turk
|
(e)
|
Arkansas
|
|
|
1,300
|
(e)
|
|
206
|
|
Coal
|
|
Ultra-supercritical
|
|
600
|
(e)
|
2011
|
APCo
|
|
Mountaineer
|
|
West
Virginia
|
|
|
2,230
|
|
|
-
|
|
Coal
|
|
IGCC
|
|
629
|
|
2012
|
CSPCo/OPCo
|
|
Great
Bend
|
|
Ohio
|
|
|
2,230
|
(f)
|
|
-
|
|
Coal
|
|
IGCC
|
|
629
|
|
2017
|
(a)
|
Amount
excludes AFUDC.
|
(b)
|
Includes
Units 3 and 4, 150 MW, declared in commercial operation on July 12,
2007
with construction costs totaling $55 million.
|
(c)
|
In
April 2007, the OCC approved that PSO will recover through a rider,
subject to a $135 million cost cap, all of the traditional costs
associated with plant in service at the time these units are placed
in
service.
|
(d)
|
In
September 2007, AEGCo purchased the under-construction Dresden plant
from
Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for
$85
million, which is included in the “Total Projected Cost” section
above.
|
(e)
|
SWEPCo
plans to own approximately 73%, or 438 MW, totaling about $950 million
in
capital investment. See “Turk Plant” section
below.
|
(f)
|
Front-end
engineering and design study is complete. Cost estimates are
not yet filed with the PUCO due to the pending appeals to the Supreme
Court of Ohio resulting from the PUCO’s April 2006 opinion and
order. See “Ohio IGCC Plant” section
below.
|
AEP
acquired the following generation facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
|
|
|
|
|
|
|
|
|
MW
|
|
Purchase
|
Company
|
|
Plant
Name
|
|
Location
|
|
Cost
|
|
Fuel
Type
|
|
Plant
Type
|
|
Capacity
|
|
Date
|
|
|
|
|
|
|
(in
millions)
|
|
|
|
|
|
|
|
|
CSPCo
|
|
Darby
|
(a)
|
Ohio
|
|
$
|
102
|
|
Gas
|
|
Simple-cycle
|
|
480
|
|
April
2007
|
AEGCo
|
|
Lawrenceburg
|
(b)
|
Indiana
|
|
|
325
|
|
Gas
|
|
Combined-cycle
|
|
1,096
|
|
May
2007
|
(a)
|
CSPCo
purchased Darby Electric Generating Station (Darby) from DPL Energy,
LLC,
a subsidiary of The Dayton Power and Light Company.
|
(b)
|
AEGCo
purchased Lawrenceburg Generating Station (Lawrenceburg), adjacent
to
I&M’s Tanners Creek Plant, from an affiliate of Public Service
Enterprise Group (PSEG). AEGCo sells the power to CSPCo under a
FERC-approved unit power agreement.
|
Ohio
IGCC Plant
In
March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of
cost recovery associated with the IGCC plant: Phase 1, recovery of
$24 million in pre-construction costs 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 average 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 a period
of no more than twelve months effective July 1, 2006. Through
September 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC
regulatory assets of $10 million and each collected the entire $12 million
approved by the PUCO. As of September 30, 2007, CSPCo and OPCo have
recorded a liability of $2 million each for the over-recovered portion.
CSPCo and OPCo expect to incur additional pre-construction costs equal to or
greater than the $12 million each recovered.
The
PUCO
indicated that if CSPCo and OPCo have not commenced a continuous course of
construction of the proposed IGCC plant within five years of the June 2006
PUCO
order, all Phase 1 costs collected for pre-construction costs, associated with
items that may be utilized in projects at other sites, must be refunded to
Ohio
ratepayers with interest. The PUCO deferred ruling on cost recovery
for Phases 2 and 3 until further hearings are held. A date for
further rehearings has not been set.
In
August
2006, the Ohio 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. The Ohio Supreme Court heard oral arguments
for these appeals in October 2007. Management believes that the
PUCO’s authorization to begin collection of Phase 1 pre-construction costs 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 1 cost-related recoveries.
Pending
the outcome of the Supreme Court litigation, CSPCo and OPCo announced they
may
delay the start of construction of the IGCC plant. Recent estimates of the
cost
to build an IGCC plant have escalated to $2.2 billion. CSPCo and OPCo
may need to request an extension to the 5-year start of construction requirement
if the commencement of construction is delayed beyond 2011.
Red
Rock Generating Facility
In
July
2006, PSO announced plans to enter into an agreement with Oklahoma Gas and
Electric (OG&E) to build a 950 MW pulverized coal ultra-supercritical
generating unit at the site of OG&E’s existing Sooner Plant near Red Rock,
in north central Oklahoma. PSO would own 50% of the new unit,
OG&E would own approximately 42% and the Oklahoma Municipal Power Authority
(OMPA) would own approximately 8%. OG&E would manage construction
of the plant. OG&E and PSO requested pre-approval to construct
the Red Rock Generating Facility and implement a recovery rider. In
March 2007, the OCC consolidated PSO’s pre-approval application with OG&E’s
request. The Red Rock Generating Facility was estimated to cost $1.8
billion and was expected to be in service in 2012. The OCC staff and
the ALJ recommended the OCC approve PSO’s and OG&E’s filing. As
of September 2007, PSO incurred approximately $20 million of pre-construction
costs and contract cancellation fees.
In
October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of
additional capacity by the year 2012, but denied PSO’s and OG&E’s
application for construction pre-approval stating PSO and OG&E failed to
fully study other alternatives. Since PSO and OG&E could not
obtain pre-approval to build the Red Rock Generating Facility, PSO and OG&E
cancelled the third party construction contract and their joint venture
development contract. Management believes the pre-construction costs
capitalized, including any cancellation fees, were prudently incurred, as
evidenced by the OCC staff and the ALJ’s recommendations that the OCC approve
PSO’s filing, and established a regulatory asset for future
recovery. Management believes such pre-construction costs are
probable of recovery and intends to seek full recovery of such costs in the
near
future. If recovery is denied, future results of operations and cash
flows would be adversely affected. As a result of the OCC’s decision,
PSO will be re-considering various alternative options to meet its capacity
needs in the future.
Turk
Plant
In
August
2006, SWEPCo announced plans to build a new base load 600 MW pulverized coal
ultra-supercritical generating unit in Arkansas named Turk
Plant. SWEPCo submitted filings with the Arkansas Public Service
Commission (APSC) in December 2006 and the PUCT and LPSC in February 2007 to
seek approvals to proceed with the plant. In September 2007, OMPA
signed a joint ownership agreement and agreed to own approximately 7% of the
Turk Plant. SWEPCo continues discussions with Arkansas Electric
Cooperative Corporation and North Texas Electric Cooperative to become potential
partners in the Turk Plant. SWEPCo anticipates owning approximately
73% of the Turk Plant and will operate the facility. The Turk Plant
is estimated to cost $1.3 billion in total with SWEPCo’s portion estimated to
cost $950 million, excluding AFUDC. If approved on a timely basis,
the plant is expected to be in-service in mid-2011. As of September
2007, SWEPCo incurred and capitalized approximately $206 million and has
contractual commitments for an additional $875 million. If the Turk
Plant is not approved, cancellation fees may be required to terminate SWEPCo’s
commitment.
In
August
2007, hearings began before the APSC seeking pre-approval of the plant. The
APSC
staff recommended the application be approved and intervenors requested the
motion be denied. In October 2007, final briefs and closing arguments
were completed by all parties during which the APSC staff and Attorney General
supported the plant. A decision by the APSC will occur within 60 days
from October 22, 2007. In September 2007, the PUCT staff recommended
that SWEPCo’s application be denied suggesting the construction of the Turk
Plant would adversely impact the development of competition in the SPP
zone. The PUCT hearings were held in October 2007. The
LPSC held hearings in September 2007 and during this proceeding, the LPSC staff
expressed support for the project. If SWEPCo is not authorized
to build the Turk plant, SWEPCo would seek recovery of incurred costs including
any cancellation fees. If SWEPCo cannot recover incurred costs,
including any cancellation fees, it could adversely affect future results of
operations, cash flows and possibly financial condition.
Electric
Transmission Texas LLC Joint Venture (Utility Operations
segment)
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 under
construction and to establish a wholesale transmission tariff for
ETT. ETT also requested PUCT approval of initial rates based on an
11.25% return on equity. A hearing was held in July
2007. On October 31, 2007, the PUCT issued an order approving
the transaction and initial rates based on 9.96% return on
equity. ETT and MidAmerican are reviewing the order.
In
February 2007, TCC also made a regulatory filing at the FERC regarding the
transfer of certain transmission assets from TCC to ETT. In April
2007, the FERC authorized the transfer. In July 2007, ETT made a
subsequent filing requesting that FERC disclaim jurisdiction over
ETT. In October 2007, FERC disclaimed jurisdiction over
ETT.
AEP
Utilities, Inc., a subsidiary of AEP, and MEHC Texas Transco LLC, a subsidiary
of MidAmerican, each would hold a 50 percent equity ownership in
ETT. ETT would not be consolidated with AEP for financial or tax
reporting purposes.
AEP
and
MidAmerican plan for ETT to invest in additional transmission projects in
ERCOT. Upon formation, the joint venture partners anticipate
investments in excess of $1 billion of joint investment in Texas ERCOT
transmission projects that could be constructed by ETT during the next several
years.
In
February 2007, ETT filed a proposal with the PUCT that addresses the Competitive
Renewable Energy Zone (CREZ) initiative of the Texas Legislature, which outlines
opportunities for additional significant investment in transmission assets
in
Texas. A CREZ hearing was held in June 2007 and the PUCT issued an interim
order
in August 2007. In that order, the PUCT directed ERCOT to perform
studies by April 2008 that determine the necessary transmission upgrades to
accommodate between 10,000 and 22,800 MW of wind development from CREZs across
the Texas panhandle and central West Texas. The PUCT also indicated
in its interim order that it plans to select transmission construction designees
in the first quarter of 2008.
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
improvements. 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.
Potomac-Appalachian
Transmission Highline (PATH) (Utility Operations
segment)
On
June
22, 2007, PJM’s Board authorized the construction of a major new transmission
line to address the reliability and efficiency needs of the PJM
system. PJM has identified a need for a new line as early as
2012. The line would be 765kV for most of its length and would run
approximately 290 miles from AEP’s Amos substation in West Virginia to Allegheny
Energy Inc.’s (AYE) proposed Kemptown station in north central Maryland (the
Amos-to-Kemptown Line). The Amos-to-Kemptown Line has been named the
“Potomac-Appalachian Transmission Highline” (PATH) by AEP and AYE.
Effective
September 1, 2007, AEP and AYE formed a joint venture by creating
Potomac-Appalachian Transmission Highline, LLC (PATH LLC) and its
subsidiaries. The subsidiaries of PATH LLC will operate as
transmission utilities owning certain electric transmission assets within PJM
including the PATH project. The Amos-to-Kemptown Line has two
segments: a segment running from AEP’s Amos substation in West
Virginia east to AYE’s Bedington substation in West Virginia (the “West Virginia
Facilities”), to be constructed and owned by PATH West Virginia Transmission
Company, LLC, and a segment running east from the Bedington substation to AYE’s
Kemptown substation in Maryland (the “Bedington-Kemptown Facilities”), to be
constructed and owned by PATH Allegheny Transmission Company, LLC.
In
addition to the Amos-to-Kemptown Line, the joint venture will also pursue a
high
voltage transmission line up to 70 miles in length in northeastern Ohio (the
“Ohio Facilities”) extending to the Pennsylvania border. The Ohio
Facilities would be constructed and owned by PATH Ohio Transmission Company,
LLC, if the project is authorized by PJM prior to 2011. This project
is currently under study in PJM’s Regional Transmission Expansion Plan
process.
The
ownership in the West Virginia Facilities and the Ohio Facilities will be shared
50/50 between AEP and AYE. The Bedington-Kemptown Facilities will be
owned solely by AYE. The ownership and management of the Ohio
Facilities will be shared 50/50 between AEP and AYE.
Both
AEP
and AYE will be providing services to the PATH companies through service
agreements. AEP will have lead responsibility for engineering, designing and
managing construction of the 765-kV elements of the project, and AEP will
provide business services to the PATH companies during the construction phase
of
the project. Both companies will provide siting, right-of-way and
regulatory services to the PATH companies.
PATH
LLC,
on behalf of the PATH operating companies, plans to file for necessary approvals
from FERC for the Amos-to-Kemptown Line in the fourth quarter of
2007. The PATH operating companies will seek regulatory approvals for
the Amos-to-Kemptown project from the state utility commissions following
completion of a routing study that is expected to occur in 2008.
The
total
cost of the Amos-to-Kemptown Line is estimated to be approximately $1.8 billion
and AEP’s estimated share will be approximately $600 million. The
PATH companies will not be consolidated with AEP for financial or tax reporting
purposes.
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, a
number of states and certain special interest groups 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. In April 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
October 2007, we announced that we had entered into a consent decree with the
Federal EPA, the DOJ, the states and the special interest groups. Under the
consent decree, we agreed to annual SO2 and NOx
emission caps for
sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia
and
West Virginia. In addition to completing the installation of previously
announced environmental retrofit projects at many of the plants, we agreed
to
install selective catalytic reduction (SCR) and flue gas desulfurization (FGD
or
scrubbers) emissions control equipment on the Rockport Plant units.
Since
2004, we spent nearly $2.6 billion on installation of emissions control
equipment on our coal-fueled plants in Kentucky, Ohio, Virginia and West
Virginia as part of a larger plan to invest more than $5.1 billion by 2010
to
reduce the emissions of our generating fleet.
Under
the
consent decree, we will pay a $15 million civil penalty and provide $36 million
for environmental projects coordinated with the federal government and $24
million to the states for environmental mitigation. We recognized
these amounts in the third quarter of 2007. See “Federal EPA
Complaint and Notice of Violation” section of Note 4.
Litigation
against three jointly-owned plants, operated by Duke Energy Ohio, Inc. and
Dayton Power and Light Company, continues. We are unable to predict
the outcome of these cases. We believe we can recover any
capital and operating costs of additional pollution control equipment that
may
be required through regulated rates or market prices for
electricity. If we are unable to recover such costs or if material
penalties are imposed, it would adversely affect future results of operations
and cash flows.
Clean
Water Act Regulations
In
2004,
the Federal EPA issued a final rule requiring all large existing power plants
with once-through cooling water systems to meet certain standards to reduce
mortality of aquatic organisms pinned against the plant’s cooling water intake
screen or entrained in the cooling water. The standards vary based on
the water bodies from which the plants draw their cooling water. We
expected additional capital and operating expenses, which the Federal EPA
estimated could be $193 million for our plants. We undertook
site-specific studies and have been evaluating site-specific compliance or
mitigation measures that could significantly change these cost
estimates.
The
rule
was challenged in the courts by states, advocacy organizations and
industry. In January 2007, the Second Circuit Court of Appeals issued
a decision remanding significant portions of the rule to the Federal
EPA. In July 2007, the Federal EPA suspended the 2004 rule, except
for the requirement that permitting agencies develop best professional judgment
(BPJ) controls for existing facility cooling water intake structures that
reflect the best technology available for minimizing adverse
environmental impact. The result is that the BPJ control standard for
cooling water intake structures in effect prior to the 2004 rule is the
applicable standard for permitting agencies pending finalization of revised
rules by the Federal EPA. We cannot predict further action of the
Federal EPA or what effect it may have on similar requirements adopted by the
states. We may seek further review or relief from the schedules
included in our permits.
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 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 natural gas operations which holds forward natural gas contracts that
were not sold with the natural 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 with 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, natural gas, coal, and emissions
and
to a lesser degree other commodities associated with our energy
business. As a result, we are subject to price risk. The
amount of risk taken is determined by the commercial operations group in
accordance with the market risk policy approved by the Finance Committee of
our
Board of Directors. Our market risk 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 consolidated balance sheet as of September 30, 2007
and the reasons for changes in our total MTM value included on our condensed
consolidated balance sheet as compared to December 31, 2006.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
September
30, 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
|
|
$ |
233
|
|
|
$ |
47
|
|
|
$ |
62
|
|
|
$ |
342
|
|
|
$ |
9
|
|
|
$ |
351
|
|
Noncurrent
Assets
|
|
|
199
|
|
|
|
63
|
|
|
|
79
|
|
|
|
341
|
|
|
|
6
|
|
|
|
347
|
|
Total
Assets
|
|
|
432
|
|
|
|
110
|
|
|
|
141
|
|
|
|
683
|
|
|
|
15
|
|
|
|
698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(148 |
) |
|
|
(53 |
) |
|
|
(64 |
) |
|
|
(265 |
) |
|
|
(2 |
) |
|
|
(267 |
) |
Noncurrent
Liabilities
|
|
|
(101 |
) |
|
|
(21 |
) |
|
|
(85 |
) |
|
|
(207 |
) |
|
|
(3 |
) |
|
|
(210 |
) |
Total
Liabilities
|
|
|
(249 |
) |
|
|
(74 |
) |
|
|
(149 |
) |
|
|
(472 |
) |
|
|
(5 |
) |
|
|
(477 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM
Derivative
Contract Net
Assets
(Liabilities)
|
|
$ |
183
|
|
|
$ |
36
|
|
|
$ |
(8 |
) |
|
$ |
211
|
|
|
$ |
10
|
|
|
$ |
221
|
|
MTM
Risk Management Contract Net Assets (Liabilities)
Nine
Months Ended September 30, 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
|
|
|
(50 |
) |
|
|
(1 |
) |
|
|
(2 |
) |
|
|
(53 |
) |
Fair
Value of New Contracts at Inception When Entered
During
the Period (a)
|
|
|
6
|
|
|
|
49
|
|
|
|
-
|
|
|
|
55
|
|
Net
Option Premiums Paid/(Received) for Unexercised or
Unexpired Option Contracts Entered During The
Period
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
Changes
in Fair Value Due to Valuation Methodology
Changes
on Forward Contracts
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During
the
Period (b)
|
|
|
7
|
|
|
|
(14 |
) |
|
|
(1 |
) |
|
|
(8 |
) |
Changes
in Fair Value Allocated to Regulated Jurisdictions
(c)
|
|
|
(18 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
(18 |
) |
Total
MTM Risk Management Contract Net Assets
(Liabilities) at September 30, 2007
|
|
$ |
183
|
|
|
$ |
36
|
|
|
$ |
(8 |
) |
|
|
211
|
|
Net
Cash Flow and Fair Value
Hedge Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
Total
MTM Risk Management Contract Net Assets at
September
30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
221
|
|
(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 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 September 30, 2007
(in
millions)
|
|
Remainder
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
After
2011
(c)
|
|
Total
|
|
Utility
Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted – Exchange
Traded Contracts
|
|
$
|
5
|
|
$
|
(15
|
)
|
$
|
3
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(7
|
)
|
Prices
Provided by Other External
Sources
– OTC Broker Quotes (a)
|
|
|
29
|
|
|
66
|
|
|
40
|
|
|
31
|
|
|
-
|
|
|
-
|
|
|
166
|
|
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
1
|
|
|
(1
|
)
|
|
6
|
|
|
5
|
|
|
7
|
|
|
6
|
|
|
24
|
|
Total
|
|
|
35
|
|
|
50
|
|
|
49
|
|
|
36
|
|
|
7
|
|
|
6
|
|
|
183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
and Marketing:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted – Exchange
Traded Contracts
|
|
|
(3
|
)
|
|
2
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Prices
Provided by Other External
Sources
– OTC Broker Quotes (a)
|
|
|
-
|
|
|
(6
|
)
|
|
3
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(3
|
)
|
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
-
|
|
|
(3
|
)
|
|
(2
|
)
|
|
8
|
|
|
7
|
|
|
29
|
|
|
39
|
|
Total
|
|
|
(3
|
)
|
|
(7
|
)
|
|
2
|
|
|
8
|
|
|
7
|
|
|
29
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted – Exchange
Traded Contracts
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Prices
Provided by Other External
Sources
– OTC Broker Quotes (a)
|
|
|
-
|
|
|
(2
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(2
|
)
|
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
-
|
|
|
-
|
|
|
(4
|
)
|
|
(4
|
)
|
|
2
|
|
|
-
|
|
|
(6
|
)
|
Total
|
|
|
-
|
|
|
(2
|
)
|
|
(4
|
)
|
|
(4
|
)
|
|
2
|
|
|
-
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted – Exchange
Traded
Contracts
|
|
|
2
|
|
|
(13
|
)
|
|
4
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(7
|
)
|
Prices
Provided by Other External
Sources
– OTC Broker Quotes (a)
|
|
|
29
|
|
|
58
|
|
|
43
|
|
|
31
|
|
|
-
|
|
|
-
|
|
|
161
|
|
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
1
|
|
|
(4
|
)
|
|
-
|
|
|
9
|
|
|
16
|
|
|
35
|
|
|
57
|
|
Total
|
|
$
|
32
|
|
$
|
41
|
|
$
|
47
|
|
$
|
40
|
|
$
|
16
|
|
$
|
35
|
|
$
|
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
independent 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 including
values determinable by other third party transactions.
|
(c)
|
There
is mark-to-market value of $35 million in individual periods beyond
2011. $14 million of this mark-to-market value is in 2012, $8
million is in 2013, $7 million is in 2014, $2 million is in 2015,
$2
million is in 2016 and $2 million is in
2017.
|
The
determination of the point at which a market is no longer supported by
independent quotes and therefore considered in the modeled category in the
preceding table varies by market. The following table generally
reports an estimate of the maximum tenors (contract maturities) of the liquid
portion of each energy market.
Maximum
Tenor of the Liquid Portion of Risk Management Contracts
As
of September 30, 2007
Commodity
|
|
Transaction
Class
|
|
Market/Region
|
|
Tenor
|
|
|
|
|
|
|
(in
Months)
|
Natural
Gas
|
|
Futures
|
|
NYMEX
/ Henry Hub
|
|
60
|
|
|
Physical
Forwards
|
|
Gulf
Coast, Texas
|
|
18
|
|
|
Swaps
|
|
Northeast,
Mid-Continent, Gulf Coast, Texas
|
|
18
|
|
|
Exchange
Option Volatility
|
|
NYMEX
/ Henry Hub
|
|
12
|
Power
|
|
Futures
|
|
AEP
East - PJM
|
|
27
|
|
|
Physical
Forwards
|
|
AEP
East - Cinergy
|
|
39
|
|
|
Physical
Forwards
|
|
AEP
- PJM West
|
|
39
|
|
|
Physical
Forwards
|
|
AEP
- Dayton (PJM)
|
|
39
|
|
|
Physical
Forwards
|
|
AEP
- ERCOT
|
|
27
|
|
|
Physical
Forwards
|
|
AEP
- Entergy
|
|
15
|
|
|
Physical
Forwards
|
|
West
Coast
|
|
39
|
|
|
Peak
Power Volatility (Options)
|
AEP
East - Cinergy, PJM
|
|
12
|
Emissions
|
|
Credits
|
|
SO2,
NOx
|
|
39
|
Coal
|
|
Physical
Forwards
|
|
PRB,
NYMEX, CSX
|
|
39
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheets
We
are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may
use various commodity derivative instruments designated in qualifying cash
flow
hedge strategies to mitigate the impact of these fluctuations on the future
cash
flows. We do not hedge all commodity price risk.
We
use
interest rate derivative transactions to manage interest rate risk related
to
existing variable rate debt and to manage interest rate exposure on anticipated
borrowings of fixed-rate debt. We do not hedge all interest rate
exposure.
We
use
foreign currency derivatives to lock in prices on certain transactions
denominated in foreign currencies where deemed necessary, and designate
qualifying instruments as cash flow hedge strategies. 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 September 30,
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
Nine
Months Ended September 30, 2007
(in
millions)
|
|
|
|
|
Interest
|
|
|
|
|
|
|
|
|
|
Rate
and
|
|
|
|
|
|
|
|
|
|
Foreign
|
|
|
|
|
|
|
Power
|
|
|
Currency
|
|
|
Total
|
|
Beginning
Balance in AOCI, December 31, 2006
|
|
$ |
17
|
|
|
$ |
(23 |
) |
|
$ |
(6 |
) |
Changes
in Fair Value
|
|
|
4
|
|
|
|
(2 |
) |
|
|
2
|
|
Reclassifications
from AOCI to Net Income for
Cash
Flow Hedges Settled
|
|
|
(15 |
) |
|
|
2
|
|
|
|
(13 |
) |
Ending
Balance in AOCI, September 30, 2007
|
|
$ |
6
|
|
|
$ |
(23 |
) |
|
$ |
(17 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
After
Tax Portion Expected to be Reclassified
to Earnings During Next 12 Months
|
|
$ |
4
|
|
|
$ |
(2 |
) |
|
$ |
2
|
|
Credit
Risk
We
limit
credit risk in our wholesale marketing and trading activities by assessing
creditworthiness of potential counterparties before entering into transactions
with them and continuing to evaluate their creditworthiness after transactions
have been initiated. 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 September 30,
2007, our credit exposure net of credit collateral to sub investment grade
counterparties was approximately 4.6%, expressed in terms of net MTM assets,
net
receivables and the net open positions for contracts not subject to MTM
(representing economic risk even though there may not be risk of accounting
loss). As of September 30, 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):
|
|
Exposure
|
|
|
|
|
|
|
|
|
Number
of
|
|
|
Net
Exposure
|
|
|
|
Before
|
|
|
|
|
|
|
|
|
Counterparties
|
|
|
of
|
|
|
|
Credit
|
|
|
Credit
|
|
|
Net
|
|
|
>10%
of
|
|
|
Counterparties
|
|
Counterparty
Credit Quality
|
|
Collateral
|
|
|
Collateral
|
|
|
Exposure
|
|
|
Net
Exposure
|
|
|
>10%
|
|
Investment
Grade
|
|
$ |
649
|
|
|
$ |
60
|
|
|
$ |
589
|
|
|
|
-
|
|
|
$ |
-
|
|
Split
Rating
|
|
|
25
|
|
|
|
11
|
|
|
|
14
|
|
|
|
2
|
|
|
|
13
|
|
Noninvestment
Grade
|
|
|
24
|
|
|
|
3
|
|
|
|
21
|
|
|
|
2
|
|
|
|
19
|
|
No
External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internal
Investment Grade
|
|
|
68
|
|
|
|
-
|
|
|
|
68
|
|
|
|
1
|
|
|
|
39
|
|
Internal
Noninvestment Grade
|
|
|
13
|
|
|
|
2
|
|
|
|
11
|
|
|
|
3
|
|
|
|
8
|
|
Total
as of September 30, 2007
|
|
$ |
779
|
|
|
$ |
76
|
|
|
$ |
703
|
|
|
|
8
|
|
|
$ |
79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 September 30, 2007
|
Remainder
|
|
|
|
|
|
2007
|
|
2008
|
|
2009
|
Estimated
Plant Output Hedged
|
95%
|
|
88%
|
|
91%
|
VaR
Associated with Risk Management Contracts
Commodity
Price Risk
We
use a
risk measurement model, which calculates Value at Risk (VaR) to measure our
commodity price risk in the risk management portfolio. The VaR is based on
the
variance-covariance method using historical prices to estimate volatilities
and
correlations and assumes a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at September 30, 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
Nine
Months Ended
|
|
|
|
|
Twelve
Months Ended
|
September
30, 2007
|
|
|
|
|
December
31, 2006
|
(in
millions)
|
|
|
|
|
(in
millions)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$1
|
|
$6
|
|
$2
|
|
$1
|
|
|
|
|
$3
|
|
$10
|
|
$3
|
|
$1
|
Interest
Rate Risk
We
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The volatilities and correlations were
based on three years of daily prices. The risk of potential loss in fair value
attributable to our exposure to interest rates, primarily related to long-term
debt with fixed interest rates, was $925 million at September 30, 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 and Nine Months Ended September 30, 2007 and
2006
(in
millions, except per-share amounts and shares outstanding)
(Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
$
|
3,423
|
|
$
|
3,478
|
|
$
|
9,127
|
|
$
|
9,259
|
|
Other
|
|
|
366
|
|
|
116
|
|
|
977
|
|
|
379
|
|
TOTAL
|
|
|
3,789
|
|
|
3,594
|
|
|
10,104
|
|
|
9,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
1,099
|
|
|
1,113
|
|
|
2,853
|
|
|
2,962
|
|
Purchased
Energy for Resale
|
|
|
358
|
|
|
271
|
|
|
895
|
|
|
674
|
|
Other
Operation and Maintenance
|
|
|
964
|
|
|
898
|
|
|
2,783
|
|
|
2,615
|
|
Gain
on Disposition of Assets, Net
|
|
|
(2
|
)
|
|
-
|
|
|
(28
|
)
|
|
(68
|
)
|
Asset
Impairments and Other Related Charges
|
|
|
-
|
|
|
209
|
|
|
-
|
|
|
209
|
|
Depreciation
and Amortization
|
|
|
381
|
|
|
382
|
|
|
1,144
|
|
|
1,084
|
|
Taxes
Other Than Income Taxes
|
|
|
191
|
|
|
186
|
|
|
565
|
|
|
567
|
|
TOTAL
|
|
|
2,991
|
|
|
3,059
|
|
|
8,212
|
|
|
8,043
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
798
|
|
|
535
|
|
|
1,892
|
|
|
1,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
and Investment Income
|
|
|
8
|
|
|
22
|
|
|
39
|
|
|
41
|
|
Carrying
Costs Income
|
|
|
14
|
|
|
3
|
|
|
38
|
|
|
66
|
|
Allowance
For Equity Funds Used During Construction
|
|
|
9
|
|
|
12
|
|
|
23
|
|
|
25
|
|
Gain
on Disposition of Equity Investments, Net
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST
AND OTHER CHARGES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
|
216
|
|
|
174
|
|
|
615
|
|
|
518
|
|
Preferred
Stock Dividend Requirements of Subsidiaries
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
2
|
|
TOTAL
|
|
|
217
|
|
|
175
|
|
|
617
|
|
|
520
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE, MINORITY
INTEREST EXPENSE AND
EQUITY EARNINGS
|
|
|
612
|
|
|
397
|
|
|
1,375
|
|
|
1,210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
205
|
|
|
133
|
|
|
443
|
|
|
394
|
|
Minority
Interest Expense
|
|
|
1
|
|
|
1
|
|
|
3
|
|
|
2
|
|
Equity
Earnings of Unconsolidated Subsidiaries
|
|
|
1
|
|
|
2
|
|
|
6
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS AND
EXTRAORDINARY LOSS
|
|
|
407
|
|
|
265
|
|
|
935
|
|
|
815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DISCONTINUED
OPERATIONS, NET OF TAX
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE EXTRAORDINARY LOSS
|
|
|
407
|
|
|
265
|
|
|
937
|
|
|
821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXTRAORDINARY
LOSS, NET OF TAX
|
|
|
-
|
|
|
-
|
|
|
(79
|
)
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
407
|
|
$
|
265
|
|
$
|
858
|
|
$
|
821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC
SHARES OUTSTANDING
|
|
|
399,222,569
|
|
|
393,913,463
|
|
|
398,412,473
|
|
|
393,763,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$
|
1.02
|
|
$
|
0.67
|
|
$
|
2.35
|
|
$
|
2.07
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.01
|
|
Income
Before Extraordinary Loss
|
|
|
1.02
|
|
|
0.67
|
|
|
2.35
|
|
|
2.08
|
|
Extraordinary
Loss, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
(0.20
|
)
|
|
-
|
|
TOTAL
BASIC EARNINGS PER SHARE
|
|
$
|
1.02
|
|
$
|
0.67
|
|
$
|
2.15
|
|
$
|
2.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED
SHARES OUTSTANDING
|
|
|
400,215,911
|
|
|
396,266,250
|
|
|
399,552,630
|
|
|
395,783,241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$
|
1.02
|
|
$
|
0.67
|
|
$
|
2.34
|
|
$
|
2.06
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
0.01
|
|
|
0.01
|
|
Income
Before Extraordinary Loss
|
|
|
1.02
|
|
|
0.67
|
|
|
2.35
|
|
|
2.07
|
|
Extraordinary
Loss, Net of Tax
|
|
|
-
|
|
|
-
|
|
|
(0.20
|
)
|
|
-
|
|
TOTAL
DILUTED EARNINGS PER SHARE
|
|
$
|
1.02
|
|
$
|
0.67
|
|
$
|
2.15
|
|
$
|
2.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
DIVIDENDS PAID PER SHARE
|
|
$
|
0.39
|
|
$
|
0.37
|
|
$
|
1.17
|
|
$
|
1.11
|
|
See
Condensed Notes to Condensed Consolidated Financial
Statements.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2007 and December 31, 2006
(in
millions)
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
196
|
|
|
$ |
301
|
|
Other
Temporary Investments
|
|
|
231
|
|
|
|
425
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
780
|
|
|
|
676
|
|
Accrued Unbilled Revenues
|
|
|
376
|
|
|
|
350
|
|
Miscellaneous
|
|
|
87
|
|
|
|
44
|
|
Allowance for Uncollectible Accounts
|
|
|
(41 |
) |
|
|
(30 |
) |
Total Accounts Receivable
|
|
|
1,202
|
|
|
|
1,040
|
|
Fuel,
Materials and Supplies
|
|
|
961
|
|
|
|
913
|
|
Risk
Management Assets
|
|
|
351
|
|
|
|
680
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
23
|
|
|
|
38
|
|
Margin
Deposits
|
|
|
61
|
|
|
|
120
|
|
Prepayments
and Other
|
|
|
86
|
|
|
|
71
|
|
TOTAL
|
|
|
3,111
|
|
|
|
3,588
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
19,749
|
|
|
|
16,787
|
|
Transmission
|
|
|
7,354
|
|
|
|
7,018
|
|
Distribution
|
|
|
11,894
|
|
|
|
11,338
|
|
Other
(including coal mining and nuclear fuel)
|
|
|
3,363
|
|
|
|
3,405
|
|
Construction
Work in Progress
|
|
|
2,809
|
|
|
|
3,473
|
|
Total
|
|
|
45,169
|
|
|
|
42,021
|
|
Accumulated
Depreciation and Amortization
|
|
|
16,139
|
|
|
|
15,240
|
|
TOTAL
- NET
|
|
|
29,030
|
|
|
|
26,781
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
2,365
|
|
|
|
2,477
|
|
Securitized
Transition Assets
|
|
|
2,115
|
|
|
|
2,158
|
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,315
|
|
|
|
1,248
|
|
Goodwill
|
|
|
76
|
|
|
|
76
|
|
Long-term
Risk Management Assets
|
|
|
347
|
|
|
|
378
|
|
Employee
Benefits and Pension Assets
|
|
|
293
|
|
|
|
327
|
|
Deferred
Charges and Other
|
|
|
804
|
|
|
|
910
|
|
TOTAL
|
|
|
7,315
|
|
|
|
7,574
|
|
|
|
|
|
|
|
|
|
|
Assets
Held for Sale
|
|
|
-
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
39,456
|
|
|
$ |
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
September
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
millions)
|
|
Accounts
Payable
|
|
$
|
1,121
|
|
$
|
1,360
|
|
Short-term
Debt
|
|
|
587
|
|
|
18
|
|
Long-term
Debt Due Within One Year
|
|
|
910
|
|
|
1,269
|
|
Risk
Management Liabilities
|
|
|
267
|
|
|
541
|
|
Customer
Deposits
|
|
|
326
|
|
|
339
|
|
Accrued
Taxes
|
|
|
616
|
|
|
781
|
|
Accrued
Interest
|
|
|
246
|
|
|
186
|
|
Other
|
|
|
835
|
|
|
962
|
|
TOTAL
|
|
|
4,908
|
|
|
5,456
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
Long-term
Debt
|
|
|
13,866
|
|
|
12,429
|
|
Long-term
Risk Management Liabilities
|
|
|
210
|
|
|
260
|
|
Deferred
Income Taxes
|
|
|
4,585
|
|
|
4,690
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
2,886
|
|
|
2,910
|
|
Asset
Retirement Obligations
|
|
|
1,059
|
|
|
1,023
|
|
Employee
Benefits and Pension Obligations
|
|
|
855
|
|
|
823
|
|
Deferred
Gain on Sale and Leaseback – Rockport Plant Unit 2
|
|
|
141
|
|
|
148
|
|
Deferred
Credits and Other
|
|
|
976
|
|
|
775
|
|
TOTAL
|
|
|
24,578
|
|
|
23,058
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
29,486
|
|
|
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
|
421,328,600
|
|
418,174,728
|
|
|
|
|
|
|
|
|
(21,499,992
shares were held in treasury at September 30, 2007 and December 31,
2006)
|
|
|
2,739
|
|
|
2,718
|
|
Paid-in
Capital
|
|
|
4,328
|
|
|
4,221
|
|
Retained
Earnings
|
|
|
3,070
|
|
|
2,696
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(228
|
)
|
|
(223
|
)
|
TOTAL
|
|
|
9,909
|
|
|
9,412
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
39,456
|
|
$
|
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 Nine Months Ended September 30, 2007 and 2006
(in
millions)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
858
|
|
|
$ |
821
|
|
Less: Discontinued
Operations, Net of Tax
|
|
|
(2 |
) |
|
|
(6 |
) |
Income
Before Discontinued Operations
|
|
|
856
|
|
|
|
815
|
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
1,144
|
|
|
|
1,084
|
|
Deferred
Income Taxes
|
|
|
44
|
|
|
|
(88 |
) |
Deferred
Investment Tax Credits
|
|
|
(18 |
) |
|
|
(20 |
) |
Extraordinary
Loss, Net of Tax
|
|
|
79
|
|
|
|
-
|
|
Asset
Impairments, Investment Value Losses and Other Related
Charges
|
|
|
-
|
|
|
|
209
|
|
Carrying
Costs Income
|
|
|
(38 |
) |
|
|
(66 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
22
|
|
|
|
(21 |
) |
Amortization
of Nuclear Fuel
|
|
|
48
|
|
|
|
38
|
|
Deferred
Property Taxes
|
|
|
118
|
|
|
|
105
|
|
Fuel
Over/Under-Recovery, Net
|
|
|
(133 |
) |
|
|
158
|
|
Gain
on Sales of Assets and Equity Investments, Net
|
|
|
(28 |
) |
|
|
(71 |
) |
Change
in Other Noncurrent Assets
|
|
|
(87 |
) |
|
|
36
|
|
Change
in Other Noncurrent Liabilities
|
|
|
116
|
|
|
|
26
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(209 |
) |
|
|
139
|
|
Fuel,
Materials and Supplies
|
|
|
(13 |
) |
|
|
(84 |
) |
Margin
Deposits
|
|
|
59
|
|
|
|
130
|
|
Accounts
Payable
|
|
|
(54 |
) |
|
|
(49 |
) |
Customer
Deposits
|
|
|
(13 |
) |
|
|
(235 |
) |
Accrued
Taxes, Net
|
|
|
(119 |
) |
|
|
176
|
|
Accrued
Interest
|
|
|
22
|
|
|
|
10
|
|
Other
Current Assets
|
|
|
(33 |
) |
|
|
12
|
|
Other
Current Liabilities
|
|
|
(133 |
) |
|
|
(108 |
) |
Net
Cash Flows From Operating Activities
|
|
|
1,630
|
|
|
|
2,196
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(2,595 |
) |
|
|
(2,428 |
) |
Change
in Other Temporary Cash Investments, Net
|
|
|
(50 |
) |
|
|
20
|
|
Purchases
of Investment Securities
|
|
|
(8,632 |
) |
|
|
(8,153 |
) |
Sales
of Investment Securities
|
|
|
8,849
|
|
|
|
8,056
|
|
Acquisitions
of Darby, Lawrenceburg and Dresden Plants
|
|
|
(512 |
) |
|
|
-
|
|
Proceeds
from Sales of Assets
|
|
|
78
|
|
|
|
120
|
|
Other
|
|
|
(73 |
) |
|
|
(72 |
) |
Net
Cash Flows Used For Investing Activities
|
|
|
(2,935 |
) |
|
|
(2,457 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Common Stock
|
|
|
116
|
|
|
|
24
|
|
Issuance
of Long-term Debt
|
|
|
1,924
|
|
|
|
1,229
|
|
Change
in Short-term Debt, Net
|
|
|
569
|
|
|
|
11
|
|
Retirement
of Long-term Debt
|
|
|
(870 |
) |
|
|
(711 |
) |
Dividends
Paid on Common Stock
|
|
|
(467 |
) |
|
|
(437 |
) |
Other
|
|
|
(72 |
) |
|
|
3
|
|
Net
Cash Flows From Financing Activities
|
|
|
1,200
|
|
|
|
119
|
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(105 |
) |
|
|
(142 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
301
|
|
|
|
401
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
196
|
|
|
$ |
259
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
549
|
|
|
$ |
462
|
|
Net
Cash Paid for Income Taxes
|
|
|
363
|
|
|
|
206
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
59
|
|
|
|
66
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
265
|
|
|
|
334
|
|
Nuclear
Fuel Expenditures Included in Accounts Payable at September
30,
|
|
|
1
|
|
|
|
-
|
|
Noncash
Assumption of Liabilities Related to Acquisitions
|
|
|
8
|
|
|
|
-
|
|
See
Condensed Notes to Condensed Consolidated Financial
Statements.
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For
the Nine Months Ended September 30, 2007 and 2006
(in
millions)
(Unaudited)
|
|
Common
Stock
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
Shares
|
|
Amount
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Other
Comprehensive Income (Loss)
|
|
Total
|
|
DECEMBER
31, 2005
|
|
|
415
|
|
$
|
2,699
|
|
$
|
4,131
|
|
$
|
2,285
|
|
$
|
(27
|
)
|
$
|
9,088
|
|
Issuance
of Common Stock
|
|
|
1
|
|
|
5
|
|
|
19
|
|
|
|
|
|
|
|
|
24
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
(437
|
)
|
|
|
|
|
(437
|
)
|
Other
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
3
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income, Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
|
|
|
18
|
|
|
Securities
Available for Sale, Net of Tax of $4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
8
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
821
|
|
|
|
|
|
821
|
|
TOTAL COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
847
|
|
SEPTEMBER
30, 2006
|
|
|
416
|
|
$
|
2,704
|
|
$
|
4,153
|
|
$
|
2,669
|
|
$
|
(1
|
)
|
$
|
9,525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
|
418
|
|
$
|
2,718
|
|
$
|
4,221
|
|
$
|
2,696
|
|
$
|
(223
|
)
|
$
|
9,412
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
|
(17
|
)
|
|
|
|
|
(17
|
)
|
Issuance
of Common Stock
|
|
|
3
|
|
|
21
|
|
|
95
|
|
|
|
|
|
|
|
|
116
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
(467
|
)
|
|
|
|
|
(467
|
)
|
Other
|
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
12
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive
Income
(Loss), Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11
|
)
|
|
(11
|
)
|
|
Securities
Available for Sale, Net of Tax of $3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
(5
|
)
|
|
SFAS
158 Costs Established as a Regulatory
Asset for
the Reapplication of SFAS 71, Net
of Tax of $6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
11
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
858
|
|
|
|
|
|
858
|
|
TOTAL COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
853
|
|
SEPTEMBER
30, 2007
|
|
|
421
|
|
$
|
2,739
|
|
$
|
4,328
|
|
$
|
3,070
|
|
$
|
(228
|
)
|
$
|
9,909
|
|
See
Condensed Notes to Condensed Consolidated Financial
Statements.
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX
TO CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
|
|
1.
|
Significant
Accounting Matters
|
2.
|
New
Accounting Pronouncements and Extraordinary Item
|
3.
|
Rate
Matters
|
4.
|
Commitments,
Guarantees and Contingencies
|
5.
|
Acquisitions,
Dispositions, 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 annual financial
statements.
In
the
opinion of management, the unaudited interim financial statements reflect all
normal and recurring accruals and adjustments necessary for a fair presentation
of our results of operations, financial position and cash flows for the interim
periods. The results of operations for the three or nine months ended
September 30, 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.
Property,
Plant and Equipment and Equity Investments
Electric
utility property, plant and equipment are stated at original purchase cost.
Property, plant and equipment of nonregulated operations and other investments
are stated at fair market value at acquisition (or as adjusted for any
applicable impairments) plus the original cost of property acquired or
constructed since the acquisition, less disposals. Additions, major
replacements and betterments are added to the plant accounts. For the
Utility Operations segment, normal and routine retirements from the plant
accounts, net of salvage, are charged to accumulated depreciation for both
cost-based rate-regulated and most nonregulated operations under the group
composite method of depreciation. The group composite method of
depreciation assumes that on average, asset components are retired at the end
of
their useful lives and thus there is no gain or loss. The equipment
in each primary electric plant account is identified as a separate
group. Under the group composite method of depreciation, continuous
interim routine replacements of items such as boiler tubes, pumps, motors,
etc.
result in the original cost, less salvage, being charged to accumulated
depreciation. For the nonregulated generation assets, a gain or loss
would be recorded if the retirement is not considered an interim routine
replacement. The depreciation rates that are established for the
generating plants take into account the past history of interim capital
replacements and the amount of salvage received. These rates and the
related lives are subject to periodic review. Gains and losses are
recorded for any retirements in the MEMCO Operations and Generation and
Marketing segments. Removal costs are charged to regulatory
liabilities for cost-based rate-regulated operations and charged to expense
for
nonregulated operations. The costs of labor, materials and overhead
incurred to operate and maintain our plants are included in operating
expenses.
Long-lived
assets are required to be tested for impairment when it is determined that
the
carrying value of the assets may no longer be recoverable or when the assets
meet the held for sale criteria under SFAS 144, “Accounting for the Impairment
or Disposal of Long-Lived Assets.” Equity investments are required to
be tested for impairment when it is determined there may be an other than
temporary loss in value.
The
fair
value of an asset or investment is the amount at which that asset or investment
could be bought or sold in a current transaction between willing parties, as
opposed to a forced or liquidation sale. Quoted market prices in
active markets are the best evidence of fair value and are used as the basis
for
the measurement, if available. In the absence of quoted prices for
identical or similar assets or investments in active markets, fair value is
estimated using various internal and external valuation methods including cash
flow analysis and appraisals.
Revenue
Recognition
Traditional
Electricity Supply and Delivery Activities
Revenues
are recognized from retail and wholesale electricity supply sales and
electricity transmission and distribution delivery services. We
recognize the revenues on our Condensed Consolidated Statements of Income upon
delivery of the energy to the customer and include unbilled as well as billed
amounts. In accordance with the applicable state commission
regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled
revenue.
Most
of
the power produced at the generation plants of the AEP East companies is sold
to
PJM, the RTO operating in the east service territory, and we purchase power
back
from the same RTO to supply power to our load. These power sales and
purchases are reported on a net basis as revenues on our Condensed Consolidated
Statements of Income. Other RTOs in which we operate do not function
in the same manner as PJM. They function as balancing organizations
and not as an exchange.
Physical
energy purchases, including those from all RTOs, that are identified as
non-trading, but excluding PJM purchases described in the preceding paragraph,
are accounted for on a gross basis in Purchased Energy for Resale on our
Condensed Consolidated Statements of Income.
In
general, we record expenses when purchased electricity is received and when
expenses are incurred, with the exception of certain power purchase-and-sale
contracts that are derivatives and accounted for using MTM accounting where
generation/supply rates are not cost-based regulated, such as in Ohio and the
ERCOT portion of Texas. In jurisdictions where the generation/supply
business is subject to cost-based regulation, the unrealized MTM amounts are
deferred as regulatory assets (for losses) and regulatory liabilities (for
gains).
For
power
purchased under derivative contracts in our west zone where we are short
capacity, we recognize as revenues the unrealized gains and losses (other than
those subject to regulatory deferral) that result from measuring these contracts
at fair value during the period before settlement. If the contract
results in the physical delivery of power from a RTO or any other counterparty,
we reverse the previously recorded unrealized gains and losses from MTM
valuations and record the settled amounts gross as Purchased Energy for
Resale. If the contract does not result in physical delivery, we
reverse the previously recorded unrealized gains and losses from MTM valuations
and record the settled amounts as revenues on our Condensed Consolidated
Statements of Income on a net basis.
Energy
Marketing and Risk Management Activities
We
engage
in wholesale electricity, natural gas, coal and emission allowances marketing
and risk management activities focused on wholesale markets where we own
assets. Our activities include the purchase and sale of energy under
forward contracts at fixed and variable prices and the buying and selling of
financial energy contracts, which include exchange traded futures and options
and over-the-counter options and swaps. We engage in certain energy
marketing and risk management transactions with RTOs.
We
recognize revenues and expenses from wholesale marketing and risk management
transactions that are not derivatives upon delivery of the
commodity. We use MTM accounting for wholesale marketing and risk
management transactions that are derivatives unless the derivative is designated
in a qualifying cash flow or fair value hedge relationship, or as a normal
purchase or sale. We include the unrealized and realized gains and
losses on wholesale marketing and risk management transactions that are
accounted for using MTM in revenues on our Condensed Consolidated Statements
of
Income on a net basis. In jurisdictions subject to cost-based
regulation, we defer the unrealized MTM amounts as regulatory assets (for
losses) and regulatory liabilities (for gains). We include unrealized
MTM gains and losses resulting from derivative contracts on our Condensed
Consolidated Balance Sheets as Risk Management Assets or Liabilities as
appropriate.
Certain
wholesale marketing and risk management transactions are designated as hedges
of
future cash flows as a result of forecasted transactions (cash flow hedge)
or as
hedges of a recognized asset, liability or firm commitment (fair value
hedge). We recognize the gains or losses on derivatives designated as
fair value hedges in revenues on our Condensed Consolidated Statements of Income
in the period of change together with the offsetting losses or gains on the
hedged item attributable to the risks being hedged. For derivatives
designated as cash flow hedges, we initially record the effective portion of
the
derivative’s gain or loss as a component of Accumulated Other Comprehensive
Income (Loss) and, depending upon the specific nature of the risk being hedged,
subsequently reclassify into revenues or expenses on our Condensed Consolidated
Statements of Income when the forecasted transaction is realized and affects
earnings. We recognize the ineffective portion of the gain or loss in
revenues or expense, depending on the specific nature of the associated hedged
risk, on our Condensed Consolidated Statements of Income immediately, except
in
those jurisdictions subject to cost-based regulation. In those
regulated jurisdictions we defer the ineffective portion as regulatory assets
(for losses) and regulatory liabilities (for gains).
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:
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
Components
|
|
(in
millions)
|
|
Securities
Available for Sale, Net of Tax
|
|
$ |
13
|
|
|
$ |
18
|
|
Cash
Flow Hedges, Net of Tax
|
|
|
(17 |
) |
|
|
(6 |
) |
SFAS
158 Costs, Net of Tax
|
|
|
(224 |
) |
|
|
(235 |
) |
Total
|
|
$ |
(228 |
) |
|
$ |
(223 |
) |
At
September 30, 2007, during the next twelve months, we expect to reclassify
approximately $2 million of net gains from cash flow hedges in AOCI to Net
Income 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
September 30, 2007, thirty-three 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 September 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
|
$/share
|
|
|
|
|
|
$/share
|
|
Earnings
Applicable to Common Stock
|
|
$ |
407
|
|
|
|
|
|
$ |
265
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Basic Shares Outstanding
|
|
|
399.2
|
|
|
$ |
1.02
|
|
|
|
393.9
|
|
|
$ |
0.67
|
|
Average
Dilutive Effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
0.5
|
|
|
|
-
|
|
|
|
2.0
|
|
|
|
-
|
|
Stock
Options
|
|
|
0.3
|
|
|
|
-
|
|
|
|
0.2
|
|
|
|
-
|
|
Restricted
Stock Units
|
|
|
0.1
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
Restricted
Shares
|
|
|
0.1
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
Average
Number of Diluted Shares
Outstanding
|
|
|
400.2
|
|
|
$ |
1.02
|
|
|
|
396.3
|
|
|
$ |
0.67
|
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
|
$/share
|
|
|
|
|
|
$/share
|
|
Earnings
Applicable to Common Stock
|
|
$ |
858
|
|
|
|
|
|
$ |
821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Basic Shares Outstanding
|
|
|
398.4
|
|
|
$ |
2.15
|
|
|
|
393.8
|
|
|
$ |
2.08
|
|
Average
Dilutive Effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
0.6
|
|
|
|
-
|
|
|
|
1.6
|
|
|
|
(0.01 |
) |
Stock
Options
|
|
|
0.4
|
|
|
|
-
|
|
|
|
0.2
|
|
|
|
-
|
|
Restricted
Stock Units
|
|
|
0.1
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
Restricted
Shares
|
|
|
0.1
|
|
|
|
-
|
|
|
|
0.1
|
|
|
|
-
|
|
Average
Number of Diluted Shares
Outstanding
|
|
|
399.6
|
|
|
$ |
2.15
|
|
|
|
395.8
|
|
|
$ |
2.07
|
|
The
assumed conversion of our share-based compensation does not affect net earnings
for purposes of calculating diluted earnings per share as of September 30,
2007.
Options
to purchase 0.1 million and 0.4 million shares of common stock were outstanding
at September 30, 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 average market price of the common shares for the period
and, therefore, the effect would not be dilutive.
Supplementary
Information
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Related
Party Transactions
|
|
(in
millions)
|
|
|
(in
millions)
|
|
AEP
Consolidated Purchased Energy:
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
Valley Electric Corporation (43.47% Owned)
|
|
$ |
59
|
|
|
$ |
54
|
|
|
$ |
164
|
|
|
$ |
167
|
|
Sweeny
Cogeneration Limited Partnership (a)
|
|
|
27
|
|
|
|
30
|
|
|
|
86
|
|
|
|
92
|
|
AEP
Consolidated Other Revenues – Barging and Other Transportation
Services – Ohio Valley Electric Corporation
(43.47% Owned)
|
|
|
7
|
|
|
|
8
|
|
|
|
24
|
|
|
|
23
|
|
AEP
Consolidated Revenues – Utility Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
Pool Purchases – Ohio Valley Electric Corporation
(43.47%
Owned)
|
|
|
(12 |
) |
|
|
-
|
|
|
|
(16 |
) |
|
|
-
|
|
(a)
|
In
October 2007, we sold our 50% ownership in the Sweeny Cogeneration
Limited
Partnership. See “Sweeny Cogeneration Plant” section of Note
5.
|
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 $6 million and $19 million
for the three and nine months ended September 30, 2006,
respectively.
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 $7
million and $23 million for the three and nine months ended September 30, 2006,
respectively. 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 AND EXTRAORDINARY
ITEM
|
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, an entity includes 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. We are evaluating the
effect of the adoption of SFAS 157 on our results of operations and financial
condition. 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. Although we have
not completed our analysis, we expect this cumulative effect adjustment will
have an immaterial impact on our financial statements. 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. Although we have not completed our analysis, we expect the
adoption of this standard to have an immaterial impact on our financial
statements.
EITF
Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based
Payment Awards” (EITF
06-11)
In
June
2007, the FASB ratified the EITF consensus on the treatment of income tax
benefits of dividends on employee share-based compensation. The issue
is how a company should recognize the income tax benefit received on dividends
that are paid to employees holding equity-classified nonvested shares,
equity-classified nonvested share units or equity-classified outstanding share
options and charged to retained earnings under SFAS 123R, “Share-Based
Payments.” Under EITF 06-11, a realized income tax benefit from
dividends or dividend equivalents that are charged to retained earnings and
are
paid to employees for equity-classified nonvested equity shares, nonvested
equity share units and outstanding equity share options should be recognized
as
an increase to additional paid-in capital.
EITF
06-11 will be applied prospectively to the income tax benefits of dividends
on
equity-classified employee share-based payment awards that are declared in
fiscal years beginning after September 15, 2007. We expect that the
adoption of this standard will have an immaterial impact on our financial
statements. We will adopt EITF 06-11 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” (FIN 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.
FIN
39-1 “Amendment of FASB Interpretation No. 39” (FIN
39-1)
In
April
2007, the FASB issued FIN 39-1. It amends FASB Interpretation No. 39,
“Offsetting of Amounts Related to Certain Contracts” by replacing the
interpretation’s definition of contracts with the definition of derivative
instruments per SFAS 133. It also requires entities that offset fair
values of derivatives with the same party under a netting agreement to also
net
the fair values (or approximate fair values) of related cash
collateral. The entities must disclose whether or not they offset
fair values of derivatives and related cash collateral and amounts recognized
for cash collateral payables and receivables at the end of each reporting
period.
FIN
39-1
is effective for fiscal years beginning after November 15, 2007. We
expect this standard to change our method of netting certain balance sheet
amounts but are unable to quantify the effect. It requires
retrospective application as a change in accounting principle for all periods
presented. We will adopt FIN 39-1 effective January 1,
2008.
Future
Accounting Changes
The
FASB’s standard-setting process is ongoing and until new standards have been
finalized and issued by the FASB, we cannot determine the impact on the
reporting of our operations and financial position that may result from any
such
future changes. The FASB is currently working on several projects
including 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.
EXTRAORDINARY
ITEM
In
April
2007, Virginia passed legislation to reestablish regulation for retail
generation and supply of electricity. As a result, we recorded an
extraordinary loss of $118 million ($79 million, net of tax) during the second
quarter of 2007 for the reestablishment of regulatory assets and liabilities
related to our Virginia retail generation and supply operations. In
2000, we discontinued SFAS 71 regulatory accounting in our Virginia jurisdiction
for retail generation and supply operations due to the passage of legislation
for customer choice and deregulation. See “Virginia Restructuring”
section of Note 3.
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
Ending
December 31, 2008, the approved three-year RSPs provide CSPCo and OPCo increases
in their generation rates by 3% and 7%, respectively, effective January 1 each
year and allow possible additional annual generation rate increases of up to
an
average of 4% per year to recover governmentally-mandated costs. In
January 2007, CSPCo and OPCo filed with the PUCO pursuant to the average 4%
generation rate provision of their RSPs to increase their annual generation
rates for 2007 by $24 million and $8 million, respectively, to recover new
governmentally-mandated costs. CSPCo and OPCo implemented these
proposed increases in May 2007 subject to refund. In October 2007,
the PUCO issued an order in the average 4% proceeding which granted CSPCo and
OPCo an annual generation rate increase through December 2008 of $19 million
and
$4 million, respectively. In September 2007, CSPCo and OPCo recorded
a provision for refund to adjust revenues consistent with the rate revenues
granted by the PUCO. Management expects that the average 4% rider
will be reduced to implement the required refunds, while OPCo would implement
a
credit to customers’ bills. CSPCo and OPCo intend to seek rehearing
of the PUCO decision.
In
October 2007, CSPCo and OPCo made a new filing with the PUCO pursuant to the
average 4% generation rate provision of their RSPs for an additional increase
in
their annual generation rates effective January 2008 of $35 million and $12
million, respectively, to recover governmentally-mandated costs and increased
costs related to marginal-loss pricing. CSPCo and OPCo will implement
these proposed increases in January 2008 subject to refund until the PUCO issues
a final order in the matter. Management is unable to predict the
outcome of this filing and its impact on future results of operations and cash
flows.
In
March
2007, CSPCo filed an application under the average 4% generation rate provision
of their RSP to adjust the Power Acquisition Rider (PAR) related to CSPCo's
acquisition of Monongahela Power Company's certified territory in Ohio. The
PAR
was increased to recover the cost of a new purchase power market contract to
serve the load for that service territory. The PUCO approved the
requested increase in the PAR, which is expected to increase CSPCo's revenues
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 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. The Office of Consumers’
Counsel, the Ohio Partners for Affordable Energy, the Ohio Energy Group and
the
PUCO staff supported this settlement agreement. In May 2007, the PUCO
adopted the settlement agreement in its entirety.
Customer
Choice Deferrals
CSPCo’s
and OPCo’s restructuring settlement agreement approved by the PUCO in 2000,
allows CSPCo and OPCo to establish 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. Through September 30, 2007, CSPCo and OPCo incurred $53
million and $54 million, respectively, of such costs and established regulatory
assets of $27 million each for the future recovery of such
costs. CSPCo and OPCo also have the right to recover $6 million and
$7 million, respectively, of equity carrying costs in addition to these
regulatory assets. In 2007, CSPCo and OPCo incurred $3 million and $4
million, respectively, of such costs and established regulatory assets of $2
million each for such costs. 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. However, failure to recover such costs would have an adverse
effect on results of operations and cash flows.
Ohio
IGCC Plant
In
March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of
cost recovery associated with the IGCC plant: Phase 1, recovery of
$24 million in pre-construction costs 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 average 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 a period
of no more than twelve months effective July 1, 2006. Through
September 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC
regulatory assets of $10 million and each collected the entire $12 million
approved by the PUCO. As of September 30, 2007, CSPCo and OPCo have
recorded a liability of $2 million each for the over-recovered portion.
CSPCo and OPCo expect to incur additional pre-construction costs equal to or
greater than the $12 million each recovered.
The
PUCO
indicated that if CSPCo and OPCo have not commenced a continuous course of
construction of the proposed IGCC plant within five years of the June 2006
PUCO
order, all Phase 1 costs collected for pre-construction costs, associated with
items that may be utilized in projects at other sites, must be refunded to
Ohio
ratepayers with interest. The PUCO deferred ruling on cost recovery
for Phases 2 and 3 until further hearings are held. A date for
further rehearings has not been set.
In
August
2006, the Ohio 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. The Ohio Supreme Court heard oral arguments
for these appeals in October 2007. 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 1 cost-related recoveries.
Pending
the outcome of the Supreme Court litigation, CSPCo and OPCo announced they
may
delay the start of construction of the IGCC plant. Recent estimates of the
cost
to build an IGCC plant have escalated to $2.2 billion. CSPCo and OPCo
may need to request an extension to the 5-year start of construction requirement
if the commencement of construction is delayed beyond 2011.
Distribution
Reliability Plan
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
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. The motion was granted in May
2007. CSPCo and OPCo do not intend to implement the enhanced
reliability plan without recovery of any incremental costs.
Ormet
Effective
January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial
customer with a 520 MW load in accordance with a settlement agreement between
CSPCo and OPCo, Ormet, its employees’ union and certain other interested parties
that 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 insufficient, an increase in RSP generation rates under the additional
average 4% generation rate provision of the RSPs.
In
December 2006, CSPCo and OPCo submitted a market price of $47.69 per MWH for
2007, which was approved by the PUCO in June 2007. CSPCo and OPCo
have each amortized $5 million of their Ohio Franchise Tax phase-out tax
regulatory liability to income through September 30, 2007. If the
PUCO approves a lower market price in 2008, it could have an adverse effect
on
future 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.
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 and related orders seeking relief in both state and federal court on
the
grounds that certain aspects of the orders are contrary to the Texas
Restructuring Legislation, PUCT rulemakings and federal law and fail to fully
compensate TCC for its net stranded cost and other true-up items. The
significant items appealed by TCC are:
·
|
The
PUCT ruling that TCC did not comply with the Texas Restructuring
Legislation and PUCT rules regarding the required auction of 15%
of its
Texas jurisdictional installed capacity, which led to a significant
disallowance of capacity auction true-up revenues,
|
·
|
The
PUCT ruling that TCC acted in a manner that was commercially unreasonable,
because TCC failed to determine a minimum price at which it would
reject
bids for the sale of its nuclear generating plant and 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 costs, and
|
·
|
The
two federal matters regarding the allocation of off-system sales
related
to fuel recoveries and the potential tax normalization
violation. See “TCC Deferred Investment Tax Credits and Excess
Deferred Federal Income Taxes” and “TCC and TNC Deferred Fuel ” sections
below.
|
Municipal
customers and other intervenors also appealed the PUCT true-up and related
orders seeking to further reduce TCC’s true-up recoveries. In March
2007, the Texas District Court judge hearing the appeal of the true-up order
affirmed the PUCT’s April 4, 2006 final true-up order for TCC with two
significant exceptions. The judge determined that the PUCT erred by
applying an invalid rule to determine the carrying cost rate for the true-up
of
stranded costs. However, the District Court did not rule that the
carrying cost rate was inappropriate. If the District Court’s ruling
on the carrying cost rate 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 determine a new rate. If the
PUCT reduces the rate, it could result in a material adverse change to TCC’s
recoverable carrying costs, results of operations, cash flows and financial
condition.
The
District Court judge also determined the PUCT improperly reduced TCC’s net
stranded plant costs for commercial unreasonableness. If upheld on
appeal, this ruling could have a materially favorable effect on TCC’s results of
operations and cash flows.
TCC,
the
PUCT and intervenors appealed the District Court true-up order rulings to the
Texas Court of Appeals. Management cannot predict the outcome of
these true-up and related proceedings. If TCC ultimately succeeds in
its appeals in both state and federal court, 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, or if TCC
has a tax normalization violation, 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 TCC’s stranded
generation costs and the amount to be securitized by $51 million related to
the
present value of ADITC and by $10 million of EDFIT associated with TCC’s
generation assets for a total reduction of $61 million. The
reductions were ordered after the PUCT concluded such reductions would not
represent a violation of the Internal Revenue Code normalization
requirements.
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 the PUCT’s proposed flow-through to customers
of the present value of the ADITC and EDFIT benefits as a reduction of stranded
costs would result in a normalization violation. To address the
matter and avoid a possible 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 is not a normalization
violation, then TCC will be required to refund the $103 million, plus additional
carrying costs adversely affecting future cash flows. However, if an
ADITC and EDFIT reduction is ultimately determined to cause a normalization
violation, TCC anticipates the PUCT will permit TCC to retain the $61 million
present value of ADITC and EDFIT plus carrying costs, favorably impacting future
results of operations and cash flows.
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 September 30, 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 actually
returned to ratepayers under a nonappealable order. In TCC’s True-up
Proceeding brief in the Texas Court of Appeals, the PUCT requested a remand
of
the tax normalization issue to consider additional evidence, including TCC’s
private letter ruling issued after close of hearings and a change in proposed
IRS regulations the PUCT had relied upon in its initial
determination. Management intends to continue its efforts to work
with the PUCT to avoid a normalization violation that would adversely affect
future results of operations and cash flows.
TCC
and TNC Deferred Fuel
TCC’s
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 substantial reductions in
TCC’s and TNC’s recoverable fuel costs for, among other things, the reallocation
of additional AEP System off-system sales margins to TCC and TNC under a
FERC-approved tariff. As of September 30, 2007, TCC has refunded the
over-recovered deferred fuel through the CTC rate rider credit. 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 margins in the federal
court. Intervenors also appealed the PUCT’s final fuel rulings in
state court seeking to increase the various allowances.
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. The Court of Appeals affirmed
the District Court’s decision in the TNC case. In April 2007, the
PUCT petitioned the United States Supreme Court for a review of the Court of
Appeals’ order. In October 2007, the United States Supreme Court
denied review of TNC’s case. As a result, TNC recorded income of $9
million in the third quarter of 2007 by reversing the previously recorded
provision resulting from the PUCT’s ordered reallocation of off-system sales
margins. Since it is probable the outcome in the TCC case, still
before the U.S. Court of Appeals, will be the same as in the TNC case, TCC
also
recorded income of $16 million by reversing its provision in the third quarter
of 2007. Based on the TNC case, TCC reduced its deferred fuel
regulatory liability by $16 million in the third quarter of 2007.
The
PUCT
or another interested party may file a complaint at the FERC to address the
allocation issue. Although management cannot predict if a complaint
may be filed at the FERC, management believes the allocations used were in
accordance with the then-existing FERC-approved SIA and additional off-system
sales margins should not be retroactively reallocated to the AEP West companies
including TCC and TNC.
TCC
Excess Earnings
In
2005,
the Texas Court of Appeals issued a decision finding that the PUCT’s prior order
from the unbundled cost of service case requiring TCC to refund to the REPs
excess earnings prior to and outside of the true-up process was unlawful under
the Texas Restructuring Legislation. In June 2007, the Texas Supreme
Court declined review. From 2002 to 2005, TCC refunded $55 million of
excess earnings under the overturned PUCT order, including interest. On remand,
the PUCT must determine how to implement the Court of Appeals decision given
that unauthorized refunds were made. TCC’s stranded cost recovery,
which is currently on appeal, may be affected by the remedy ordered as a result
of the unauthorized refunds. In 2005, management reflected the
obligation to refund excess earnings to customers through the true-up process
and recorded a regulatory asset for the expected refund to be received from
the
REPs, and believes its accounting is correct. However, certain
parties continue to take positions that, if adopted, could result in TCC being
required to pay additional amounts of excess earnings or interest which would
adversely affect future results of operations and cash
flows. Management cannot predict the outcome of these
matters.
TCC
Oklaunion Refund
In
2005,
TCC filed a special request with the PUCT allowing TCC to file its True-up
Proceeding before it had completed the sale of its share of the Oklaunion power
plant. TCC agreed to provide customers the net economic benefit
related to its continued ownership of the Oklaunion power plant until the sale
closed. TCC also agreed to reduce stranded costs in the event the
Oklaunion power plant sales price increased. In June 2007, TCC filed
with the PUCT reporting no change in the sales price and to include the net
economic benefit from the operation of the Oklaunion power plant in the CTC
credit rider. As of September 30, 2007, TCC has recorded a $4 million
regulatory liability for the net economic benefit related to the operation
of
the Oklaunion power plant. Management is unable to predict the
ultimate outcome of this filing. If the PUCT orders a refund greater
than the $4 million recorded liability, it would have an adverse 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 increases in annual base rates of $81
million and $25 million, respectively. Both requests included a
return on common equity of 11.25% and a favorable impact from an expiration
of
the CSW merger savings rate credits (merger credits). In March 2007,
various intervenors and the PUCT staff filed their recommendations with
increases ranging from $8 million to $30 million for TCC. The
recommended return on common equity ranged from 9.00% to 9.75%. In
April 2007, TCC filed rebuttal testimony reducing its requested increase to
$70
million including a reduced requested return on common equity of
10.75%. In May 2007, TNC reached a settlement agreement for a revenue
increase of $14 million including an $8 million increase in base rates and
a $6
million increase related to the impact of the expiration of the merger
credits. TNC received a final order in May 2007 and began billing the
increase in June 2007.
Beginning
in June 2007, TCC implemented an interim base rate increase of $50 million,
subject to refund, in accordance with Texas law. In addition, TCC’s
merger credits were terminated in June 2007, which effectively increased base
rates by $20 million on an annual basis. In May 2007, an ALJ issued
an interim order affirming the termination of the merger credits. In
June 2007, the PUCT affirmed the ALJ ruling. In August 2007, an ALJ
issued a proposal for decision. In October 2007, the PUCT affirmed
the ALJ’s proposal for decision. TCC recognized revenues consistent
with the final order which established a $20 million base rate increase, a
$7
million decrease in depreciation rates, a $20 million increase in revenues
related to the expiration of TCC’s merger credits and a return on common equity
of 9.96%. TCC estimates the base rate annual impact of this final
order will increase TCC’s pretax income by $47 million.
SWEPCo
Fuel Reconciliation – Texas
In
June
2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas
retail operations for the three-year reconciliation period ended December 31,
2005. 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 PUCT staff and intervenor disallowances ranged from
$10 million to $28 million. In June 2007, an ALJ issued a proposal
for decision recommending a $17 million disallowance. Results of
operations for the second quarter of 2007 were adversely affected by $25 million
to reflect the ALJ’s decision that apply to the reconciliation period and
subsequent periods through 2007. In August 2007, the PUCT issued a
final order affirming the ALJ report. In September 2007, SWEPCo filed
a motion for rehearing. In October 2007, the PUCT granted SWEPCo’s
motion for rehearing. The PUCT reversed its prior determination that
SO2 allowance
gains should be credited through the fuel clause. However, the PUCT
ruled SWEPCo was obligated to credit the fuel clause with gains from sales
of
emissions allowances through June 30, 2006. This change affects
allowances sold after June 2006 and its impact will be considered in the fourth
quarter of 2007. In October 2007, the PUCT issued a revised order
which should allow SWEPCo to reverse $7 million of its earlier provision in
the
fourth quarter of 2007. SWEPCO is considering whether to challenge
other parts of the order.
ERCOT
Price-to-Beat (PTB) Fuel Factor Appeal
Several
parties including the Office of Public Utility Counsel and the cities served
by
both TCC and TNC appealed the PUCT’s December 2001 orders establishing initial
PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU (TCC’s and TNC’s
respective former affiliated REPs). In 2003, the District Court ruled
the PUCT record lacked substantial evidence regarding the amount of
unaccounted-for energy (UFE) included in TNC’s PTB fuel factor. The
Court of Appeals upheld the District Court regarding the UFE
issue. AEP’s third quarter 2005 pretax earnings were adversely
affected by $3 million at an assumed 1% UFE factor to reflect the impact of
the
court’s decision. The Supreme Court of Texas has remanded this issue
to the PUCT. If the PUCT adopts a different UFE factor on remand,
future results of operations and cash flows would be adversely
affected. Management is unable to predict the outcome of this remand
or its impact on future results of operations and cash flows.
Stall
Unit
See
“Stall Unit” section within Louisiana Rate Matters for disclosure.
Turk
Plant
See
“Turk
Plant” section within Arkansas Rate Matters for disclosure.
Virginia
Rate Matters
Virginia
Restructuring
In
April
2004, Virginia enacted legislation that amended the Virginia Electric Utility
Restructuring Act extending the transition period to market rates for the
generation and supply of electricity, including the extension of capped rates,
through December 31, 2010. The legislation provided APCo with
specified cost recovery opportunities during the extended capped rate period,
including two optional bundled general base rate changes and an opportunity
for
timely recovery, through a separate rate mechanism, of certain unrecovered
incremental environmental and reliability costs incurred on and after July
1,
2004. Under the amended restructuring law, APCo continues to have an
active fuel clause recovery mechanism in Virginia and continues to have the
opportunity to recover incremental E&R costs.
In
April
2007, the Virginia legislature adopted a comprehensive law providing for the
re-regulation of electric utilities’ generation and supply
rates. These amendments shorten the transition period by two years
(from 2010 to 2008) after which rates for retail generation and supply will
return to cost-based regulation in lieu of market-based rates. 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 investments, (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 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
with a true-up to actual. The legislation also allows APCo to
continue to defer and recover incremental environmental and reliability costs
incurred through December 31, 2008. The new re-regulation legislation
should result in significant positive effects on APCo’s future earnings and cash
flows from the mandated enhanced future returns on equity, the reduction of
regulatory lag from the opportunities to adjust base rates on a biennial basis
and the new opportunities to request timely recovery of certain new costs not
included in base rates.
With
the
new re-regulation legislation, APCo’s generation business again met the criteria
for application of regulatory accounting principles under SFAS
71. The extraordinary pretax reduction in APCo’s earnings and
shareholder’s equity from reapplication of SFAS 71 regulatory accounting of $118
million ($79 million, net of tax) was recorded in the second quarter of
2007. This extraordinary net loss relates to the reestablishment of
$139 million in net generation-related customer-provided removal costs as a
regulatory liability, offset by the restoration of $21 million of deferred
state
income taxes as a regulatory asset. In addition, APCo established a
regulatory asset of $17 million for qualifying SFAS 158 pension costs of the
generation operations that, for ratemaking purposes, are deferred for future
recovery under the new re-regulation legislation. AOCI and Deferred
Income Taxes increased by $11 million and $6 million, respectively.
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 its active fuel
clause. 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 was
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. In May 2006, the Virginia SCC issued an order placing the
net requested base rate increase of $198 million into effect on October 2,
2006,
subject to refund.
In
May
2007, the Virginia SCC issued a final order approving an overall annual base
rate increase of $24 million effective as of October 2006 and approving a return
on equity of 10.0%. As a result of the final order, APCo’s second
quarter pretax earnings decreased by approximately $3 million due to a decrease
in revenues of $42 million net of a recorded provision for refund and related
interest offset by (a) a $15 million net effect from the deferral of unrecovered
incremental E&R costs incurred from October 1, 2006 through June 30, 2007 to
be collected in a future E&R filing, (b) a $9 million net deferral of ARO
costs to be recovered over 10 years and (c) a $15 million retroactive decrease
in depreciation expense. As a result of the Virginia SCC decision to
limit the recovery of incremental E&R costs through the new base rates, APCo
will continue to defer for future recovery unrecovered incremental E&R costs
incurred through 2008 utilizing the E&R surcharge mechanism. APCo
completed the $127 million refund in August 2007.
Virginia
E&R Costs Recovery Filing
In
July
2007, APCo filed a request with the Virginia SCC seeking recovery over the
twelve months beginning December 1, 2007 of approximately $60 million of
unrecovered incremental E&R costs inclusive of carrying costs thereon
incurred from October 1, 2005 through September 30, 2006. In August
2007, the Virginia SCC issued a scheduling order to begin the proceeding before
a hearing examiner on November 5, 2007. In October 2007, the Virginia
SCC staff and the Attorney General both filed testimony recommending that APCo
recover $49 million of its $60 million of requested E&R
costs. The two differences between APCo’s request and the Virginia
SCC staff and the Attorney General’s recommendations relate to the recovery of
carrying costs on the unrecovered incremental E&R costs and the appropriate
return on equity rate. APCo intends to file in 2008 for recovery of
additional incurred incremental E&R costs recorded and deferred after
September 30, 2006.
APCo
is
currently recovering $21 million of incurred E&R costs through the initial
E&R surcharge that will expire on November 30, 2007. Through
September 30, 2007, APCo deferred $70 million in incremental E&R costs to be
recovered in the current and future E&R filings. APCo has not
recognized $15 million of equity carrying charges, which are recognizable when
collected. The $70 million regulatory asset does not include carrying
costs on the unrecovered incremental E&R costs and is based on a return on
equity rate which approximates the Virginia SCC staff and Attorney General’s
recommendations. As a result, if APCo is awarded only $49 million for
the E&R costs incurred for the twelve months ended September 30, 2006 as
recommended by the Virginia SCC staff and the Attorney General, it will not
have
to reverse any of its regulatory asset deferrals.
Virginia
Fuel Clause Filing
In
July
2007, APCo filed an application with the Virginia SCC to seek an annualized
increase, effective September 1, 2007, of $33 million for fuel costs and a
sharing of the benefits of off-system sales between APCo and its
customers. This filing was made in compliance with the minimum 25%
retention of off-system sales margins provision of the new re-regulation
legislation which is effective with the first fuel clause filing after July
1,
2007. This sharing requirement in the new law also includes a true-up
to actual off-system sales margins. In addition, APCo requested
authorization to defer for future recovery the difference between off-system
sales margins credited to customers at 100% of the ordered amount through the
current base rate margin rider and 75% of actual off-system sales margins as
provided in the new law from July 1, 2007 until the new fuel rate becomes
effective.
In
August
2007, the Virginia SCC issued a scheduling order that implemented APCo’s
proposed termination of its base rate off-system sales margin rider on an
interim basis, subject to refund, on September 1, 2007. The order
also implemented APCo’s proposed new fuel factor on an interim basis, effective
September 1, 2007, which includes a credit for the sharing of 75% of off-system
sales margins with customers in compliance with the new law. In
October 2007, APCo, the Virginia SCC staff and certain intervenors filed
memorandums addressing legal issues identified by the Virginia SCC regarding
the
appropriateness of the timing of the implementation of the new expanded fuel
factor and off-system sales margins sharing with customers. Hearings
are scheduled for November 2007. In October 2007, the Virginia SCC
staff submitted testimony stating off-system sales margin sharing for July
and
August 2007 should be denied. In addition, the Virginia SCC staff
asserted that no language exists in the statute requiring implementation of
off-system sales margin sharing any earlier than 2011. Future results
of operations and cash flows could be adversely affected if the Virginia SCC
delays the effective date of the new expanded fuel clause beyond APCo’s filed
request.
West
Virginia IGCC Plant
In
July
2007, APCo filed a request with the Virginia SCC to recover, over the twelve
months beginning January 1, 2009, a return on projected construction work in
progress including development, design and planning costs from July 1, 2007
through December 31, 2009 estimated to be $45 million associated with the
proposed 629 MW IGCC plant to be constructed in West Virginia for an estimated
cost of $2.2 billion. APCo is requesting authorization to defer a
return on actual pre-construction costs incurred beginning July 1, 2007 until
such costs are recovered, starting January 1, 2009 in accordance with the new
re-regulation legislation. The new re-regulation legislation provides
for full recovery of all costs plus return on equity incentives for such new
capacity once the plant is placed in service. See “West Virginia IGCC
Plant” section within West Virginia Rate Matters.
West
Virginia Rate Matters
APCo
and WPCo Expanded Net Energy Cost (ENEC) Filing
In
April
2007, the WVPSC issued an order establishing an investigation and hearing
concerning APCo’s and WPCo’s 2007 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 cost surcharges to become effective July 1, 2007. In
June 2007, the WVPSC issued an order approving, without modification, a joint
stipulation and agreement for settlement reached among the
parties. The settlement agreement provided for an increase in annual
non-base revenues of approximately $86 million effective July 1,
2007. This annual revenue increase primarily includes $55 million of
ENEC and $29 million of construction cost surcharges. The ENEC
portion of the increase is subject to a true-up, which should avoid an earnings
affect from an under-recovery of ENEC costs if they exceed the $55
million.
West
Virginia IGCC Plant
In
January 2006, APCo filed a petition with the WVPSC requesting its approval
of a
Certificate of Public Convenience and Necessity (CCN) to construct a 629 MW
IGCC
plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
County, WV.
In
June
2007, APCo filed testimony with the WVPSC supporting the requests for a CCN
and
for pre-approval of a surcharge rate mechanism to provide for the timely
recovery of both the ongoing finance costs of the project during the
construction period as well as the capital costs, operating costs and a return
on equity once the facility is placed into commercial operation. If
APCo receives all necessary approvals, the plant could be completed as early
as
mid-2012 and currently is expected to cost an estimated $2.2
billion. In July 2007, the WVPSC staff and
intervenors filed to delay the procedural schedule by 90 days. APCo
supported the changes to the procedural schedule. The statutory
decision deadline was revised to March 2008. In July 2007, the WVPSC
approved the revised procedural schedule. Through September 30, 2007,
APCo deferred pre-construction IGCC costs totaling $11 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
Indiana
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 (OUCC) that would provide direct benefits to I&M's
customers if new lower book depreciation rates were 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 were to be 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 and parties to
the settlement agreed to 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. In June 2007, the IURC approved the
settlement agreement, but modified the effective date of the new book
depreciation rates to the date I&M filed a general rate
petition. On June 19, 2007, I&M and the OUCC notified the IURC
that the parties would accept the modification to the settlement
agreement. Therefore, I&M filed its rate petition and reduced its
book depreciation rates as agreed upon in the settlement agreement.
The
settlement agreement modification reduced book depreciation rates, which will
result in an increase of $37 million in pretax earnings for the period June
19,
2007 to December 31, 2007. The $37 million increase is partially
offset by a $5 million regulatory liability, recorded in June 2007, to provide
for the agreed-upon fuel credit. I&M’s approved book depreciation
rates are subject to further review in the general rate
case. Management expects new base rates will become effective in
early 2009.
Indiana
Rate Filing
In
June
2007, I&M filed a rate notification petition with the IURC regarding its
intent to file for a base rate increase with a proposed test year ended
September 30, 2007. The petition indicated, among other things, the
filing would include a request to implement rate tracker mechanisms for certain
variable components of the cost of service including PJM RTO costs, reliability
enhancement costs, demand side management/energy efficiency program costs,
off-system sales margins, and net environmental compliance
costs. This filing will also reflect the revenue requirement
reduction associated with an annual reduction in book depreciation expense.
In
August 2007, the IURC approved the September 30, 2007 test year and the
inclusion of the above trackers in the rate filing with a rate case to be filed
no later than January 31, 2008. Management expects to file the case
in early 2008 with a decision expected in early 2009.
Indiana
Rate Cap
Effective
July 1, 2007, I&M’s rate cap ended for both base and fuel rates in
Indiana. As a result, I&M’s fuel factor in Indiana increased with
the July 2007 billing month to recover the projected cost of
fuel. I&M will resume deferring through revenues any
under/over-recovered fuel costs for future recovery/refund. Under the
capped rates, I&M was unable to recover $44 million of fuel costs since 2004
of which $7 million adversely impacted 2007 pretax earnings through June 30,
2007. Future results of operations should no longer be adversely
impacted by fuel costs.
Michigan
Rate Matters
Michigan
Depreciation Study Filing
In
December 2006, I&M filed a depreciation study in Michigan seeking to reduce
its book depreciation rates. In September 2007, the Michigan Public
Service Commission (MPSC) approved a settlement agreement authorizing I&M to
implement new book depreciation rates. Based on the depreciation
study included in the settlement, I&M agreed to decrease pretax
annual depreciation expense, on a Michigan jurisdictional basis, by
approximately $10 million. This settlement reflects 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 retail
customers’ electric service rates. In addition and as a result of the
new MPSC-approved rates, I&M will decrease pretax annual depreciation
expense, on a FERC jurisdictional basis, by approximately $11 million which
will
reduce wholesale rates for customers representing half the load beginning
in
November 2007 and reduce wholesale rates for the remaining customers in June
2008.
Kentucky
Rate Matters
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 by
the
KPSC.
In
November 2006, the Kentucky Attorney General (AG) 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 specifically as it relates to the recovery of affiliated AEP
Power Pool costs. In KPCo’s order, the KPSC approved 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 AEP Power Pool
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 and paid
through the AEP Power Pool 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. If the appeal is successful, future results of operations and
cash flows could be adversely affected.
Validity
of Nonstatutory Surcharges
In
August
2007, the Franklin Circuit Court concluded the KPSC did not have the authority
to order a surcharge for a gas company subsidiary of Duke Energy absent a full
cost of service rate proceeding due to the lack of statutory
authority. The ruling results from the AG’s appeal of the KPSC’s
approval of a natural gas distribution surcharge for replacement of gas
mains. The AG notified the KPSC that the Franklin County Circuit
Court judge’s order in the Duke Energy case can be interpreted to include
existing surcharges, rates or fees established outside of the context of a
general rate case proceeding and not specifically authorized by statute,
including fuel clauses. The KPSC and Duke Energy are appealing the
Franklin County Circuit Court decision.
Although
this order is not directly applicable to KPCo, it is possible that the AG or
another intervenor could appeal an existing surcharge KPCo is collecting to
the
Franklin County Circuit Court. KPCo’s fuel clause, annual Rockport
Plant capacity surcharge, merger surcredit and credit system sales rider are
not
specifically authorized by statute. These surcharges are currently producing
net
annual revenues of approximately $10 million. KPCo’s Environmental
and demand side management surcharges are specifically authorized by
statute. The KPSC has asked interested parties to brief the issue in
KPCo’s outstanding fuel cost proceeding. The AG’s filed brief took
the position that the KPCo fuel clause should be invalidated because the KPSC
lacked the authority by statute to implement a fuel clause for KPCo without
a
full rate case review. In August 2007, the KPSC issued an order
stating despite the Franklin County Circuit Court decision, the KPSC has the
authority to provide for surcharges and surcredits at least until a Court of
Appeals ruling. The appeals process could take up to two years to
complete. In August 2007, the AG agreed to stipulate to a stay order
over the Franklin County Circuit Court’s decision pending the appeal
decision. KPCo’s exposure is indeterminable at this
time. If the appeal is unfavorable, future results of operations and
cash flows could be adversely affected.
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 purchased power costs through its fuel clause
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
2004,
an Oklahoma ALJ found that the OCC lacks authority to examine whether AEP
deviated from the FERC-approved allocation methodology for off-system sales
margins and held that any such complaints should be addressed at the
FERC. In August 2007, the OCC issued an order adopting the ALJ’s
recommendation that the allocation of system sales/trading margins is a FERC
jurisdictional issue. The Oklahoma Industrial Energy Customers (OIEC)
filed a motion asking the OCC to reconsider its order on the jurisdictional
issue. The OCC stayed its final order regarding the FERC
jurisdictional issue. In October 2007, the OCC lifted its stay stating the
OCC
does not have jurisdiction regarding the allocation methodology for off-system
sales margins.
The
OIEC
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 the AEP System deviated from the FERC-approved allocation
methodologies, but even if one were asserted, management believes that its
allocation of off-system sales margins under the FERC-approved SIA agreement
was
consistent with that agreement. In October 2007, the OCC directed OCC
Staff to file a complaint at FERC concerning this matter.
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 PSO failed
to achieve that he alleges existed during the year. In August 2007,
an ALJ issued a report recommending that PSO’s fuel procurement practices were
prudent and no adjustments were warranted. No parties appealed the
recommendation. In October 2007, the OCC issued a final order
adopting the ALJ’s report.
In
February 2006, the OCC enacted a rule, 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 periodic
reviews. PSO filed its testimony in June 2007 covering the year 2005.
The OCC Staff and intervenors filed testimony in September 2007.
In
May
2007, PSO submitted a filing to the OCC to adjust its fuel/purchase power
rates. In the filing, PSO netted the $42 million of under-recovered
pre-2002 reallocated purchased power costs against their $48 million
over-recovered fuel balance as of April 30, 2007. The $6 million net
over-recovered fuel/purchased power cost deferral balance will be refunded
over
the twelve-month period beginning June 2007. However, in August 2007,
the OIEC filed a motion asking the OCC to order a refund of the $42 million
pre-2002 reallocated purchased power costs netted against the current
over-recovered fuel balance. In October 2007, the OCC denied the
OIEC’s request for refund of the $42 million of under-recovered pre-2002
reallocated purchased power costs.
Management
cannot predict the outcome of the pending fuel and purchased power costs and
prudence reviews, or planned future reviews, but believes that PSO’s fuel and
purchased power procurement practices and costs are prudent and properly
incurred.
Oklahoma
Rate Filing
In
November 2006, PSO filed a request to increase base rates by $50 million for
Oklahoma jurisdictional customers and set return on equity at 11.75% with a
proposed effective date in the second quarter of 2007. PSO also
proposed a formula rate plan that, if approved as filed, would 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 proposed formula rate
plan 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 prevent the capitalization of a significant amount of AFUDC that
would have been recorded during the construction period and recovered in the
future through depreciation expense.
The
ALJ
issued a report in May 2007 recommending a 10.5% return on equity but did not
compute an overall revenue requirement. The ALJ’s report did not
recommend adopting a formula rate plan, but did recommend recovery through
a
rider of certain generation and transmission projects’ financing costs during
construction. However, the report also contained an alternative
recommendation that the OCC could delay a decision on the rider and take up
this
issue in PSO’s application seeking regulatory approval of a new coal-fueled
generating unit. PSO implemented interim rates, subject to refund,
for residential customers beginning July 2007.
In
October 2007, the OCC issued a final order providing for a $10 million annual
increase in base rates with a return on equity of 10%. The final
order also provides for lower depreciation rates, which PSO estimates will
decrease depreciation expense by approximately $10 million on an annual
basis. PSO estimates the annual impact of this final order will
increase PSO’s pretax income by $20 million. The final order also
requires PSO to file a plan with the OCC to promote energy efficiency and
conservation programs within 60 days. PSO implemented the approved
rates in October 2007.
Lawton
and Peaking Generation Settlement Agreement
In
November 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 in June 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 OCC staff, the Attorney General, the Oklahoma Industrial
Energy Consumers and Lawton Cogeneration, L.L.C. supported this settlement
agreement. 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 including permits,
options and engineering studies. PSO paid the $35 million purchase
fee in June 2007 and recorded the purchase fee as a regulatory asset and will
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, currently expected to be 2008. PSO expects these
units will have a substantially lower plant-in-service cost than the proposed
Lawton Cogeneration Facility. PSO may request approval from the OCC
for recovery of costs exceeding the cost cap if special circumstances occur
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. Under the settlement, 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.
Red
Rock Generating Facility
In
July
2006, PSO announced plans to enter into an agreement with Oklahoma Gas and
Electric (OG&E) to build a 950 MW pulverized coal ultra-supercritical
generating unit at the site of OG&E’s existing Sooner Plant near Red Rock,
in north central Oklahoma. PSO would own 50% of the new unit,
OG&E would own approximately 42% and the Oklahoma Municipal Power Authority
(OMPA) would own approximately 8%. OG&E would manage construction
of the plant. OG&E and PSO requested pre-approval to construct
the Red Rock Generating Facility and implement a recovery rider. In
March 2007, the OCC consolidated PSO’s pre-approval application with OG&E’s
request. The Red Rock Generating Facility was estimated to cost $1.8
billion and was expected to be in service in 2012. The OCC staff and
the ALJ recommended the OCC approve PSO’s and OG&E’s filing. As
of September 2007, PSO incurred approximately $20 million of pre-construction
costs and contract cancellation fees.
In
October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of
additional capacity by the year 2012, but denied PSO’s and OG&E’s
application for construction pre-approval stating PSO and OG&E failed to
fully study other alternatives. Since PSO and OG&E could not
obtain pre-approval to build the Red Rock Generating Facility, PSO and OG&E
cancelled the third party construction contract and their joint venture
development contract. Management believes the pre-construction costs
capitalized, including any cancellation fees, were prudently incurred, as
evidenced by the OCC staff and the ALJ’s recommendations that the OCC approve
PSO’s filing, and established a regulatory asset for future
recovery. Management believes such pre-construction costs are
probable of recovery and intends to seek full recovery of such costs in the
near
future. If recovery is denied, future results of operations and cash
flows would be adversely affected. As a result of the OCC’s decision,
PSO will consider various alternative options to meet its capacity needs in
the
future.
2007
Oklahoma Ice Storm
In
October 2007, PSO filed with the OCC requesting recovery of $13 million of
operation and maintenance expenses related to service restoration effort after
a
January 2007 ice storm. PSO proposed to establish a regulatory asset
of $13 million and to amortize this asset coincident with the gains from the
sale of SO2
allowances made during 2007 and thereafter until such gains provide for the
full
recovery of the regulatory asset. If the OCC adopts the PSO proposal,
it would have a favorable impact on future results of operations and cash
flows.
Louisiana
Rate Matters
Louisiana
Compliance Filing
In
October 2002, SWEPCo filed detailed financial information typically utilized
in
a revenue requirement filing, including a jurisdictional cost of service, with
the LPSC. 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
jurisdictional customers, based on a proposed 10% return on
equity. The recommended reduction range was 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. Constructive settlement negotiations are making meaningful
progress. At this time, management is unable to predict the outcome
of this proceeding. If a rate reduction is ultimately ordered, it
would adversely affect future results of operations, cash flows and possibly
financial condition.
Stall
Unit
In
May
2006, SWEPCo announced plans to build a new intermediate load 480 MW natural
gas-fired combustion turbine combined cycle generating unit at its existing
Arsenal Hill Plant location in Shreveport, Louisiana. SWEPCo
submitted the appropriate filings with the PUCT and the Arkansas Public Service
Commission (APSC) during the third quarter of 2006 and the LPSC during the
first
quarter of 2007 to seek approvals to construct the unit. The Stall
Unit is estimated to cost $375 million, excluding AFUDC, and expected to be
in
service in mid-2010. As of September 2007, SWEPCo incurred and
capitalized approximately $15 million and has contractual commitments of an
additional $17 million. If the Stall Unit is not approved,
cancellation fees may be required to terminate SWEPCo’s commitment.
In
March
2007, the PUCT approved SWEPCo’s request. In Louisiana, this request
has been separated from the original request, which included the Turk
Plant. Neither the LPSC nor the APSC have set a procedural schedule
for the project. The project is contingent upon obtaining
pre-approval from the APSC, the LPSC, the PUCT and the Louisiana Department
of
Environmental Quality. If SWEPCo is not authorized to build the Stall
Unit, SWEPCo would seek recovery of incurred costs including any cancellation
fees. If SWEPCo cannot recover incurred costs, including any
cancellation fees, it could adversely affect future results of operations,
cash
flows and possibly financial condition.
Turk
Plant
See
“Turk
Plant” section within Arkansas Rate Matters for disclosure.
Arkansas
Rate Matters
Turk
Plant
In
August
2006, SWEPCo announced plans to build a new base load 600 MW pulverized coal
ultra-supercritical generating unit in Arkansas named Turk
Plant. SWEPCo submitted filings with the APSC in December 2006 and
the PUCT and LPSC in February 2007 to seek approvals to proceed with the
plant. In September 2007, OMPA signed a joint ownership agreement and
agreed to own approximately 7% of the Turk Plant. SWEPCo continues
discussions with Arkansas Electric Cooperative Corporation and North Texas
Electric Cooperative to become potential partners in the Turk
Plant. SWEPCo anticipates owning approximately 73% of the Turk Plant
and will operate the facility. The Turk Plant is estimated to cost
$1.3 billion in total with SWEPCo’s portion estimated to cost $950 million,
excluding AFUDC. If approved on a timely basis, the plant is expected
to be in-service in mid-2011. As of September 2007, SWEPCo incurred
and capitalized approximately $206 million and has contractual commitments
for
an additional $875 million. If the Turk Plant is not approved,
cancellation fees may be required to terminate SWEPCo’s commitment.
In
August
2007, hearings began before the APSC seeking pre-approval of the plant. The
APSC
staff recommended the application be approved and intervenors requested the
motion be denied. In October 2007, final briefs and closing arguments
were completed by all parties during which the APSC staff and Attorney General
supported the plant. A decision by the APSC will occur within 60 days
from October 22, 2007. In September 2007, the PUCT staff recommended
that SWEPCo’s application be denied suggesting the construction of the Turk
Plant would adversely impact the development of competition in the SPP
zone. The PUCT hearings were held in October 2007. The
LPSC held hearings in September 2007 and during this proceeding, the LPSC staff
expressed support for the project. If SWEPCo is not authorized
to build the Turk plant, SWEPCo would seek recovery of incurred costs including
any cancellation fees. If SWEPCo cannot recover incurred costs,
including any cancellation fees, it could adversely affect future results of
operations, cash flows and possibly financial condition.
Stall
Unit
See
“Stall Unit” section within Louisiana Rate Matters for disclosure.
FERC
Rate Matters
Transmission
Rate Proceedings at the FERC
SECA
Revenue Subject to Refund
Effective
December 1, 2004, AEP and other transmission owners in the region covered by
PJM
and the Midwest ISO (MISO) eliminated transaction-based through-and-out
transmission service (T&O) charges in accordance with FERC orders and
collected load-based charges, referred to as RTO SECA, to mitigate the loss
of
T&O revenues on a temporary basis through March 31,
2006. 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 they collected. If a refund is
ordered, the AEP East companies would also receive refunds related to the SECA
rates they paid to third parties. The AEP East companies recognized
gross SECA revenues of $220 million. Approximately $10 million of these recorded
SECA revenues billed by PJM were not collected. The AEP East
companies filed a motion with the FERC to force payment of these uncollected
SECA billings.
In
August
2006, a FERC ALJ issued an initial decision, finding that the rate design for
the recovery of SECA charges was flawed and that a large portion of the “lost
revenues” reflected in the SECA rates 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.
In
2006,
the AEP East companies provided reserves of $37 million in net refunds for
current and future SECA settlements with all of the AEP East companies’ SECA
customers. The AEP East companies reached settlements with certain
SECA customers related to approximately $69 million of such revenues for a
net
refund of $3 million. The AEP East companies are in the process of
completing two settlements-in-principle on an additional $36 million of SECA
revenues and expect to make net refunds of $4 million when those settlements
are
approved. Thus, completed and in-process settlements cover $105
million of SECA revenues and will consume about $7 million of the reserves
for
refunds, leaving approximately $115 million of contested SECA revenues and
$30
million of refund reserves. If the ALJ’s initial decision were upheld
in its entirety, it would disallow approximately $90 million of the AEP East
companies’ remaining $115 million of unsettled gross SECA
revenues. Based on recent settlement experience and the expectation
that most of the $115 million of unsettled SECA revenues will be settled,
management believes that the remaining reserve of $30 million will be adequate
to cover all remaining settlements.
In
September 2006, AEP, together with Exelon Corporation 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 contradicts prior related FERC decisions,
which are presently subject to rehearing. Furthermore, management
believes the ALJ’s findings on key issues are largely without
merit. As directed by the FERC, management is working to settle the
remaining $115 million of unsettled revenues within the remaining reserve
balance. Although management believes it has meritorious arguments
and can settle with the remaining customers within the amount provided,
management cannot predict the ultimate outcome of ongoing settlement talks
and,
if necessary, any future FERC proceedings or court appeals. If the
FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of
the remaining unsettled claims within the amount provided, it will have an
adverse effect on future results of operations, cash flows and financial
condition.
The
FERC PJM Regional Transmission Rate Proceeding
In
January 2005, certain transmission owners in PJM proposed continuation of the
zonal rate design in PJM after the June 2005 FERC deadline. With the
elimination of T&O rates and the expiration of SECA rates, zonal rates would
provide the AEP System no revenue for use of its transmission facilities by
other parties in PJM and the MISO. AEP protested the zonal rate
proposal and 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 the
AEP
East companies 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 proposed and supported a
new PJM rate regime generally referred to as a Highway/Byway rate
design.
Hearings
were held in April 2006 and the ALJ issued an initial decision in July
2006. The ALJ found the existing PJM zonal rate design to be unjust
and determined that it should be replaced. The ALJ found the
Highway/Byway proposed rates 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.
In
April
2007, the FERC issued an order reversing the ALJ’s decision. The FERC
ruled that the current PJM rate design is just and reasonable for existing
transmission facilities. However, the FERC 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 bear the full cost of the existing AEP east transmission
zone facilities. Presently AEP is collecting the full cost of those
facilities from its retail customers with the exception of Indiana and Michigan
customers. As a result of this order, the AEP East companies’
customers will also be charged a share of the cost of future new 500 kV and
higher voltage transmission facilities built in PJM, most of which are expected
to be upgrades of the facilities 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 has requested rehearing of this
order. Management cannot estimate at this time what effect, if any,
this order will have on the AEP East companies’ future construction of new east
transmission facilities, results of operations, cash flows and financial
condition. In May 2007, the AEP East companies filed for rehearing
related to this FERC decision.
Since
the
FERC’s decision in 2005 to cease through-and-out rates and replace them
temporarily with SECA rates, which ceased on April 1, 2006, the AEP East
companies increased their retail rates in all states except Indiana, Michigan
and Tennessee to recover lost T&O and SECA revenues. The AEP East
companies presently recover from retail customers approximately 85% of the
lost
T&O/SECA transmission revenues of $128 million a year. Future
results of operations, cash flows and financial condition will continue to
be
adversely affected in Indiana, Michigan and Tennessee until these lost
T&O/SECA transmission revenues are recovered in retail rates.
The
FERC PJM and MISO Regional Transmission Rate Proceeding
In
the
SECA proceedings, the FERC ordered the RTOs and transmission owners in the
PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to
establish a permanent transmission rate design for the Super Region effective
February 1, 2008. All of the transmission owners in PJM and MISO,
with the exception of AEP and one MISO transmission owner, voted to continue
zonal rates in both RTOs. In September 2007, AEP filed a formal
complaint proposing a highway/byway rate design be implemented for the Super
Region. AEP argues the use of other PJM and MISO facilities by AEP is
not as large as the use of AEP transmission by others in PJM and
MISO. Therefore a regional rate design change is required to
recognize the provision and use of transmission service in the Super Region
since it is not sufficiently uniform between transmission owners and users
to
justify zonal rates. Management is unable to predict the outcome of
this case.
SPP
Transmission Formula Rate Filing
In
June
2007, AEPSC filed revised tariff sheets on behalf of PSO and SWEPCo for the
AEP
pricing zone of the SPP OATT. The revised tariff sheets seek to
establish an up-to-date revenue requirement for SPP transmission services over
the facilities owned by PSO and SWEPCo and implement a transmission cost of
service formula rate.
PSO
and
SWEPCo requested an effective date of September 1, 2007 for the revised
tariff. The primary impact of the filed revised tariff will be an
increase in network transmission service revenues from nonaffiliated municipal
and rural cooperative utilities in the AEP pricing zone of SPP. If
the proposed formula rate and requested return on equity are approved, the
2008
network transmission service revenues from nonaffiliates will increase by
approximately $10 million compared to the revenues that would result from the
presently approved network transmission rate. PSO and SWEPCo take
service under the same rate, and will also incur the increased OATT charges
resulting from the filing, but will receive corresponding revenue to offset
the
increase. In August 2007, the FERC issued an order conditionally
accepting PSO’s and SWEPCo’s proposed formula rate, subject to a compliance
filing, suspended the effective date until February 1, 2008 and established
hearing and settlement judge proceedings. In October 2007, AEPSC submitted
a
compliance filing on behalf of PSO and SWEPCo. Multiple intervenors
have protested or requested re-hearing of the order. Discovery and
settlement discussions have begun.
PJM
Marginal-Loss Pricing
On
June
1, 2007, in response to a 2006 FERC order, PJM revised its methodology for
considering transmission line losses in generation dispatch and the calculation
of locational marginal prices. Marginal-loss dispatch
recognizes the varying delivery costs of transmitting electricity from
individual generator locations to the places where customers consume the
energy. Prior to the implementation of marginal-loss dispatch, PJM
used average losses in dispatch and in the calculation of locational marginal
prices. Locational marginal prices in PJM now include the real-time
impact of transmission losses from individual sources to loads. Due
to the implementation of marginal-loss pricing, for the period June 1, 2007
through September 30, 2007, AEP experienced an increase in the cost of
delivering energy from the generating plant locations to customer load zones
partially offset by cost recoveries and increased off-system sales resulting
in
a net loss of approximately $25 million. AEP has initiated
discussions with PJM regarding the impact it is experiencing from the change
in
methodology and will pursue through the appropriate stakeholder processes a
modification of such methodology. Management believes these
additional costs should be recoverable through retail and/or cost-based
wholesale rates and is seeking recovery in current and future fuel or base
rate
filings as appropriate in each of its eastern zone states. In the
interim, these costs will have an adverse effect on future results of operations
and cash flows. Management is unable to predict whether full recovery
will ultimately be approved.
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. There is no
collateral held in relation to any guarantees in excess of our ownership
percentages. In the event any guarantee is drawn, there is no
recourse to third parties unless specified below.
Letters
of Credit
We
enter
into standby letters of credit (LOCs) with third parties. These LOCs
cover items such as gas and electricity risk management contracts, construction
contracts, insurance programs, security deposits, debt service reserves and
credit enhancements for issued bonds. As the parent company, we
issued all of these LOCs in our ordinary course of business on behalf of our
subsidiaries. At September 30, 2007, the maximum future payments for
all the LOCs were approximately $69 million with maturities ranging from
November 2007 to October 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 $65 million. Since SWEPCo uses self-bonding, the
guarantee provides for SWEPCo to commit to use its resources to complete the
reclamation in the event the work is not completed by Sabine Mining Company
(Sabine), an entity consolidated under FIN 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 September 30, 2007, SWEPCo has collected approximately
$33 million through a rider for final mine closure costs, of which approximately
$15 million is recorded in Deferred Credits and Other and approximately $18
million is recorded in Asset Retirement Obligations on our Condensed
Consolidated Balance Sheets.
Sabine
charges SWEPCo, its only customer, all of 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 $1.3
billion (approximately $1 billion relates to the Bank of America (BOA)
litigation, see “Enron Bankruptcy” section of this note). There are
no material liabilities recorded for any indemnifications.
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. Assuming the fair market value of the
equipment is zero at the end of the lease term, the maximum potential loss
for
these lease agreements was approximately $59 million ($39 million, net of tax)
as of September 30, 2007.
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. Assuming the fair market value of the equipment is zero at
the end of the current lease term, the maximum potential loss was approximately
$30 million ($20 million, net of tax) as of September 30, 2007. 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 20-year period. In April 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.
On
October 9, 2007, we announced that we had entered into a consent decree with
the
Federal EPA, the DOJ, the states and the special interest groups. Under the
consent decree, we agreed to annual SO2 and NOx
emission caps for
sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia
and
West Virginia. In addition to completing the installation of previously
announced environmental retrofit projects at many of the plants, including
the
installation of flue gas desulfurization (FGD or scrubbers) equipment at Big
Sandy and at Muskingum River plants by the end of 2015, we agreed to install
selective catalytic reduction (SCR) and FGD emissions control equipment at
Rockport Plant. Unit 1 at the Rockport Plant will be retrofit by the end of
2017, and Unit 2 will be retrofit by the end of 2019. We also agreed
to install selective non-catalytic reduction, a NOx-reduction
technology, by the end of 2009 at Clinch River Plant.
Since
2004, we spent nearly $2.6 billion on installation of emissions control
equipment on our coal-fueled plants in Kentucky, Ohio, Virginia and West
Virginia as part of a larger plan to invest more than $5.1 billion by 2010
to
reduce the emissions of our generating fleet.
We
agreed
to operate SCRs year round during 2008 at Mountaineer, Muskingum River and
Amos
plants, and agreed to plant-specific SO2 emission
limits for
Clinch River and Kammer plants.
Under
the
consent decree, we will pay a $15 million civil penalty and provide $36 million
for environmental mitigation projects coordinated with the federal government
and $24 million to the states for environmental mitigation. We
expensed these amounts in the third quarter of 2007.
The
consent decree will resolve all issues related to various parties’ claims
against us in the two pending NSR cases. The consent decree has been filed
with
the U.S. District Court. The consent decree is subject to a 30-day public
comment period and final approval by the Court. A hearing on the
motion to approve the consent decree is scheduled for December 10,
2007.
We
believe we can recover any capital and operating costs of additional pollution
control equipment that may be required as a result of the consent decree
through
regulated rates or market prices of electricity. If we are unable to
recover such costs, it would adversely affect our future results of operations,
cash flows and possibly financial condition.
Cases
are
still pending that could affect CSPCo’s share of jointly-owned units at
Beckjord, Zimmer, and Stuart stations. No trial date has yet been
established in the Stuart case, but the units, operated by Dayton Power and
Light Company, are equipped with SCR controls and the installation of FGD
controls will be completed in 2007. The Beckjord and Zimmer case is
scheduled for a liability trial in May 2008. Zimmer is equipped with
both FGD and SCR controls. Beckjord and Zimmer are operated by Duke
Energy Ohio, Inc. 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.
We
are
unable to estimate the loss or range of loss related to any contingent
liability, if any, we might have for civil penalties under the pending CAA
proceedings for our jointly-owned plants. 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 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 to commence during the first quarter of 2008.
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. In
June 2007, TCEQ denied that motion.
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. The Second Circuit requested supplemental briefs
addressing the impact of the Supreme Court’s decision on this
case. 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
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
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
May
2007, the United States Court of Appeals for the Second Circuit ruled that
the
lower court was correct in finding that TEM breached the PPA and we did not
breach the PPA. It also ruled that the lower court applied an
incorrect standard in denying us any damages for TEM’s breach of the 20-year
term of the PPA holding that we are entitled to the benefit of our bargain
and
that the trial court must determine our damages. The Court of Appeals
vacated approximately $117 million of our $123 million judgment for damages
against TEM related to replacement products and remanded the issue for further
proceedings to determine the correct amount of those damages. One
part of the judgment is final, that involves TEM’s liability for damages
applicable to gas peaking and post-actual commercial operation date
products. We expect TEM to pay the amount of those damages,
approximately $8 million, including interest, in the fourth quarter of
2007.
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. 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
August
2007, the Judge in the New York action, issued a decision granting BOA summary
judgment without awarding any damages and dismissing our claims. The
Judge held another hearing in September 2007 and said that he plans a further
hearing on the damages issue. We asked the Judge to certify an appeal
of the legal issues decided by his summary judgment rulings prior to any ruling
on damages. At this time we are unable to predict how the Judge will
rule on the pending request. If the Judge issues a judgment directing
us to pay an amount in excess of the gain on the sale of HPL, described below,
and if we are unsuccessful in having the judgment reversed or modified, the
judgment could have a material adverse effect on results of operations, cash
flows, 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 and recognition of the gain on the sale 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,
estimated to be $382 million and $380 million at September 30, 2007 and December
31, 2006, respectively, 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 a material 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. In August
2007, the appeals court reversed the trial court’s decision and held that the
plaintiff did have standing to pursue his claim. The appeals court remanded
the
case to the trial court to consider the issue of whether the plaintiff is an
adequate representative for the class of plan participants on whose behalf
the
litigation would be pursued. 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 and subsequently, the judge in Nevada
dismissed a number of the remaining cases on the basis of the filed rate
doctrine. Plaintiffs in these cases appealed the
decisions. In July 2007, the judge in the California cases stayed
those proceedings pending a decision by the Ninth Circuit in the federal
cases. In September 2007, the United States Court of Appeals for the
Ninth Circuit reversed the dismissal of two of the cases and remanded those
cases to the trial court. However, the Ninth Circuit must rule on
AEP’s claim that the plaintiffs failed to timely appeal the trial judge’s
separate dismissal of AEP. In the other case, AEP has pending before
the trial court a separate motion to dismiss based on plaintiffs’ failure to
state a claim against the AEP companies that was not addressed when the trial
judge dismissed the case based on the filed rate doctrine. 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 because the market for power was allegedly dysfunctional
at
the time such contracts were executed. An ALJ recommended rejection
of the complaint, holding 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. On
September 25, 2007, the U.S. Supreme Court decided to review the Ninth Circuit’s
decision. 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 $2
million. CSPCo completed the purchase in April 2007. The
Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple
cycle power plant with a generating capacity of 480 MW.
Lawrenceburg
Generating Station (Utility Operations segment)
In
January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station
(Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG)
for
$325 million and the assumption of liabilities of $3 million. AEGCo
completed the purchase in May 2007. The Lawrenceburg plant is located
in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a
natural gas, combined cycle power plant with a generating capacity of 1,096
MW. AEGCo sells the power to CSPCo through a FERC-approved unit power
contract.
Dresden
Plant (Utility Operations segment)
In
August
2007, AEGCo agreed to purchase the partially completed Dresden Plant from
Dominion Resources, Inc. for $85 million and the assumption of liabilities
of $2
million. AEGCo completed the purchase in September
2007. Management estimates that approximately $180 million in
additional costs (excluding AFUDC) will be required to finish the construction
of the plant. The Dresden Plant is located near Dresden, Ohio and is
a natural gas, combined cycle power plant. When completed in 2009,
the Dresden Plant will have a generating capacity of 580 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 capital
adjustments. The sale did not have an impact on our results of
operations nor do we expect the 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 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.
Sweeny
Cogeneration Plant (Generation and Marketing segment)
In
October 2007, we sold our 50% equity interest in the Sweeny Cogeneration Plant
(Sweeny) to ConocoPhillips for approximately $80 million, including working
capital and the buyer’s assumption of project debt. The Sweeny
Cogeneration Plant is a 450 MW cogeneration plant located within ConocoPhillips’
Sweeny refinery complex southwest of Houston, Texas. We are the
managing partner of the plant, which is co-owned by General Electric
Company. As a result of the sale, we estimate that we will realize a
$46 million pretax gain in the fourth quarter of 2007.
In
addition to the sale of our interest in Sweeny, we agreed to separately sell
our
purchase power contract for our share of power generated by Sweeny through
2014
for $11 million to ConocoPhillips. ConocoPhillips also agreed to assume certain
related third-party power obligations. These transactions were
completed in conjunction with the sale of our 50% equity interest in October
2007. As a result of this sale, we estimate that we will realize an
$11 million pretax gain in the fourth quarter of 2007. In the fourth
quarter of 2007, we estimate that we will realize a total of $57 million in
pretax gains related to the sales of our investments in the Sweeny Plant and
the
related purchase power contracts.
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. In February 2006, we
completed the sale of the 50% interest in Bajio for $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 the
following in 2007 and 2006 related to discontinued operations:
|
|
U.K.
Generation
(a)
|
|
Nine
Months Ended September 30,
|
|
(in
millions)
|
|
2007
Revenue
|
|
$
|
-
|
|
2007
Pretax Income
|
|
|
3
|
|
2007
Earnings, Net of Tax
|
|
|
2
|
|
|
|
|
|
|
2006
Revenue
|
|
$
|
-
|
|
2006
Pretax Income
|
|
|
9
|
|
2006
Earnings, Net of Tax
|
|
|
6
|
|
(a)
|
The
2007 amounts relate to tax adjustments from the sale. Amounts
in 2006 relate to a release of accrued liabilities for the settlement
of
the London office lease and tax adjustments related to the
sale.
|
For
the
quarter ended September 30, 2007 and 2006, there was no income statement impact
related to our discontinued operations. There were no cash flows used
for or provided by operating, investing or financing activities related to
our
discontinued operations for the nine months ended September 30, 2007 and
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. 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
did not meet the “component-of-an-entity” criteria because the plant did not
have cash flows that can be clearly distinguished operationally. The
plant also did not meet the “component-of-an-entity” criteria for financial
reporting purposes because the plant did not operate individually, but rather
as
a part of the AEP System.
Assets
Held for Sale were as follows:
|
|
September
30,
|
|
|
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 are 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 and nine months ended September 30, 2007 and
2006:
|
|
|
|
|
Other
|
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension
Plans
|
|
|
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Three
Months Ended September 30, 2007 and 2006
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
24
|
|
|
$ |
23
|
|
|
$ |
11
|
|
|
$ |
10
|
|
Interest
Cost
|
|
|
59
|
|
|
|
57
|
|
|
|
26
|
|
|
|
26
|
|
Expected
Return on Plan Assets
|
|
|
(85 |
) |
|
|
(82 |
) |
|
|
(26 |
) |
|
|
(24 |
) |
Amortization
of Transition Obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
6
|
|
|
|
7
|
|
Amortization
of Net Actuarial Loss
|
|
|
15
|
|
|
|
20
|
|
|
|
3
|
|
|
|
5
|
|
Net
Periodic Benefit Cost
|
|
$ |
13
|
|
|
$ |
18
|
|
|
$ |
20
|
|
|
$ |
24
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension
Plans
|
|
|
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Nine
Months Ended September 30, 2007 and 2006
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
72
|
|
|
$ |
71
|
|
|
$ |
32
|
|
|
$ |
30
|
|
Interest
Cost
|
|
|
176
|
|
|
|
171
|
|
|
|
78
|
|
|
|
76
|
|
Expected
Return on Plan Assets
|
|
|
(254 |
) |
|
|
(248 |
) |
|
|
(78 |
) |
|
|
(70 |
) |
Amortization
of Transition Obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
20
|
|
|
|
21
|
|
Amortization
of Net Actuarial Loss
|
|
|
44
|
|
|
|
59
|
|
|
|
9
|
|
|
|
15
|
|
Net
Periodic Benefit Cost
|
|
$ |
38
|
|
|
$ |
53
|
|
|
$ |
61
|
|
|
$ |
72
|
|
As
outlined in our 2006 Annual Report, our primary business strategy and the core
of our business 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 continues to have
commission-determined transition rates.
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, 30% relates to agricultural
products, 18% relates to steel and 17% relates to other
commodities.
|
Generation
and Marketing
·
|
IPPs,
wind farms and marketing and risk management activities primarily
in
ERCOT. Our 50% interest in the Sweeny Cogeneration Plant was
sold in October 2007. See “Sweeny Cogeneration Plant” section
of Note 5.
|
The
remainder of our activities is presented as All Other. While not
considered a business segment, All Other includes:
·
|
Parent’s
guarantee revenue received from affiliates, 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 and nine
months ended September 30, 2007 and 2006 and balance sheet information as of
September 30, 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 September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$ |
3,423
|
|
|
$ |
134
|
|
|
$ |
241
|
|
|
$ |
(9 |
) |
|
$ |
-
|
|
|
$ |
3,789
|
|
Other
Operating Segments
|
|
|
177
|
|
|
|
4
|
|
|
|
(161 |
) |
|
|
19
|
|
|
|
(39 |
) |
|
|
-
|
|
Total
Revenues
|
|
$ |
3,600
|
|
|
$ |
138
|
|
|
$ |
80
|
|
|
$ |
10
|
|
|
$ |
(39 |
) |
|
$ |
3,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$ |
388
|
|
|
$ |
18
|
|
|
$ |
3
|
|
|
$ |
(2 |
) |
|
$ |
-
|
|
|
$ |
407
|
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
|
MEMCO
Operations
|
|
|
Generation
and
Marketing
|
|
|
All
Other (a)
|
|
|
Reconciling
Adjustments
|
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Three
Months Ended September 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External Customers
|
|
$ |
3,478
|
|
|
$ |
135
|
|
|
$ |
14
|
|
|
$ |
(33 |
) |
|
$ |
-
|
|
|
$ |
3,594
|
|
Other Operating Segments
|
|
|
(41 |
) |
|
|
4
|
|
|
|
-
|
|
|
|
52
|
|
|
|
(15 |
) |
|
|
-
|
|
Total
Revenues
|
|
$ |
3,437
|
|
|
$ |
139
|
|
|
$ |
14
|
|
|
$ |
19
|
|
|
$ |
(15 |
) |
|
$ |
3,594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$ |
378
|
|
|
$ |
19
|
|
|
$ |
4
|
|
|
$ |
(136 |
) |
|
$ |
-
|
|
|
$ |
265
|
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
|
MEMCO
Operations
|
|
|
Generation
and
Marketing
|
|
|
All
Other (a)
|
|
|
Reconciling
Adjustments
|
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$ |
9,127
|
|
|
$ |
367
|
|
|
$ |
574
|
|
|
$ |
36
|
|
|
$ |
-
|
|
|
$ |
10,104
|
|
Other
Operating Segments
|
|
|
460
|
|
|
|
10
|
|
|
|
(347 |
) |
|
|
(14 |
) |
|
|
(109 |
) |
|
|
-
|
|
Total
Revenues
|
|
$ |
9,587
|
|
|
$ |
377
|
|
|
$ |
227
|
|
|
$ |
22
|
|
|
$ |
(109 |
) |
|
$ |
10,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued
Operations
and Extraordinary Loss
|
|
$ |
879
|
|
|
$ |
40
|
|
|
$ |
17
|
|
|
$ |
(1 |
) |
|
$ |
-
|
|
|
$ |
935
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
2
|
|
Extraordinary
Loss, Net of Tax
|
|
|
(79 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(79 |
) |
Net
Income
|
|
$ |
800
|
|
|
$ |
40
|
|
|
$ |
17
|
|
|
$ |
1
|
|
|
$ |
-
|
|
|
$ |
858
|
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
|
MEMCO
Operations
|
|
|
Generation
and
Marketing
|
|
|
All
Other (a)
|
|
|
Reconciling
Adjustments
|
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$ |
9,259
|
|
|
$ |
368
|
|
|
$ |
47
|
|
|
$ |
(36 |
) |
|
$ |
-
|
|
|
$ |
9,638
|
|
Other
Operating Segments
|
|
|
(60 |
) |
|
|
9
|
|
|
|
-
|
|
|
|
89
|
|
|
|
(38 |
) |
|
|
-
|
|
Total
Revenues
|
|
$ |
9,199
|
|
|
$ |
377
|
|
|
$ |
47
|
|
|
$ |
53
|
|
|
$ |
(38 |
) |
|
$ |
9,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued
Operations
|
|
$ |
902
|
|
|
$ |
54
|
|
|
$ |
10
|
|
|
$ |
(151 |
) |
|
$ |
-
|
|
|
$ |
815
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6
|
|
|
|
-
|
|
|
|
6
|
|
Net
Income (Loss)
|
|
$ |
902
|
|
|
$ |
54
|
|
|
$ |
10
|
|
|
$ |
(145 |
) |
|
$ |
-
|
|
|
$ |
821
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
MEMCO
Operations
|
|
Generation
and
Marketing
|
|
All
Other (a)
|
|
Reconciling
Adjustments
|
|
Consolidated
|
|
September
30, 2007
|
|
(in
millions)
|
|
Total
Property, Plant and Equipment
|
|
$
|
44,547
|
|
$
|
255
|
|
$
|
566
|
|
$
|
38
|
|
$
|
(237
|
)
(b)
|
$
|
45,169
|
|
Accumulated
Depreciation and
Amortization
|
|
|
15,978
|
|
|
58
|
|
|
105
|
|
|
7
|
|
|
(9
|
)
(b)
|
|
16,139
|
|
Total
Property, Plant and Equipment –
Net
|
|
$
|
28,569
|
|
$
|
197
|
|
$
|
461
|
|
$
|
31
|
|
$
|
(228
|
)
(b)
|
$
|
29,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
38,423
|
|
$
|
326
|
|
$
|
746
|
|
$
|
11,948
|
|
$
|
(11,987
|
)
(c)
|
$
|
39,456
|
|
|
|
|
|
|
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
|
)(c)
|
$
|
37,987
|
|
Assets
Held for Sale
|
|
|
44
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
44
|
|
(a)
|
All
Other includes:
|
|
·
|
Parent’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 Property, Plant and Equipment and Accumulated
Depreciation and Amortization as of September 30, 2007 represent
the
elimination of an intercompany capital lease that began during the
first
quarter of 2007.
|
(c)
|
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.
|
We,
along
with our subsidiaries, file a consolidated federal income tax
return. The allocation of the AEP System’s current consolidated
federal income tax to the AEP System companies allocates the benefit of current
tax losses to the AEP System companies giving rise to such losses in determining
their current expense. The tax benefit of the parent is allocated to
our subsidiaries with taxable income. With the exception of the loss
of the parent company, the method of allocation approximates a separate return
result for each company in the consolidated group.
Audit
Status
We,
along
with our subsidiaries, 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 examination 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 on 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 2005 are presently being audited by the IRS and we anticipate
that
the audit of the 2000 through 2003 years will be completed by the end of
2007.
The
IRS
has proposed certain adjustments to our foreign tax credit and interest
allocation positions. Management has evaluated the proposed
adjustments and has agreed to pay the related taxes. Management does
not anticipate that the adjustments will 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 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 the timing of such deductibility
is
uncertain. 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 Other Operation
and Maintenance. As of January 1, 2007, we accrued $25 million for
the payment of uncertain interest and penalties.
Michigan
Tax Restructuring
On
July
12, 2007, the Governor of Michigan signed Michigan Senate Bill 0094 (MBT Act)
and related companion bills into law providing a comprehensive restructuring
of
Michigan’s principal business tax. The new law is effective January
1, 2008 and replaces the Michigan Single Business Tax that is scheduled to
expire at the end of 2007. The MBT Act is composed of a new tax which
will be calculated based upon two components: (a) a business income
tax (BIT) imposed at a rate of 4.95% and (b) a modified gross receipts tax
(GRT)
imposed at a rate of 0.80%, which will collectively be referred to as the
BIT/GRT tax calculation. The new law also includes significant
credits for engaging in Michigan-based activity.
On
September 30, 2007, the Governor of Michigan signed House Bill 5198 which amends
the MBT Act to provide for a new deduction on the BIT and GRT tax returns equal
to the book-tax basis differences triggered as a result of the enactment of
the
MBT Act. This new state-only temporary difference will be deducted
over a 15-year period on the MBT Act tax returns starting in
2015. The purpose of the new MBT Act state deduction was to provide
companies relief from the recordation of the SFAS 109 Income Tax
Liability. We have evaluated the impact of the MBT Act and the
application of the MBT Act will not materially affect our results of operations,
cash flows or financial condition.
Long-term
Debt
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
Type
of Debt
|
|
(in
millions)
|
|
Senior
Unsecured Notes
|
|
$ |
9,752
|
|
|
$ |
8,653
|
|
Pollution
Control Bonds
|
|
|
2,134
|
|
|
|
1,950
|
|
First
Mortgage Bonds
|
|
|
-
|
|
|
|
90
|
|
Defeased
First Mortgage Bonds (a)
|
|
|
19
|
|
|
|
27
|
|
Notes
Payable
|
|
|
303
|
|
|
|
337
|
|
Securitization
Bonds
|
|
|
2,257
|
|
|
|
2,335
|
|
Notes
Payable To Trust
|
|
|
113
|
|
|
|
113
|
|
Spent
Nuclear Fuel Obligation (b)
|
|
|
257
|
|
|
|
247
|
|
Other
Long-term Debt
|
|
|
2
|
|
|
|
2
|
|
Unamortized
Discount (net)
|
|
|
(61 |
) |
|
|
(56 |
) |
Total
Long-term Debt Outstanding
|
|
|
14,776
|
|
|
|
13,698
|
|
Less
Portion Due Within One Year
|
|
|
910
|
|
|
|
1,269
|
|
Long-term
Portion
|
|
$ |
13,866
|
|
|
$ |
12,429
|
|
(a)
|
In
May 2004, cash and treasury securities were deposited 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
September 30, 2007 and December 31, 2006. Trust Fund Assets
related to this obligation of $22 million and $2 million at September
30,
2007 and December 31, 2006, respectively, are included in Other Temporary
Investments and $21 million at December 31, 2006, is included in
Other
Noncurrent Assets on our Condensed Consolidated Balance
Sheets. In December 2005, cash and treasury securities were
deposited with a trustee to defease the remaining TNC outstanding
First
Mortgage Bond. The defeased TNC First Mortgage Bond was retired
in June 2007. The defeased TNC First Mortgage Bond had a
balance of $8 million at December 31, 2006. Trust
fund assets related to this obligation of $9 million at December
31, 2006,
are included in Other Temporary 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 $280 million and $274 million
at
September 30, 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 nine months of 2007 are shown in the tables below.
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
|
(in
millions)
|
|
(%)
|
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
Pollution
Control Bonds
|
|
$
|
75
|
|
Variable
|
|
2037
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
250
|
|
5.65
|
|
2012
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
250
|
|
6.70
|
|
2037
|
|
CSPCo
|
|
Pollution
Control Bonds
|
|
|
45
|
|
Variable
|
|
2040
|
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
65
|
|
4.90
|
|
2037
|
|
OPCo
|
|
Senior
Unsecured Notes
|
|
|
400
|
|
Variable
|
|
2010
|
|
PSO
|
|
Pollution
Control Bonds
|
|
|
13
|
|
4.45
|
|
2020
|
|
SWEPCo
|
|
Senior
Unsecured Notes
|
|
|
250
|
|
5.55
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Registrant:
|
|
|
|
|
|
|
|
|
|
|
AEGCo
|
|
Senior
Unsecured Notes
|
|
|
220
|
|
6.33
|
|
2037
|
(a)
|
KPCo
|
|
Senior
Unsecured Notes
|
|
|
325
|
|
6.00
|
|
2017
|
|
TCC
|
|
Pollution
Control Bonds
|
|
|
6
|
|
4.45
|
|
2020
|
|
TNC
|
|
Pollution
Control Bonds
|
|
|
44
|
|
4.45
|
|
2020
|
|
Total
Issuances
|
|
|
|
$
|
1,943
|
(b)
|
|
|
|
|
The
above
borrowing arrangements do not contain guarantees, collateral or dividend
restrictions.
(a)
|
AEGCo’s
senior unsecured notes due 2037 are payable over the life of the
notes as
a $7.3 million annual principal amount plus accrued interest paid
semiannually in March and September.
|
(b)
|
Amount
indicated on statement of cash flows of $1,924 million is net of
issuance
costs and unamortized premium or
discount.
|
In
May
2007, I&M remarketed its outstanding $50 million Pollution Control Bonds,
resulting in a new interest rate of 4.625%. No proceeds were received
related to this remarketing. The principal amount of the Pollution
Control Bonds is reflected in Long-term Debt on our Condensed Consolidated
Balance Sheet as of September 30, 2007.
In
August
2007, TCC remarketed its outstanding $60 million Pollution Control Bonds,
resulting in a new interest rate of 5.20%. No proceeds were received
related to this remarketing. The principal amount of Pollution
Control Bonds is reflected in Long-term Debt on our Condensed Consolidated
Balance Sheet as of September 30, 2007.
|
|
|
|
Principal
|
|
Interest
|
|
|
|
Company
|
|
Type
of Debt
|
|
Amount
Paid
|
|
Rate
|
|
Due
Date
|
|
|
|
|
|
(in
millions)
|
|
(%)
|
|
|
|
Retirements
and Principal Payments:
|
|
|
|
|
|
|
|
AEP
|
|
Senior
Unsecured Notes
|
|
$
|
345
|
|
4.709
|
|
2007
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
125
|
|
Variable
|
|
2007
|
|
OPCo
|
|
Notes
Payable
|
|
|
3
|
|
6.81
|
|
2008
|
|
OPCo
|
|
Notes
Payable
|
|
|
6
|
|
6.27
|
|
2009
|
|
PSO
|
|
Pollution
Control Bonds
|
|
|
13
|
|
6.00
|
|
2020
|
|
SWEPCo
|
|
First
Mortgage Bonds
|
|
|
90
|
|
7.00
|
|
2007
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
4
|
|
4.47
|
|
2011
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
4
|
|
6.36
|
|
2007
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
3
|
|
Variable
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Registrant:
|
|
|
|
|
|
|
|
|
|
|
AEGCo
|
|
Senior
Unsecured Notes
|
|
|
2
|
|
6.33
|
|
2037
|
(a)
|
AEP
Subsidiaries
|
|
Notes
Payable
|
|
|
10
|
|
Variable
|
|
2017
|
|
CSW
Energy, Inc.
|
|
Notes
Payable
|
|
|
4
|
|
5.88
|
|
2011
|
|
KPCo
|
|
Senior
Unsecured Notes
|
|
|
125
|
|
5.50
|
|
2007
|
|
TCC
|
|
Securitization
Bonds
|
|
|
53
|
|
5.01
|
|
2008
|
|
TCC
|
|
Securitization
Bonds
|
|
|
25
|
|
4.98
|
|
2010
|
|
TCC
|
|
Pollution
Control Bonds
|
|
|
6
|
|
6.00
|
|
2020
|
|
TNC
|
|
Pollution
Control Bonds
|
|
|
44
|
|
6.00
|
|
2020
|
|
TNC
|
|
Defeased
First Mortgage Bonds
|
|
|
8
|
|
7.75
|
|
2007
|
|
Total
Retirements and
Principal
Payments
|
|
|
$
|
870
|
|
|
|
|
|
(a)
|
AEGCo’s
Senior Unsecured Notes due 2037 are payable over the life of the
notes as
a $7.3 million annual principal amount plus accrued interest paid
semiannually in March and
September.
|
In
October 2007, KPCo retired $48 million of 6.91% Senior Unsecured Notes due
in
2007.
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 was as
follows:
|
|
September
30, 2007
|
|
|
December
31, 2006
|
|
|
|
Outstanding
|
|
Interest
|
|
|
Outstanding
|
|
Interest
|
|
|
|
Amount
|
|
Rate
|
|
|
Amount
|
|
Rate
|
|
Type
of Debt
|
|
(in
millions)
|
|
|
|
|
|
(in
millions)
|
|
|
|
|
Commercial
Paper – AEP
|
|
$
|
559
|
|
|
5.60
|
%
|
(a)
|
$
|
-
|
|
|
-
|
|
Commercial
Paper – JMG (b)
|
|
|
2
|
|
|
5.3588
|
%
|
|
|
1
|
|
|
5.56
|
%
|
Line
of Credit – Sabine (c)
|
|
|
26
|
|
|
6.07
|
%
|
|
|
17
|
|
|
6.38
|
%
|
Total
|
|
$
|
587
|
|
|
|
|
|
$
|
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.
Dividend
Restrictions
Under
the
Federal Power Act, AEP’s public utility subsidiaries are restricted from paying
dividends out of stated capital.
Sale
of Receivables – AEP Credit
In
October 2007, we renewed AEP Credit’s sale of receivables
agreement. The sale of receivables agreement provides a commitment of
$650 million from a bank conduit to purchase receivables from AEP
Credit. Under the agreement, the commitment will increase to $700
million for the months of August and September to accommodate seasonal
demand. This agreement will expire in October 2008.
APPALACHIAN
POWER COMPANY
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Third
Quarter of 2007 Compared to Third Quarter of 2006
Reconciliation
of Third Quarter of 2006 to Third Quarter of 2007
Net
Income
(in
millions)
Third
Quarter of 2006
|
|
|
|
|
$ |
31
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
13
|
|
|
|
|
|
Off-system
Sales
|
|
|
18
|
|
|
|
|
|
Transmission
Revenues, Net
|
|
|
(22 |
) |
|
|
|
|
Other
|
|
|
(14 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(27 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
9
|
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
1
|
|
|
|
|
|
Carrying
Costs Income
|
|
|
36
|
|
|
|
|
|
Other
Income, Net
|
|
|
(8 |
) |
|
|
|
|
Interest
Expense
|
|
|
(18 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
Third Quarter of 2007
|
|
|
|
|
|
$ |
24
|
|
Net
Income decreased $7 million to $24 million. The key drivers of the
decrease were a $5 million decrease in Gross Margin and a $7 million increase
in
Operating Expenses and Other, partially offset by a $5 million decrease in
Income Tax Expense.
The
major
components of the change in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $13 million due to the impact of the Virginia
base rate
order issued in May 2007, the Virginia E&R and fuel cost recovery
filings and increased demand in the residential class associated
with
favorable weather conditions. Cooling degree days increased
approximately 22%.
|
·
|
Margins
from Off-System sales increased $18 million primarily due to higher
sales
volumes and power prices in the east, benefits from AEP’s eastern natural
gas fleet, and higher trading margins.
|
·
|
Transmission
Revenues, Net decreased $22 million primarily due to PJM’s revision of its
pricing methodology for transmission line losses to marginal-loss
pricing
effective June 1, 2007. See “PJM Marginal-Loss Pricing” section
of Note 3.
|
·
|
Other
revenue decreased $14 million primarily due to the reversal in
the third
quarter of 2006 of previously deferred gains on sales of allowances
associated with the Virginia Environmental and Reliability Costs
(E&R)
case.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $27 million primarily
due to
the settlement agreement regarding alleged violations of the NSR
provisions of the CAA, of which $26 million was allocated to
APCo. See “Federal EPA Complaint and Notice of Violation”
section of Note 4.
|
·
|
Depreciation
and Amortization expenses decreased $9 million primarily due to
the
write-off in the third quarter of 2006 of previously deferred depreciation
expenses associated with the E&R case.
|
·
|
Carrying
Costs Income increased $36 million primarily due to the write-off
in the
third quarter of 2006 of previously recorded carrying costs income
associated with the E&R case.
|
·
|
Other
Income, Net decreased $8 million primarily due to a $6 million
decrease in
the equity component of AFUDC resulting from AFUDC recorded in
the third
quarter of 2006 associated with the E&R case and a lower construction
work in progress (CWIP) balance after the Wyoming-Jacksons Ferry
765 kV
line and the Mountaineer scrubber were placed into service. In
addition, interest income from the Utility Money Pool decreased
$2
million.
|
·
|
Interest
Expense increased $18 million primarily due to a $9 million decrease
in
the debt component of AFUDC resulting from AFUDC recorded in the
third
quarter of 2006 associated with the E&R case. In addition,
Interest Expense also increased due to a $2 million increase in
interest
expense from the Utility Money Pool and a $4 million increase in
interest
expense from long-term debt issuances.
|
·
|
Income
Tax Expense decreased $5 million primarily due to a decrease in
pretax
book income and state income taxes partially offset by changes
in certain
book/tax differences accounted for on a flow-through
basis.
|
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Reconciliation
of Nine Months Ended September 30, 2006 to Nine Months Ended September 30,
2007
Net
Income Before Extraordinary Loss
(in
millions)
Nine
Months Ended September 30, 2006
|
|
|
|
|
$ |
114
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
9
|
|
|
|
|
|
Off-system
Sales
|
|
|
30
|
|
|
|
|
|
Transmission
Revenues, Net
|
|
|
(32 |
) |
|
|
|
|
Other
|
|
|
(10 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(35 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
16
|
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
3
|
|
|
|
|
|
Carrying
Costs Income
|
|
|
36
|
|
|
|
|
|
Other
Income, Net
|
|
|
(13 |
) |
|
|
|
|
Interest
Expense
|
|
|
(33 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(26 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
NNine
Months Ended September 30, 2007
|
|
|
|
|
|
$ |
98
|
|
Net
Income Before Extraordinary Loss decreased $16 million to $98 million in
2007. The key drivers of the decrease were a $26 million increase in
Operating Expenses and Other, partially offset by a $13 million decrease
in
Income Tax Expense.
The
major
components of the change in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $9 million due to the impact of the Virginia
base rate
order issued in May 2007, the Virginia E&R and fuel cost recovery
filings and increased demand in the residential class associated
with
favorable weather conditions. Cooling degree days increased
approximately 33%.
|
·
|
Margins
for Off-system Sales increased $30 million primarily due to higher
trading
margins.
|
·
|
Transmission
Revenues, Net decreased $32 million primarily due to PJM’s revision of its
pricing methodology for transmission line losses to marginal-loss
pricing
effective June 1, 2007. See “PJM Marginal-Loss Pricing” section
of Note 3.
|
·
|
Other
revenue decreased $10 million primarily due to lower gains on sales
of
allowances and the reversal in the third quarter of 2006 of previously
deferred gains on sales of allowances associated with the E&R
case.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $35 million primarily
due to
the following:
|
|
·
|
A
$26 million increase resulting from the settlement between AEP
and the
Federal EPA regarding alleged violations of the NSR provisions
of the
CAA. The $26 million represents APCo’s allocation of the
settlement. See “Federal EPA Complaint and Notice of Violation”
section of Note 4.
|
|
·
|
A
$9 million increase in steam maintenance expenses resulting from
2007
forced and planned outages at the Amos and Glen Lyn
plants.
|
·
|
Depreciation
and Amortization expenses decreased $16 million primarily due to
the
following:
|
|
·
|
An
$8 million decrease resulting from lower Virginia depreciation
rates
implemented retroactively to January 2006 partially offset by additional
depreciation expense for the Wyoming-Jacksons Ferry 765 kV line,
which was
energized and placed in service in June 2006, and the Mountaineer
scrubber, which was placed in service in February 2007.
|
|
·
|
A
$10 million decrease resulting from a net deferral of $10 million
in ARO
costs as approved in APCo’s Virginia base rate case.
|
|
·
|
A
$9 million decrease in depreciation expense related to the write-off
in
the third quarter of 2006 of previously deferred depreciation expense
associated with the E&R case.
|
|
These
decreases were partially offset by:
|
|
·
|
The
amortization of carrying charges of $12 million that are being
collected
through E&R surcharges.
|
·
|
Carrying
Costs Income increased $36 million primarily due to the write-off
in the
third quarter of 2006 of previously recorded carrying costs income
associated with the E&R case.
|
·
|
Other
Income, Net decreased $13 million primarily due to lower interest
income
from the Utility Money Pool of $4 million. In addition, the equity
component of AFUDC decreased $8 million resulting from AFUDC recorded
in
the third quarter of 2006 associated with the E&R case and a lower
CWIP balance after the Wyoming-Jacksons Ferry 765 kV line and the
Mountaineer scrubber were placed into service.
|
·
|
Interest
Expense increased $33 million primarily due to a $14 million decrease
in
the debt component of AFUDC resulting from AFUDC recorded in the
third
quarter of 2006 associated with the E&R case, a $13 million increase
in interest expense from long-term debt issuances, a $4 million
increase
in the interest on the Virginia provision for revenue collected
subject to
refund and a $3 million increase in interest expense from the Utility
Money Pool.
|
·
|
Income
Tax Expense decreased $13 million primarily due to a decrease in
pretax
book income and state income taxes partially offset by changes
in certain
book/tax differences accounted for on a flow-through
basis.
|
Financial
Condition
Credit
Ratings
The
rating agencies currently have APCo on stable outlook. Current
ratings are as follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
Baa2
|
|
BBB
|
|
BBB+
|
Cash
Flow
Cash
flows for the nine months ended September 30, 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
|
|
|
221,534
|
|
|
430,735
|
|
|
Investing
Activities
|
|
|
(570,019
|
)
|
|
(719,590
|
)
|
|
Financing
Activities
|
|
|
347,436
|
|
|
288,363
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(1,049
|
)
|
|
(492
|
)
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
1,269
|
|
$
|
1,249
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $222 million in 2007. APCo
produced Net Income of $19 million during the period and had noncash expense
items of $142 million for Depreciation and Amortization and $79 million for
Extraordinary Loss for the Reapplication of Regulatory Accounting for Generation
and $23 million for Carrying Costs Income. The other changes in
assets and liabilities represent items that had a current period cash flow
impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The current period activity in working capital
included no significant unusual items.
Net
Cash
Flows From Operating Activities were $431 million in 2006. APCo
produced Net Income of $114 million during the period and a noncash expense
item
of $158 million for Depreciation and Amortization. The other changes
in assets and liabilities represent items that had a current period cash
flow
impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The current period activity in working capital
included no significant items.
Investing
Activities
Net
Cash
Flows Used For Investing Activities during 2007 and 2006 primarily reflect
construction expenditures of $538 million and $633 million,
respectively. Construction expenditures are primarily for projects to
improve service reliability for transmission and distribution, as well as
environmental upgrades at power plants 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 flue gas desulfurization
projects at the Amos and Mountaineer plants. In February 2007, the
flue gas desulfurization project was completed at the Mountaineer
plant. Based upon APCo’s current forecast, APCo expects construction
expenditures to be approximately $200 million for the remainder of 2007,
excluding AFUDC. In addition, APCo’s investments in the Utility Money
Pool increased by $39 million and $94 million in 2007 and 2006,
respectively.
Financing
Activities
Net
Cash
Flows From Financing Activities in 2007 were $347 million primarily due to
the
issuance of $75 million of Pollution Control Bonds in May 2007 and the issuance
of $500 million of Senior Unsecured Notes in August 2007, net of the retirement
of $125 million of Senior Unsecured Notes in June 2007. APCo also
reduced its short-term borrowings from the Utility Money Pool by $35
million.
Net
Cash
Flows From Financing Activities were $288 million in 2006. In 2006,
APCo issued $500 million in Senior Notes and $50 million in Pollution Control
Bonds. APCo also retired First Mortgage Bonds of $100 million and
reduced its short-term borrowings from the Utility Money Pool by $194
million. In addition, APCo received funds of $68 million related to a
long-term coal purchase contract amended in March 2006.
Financing
Activity
Long-term
debt issuances and retirements during the first nine months of 2007
were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$
|
75,000
|
|
Variable
|
|
2037
|
Senior
Unsecured Notes
|
|
|
250,000
|
|
5.65
|
|
2012
|
Senior
Unsecured Notes
|
|
|
250,000
|
|
6.70
|
|
2037
|
Retirements
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Senior
Unsecured Notes
|
|
$
|
125,000
|
|
Variable
|
|
2007
|
Liquidity
APCo
has
solid investment grade ratings, which provide ready access to capital markets
in
order to issue new debt or refinance long-term debt maturities. In
addition, APCo participates in the Utility Money Pool, which provides access
to
AEP’s liquidity.
Summary
Obligation Information
A
summary
of contractual obligations is included in the 2006 Annual Report and has
not
changed significantly from year-end other than the debt issuances and
retirements discussed in “Cash Flow” and “Financing Activity” above and the
obligations resulting from the settlement agreement regarding alleged violations
of the NSR provisions of the CAA. See “Federal EPA Complaint and
Notice of Violations” section of Note 4.
Significant
Factors
Virginia
Restructuring
In
April
2007, the Virginia legislature adopted a comprehensive law providing for
the
re-regulation of electric utilities’ generation and supply
rates. These amendments shorten the transition period by two years
(from 2010 to 2008) after which rates for retail generation and supply will
return to a form of cost-based regulation in lieu of market-based
rates. 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 investments, (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 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 with a true-up to actual. The
legislation also allows APCo to continue to defer and recover incremental
environmental and reliability costs incurred through December 31,
2008. The new re-regulation legislation should result in significant
positive effects on APCo’s future earnings and cash flows from the mandated
enhanced future returns on equity, the reduction of regulatory lag from the
opportunities to adjust base rates on a biennial basis and the new opportunities
to request timely recovery of certain new costs not included in base
rates.
Litigation
and Regulatory Activity
In
the
ordinary course of business, APCo is involved in employment, commercial,
environmental and regulatory litigation. Since it is difficult to
predict the outcome of these proceedings, management cannot state what the
eventual outcome of these proceedings will be, or what the timing of the
amount
of any loss, fine or penalty may be. Management does, however, assess
the probability of loss for such contingencies and accrues a liability for
cases
which have a probable likelihood of loss and the loss amount can be
estimated. For details on pending litigation and regulatory
proceedings, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 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 results of operations, financial condition and cash
flows.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of relevant factors.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 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
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion within AEP’s “Quantitative and
Qualitative Disclosures About Risk Management Activities”
section. The following tables provide information about AEP’s risk
management activities’ effect on APCo.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included on the condensed consolidated balance sheet as of September 30,
2007
and the reasons for changes in total MTM value as compared to December 31,
2006.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of September 30, 2007
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
|
Cash
Flow &
Fair
Value Hedges
|
|
|
DETM
Assignment (a)
|
|
|
Total
|
|
Current
Assets
|
|
$ |
65,385
|
|
|
$ |
3,806
|
|
|
$ |
-
|
|
|
$ |
69,191
|
|
Noncurrent
Assets
|
|
|
80,970
|
|
|
|
2,240
|
|
|
|
-
|
|
|
|
83,210
|
|
Total
MTM Derivative Contract Assets
|
|
|
146,355
|
|
|
|
6,046
|
|
|
|
-
|
|
|
|
152,401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(47,471 |
) |
|
|
(1,129 |
) |
|
|
(3,878 |
) |
|
|
(52,478 |
) |
Noncurrent
Liabilities
|
|
|
(48,866 |
) |
|
|
(214 |
) |
|
|
(6,478 |
) |
|
|
(55,558 |
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(96,337 |
) |
|
|
(1,343 |
) |
|
|
(10,356 |
) |
|
|
(108,036 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$ |
50,018
|
|
|
$ |
4,703
|
|
|
$ |
(10,356 |
) |
|
$ |
44,365
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2006 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 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
|
|
|
(10,155
|
)
|
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
|
|
|
503
|
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
3,858
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
3,068
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
50,018
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
4,703
|
|
DETM
Assignment (d)
|
|
|
(10,356
|
)
|
Total
MTM Risk Management Contract Net Assets at September 30,
2007
|
|
$
|
44,365
|
|
(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
total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of net assets/liabilities to give an indication
of when
these MTM amounts will settle and generate
cash.
|
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets
Fair
Value of Contracts as of September 30, 2007
(in
thousands)
|
|
Remainder
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
After
2011
|
|
Total
|
Prices
Actively Quoted – Exchange
Traded
Contracts
|
|
$
|
3,994
|
|
$
|
(5,820
|
)
|
$
|
1,134
|
|
$
|
(20
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
(712
|
)
|
Prices
Provided by Other External
Sources
– OTC Broker Quotes (a)
|
|
|
1,170
|
|
|
17,393
|
|
|
13,606
|
|
|
10,310
|
|
|
-
|
|
|
-
|
|
|
42,479
|
|
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
754
|
|
|
660
|
|
|
1,027
|
|
|
1,685
|
|
|
2,112
|
|
|
2,013
|
|
|
8,251
|
|
Total
|
|
$
|
5,918
|
|
$
|
12,233
|
|
$
|
15,767
|
|
$
|
11,975
|
|
$
|
2,112
|
|
$
|
2,013
|
|
$
|
50,018
|
|
(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
independent 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 including
values determinable by other third party
transactions.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheet
APCo
is
exposed to market fluctuations in energy commodity prices impacting its power
operations. Management monitors these risks on future operations and
may use various commodity derivative instruments designated in qualifying
cash
flow hedge strategies to mitigate the impact of these fluctuations on future
cash flows. Management does not hedge all commodity price
risk.
Management
uses interest rate derivative transactions to manage interest rate risk related
to anticipated borrowings of fixed-rate debt. Management does not
hedge all interest rate risk.
Management
uses foreign currency derivatives to lock in prices on certain transactions
denominated in foreign currencies where deemed necessary, and designate
qualifying instruments as cash flow hedge strategies. Management does
not hedge all foreign currency.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on the Condensed Consolidated Balance Sheets and the reasons
for the changes from December 31, 2006 to September 30, 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
Nine
Months Ended September 30, 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
|
|
|
3,049
|
|
|
|
(2
|
)
|
|
|
(313
|
)
|
|
|
2,734
|
|
Reclassifications
from AOCI to Net Income for
Cash Flow Hedges Settled
|
|
|
(4,788
|
)
|
|
|
5
|
|
|
|
1,049
|
|
|
|
(3,734
|
)
|
Ending
Balance in AOCI September 30, 2007
|
|
$
|
3,593
|
|
|
$
|
(161
|
)
|
|
$
|
(6,979
|
)
|
|
$
|
(3,547
|
)
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $740 thousand gain.
Credit
Risk
Counterparty
credit quality and exposure is generally consistent with that of
AEP.
VaR
Associated with Risk Management Contracts
Management
uses a risk measurement model, which calculates Value at Risk (VaR) to measure
commodity price risk in the risk management portfolio. The VaR is based on
the
variance-covariance method using historical prices to estimate volatilities
and
correlations and assumes a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at September 30, 2007, a near
term typical change in commodity prices is not expected to have a material
effect on results of operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended
September
30, 2007
|
|
|
Twelve
Months Ended
December
31, 2006
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
End
|
|
|
High
|
|
|
Average
|
|
|
Low
|
|
|
End
|
|
|
High
|
|
|
Average
|
|
|
Low
|
|
$ |
231
|
|
|
$ |
2,328
|
|
|
$ |
683
|
|
|
$ |
168
|
|
|
$ |
756
|
|
|
$ |
1,915
|
|
|
$ |
658
|
|
|
$ |
358
|
|
VaR
Associated with Debt Outstanding
Management
utilizes 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 exposure to interest rates primarily related to long-term
debt with fixed interest rates was $219 million and $153 million at September
30, 2007 and December 31, 2006, respectively. Management would not expect
to
liquidate the entire debt portfolio in a one-year holding period; therefore,
a
near term change in interest rates should not negatively affect results of
operations or consolidated financial position.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2007 and
2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
639,830
|
|
|
$ |
588,684
|
|
|
$ |
1,740,565
|
|
|
$ |
1,612,735
|
|
Sales
to AEP Affiliates
|
|
|
64,099
|
|
|
|
57,177
|
|
|
|
181,015
|
|
|
|
177,557
|
|
Other
|
|
|
2,647
|
|
|
|
2,740
|
|
|
|
8,134
|
|
|
|
7,338
|
|
TOTAL
|
|
|
706,576
|
|
|
|
648,601
|
|
|
|
1,929,714
|
|
|
|
1,797,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
200,702
|
|
|
|
184,275
|
|
|
|
535,906
|
|
|
|
506,368
|
|
Purchased
Electricity for Resale
|
|
|
47,430
|
|
|
|
41,027
|
|
|
|
117,708
|
|
|
|
98,622
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
171,288
|
|
|
|
130,826
|
|
|
|
443,519
|
|
|
|
356,682
|
|
Other
Operation
|
|
|
94,190
|
|
|
|
63,149
|
|
|
|
236,944
|
|
|
|
210,206
|
|
Maintenance
|
|
|
49,708
|
|
|
|
53,874
|
|
|
|
146,875
|
|
|
|
138,381
|
|
Depreciation
and Amortization
|
|
|
51,864
|
|
|
|
61,270
|
|
|
|
142,100
|
|
|
|
158,226
|
|
Taxes
Other Than Income Taxes
|
|
|
23,561
|
|
|
|
24,464
|
|
|
|
67,811
|
|
|
|
70,355
|
|
TOTAL
|
|
|
638,743
|
|
|
|
558,885
|
|
|
|
1,690,863
|
|
|
|
1,538,840
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
67,833
|
|
|
|
89,716
|
|
|
|
238,851
|
|
|
|
258,790
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
510
|
|
|
|
2,463
|
|
|
|
1,539
|
|
|
|
6,228
|
|
Carrying
Costs Income (Expense)
|
|
|
8,701
|
|
|
|
(27,316 |
) |
|
|
22,817
|
|
|
|
(13,532 |
) |
Allowance
for Equity Funds Used During Construction
|
|
|
1,084
|
|
|
|
6,748
|
|
|
|
5,442
|
|
|
|
13,307
|
|
Interest
Expense
|
|
|
(44,980 |
) |
|
|
(27,103 |
) |
|
|
(121,758 |
) |
|
|
(89,024 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
33,148
|
|
|
|
44,508
|
|
|
|
146,891
|
|
|
|
175,769
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
9,090
|
|
|
|
13,972
|
|
|
|
49,325
|
|
|
|
61,992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE EXTRAORDINARY LOSS
|
|
|
24,058
|
|
|
|
30,536
|
|
|
|
97,566
|
|
|
|
113,777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extraordinary
Loss – Reapplication of Regulatory Accounting
for
Generation, Net of Tax
|
|
|
-
|
|
|
|
-
|
|
|
|
(78,763 |
) |
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
24,058
|
|
|
|
30,536
|
|
|
|
18,803
|
|
|
|
113,777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements Including Capital
Stock Expense
and Other
|
|
|
238
|
|
|
|
238
|
|
|
|
714
|
|
|
|
714
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
23,820
|
|
|
$ |
30,298
|
|
|
$ |
18,089
|
|
|
$ |
113,063
|
|
The
common stock of APCo is wholly-owned by AEP.
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Nine Months Ended September 30, 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
|
|
|
|
|
|
|
|
|
|
|
(7,500 |
) |
|
|
|
|
|
|
(7,500 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(600 |
) |
|
|
|
|
|
|
(600 |
) |
Capital
Stock Expense and Other
|
|
|
|
|
|
|
118
|
|
|
|
(114 |
) |
|
|
|
|
|
|
4
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,795,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $7,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,014
|
|
|
|
13,014
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
113,777
|
|
|
|
|
|
|
|
113,777
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
126,791
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$ |
260,458
|
|
|
$ |
924,955
|
|
|
$ |
740,579
|
|
|
$ |
(3,596 |
) |
|
$ |
1,922,396
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$ |
260,458
|
|
|
$ |
1,024,994
|
|
|
$ |
805,513
|
|
|
$ |
(54,791 |
) |
|
$ |
2,036,174
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(2,685 |
) |
|
|
|
|
|
|
(2,685 |
) |
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(25,000 |
) |
|
|
|
|
|
|
(25,000 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(600 |
) |
|
|
|
|
|
|
(600 |
) |
Capital
Stock Expense and Other
|
|
|
|
|
|
|
117
|
|
|
|
(114 |
) |
|
|
|
|
|
|
3
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,007,892
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net of
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $539
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,000 |
) |
|
|
(1,000 |
) |
SFAS
158 Costs Established as a Regulatory
Asset
Related to the Reapplication of
SFAS
71, Net of Tax of $6,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,245
|
|
|
|
11,245
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
18,803
|
|
|
|
|
|
|
|
18,803
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
260,458
|
|
|
$ |
1,025,111
|
|
|
$ |
795,917
|
|
|
$ |
(44,546 |
) |
|
$ |
2,036,940
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,269
|
|
|
$ |
2,318
|
|
Advances
to Affiliates
|
|
|
38,573
|
|
|
|
-
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
200,173
|
|
|
|
180,190
|
|
Affiliated Companies
|
|
|
79,576
|
|
|
|
98,237
|
|
Accrued Unbilled Revenues
|
|
|
34,668
|
|
|
|
46,281
|
|
Miscellaneous
|
|
|
3,366
|
|
|
|
3,400
|
|
Allowance for Uncollectible Accounts
|
|
|
(10,379 |
) |
|
|
(4,334 |
) |
Total
Accounts Receivable
|
|
|
307,404
|
|
|
|
323,774
|
|
Fuel
|
|
|
85,468
|
|
|
|
77,077
|
|
Materials
and Supplies
|
|
|
66,387
|
|
|
|
56,235
|
|
Risk
Management Assets
|
|
|
69,191
|
|
|
|
105,376
|
|
Accrued
Tax Benefits
|
|
|
8,881
|
|
|
|
3,748
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
-
|
|
|
|
29,526
|
|
Prepayments
and Other
|
|
|
39,402
|
|
|
|
20,126
|
|
TOTAL
|
|
|
616,575
|
|
|
|
618,180
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
3,499,672
|
|
|
|
2,844,803
|
|
Transmission
|
|
|
1,663,553
|
|
|
|
1,620,512
|
|
Distribution
|
|
|
2,341,513
|
|
|
|
2,237,887
|
|
Other
|
|
|
348,901
|
|
|
|
339,450
|
|
Construction
Work in Progress
|
|
|
678,095
|
|
|
|
957,626
|
|
Total
|
|
|
8,531,734
|
|
|
|
8,000,278
|
|
Accumulated
Depreciation and Amortization
|
|
|
2,578,083
|
|
|
|
2,476,290
|
|
TOTAL
- NET
|
|
|
5,953,651
|
|
|
|
5,523,988
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
680,644
|
|
|
|
622,153
|
|
Long-term
Risk Management Assets
|
|
|
83,210
|
|
|
|
88,906
|
|
Deferred
Charges and Other
|
|
|
149,137
|
|
|
|
163,089
|
|
TOTAL
|
|
|
912,991
|
|
|
|
874,148
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
7,483,217
|
|
|
$ |
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
September
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
-
|
|
|
$ |
34,975
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
218,212
|
|
|
|
296,437
|
|
Affiliated
Companies
|
|
|
88,326
|
|
|
|
105,525
|
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
399,214
|
|
|
|
324,191
|
|
Risk
Management Liabilities
|
|
|
52,478
|
|
|
|
81,114
|
|
Customer
Deposits
|
|
|
56,143
|
|
|
|
56,364
|
|
Accrued
Taxes
|
|
|
52,072
|
|
|
|
60,056
|
|
Accrued
Interest
|
|
|
62,775
|
|
|
|
30,617
|
|
Other
|
|
|
109,085
|
|
|
|
142,326
|
|
TOTAL
|
|
|
1,038,305
|
|
|
|
1,131,605
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
2,547,043
|
|
|
|
2,174,473
|
|
Long-term
Debt – Affiliated
|
|
|
100,000
|
|
|
|
100,000
|
|
Long-term
Risk Management Liabilities
|
|
|
55,558
|
|
|
|
64,909
|
|
Deferred
Income Taxes
|
|
|
931,955
|
|
|
|
957,229
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
502,425
|
|
|
|
309,724
|
|
Deferred
Credits and Other
|
|
|
253,239
|
|
|
|
224,439
|
|
TOTAL
|
|
|
4,390,220
|
|
|
|
3,830,774
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
5,428,525
|
|
|
|
4,962,379
|
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
17,752
|
|
|
|
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
|
|
|
1,025,111
|
|
|
|
1,024,994
|
|
Retained
Earnings
|
|
|
795,917
|
|
|
|
805,513
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(44,546 |
) |
|
|
(54,791 |
) |
TOTAL
|
|
|
2,036,940
|
|
|
|
2,036,174
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
7,483,217
|
|
|
$ |
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 Nine Months Ended September 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
18,803
|
|
|
$ |
113,777
|
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation and Amortization
|
|
|
142,100
|
|
|
|
158,226
|
|
Deferred Income Taxes
|
|
|
32,021
|
|
|
|
(7,753 |
) |
Extraordinary Loss, Net of Tax
|
|
|
78,763
|
|
|
|
-
|
|
Carrying Costs (Income) Expense
|
|
|
(22,817 |
) |
|
|
13,532
|
|
Mark-to-Market of Risk Management Contracts
|
|
|
1,603
|
|
|
|
(3,817 |
) |
Change in Other Noncurrent Assets
|
|
|
(14,627 |
) |
|
|
1,714
|
|
Change in Other Noncurrent Liabilities
|
|
|
27,247
|
|
|
|
20,171
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts Receivable, Net
|
|
|
(87 |
) |
|
|
24,423
|
|
Fuel, Materials and Supplies
|
|
|
(11,387 |
) |
|
|
3,446
|
|
Margin Deposits
|
|
|
(2,300 |
) |
|
|
27,103
|
|
Accounts Payable
|
|
|
(38,724 |
) |
|
|
22,063
|
|
Customer Deposits
|
|
|
(221 |
) |
|
|
(23,591 |
) |
Accrued Taxes, Net
|
|
|
(9,990 |
) |
|
|
43,071
|
|
Accrued Interest
|
|
|
28,596
|
|
|
|
30,780
|
|
Fuel Over/Under Recovery, Net
|
|
|
35,770
|
|
|
|
830
|
|
Other Current Assets
|
|
|
(17,520 |
) |
|
|
4,972
|
|
Other Current Liabilities
|
|
|
(25,696 |
) |
|
|
1,788
|
|
Net
Cash Flows From Operating Activities
|
|
|
221,534
|
|
|
|
430,735
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(537,930 |
) |
|
|
(633,164 |
) |
Change
in Other Cash Deposits, Net
|
|
|
(29 |
) |
|
|
(873 |
) |
Change
in Advances to Affiliates, Net
|
|
|
(38,573 |
) |
|
|
(93,764 |
) |
Proceeds
from Sales of Assets
|
|
|
6,713
|
|
|
|
8,211
|
|
Other
|
|
|
(200 |
) |
|
|
-
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(570,019 |
) |
|
|
(719,590 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
568,778
|
|
|
|
544,364
|
|
Change
in Advances from Affiliates, Net
|
|
|
(34,975 |
) |
|
|
(194,133 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(125,009 |
) |
|
|
(100,008 |
) |
Retirement
of Cumulative Preferred Stock
|
|
|
(9 |
) |
|
|
(16 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(3,316 |
) |
|
|
(4,008 |
) |
Funds
From Amended Coal Contract
|
|
|
-
|
|
|
|
68,078
|
|
Amortization
of Funds From Amended Coal Contract
|
|
|
(32,433 |
) |
|
|
(17,814 |
) |
Dividends
Paid on Common Stock
|
|
|
(25,000 |
) |
|
|
(7,500 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(600 |
) |
|
|
(600 |
) |
Net
Cash Flows From Financing Activities
|
|
|
347,436
|
|
|
|
288,363
|
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(1,049 |
) |
|
|
(492 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
2,318
|
|
|
|
1,741
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,269
|
|
|
$ |
1,249
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
86,199
|
|
|
$ |
51,537
|
|
Net
Cash Paid for Income Taxes
|
|
|
6,688
|
|
|
|
12,047
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
2,738
|
|
|
|
2,598
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
90,315
|
|
|
|
131,692
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to APCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to
APCo.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
COLUMBUS
SOUTHERN POWER COMPANY
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
In
March
2007, CSPCo and AEGCo entered into a ten-year unit power agreement (UPA)
for the
entire output from the Lawrenceburg Plant effective with AEGCo’s purchase of the
plant in May 2007. The UPA has an option for an additional two-year
period. I&M operates the plant under an agreement with
AEGCo. Under the UPA, CSPCo pays AEGCo for the capacity,
depreciation, fuel, operation, maintenance and tax expenses. These
payments are due regardless of the plant’s operating status. Fuel,
operation and maintenance payments are based on actual costs
incurred. All expenses will be trued up periodically.
Results
of Operations
Third
Quarter of 2007 Compared to Third Quarter of 2006
Reconciliation
of Third Quarter of 2006 to Third Quarter of 2007
Net
Income
(in
millions)
Third
Quarter of 2006
|
|
|
|
|
$ |
84
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
40
|
|
|
|
|
|
Off-system
Sales
|
|
|
7
|
|
|
|
|
|
Transmission
Revenues, Net
|
|
|
(13 |
) |
|
|
|
|
Other
|
|
|
1
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(27 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
4
|
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(3 |
) |
|
|
|
|
Other
Income, Net
|
|
|
(1 |
) |
|
|
|
|
Interest
Expense
|
|
|
(4 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(31 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
Third
Quarter of 2007
|
|
|
|
|
|
$ |
85
|
|
Net
Income remained relatively flat in the third quarter of 2007 compared to
the
third quarter of 2006. The key components of the $1 million increase
in Net Income were a $35 million increase in Gross Margin offset by a $31
million increase in Operating Expenses and Other and a $3 million increase
in
Income Tax Expense.
The
major
components of the increase in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $40 million primarily due to:
|
|
·
|
A
$35 million increase in capacity settlements due to recent plant
acquisitions and changes in relative peak demands of AEP Power
Pool
members under the Interconnection Agreement.
|
|
·
|
A
$15 million increase in industrial revenue due to the addition
of Ormet, a
major industrial customer effective January 1, 2007. See
“Ormet” section of Note 3.
|
|
·
|
An
$11 million increase in rate revenues related to a $13 million
increase in
CSPCo’s RSP offset by a $3 million decrease related to recovery of IGCC
preconstruction costs. See “Ohio Rate Matters” section of Note
3. The decrease in rate recovery of IGCC preconstruction costs
was offset by the decreased amortization of deferred expenses in
Depreciation and Amortization. CSPCo’s recovery of Phase 1 of
IGCC preconstruction costs ended in July 2007.
|
|
These
increases were partially offset by:
|
|
·
|
A
$28 million decrease in fuel margins.
|
·
|
Margins
from Off-system Sales increased $7 million primarily due to higher
sales
volumes and power prices in the east, benefits from AEP’s eastern natural
gas fleet, and higher trading margins.
|
·
|
Transmission
Revenues, Net decreased $13 million primarily due to PJM’s revision of its
pricing methodology for transmission line losses to marginal-loss
pricing
effective June 1, 2007. See “PJM Marginal-Loss Pricing” section
of Note 3.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $27 million primarily
due
to:
|
·
|
A
$15 million increase due to the settlement agreement regarding
alleged
violations of the NSR provisions of the CAA. The $15 million
represents CSPCo’s allocation of the settlement. See “Federal
EPA Complaint and Notice of Violation” section of Note
4.
|
·
|
An
$8 million increase in expenses related to CSPCo’s UPA for AEGCo’s
Lawrenceburg Plant which began in May 2007.
|
·
|
A
$7 million increase in overhead line expenses due to the 2006 recognition
of a regulatory asset related to PUCO orders regarding distribution
service reliability and restoration costs.
|
·
|
Depreciation
and Amortization decreased $4 million due to the end of amortization
of
IGCC preconstruction costs in 2007. The decrease in
amortization of IGCC preconstruction costs was offset by a corresponding
decrease in Retail Margins. CSPCo’s recovery of Phase 1 of IGCC
preconstruction costs ended in July 2007.
|
·
|
Taxes
Other Than Income Taxes increased $3 million due to increases in
property
taxes and state excise taxes.
|
·
|
Interest
Expense increased $4 million partially due to a decrease in the
debt
component of AFUDC.
|
·
|
Income
Tax Expense increased $3 million primarily due to an increase in
pretax
book income, state income taxes and changes in certain book/tax
differences accounted for on a flow-through
basis.
|
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Reconciliation
of Nine Months Ended September 30, 2006 to Nine Months Ended September 30,
2007
Net
Income
(in
millions)
Nine
Months Ended September 30, 2006
|
|
|
|
|
$ |
168
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
134
|
|
|
|
|
|
Off-system
Sales
|
|
|
7
|
|
|
|
|
|
Transmission
Revenues, Net
|
|
|
(20 |
) |
|
|
|
|
Other
|
|
|
(2 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
119
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(45 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(4 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
2
|
|
|
|
|
|
Interest
Expense
|
|
|
(1 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(48 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(27 |
) |
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
$ |
212
|
|
Net
Income increased $44 million to $212 million in 2007. The key driver
of the increase was a $119 million increase in Gross Margin offset by a $48
million increase in Operating Expenses and Other and a $27 million increase
in
Income Tax Expense.
The
major
components of the increase in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $134 million primarily due to:
|
|
·
|
A
$53 million increase in capacity settlements due to changes in
relative
peak demands of AEP Power Pool members under the Interconnection
Agreement
and recent plant acquisitions.
|
|
·
|
A
$46 million increase in rate revenues related to a $35 million
increase in
CSPCo’s RSP, an $8 million increase related to recovery of storm costs
and
a $3 million increase related to 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. CSPCo’s recovery of Phase 1
of IGCC preconstruction costs ended in July 2007.
|
|
·
|
A
$36 million increase in industrial revenue primarily due to the
addition
of Ormet, a major industrial customer, effective January 1,
2007. See “Ormet” section of Note 3.
|
|
·
|
A
$32 million increase in residential and commercial revenue primarily
due
to a 30% increase in cooling degree days and a 33% increase in
heating
degree days.
|
|
These
increases were partially offset by:
|
|
·
|
A
$50 million decrease in fuel margins.
|
·
|
Margins
from Off-system Sales increased $7 million primarily due to higher
trading
margins.
|
·
|
Transmission
Revenues, Net decreased $20 million primarily due to PJM’s revision of its
pricing methodology for transmission line losses to marginal-loss
pricing
effective June 1, 2007. See “PJM Marginal-Loss Pricing” section
of Note 3.
|
·
|
Other
revenues decreased $2 million primarily due to lower gains on sales
of
emission allowances.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $45 million primarily
due
to:
|
|
·
|
A
$15 million increase in overhead line expenses, of which $7 million
relates to the recognition in 2006 of a regulatory asset related
to PUCO
orders regarding distribution service reliability and restoration
costs
and an $8 million increase in 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
$15 million increase due to the settlement agreement regarding
alleged
violations of the NSR provisions of the CAA. The $15 million
represents CSPCo’s allocation of the settlement. See “Federal
EPA Complaint and Notice of Violation” section of Note
4.
|
|
·
|
A
$12 million increase in expenses related to CSPCo’s UPA for AEGCo’s
Lawrenceburg Plant which began in May 2007.
|
·
|
Depreciation
and Amortization increased $4 million primarily due to the amortization
of
IGCC preconstruction costs beginning in July 2006. The increase
in amortization of IGCC preconstruction costs was offset by a
corresponding increase in Retail Margins. CSPCo’s recovery of
Phase 1 of IGCC preconstruction costs ended in July
2007.
|
·
|
Income
Tax Expense increased $27 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 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
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See 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
Management
utilizes 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
exposure to interest rates primarily related to long-term debt with fixed
interest rates was $79 million and $70 million at September 30, 2007 and
December 31, 2006, respectively. Management would not expect to
liquidate the entire debt portfolio in a one-year holding period; therefore,
a
near term change in interest rates should not negatively affect results of
operations or consolidated financial position.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2007 and
2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
553,518
|
|
|
$ |
513,643
|
|
|
$ |
1,446,632
|
|
|
$ |
1,321,422
|
|
Sales
to AEP Affiliates
|
|
|
52,331
|
|
|
|
24,806
|
|
|
|
110,700
|
|
|
|
60,337
|
|
Other
|
|
|
1,292
|
|
|
|
1,449
|
|
|
|
3,743
|
|
|
|
4,016
|
|
TOTAL
|
|
|
607,141
|
|
|
|
539,898
|
|
|
|
1,561,075
|
|
|
|
1,385,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
103,560
|
|
|
|
90,510
|
|
|
|
255,764
|
|
|
|
231,543
|
|
Purchased
Electricity for Resale
|
|
|
49,619
|
|
|
|
35,449
|
|
|
|
113,765
|
|
|
|
87,902
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
107,386
|
|
|
|
102,669
|
|
|
|
278,715
|
|
|
|
272,334
|
|
Other
Operation
|
|
|
83,625
|
|
|
|
66,188
|
|
|
|
207,300
|
|
|
|
179,993
|
|
Maintenance
|
|
|
24,250
|
|
|
|
14,704
|
|
|
|
73,537
|
|
|
|
56,140
|
|
Depreciation
and Amortization
|
|
|
47,589
|
|
|
|
51,156
|
|
|
|
147,332
|
|
|
|
143,524
|
|
Taxes
Other Than Income Taxes
|
|
|
41,382
|
|
|
|
38,586
|
|
|
|
117,760
|
|
|
|
119,875
|
|
TOTAL
|
|
|
457,411
|
|
|
|
399,262
|
|
|
|
1,194,173
|
|
|
|
1,091,311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
149,730
|
|
|
|
140,636
|
|
|
|
366,902
|
|
|
|
294,464
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
166
|
|
|
|
989
|
|
|
|
782
|
|
|
|
1,919
|
|
Carrying
Costs Income
|
|
|
1,261
|
|
|
|
1,046
|
|
|
|
3,492
|
|
|
|
3,082
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
738
|
|
|
|
659
|
|
|
|
2,130
|
|
|
|
1,466
|
|
Interest
Expense
|
|
|
(19,530 |
) |
|
|
(15,813 |
) |
|
|
(51,193 |
) |
|
|
(50,247 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
132,365
|
|
|
|
127,517
|
|
|
|
322,113
|
|
|
|
250,684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
46,911
|
|
|
|
43,496
|
|
|
|
109,656
|
|
|
|
83,064
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
85,454
|
|
|
|
84,021
|
|
|
|
212,457
|
|
|
|
167,620
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
Stock Expense
|
|
|
39
|
|
|
|
39
|
|
|
|
118
|
|
|
|
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
85,415
|
|
|
$ |
83,982
|
|
|
$ |
212,339
|
|
|
$ |
167,502
|
|
The
common stock of CSPCo is wholly-owned by AEP.
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Nine Months Ended September 30, 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
|
|
|
|
|
|
|
|
|
|
|
(67,500 |
) |
|
|
|
|
|
|
(67,500 |
) |
Capital
Stock Expense
|
|
|
|
|
|
|
118
|
|
|
|
(118 |
) |
|
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
914,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,940
|
|
|
|
3,940
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
167,620
|
|
|
|
|
|
|
|
167,620
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
171,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$ |
41,026
|
|
|
$ |
580,153
|
|
|
$ |
461,367
|
|
|
$ |
3,060
|
|
|
$ |
1,085,606
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$ |
41,026
|
|
|
$ |
580,192
|
|
|
$ |
456,787
|
|
|
$ |
(21,988 |
) |
|
$ |
1,056,017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(3,022 |
) |
|
|
|
|
|
|
(3,022 |
) |
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(90,000 |
) |
|
|
|
|
|
|
(90,000 |
) |
Capital
Stock Expense and Other
|
|
|
|
|
|
|
118
|
|
|
|
(118 |
) |
|
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
962,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $1,231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,285 |
) |
|
|
(2,285 |
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
212,457
|
|
|
|
|
|
|
|
212,457
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
210,172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
41,026
|
|
|
$ |
580,310
|
|
|
$ |
576,104
|
|
|
$ |
(24,273 |
) |
|
$ |
1,173,167
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,695
|
|
|
$ |
1,319
|
|
Other
Cash Deposits
|
|
|
45,511
|
|
|
|
1,151
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
53,919
|
|
|
|
49,362
|
|
Affiliated Companies
|
|
|
36,934
|
|
|
|
62,866
|
|
Accrued Unbilled Revenues
|
|
|
33,756
|
|
|
|
11,042
|
|
Miscellaneous
|
|
|
7,792
|
|
|
|
4,895
|
|
Allowance for Uncollectible Accounts
|
|
|
(842 |
) |
|
|
(546 |
) |
Total
Accounts Receivable
|
|
|
131,559
|
|
|
|
127,619
|
|
Fuel
|
|
|
42,518
|
|
|
|
37,348
|
|
Materials
and Supplies
|
|
|
36,784
|
|
|
|
31,765
|
|
Emission
Allowances
|
|
|
3,103
|
|
|
|
3,493
|
|
Risk
Management Assets
|
|
|
38,776
|
|
|
|
66,238
|
|
Prepayments
and Other
|
|
|
15,305
|
|
|
|
19,719
|
|
TOTAL
|
|
|
315,251
|
|
|
|
288,652
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
2,055,590
|
|
|
|
1,896,073
|
|
Transmission
|
|
|
498,180
|
|
|
|
479,119
|
|
Distribution
|
|
|
1,538,056
|
|
|
|
1,475,758
|
|
Other
|
|
|
204,395
|
|
|
|
191,103
|
|
Construction
Work in Progress
|
|
|
360,560
|
|
|
|
294,138
|
|
Total
|
|
|
4,656,781
|
|
|
|
4,336,191
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,672,118
|
|
|
|
1,611,043
|
|
TOTAL
- NET
|
|
|
2,984,663
|
|
|
|
2,725,148
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
263,054
|
|
|
|
298,304
|
|
Long-term
Risk Management Assets
|
|
|
47,634
|
|
|
|
56,206
|
|
Deferred
Charges and Other
|
|
|
95,464
|
|
|
|
152,379
|
|
TOTAL
|
|
|
406,152
|
|
|
|
506,889
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
3,706,066
|
|
|
$ |
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
September
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
123,043
|
|
|
$ |
696
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
104,217
|
|
|
|
112,431
|
|
Affiliated
Companies
|
|
|
44,320
|
|
|
|
59,538
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
112,000
|
|
|
|
-
|
|
Risk
Management Liabilities
|
|
|
29,305
|
|
|
|
49,285
|
|
Customer
Deposits
|
|
|
41,467
|
|
|
|
34,991
|
|
Accrued
Taxes
|
|
|
109,477
|
|
|
|
166,551
|
|
Other
|
|
|
74,852
|
|
|
|
58,011
|
|
TOTAL
|
|
|
638,681
|
|
|
|
481,503
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
1,030,123
|
|
|
|
1,097,322
|
|
Long-term
Debt – Affiliated
|
|
|
100,000
|
|
|
|
100,000
|
|
Long-term
Risk Management Liabilities
|
|
|
31,907
|
|
|
|
40,477
|
|
Deferred
Income Taxes
|
|
|
451,456
|
|
|
|
475,888
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
171,431
|
|
|
|
179,048
|
|
Deferred
Credits and Other
|
|
|
109,301
|
|
|
|
90,434
|
|
TOTAL
|
|
|
1,894,218
|
|
|
|
1,983,169
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,532,899
|
|
|
|
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
|
|
|
580,310
|
|
|
|
580,192
|
|
Retained
Earnings
|
|
|
576,104
|
|
|
|
456,787
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(24,273 |
) |
|
|
(21,988 |
) |
TOTAL
|
|
|
1,173,167
|
|
|
|
1,056,017
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$ |
3,706,066
|
|
|
$ |
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 Nine Months Ended September 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
212,457
|
|
|
$ |
167,620
|
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
147,332
|
|
|
|
143,524
|
|
Deferred
Income Taxes
|
|
|
(13,959 |
) |
|
|
(5,097 |
) |
Carrying
Costs Income
|
|
|
(3,492 |
) |
|
|
(3,082 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
3,982
|
|
|
|
(4,502 |
) |
Deferred
Property Taxes
|
|
|
57,890
|
|
|
|
49,518
|
|
Change
in Other Noncurrent Assets
|
|
|
(31,329 |
) |
|
|
(24,692 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
2,713
|
|
|
|
11,752
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(13,040 |
) |
|
|
(3,374 |
) |
Fuel,
Materials and Supplies
|
|
|
(2,332 |
) |
|
|
(8,200 |
) |
Accounts
Payable
|
|
|
(13,336 |
) |
|
|
31,765
|
|
Customer
Deposits
|
|
|
6,476
|
|
|
|
(14,565 |
) |
Accrued
Taxes, Net
|
|
|
(44,295 |
) |
|
|
(8,981 |
) |
Other
Current Assets
|
|
|
(415 |
) |
|
|
26,838
|
|
Other
Current Liabilities
|
|
|
8,817
|
|
|
|
(2,878 |
) |
Net
Cash Flows From Operating Activities
|
|
|
317,469
|
|
|
|
355,646
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(246,130 |
) |
|
|
(207,875 |
) |
Change
in Other Cash Deposits, Net
|
|
|
(44,360 |
) |
|
|
(1,151 |
) |
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
|
(60,417 |
) |
Acquisition
of Darby Plant
|
|
|
(102,032 |
) |
|
|
-
|
|
Proceeds
from Sales of Assets
|
|
|
1,016
|
|
|
|
1,525
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(391,506 |
) |
|
|
(267,918 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
44,257
|
|
|
|
-
|
|
Change
in Advances from Affiliates, Net
|
|
|
122,347
|
|
|
|
(17,609 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(2,191 |
) |
|
|
(2,308 |
) |
Dividends
Paid on Common Stock
|
|
|
(90,000 |
) |
|
|
(67,500 |
) |
Net
Cash Flows From (Used For) Financing Activities
|
|
|
74,413
|
|
|
|
(87,417 |
) |
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
376
|
|
|
|
311
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,319
|
|
|
|
940
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,695
|
|
|
$ |
1,251
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
53,464
|
|
|
$ |
52,958
|
|
Net
Cash Paid for Income Taxes
|
|
|
93,709
|
|
|
|
35,561
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,900
|
|
|
|
2,130
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
34,630
|
|
|
|
22,955
|
|
Noncash
Assumption of Liabilities Related to Acquisition of Darby
Plant
|
|
|
2,339
|
|
|
|
-
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS
OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to CSPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to
CSPCo.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Acquisition
|
Note
5
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
INDIANA
MICHIGAN POWER COMPANY
AND
SUBSIDIARIES
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Third
Quarter of 2007 Compared to Third Quarter of 2006
Reconciliation
of Third Quarter of 2006 to Third Quarter of 2007
Net
Income
(in
millions)
Third
Quarter of 2006
|
|
|
|
|
$ |
35
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
7
|
|
|
|
|
|
FERC
Municipals and Cooperatives
|
|
|
14
|
|
|
|
|
|
Off-system
Sales
|
|
|
7
|
|
|
|
|
|
Transmission
Revenues, Net
|
|
|
(11 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(11 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
18
|
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1 |
) |
|
|
|
|
Other
Income
|
|
|
(2 |
) |
|
|
|
|
Interest
Expense
|
|
|
(1 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
Third
Quarter of 2007
|
|
|
|
|
|
$ |
49
|
|
Net
Income increased $14 million to $49 million in 2007. The key drivers
of the increase were a $17 million increase in Gross Margin and a $3 million
decrease in Operating Expenses and Other partially offset by a $6 million
increase in Income Tax Expense.
The
major
components of the increase in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $7 million primarily due to higher fuel margins
of $9
million due to reactivation of the fuel clause and higher retail
sales of
$5 million reflecting favorable weather conditions as cooling degree
days
increased for both the Indiana and Michigan
jurisdictions. Lower revenues from financial transmission
rights, net of congestion, due to fewer constraints in the PJM
market
partially offset the increases.
|
·
|
FERC
Municipals and Cooperatives margins increased $14 million due to
the
addition of new municipal contracts effective January 2007 including
new
rates and increased customer demand.
|
·
|
Margins
from Off-system Sales increased $7 million primarily due to higher
sales
volumes and power prices in the east, benefits from AEP’s eastern natural
gas fleet, and higher trading margins.
|
·
|
Transmission
Revenues, Net decreased $11 million primarily due to PJM’s revision of its
pricing methodology for transmission line losses to marginal-loss
pricing
effective June 1, 2007. See “PJM Marginal-Loss Pricing” section
of Note 3.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $11 million primarily
due to
a settlement agreement regarding alleged violations of the NSR
provisions
of the CAA, of which $14 million was allocated to I&M. See
“Federal EPA Complaint and Notice of Violation” section of Note
4.
|
·
|
Depreciation
and Amortization expense decreased $18 million primarily due to
a
settlement agreement approved by the IURC reducing depreciation
rates to
reflect longer estimated lives for Cook and Tanners Creek
plants. See “Indiana Depreciation Study Filing” section of Note
3.
|
·
|
Income
Tax Expense increased $6 million primarily due to an increase in
pretax
book income and a decrease in amortization of investment tax credits,
partially offset by changes in certain book/tax differences accounted
for
on a flow-through basis and state income
taxes.
|
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Reconciliation
of Nine Months Ended September 30, 2006 to Nine Months Ended September 30,
2007
Net
Income
(in
millions)
Nine
Months Ended September 30, 2006
|
|
|
|
|
$ |
121
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(20 |
) |
|
|
|
|
FERC
Municipals and Cooperatives
|
|
|
40
|
|
|
|
|
|
Off-system
Sales
|
|
|
9
|
|
|
|
|
|
Transmission
Revenues, Net
|
|
|
(12 |
) |
|
|
|
|
Other
|
|
|
(4 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(31 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
8
|
|
|
|
|
|
Other
Income
|
|
|
(4 |
) |
|
|
|
|
Interest
Expense
|
|
|
(5 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(32 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
$ |
109
|
|
Net
Income decreased $12 million to $109 million in 2007. The key driver
of the decrease was a $32 million increase in Operating Expenses and Other
partially offset by a $13 million increase in Gross Margin and a $7 million
decrease in Income Tax Expense.
The
major
components of the increase in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power, were as follows:
·
|
Retail
Margins decreased $20 million primarily due to a $37 million reduction
in
capacity settlement revenues under the Interconnection Agreement
reflecting I&M’s new peak demand in July 2006 and lower revenues from
financial transmission rights, net of congestion, of $21 million
due to
fewer constraints in the PJM market. Higher retail sales of $32
million reflecting favorable weather conditions partially offset
the
decreases. Heating and cooling degree days increased
significantly in both the Indiana and Michigan
jurisdictions.
|
·
|
FERC
Municipals and Cooperatives margins increased $40 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 increased $9 million primarily due to higher
trading
margins.
|
·
|
Transmission
Revenues, Net decreased $12 million primarily due to PJM’s revision of its
pricing methodology for transmission line losses to marginal-loss
pricing
effective June 1, 2007. See “PJM Marginal-Loss Pricing” section
of Note 3.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other Operation
and Maintenance expenses increased $31 million primarily due to
the
settlement agreement regarding alleged violations of the NSR provisions
of
the CAA, of which $14 million was allocated to I&M, a $13 million
increase in coal-fired plant maintenance expenses resulting from
planned
outages at Rockport and Tanners Creek plants and an $8 million
increase in
transmission expense primarily due to reduced credits under the
Transmission Equalization Agreement. Credits decreased due to
I&M’s 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 I&M’s share of the transmission
investment pool.
|
·
|
Depreciation
and Amortization expense decreased $8 million primarily due to
a $14
million decrease in depreciation related to the revised depreciation
rates
in Indiana partially offset by an increase in amortization related
to
capitalized software development costs.
|
·
|
Interest
Expense increased $5 million primarily due to an increase in outstanding
long-term debt.
|
·
|
Income
Tax Expense decreased $7 million primarily due to a decrease in
pretax
book income and changes in certain book/tax differences accounted
for on a
flow-through basis, partially offset by a decrease in amortization
of
investment tax credits.
|
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
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See 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
Management
utilizes 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 exposure to interest rates primarily related to long-term
debt with fixed interest rates was $109 million and $93 million at September
30,
2007 and December 31, 2006, respectively. Management would not expect to
liquidate the entire debt portfolio in a one-year holding period; therefore,
a
near term change in interest rates should not negatively affect results of
operations or consolidated financial position.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2007 and
2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
478,907
|
|
|
$ |
449,259
|
|
|
$ |
1,286,223
|
|
|
$ |
1,224,609
|
|
Sales
to AEP Affiliates
|
|
|
56,262
|
|
|
|
54,793
|
|
|
|
186,653
|
|
|
|
223,728
|
|
Other
– Affiliated
|
|
|
16,250
|
|
|
|
12,903
|
|
|
|
43,488
|
|
|
|
37,838
|
|
Other
– Nonaffiliated
|
|
|
7,757
|
|
|
|
8,580
|
|
|
|
21,718
|
|
|
|
24,593
|
|
TOTAL
|
|
|
559,176
|
|
|
|
525,535
|
|
|
|
1,538,082
|
|
|
|
1,510,768
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
103,740
|
|
|
|
98,135
|
|
|
|
290,507
|
|
|
|
283,734
|
|
Purchased
Electricity for Resale
|
|
|
26,580
|
|
|
|
20,450
|
|
|
|
63,830
|
|
|
|
46,993
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
96,451
|
|
|
|
92,052
|
|
|
|
249,755
|
|
|
|
259,304
|
|
Other
Operation
|
|
|
129,439
|
|
|
|
119,661
|
|
|
|
367,483
|
|
|
|
340,666
|
|
Maintenance
|
|
|
58,502
|
|
|
|
56,960
|
|
|
|
146,657
|
|
|
|
142,531
|
|
Depreciation
and Amortization
|
|
|
35,604
|
|
|
|
53,404
|
|
|
|
145,801
|
|
|
|
153,897
|
|
Taxes
Other Than Income Taxes
|
|
|
19,704
|
|
|
|
18,472
|
|
|
|
56,936
|
|
|
|
56,343
|
|
TOTAL
|
|
|
470,020
|
|
|
|
459,134
|
|
|
|
1,320,969
|
|
|
|
1,283,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
89,156
|
|
|
|
66,401
|
|
|
|
217,113
|
|
|
|
227,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
252
|
|
|
|
1,102
|
|
|
|
1,547
|
|
|
|
2,459
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
1,734
|
|
|
|
2,517
|
|
|
|
2,726
|
|
|
|
5,881
|
|
Interest
Expense
|
|
|
(18,312 |
) |
|
|
(17,228 |
) |
|
|
(57,744 |
) |
|
|
(52,663 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
72,830
|
|
|
|
52,792
|
|
|
|
163,642
|
|
|
|
182,977
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
23,706
|
|
|
|
18,231
|
|
|
|
55,020
|
|
|
|
62,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
49,124
|
|
|
|
34,561
|
|
|
|
108,622
|
|
|
|
120,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
85
|
|
|
|
85
|
|
|
|
255
|
|
|
|
255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
49,039
|
|
|
$ |
34,476
|
|
|
$ |
108,367
|
|
|
$ |
120,709
|
|
The
common stock of I&M is wholly-owned by AEP.
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Nine Months Ended September 30, 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
|
|
|
|
|
|
|
|
|
|
|
(30,000 |
) |
|
|
|
|
|
|
(30,000 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(255 |
) |
|
|
|
|
|
|
(255 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,189,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,712
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,036 |
) |
|
|
(5,036 |
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
120,964
|
|
|
|
|
|
|
|
120,964
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
115,928
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$ |
56,584
|
|
|
$ |
861,290
|
|
|
$ |
396,496
|
|
|
$ |
(8,605 |
) |
|
$ |
1,305,765
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$ |
56,584
|
|
|
$ |
861,290
|
|
|
$ |
386,616
|
|
|
$ |
(15,051 |
) |
|
$ |
1,289,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
327
|
|
|
|
|
|
|
|
327
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(30,000 |
) |
|
|
|
|
|
|
(30,000 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(255 |
) |
|
|
|
|
|
|
(255 |
) |
Gain
on Reacquired Preferred Stock
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,259,512
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,747 |
) |
|
|
(1,747 |
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
108,622
|
|
|
|
|
|
|
|
108,622
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106,875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
56,584
|
|
|
$ |
861,291
|
|
|
$ |
465,310
|
|
|
$ |
(16,798 |
) |
|
$ |
1,366,387
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
2,190
|
|
|
$ |
1,369
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
74,743
|
|
|
|
82,102
|
|
Affiliated Companies
|
|
|
61,771
|
|
|
|
108,288
|
|
Accrued Unbilled Revenues
|
|
|
12,424
|
|
|
|
2,206
|
|
Miscellaneous
|
|
|
1,627
|
|
|
|
1,838
|
|
Allowance for Uncollectible Accounts
|
|
|
(863 |
) |
|
|
(601 |
) |
Total
Accounts Receivable
|
|
|
149,702
|
|
|
|
193,833
|
|
Fuel
|
|
|
48,261
|
|
|
|
64,669
|
|
Materials
and Supplies
|
|
|
136,332
|
|
|
|
129,953
|
|
Risk
Management Assets
|
|
|
37,351
|
|
|
|
69,752
|
|
Accrued
Tax Benefits
|
|
|
177
|
|
|
|
27,378
|
|
Prepayments
and Other
|
|
|
17,968
|
|
|
|
15,170
|
|
TOTAL
|
|
|
391,981
|
|
|
|
502,124
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
3,402,220
|
|
|
|
3,363,813
|
|
Transmission
|
|
|
1,067,434
|
|
|
|
1,047,264
|
|
Distribution
|
|
|
1,180,230
|
|
|
|
1,102,033
|
|
Other
(including nuclear fuel and coal mining)
|
|
|
558,168
|
|
|
|
529,727
|
|
Construction
Work in Progress
|
|
|
179,597
|
|
|
|
183,893
|
|
Total
|
|
|
6,387,649
|
|
|
|
6,226,730
|
|
Accumulated
Depreciation, Depletion and Amortization
|
|
|
3,003,588
|
|
|
|
2,914,131
|
|
TOTAL
- NET
|
|
|
3,384,061
|
|
|
|
3,312,599
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
282,020
|
|
|
|
314,805
|
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,314,892
|
|
|
|
1,248,319
|
|
Long-term
Risk Management Assets
|
|
|
45,810
|
|
|
|
59,137
|
|
Deferred
Charges and Other
|
|
|
92,710
|
|
|
|
109,453
|
|
TOTAL
|
|
|
1,735,432
|
|
|
|
1,731,714
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
5,511,474
|
|
|
$ |
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
September
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
24,234
|
|
|
$ |
91,173
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
118,010
|
|
|
|
146,733
|
|
Affiliated
Companies
|
|
|
44,772
|
|
|
|
65,497
|
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
-
|
|
|
|
50,000
|
|
Risk
Management Liabilities
|
|
|
28,340
|
|
|
|
52,083
|
|
Customer
Deposits
|
|
|
31,498
|
|
|
|
34,946
|
|
Accrued
Taxes
|
|
|
69,302
|
|
|
|
59,652
|
|
Other
|
|
|
133,966
|
|
|
|
128,461
|
|
TOTAL
|
|
|
450,122
|
|
|
|
628,545
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
1,564,811
|
|
|
|
1,505,135
|
|
Long-term
Risk Management Liabilities
|
|
|
30,717
|
|
|
|
42,641
|
|
Deferred
Income Taxes
|
|
|
305,429
|
|
|
|
335,000
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
757,136
|
|
|
|
753,402
|
|
Asset
Retirement Obligations
|
|
|
841,791
|
|
|
|
809,853
|
|
Deferred
Credits and Other
|
|
|
187,001
|
|
|
|
174,340
|
|
TOTAL
|
|
|
3,686,885
|
|
|
|
3,620,371
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,137,007
|
|
|
|
4,248,916
|
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
8,080
|
|
|
|
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
|
|
|
861,291
|
|
|
|
861,290
|
|
Retained
Earnings
|
|
|
465,310
|
|
|
|
386,616
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(16,798 |
) |
|
|
(15,051 |
) |
TOTAL
|
|
|
1,366,387
|
|
|
|
1,289,439
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
5,511,474
|
|
|
$ |
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 Nine Months Ended September 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
108,622
|
|
|
$ |
120,964
|
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
145,801
|
|
|
|
153,897
|
|
Deferred
Income Taxes
|
|
|
(9,235 |
) |
|
|
7,734
|
|
Amortization
(Deferral) of Incremental Nuclear Refueling Outage Expenses,
Net
|
|
|
14,450
|
|
|
|
(20,673 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
6,226
|
|
|
|
(4,915 |
) |
Amortization
of Nuclear Fuel
|
|
|
48,360
|
|
|
|
37,839
|
|
Change
in Other Noncurrent Assets
|
|
|
14,437
|
|
|
|
16,508
|
|
Change
in Other Noncurrent Liabilities
|
|
|
33,995
|
|
|
|
35,920
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
34,569
|
|
|
|
37,368
|
|
Fuel,
Materials and Supplies
|
|
|
14,584
|
|
|
|
(20,665 |
) |
Accounts
Payable
|
|
|
(27,015 |
) |
|
|
29,483
|
|
Customer
Deposits
|
|
|
(3,448 |
) |
|
|
(14,315 |
) |
Accrued
Taxes, Net
|
|
|
41,243
|
|
|
|
28,292
|
|
Other
Current Assets
|
|
|
(3,459 |
) |
|
|
20,997
|
|
Other
Current Liabilities
|
|
|
2,282
|
|
|
|
25,489
|
|
Net
Cash Flows From Operating Activities
|
|
|
421,412
|
|
|
|
453,923
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(191,110 |
) |
|
|
(240,806 |
) |
Purchases
of Investment Securities
|
|
|
(561,509 |
) |
|
|
(559,803 |
) |
Sales
of Investment Securities
|
|
|
505,620
|
|
|
|
517,017
|
|
Acquisitions
of Nuclear Fuel
|
|
|
(73,112 |
) |
|
|
(72,614 |
) |
Other
|
|
|
670
|
|
|
|
3,344
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(319,441 |
) |
|
|
(352,862 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
-
|
|
|
|
49,745
|
|
Change
in Advances from Affiliates, Net
|
|
|
(66,939 |
) |
|
|
(66,086 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
-
|
|
|
|
(50,000 |
) |
Retirement
of Cumulative Preferred Stock
|
|
|
(2 |
) |
|
|
(1 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(3,954 |
) |
|
|
(4,612 |
) |
Dividends
Paid on Common Stock
|
|
|
(30,000 |
) |
|
|
(30,000 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(255 |
) |
|
|
(255 |
) |
Net
Cash Flows Used For Financing Activities
|
|
|
(101,150 |
) |
|
|
(101,209 |
) |
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
821
|
|
|
|
(148 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,369
|
|
|
|
854
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
2,190
|
|
|
$ |
706
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
49,628
|
|
|
$ |
37,708
|
|
Net
Cash Paid for Income Taxes
|
|
|
14,395
|
|
|
|
20,180
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
5,847
|
|
|
|
4,359
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
23,935
|
|
|
|
29,755
|
|
Acquisition
of Nuclear Fuel in Accounts Payable at September 30,
|
|
|
691
|
|
|
|
-
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to I&M’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to
I&M.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
OHIO
POWER COMPANY CONSOLIDATED
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Third
Quarter of 2007 Compared to Third Quarter of 2006
Reconciliation
of Third Quarter of 2006 to Third Quarter of 2007
Net
Income
(in
millions)
Third
Quarter of 2006
|
|
|
|
|
$ |
83
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
30
|
|
|
|
|
|
Off-system
Sales
|
|
|
(7 |
) |
|
|
|
|
Transmission
Revenues, Net
|
|
|
(15 |
) |
|
|
|
|
Other
|
|
|
(1 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(4 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(2 |
) |
|
|
|
|
Other
Income, Net
|
|
|
(1 |
) |
|
|
|
|
Interest
Expense
|
|
|
(11 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(18 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2007
|
|
|
|
|
|
$ |
75
|
|
Net
Income decreased $8 million to $75 million in 2007. The key driver of
the decrease was an $18 million increase in Operating Expenses and Other
offset
by a $7 million increase in Gross Margin and a $3 million decrease in Income
Tax
Expense.
The
major
components of the increase in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
|
|
|
·
|
Retail
Margins increased $30 million partially due to a $13 million increase
in
industrial revenue primarily due to the addition of Ormet, a major
industrial customer, effective January 1, 2007. See “Ormet”
section of Note 3. Retail Margins also increased due to a $3
million increase in rate revenues primarily related to an $8 million
increase in OPCo’s RSP partially offset by a $3 million decrease related
to rate recovery of IGCC preconstruction costs. See “Ohio Rate
Matters” section of Note 3. The decrease in rate recovery of
IGCC preconstruction costs was offset by the decreased amortization
of
deferred expenses in Depreciation and Amortization.
|
·
|
Margins
from Off-system Sales decreased $7 million primarily due to a $10
million
decrease related to OPCo’s purchase power and sale agreement with Dow
Chemical Company (Dow) which ended in November 2006 and a decrease
in
OPCo’s allocated share of off-system sales revenue due to an affiliate’s
new peak. These decreases were offset by higher sales volumes
and power prices in the east, benefits from AEP’s eastern natural gas
fleet, and higher trading margins.
|
·
|
Transmission
Revenues, Net decreased $15 million primarily due to PJM’s revision of its
pricing methodology for transmission line losses to marginal-loss
pricing
effective June 1, 2007. See “PJM Marginal-Loss Pricing” section
of Note 3.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $4 million primarily
due
to:
|
|
·
|
A
$17 million increase due to the settlement agreement regarding
alleged
violations of the NSR provisions of the CAA. The $17 million
represents OPCo’s allocation of the settlement. See “Federal
EPA Complaint and Notice of Violation” section of Note
4.
|
|
·
|
A
$7 million increase in overhead line expenses due to the 2006 recognition
of a regulatory asset related to PUCO orders regarding distribution
service reliability and restoration costs.
|
|
These
increases were partially offset by:
|
|
·
|
A
$10 million decrease due to the absence of maintenance and rental
expenses
related to OPCo’s purchase power and sale agreement with Dow which ended
in November 2006. The decrease in Other Operation and
Maintenance expenses related to Dow were offset by a corresponding
decrease in margins from Off-system Sales.
|
|
·
|
A
$3 million decrease in maintenance from planned and forced outages
at the
Muskingum River and Kammer Plants related to boiler tube inspections
in
2006.
|
·
|
Depreciation
and Amortization increased $2 million primarily due to a $7 million
increase in depreciation related to environmental improvements
placed in
service at the Mitchell Plant. This increase was offset by
decreased amortization of IGCC preconstruction costs of $3 million
and a
$2 million amortization of a regulatory liability related to
Ormet. See “Ormet” section of Note 3. The decrease
in amortization of IGCC preconstruction costs was offset by a
corresponding decrease in Retail Margins.
|
·
|
Interest
Expense increased $11 million due to additional long-term debt
and a
decrease in the debt component of AFUDC as a result of Mitchell
Plant
environmental improvements placed in service.
|
·
|
Income
Tax Expense decreased $3 million primarily due to a decrease in
pretax
book income offset by changes in certain book/tax differences accounted
for on a flow-through basis.
|
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Reconciliation
of Nine Months Ended September 30, 2006 to Nine Months Ended September 30,
2007
Net
Income
(in
millions)
Nine
Months Ended September 30, 2006
|
|
|
|
|
$ |
202
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
152
|
|
|
|
|
|
Off-system
Sales
|
|
|
(23 |
) |
|
|
|
|
Transmission
Revenues, Net
|
|
|
(26 |
) |
|
|
|
|
Other
|
|
|
(16 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
87
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
1
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(14 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(2 |
) |
|
|
|
|
Other
Income, Net
|
|
|
(1 |
) |
|
|
|
|
Interest
Expense
|
|
|
(23 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(39 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
$ |
229
|
|
Net
Income increased $27 million to $229 million in 2007. The key driver
of the increase was an $87 million increase in Gross Margin offset by a $39
million increase in Operating Expenses and Other and a $21 million increase
in
Income Tax Expense.
The
major
components of the increase in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $152 million primarily due to the
following:
|
|
·
|
A
$42 million increase in capacity settlements under the Interconnection
Agreement related to certain affiliates’ peaks and the June 2006
expiration of OPCo’s supplemental capacity and energy obligation to
Buckeye Power, Inc. under the Cardinal Station
Agreement.
|
|
·
|
A
$38 million increase in rate revenues primarily related to a $26
million
increase in OPCo’s RSP, a $9 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
$31 million increase in industrial revenue due to the addition
of Ormet, a
major industrial customer, effective January 1, 2007. See
“Ormet” section of Note 3.
|
|
·
|
A
$20 million increase in residential and commercial revenue primarily
due
to a 26% increase in cooling degree days and a 27% increase in
heating
degree days.
|
·
|
Margins
from Off-system Sales decreased $23 million primarily due to a
decrease in
OPCo’s allocated share of off-system sales revenue due to an affiliate’s
new peak and a $20 million decrease related to OPCo’s purchase power and
sale agreement with Dow Chemical Company (Dow) which ended in November
2006. Higher trading margins helped to offset a portion of the
decrease over last year.
|
·
|
Transmission
Revenues, Net decreased $26 million primarily due to PJM’s revision of its
pricing methodology for transmission line losses to marginal-loss
pricing
effective June 1, 2007. See “PJM Marginal-Loss Pricing” section
of Note 3.
|
·
|
Other
revenues decreased $16 million primarily due to a $7 million decrease
related to the April 2006 expiration of an obligation to sell supplemental
capacity and energy to Buckeye Power, Inc. under the Cardinal Station
Agreement and a $5 million decrease in gains on sales of emission
allowances.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses decreased $1 million primarily
due to
the following:
|
|
·
|
A
$21 million decrease in maintenance from planned and forced outages
at the
Muskingum River, Kammer and Sporn Plants related to boiler tube
inspections in 2006.
|
|
·
|
A
$20 million decrease in maintenance and rental expenses related
to OPCo’s
purchase power and sale agreement with Dow which ended in November
2006. This decrease was offset by a corresponding decrease in
margins from Off-system Sales.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$17 million increase due to the settlement agreement regarding
alleged
violations of the NSR provisions of the CAA. See “Federal EPA
Complaint and Notice of Violation” section of Note 4.
|
|
·
|
A
$13 million increase in overhead line expenses due to the 2006
recognition
of a regulatory asset related to PUCO orders regarding distribution
service reliability and restoration costs and the amortization
of deferred
storm expenses recovered through a cost-recovery rider. The
increase in the amortization of deferred storm expenses was offset
by a
corresponding increase in Retail Margins.
|
|
·
|
A
$7 million increase in removal costs related to planned and forced
outages
at the Gavin, Mitchell and Cardinal Plants.
|
·
|
Depreciation
and Amortization increased $14 million primarily due to a $16 million
increase in depreciation related to environmental improvements
placed in
service at the Mitchell Plant and the amortization of IGCC preconstruction
costs of $3 million in 2007. These increases were partially
offset by a $5 million decrease related to the amortization of
a
regulatory liability related to Ormet. See “Ormet” section of
Note 3. The increase in amortization of IGCC preconstruction
costs was offset by a corresponding increase in Retail
Margins.
|
·
|
Interest
Expense increased $23 million primarily due to additional long-term
debt.
|
·
|
Income
Tax Expense increased $21 million primarily due to an increase
in pretax
book income and state income taxes.
|
Financial
Condition
Credit
Ratings
The
rating agencies currently have OPCo on stable outlook. Current ratings are
as
follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
A3
|
|
BBB
|
|
BBB+
|
Cash
Flow
Cash
flows for the nine months ended September 30, 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
|
|
|
402,980
|
|
|
|
470,180
|
|
Investing
Activities
|
|
|
(743,260 |
) |
|
|
(703,550 |
) |
Financing
Activities
|
|
|
351,381
|
|
|
|
233,455
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
11,101
|
|
|
|
85
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
12,726
|
|
|
$ |
1,325
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $403 million in 2007. OPCo
produced Net Income of $229 million during the period and a noncash expense
item
of $253 million for Depreciation and Amortization. The other changes
in assets and liabilities represent items that had a 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
included two significant items. Accounts Payable had a $60 million
cash outflow partially due to emission allowance payments in January 2007,
reduced accruals for Mitchell Plant environmental projects that went into
service in 2007 and timing differences for payments to
affiliates. Accounts Receivable, Net had a $33 million cash outflow
partially due to the timing of collections of receivables.
Net
Cash
Flows From Operating Activities were $470 million in 2006. OPCo
produced Net Income of $202 million during the period and a noncash expense
item
of $239 million for Depreciation and Amortization. The other changes
in assets and liabilities represent items that had a current period cash
flow
impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The activity in working capital primarily included
two significant items. Accounts Receivable, Net had a $78 million
cash inflow primarily due to the collection of receivables related to power
sales to affiliates. Accounts Payable had a $45 million cash outflow
primarily due to timing differences for payments to affiliates related to
emission allowances and the AEP Power Pool.
Investing
Activities
Net
Cash
Flows Used For Investing Activities were $743 million and $704 million in
2007
and 2006, respectively. Construction Expenditures were $751 million
and $715 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 flue gas
desulfurization projects at the Cardinal, Amos and Mitchell
Plants. In January 2007, environmental upgrades were completed for
Unit 1 and 2 at the Mitchell Plant. Based upon OPCo’s current
forecast, OPCo expects construction expenditures to be approximately $150
million for the remainder of 2007, excluding AFUDC.
Financing
Activities
Net
Cash
Flows From Financing Activities were $351 million in 2007. OPCo
issued $400 million of Senior Unsecured Notes and $65 million of Pollution
Control Bonds. OPCo reduced borrowings by $96 million from the
Utility Money Pool.
Net
Cash
Flows From Financing Activities were $233 million for 2006. OPCo
issued $350 million of Senior Unsecured Notes and $65 million of Pollution
Control Bonds. OPCo retired Notes Payable-Affiliated of $200
million. OPCo received a Capital Contribution from Parent of $70
million.
Financing
Activity
Long-term
debt issuances and retirements during the first nine months of 2007
were:
Issuances
Type
of Debt
|
|
Principal
Amount
|
|
|
Interest
Rate
|
|
Due
Date
|
|
|
(in
thousands)
|
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$ |
65,000
|
|
|
|
4.90
|
|
2037
|
Senior
Unsecured Notes
|
|
|
400,000
|
|
|
Variable
|
|
2010
|
Retirements
Type
of Debt
|
|
Principal
Amount
|
|
|
Interest
Rate
|
|
Due
Date
|
|
|
(in
thousands)
|
|
|
(%)
|
|
|
Notes
Payable – Nonaffiliated
|
|
$ |
2,927
|
|
|
|
6.81
|
|
2008
|
Notes
Payable – Nonaffiliated
|
|
|
6,000
|
|
|
|
6.27
|
|
2009
|
Liquidity
OPCo
has
solid investment grade ratings, which provide ready access to capital markets
in
order to issue new debt, refinance short-term debt or refinance long-term
debt
maturities. In addition, OPCo participates in the Utility Money Pool,
which provides access to AEP’s liquidity.
Summary
Obligation Information
A
summary
of contractual obligations is included in the 2006 Annual Report and has
not
changed significantly from year-end other than the debt issuances and
retirements discussed in “Cash Flow” and “Financing Activity” above and the
obligations resulting from the settlement agreement regarding alleged violations
of the NSR provisions of the CAA. See “Federal EPA Complaint and
Notice of Violations” section of Note 4.
Significant
Factors
Litigation
and Regulatory Activity
In
the
ordinary course of business, OPCo is involved in employment, commercial,
environmental and regulatory litigation. Since it is difficult to
predict the outcome of these proceedings, management cannot state what the
eventual outcome of these proceedings will be, or what the timing of the
amount
of any loss, fine or penalty may be. Management does, however, assess
the probability of loss for such contingencies and accrues a liability for
cases
which have a probable likelihood of loss and the loss amount can be
estimated. For details on pending litigation and regulatory
proceedings, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 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 results of operations, financial condition and cash
flows.
See
the
“Combined Management’s Discussion and Analysis of Registrant Subsidiaries”
section for additional discussion of relevant factors.
Critical
Accounting Estimates
See
the
“Critical Accounting Estimates” section of “Combined Management’s Discussion and
Analysis of Registrant Subsidiaries” in the 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
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion within AEP’s “Quantitative and
Qualitative Disclosures About Risk Management Activities”
section. The following tables provide information about AEP’s risk
management activities’ effect on OPCo.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in the condensed consolidated balance sheet as of September 30,
2007
and the reasons for changes in total MTM value as compared to December 31,
2006.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of September 30, 2007
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
|
Cash
Flow Hedges
|
|
|
DETM
Assignment (a)
|
|
|
Total
|
|
Current
Assets
|
|
$ |
45,622
|
|
|
$ |
1,401
|
|
|
$ |
-
|
|
|
$ |
47,023
|
|
Noncurrent
Assets
|
|
|
55,412
|
|
|
|
987
|
|
|
|
-
|
|
|
|
56,399
|
|
Total
MTM Derivative Contract Assets
|
|
|
101,034
|
|
|
|
2,388
|
|
|
|
-
|
|
|
|
103,422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(35,178 |
) |
|
|
(229 |
) |
|
|
(2,616 |
) |
|
|
(38,023 |
) |
Noncurrent
Liabilities
|
|
|
(33,907 |
) |
|
|
(402 |
) |
|
|
(4,370 |
) |
|
|
(38,679 |
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(69,085 |
) |
|
|
(631 |
) |
|
|
(6,986 |
) |
|
|
(76,702 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$ |
31,949
|
|
|
$ |
1,757
|
|
|
$ |
(6,986 |
) |
|
$ |
26,720
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 in the 2006 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 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
|
|
|
(6,663
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
3,267
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
340
|
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
2,411
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(448
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
31,949
|
|
Net
Cash Flow Hedge Contracts
|
|
|
1,757
|
|
DETM
Assignment (d)
|
|
|
(6,986
|
)
|
Total
MTM Risk Management Contract Net Assets at September 30,
2007
|
|
$
|
26,720
|
|
(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 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
total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of net assets/liabilities to give an indication
of when
these MTM amounts will settle and generate
cash.
|
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets
Fair
Value of Contracts as of September 30, 2007
(in
thousands)
|
|
Remainder
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
After
2011
|
|
Total
|
|
Prices
Actively Quoted – Exchange Traded
Contracts
|
|
$
|
2,927
|
|
$
|
(4,308
|
)
|
$
|
857
|
|
$
|
(30
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
(554
|
)
|
Prices
Provided by Other External
Sources
– OTC Broker Quotes (a)
|
|
|
110
|
|
|
11,983
|
|
|
9,396
|
|
|
6,954
|
|
|
-
|
|
|
-
|
|
|
28,443
|
|
Prices
Based on Models and Other Valuation Methods
(b)
|
|
|
42
|
|
|
(557
|
)
|
|
661
|
|
|
1,132
|
|
|
1,424
|
|
|
1,358
|
|
|
4,060
|
|
Total
|
|
$
|
3,079
|
|
$
|
7,118
|
|
$
|
10,914
|
|
$
|
8,056
|
|
$
|
1,424
|
|
$
|
1,358
|
|
$
|
31,949
|
|
(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
independent 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 including
values determinable by other third party
transactions.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheet
OPCo
is
exposed to market fluctuations in energy commodity prices impacting power
operations. Management monitors these risks on future operations and
may use various commodity derivative instruments designated in qualifying
cash
flow hedge strategies to mitigate the impact of these fluctuations on future
cash flows. Management does not hedge all commodity price
risk.
Management
uses interest rate derivative transactions to manage interest rate risk related
to anticipated borrowings of fixed-rate debt. Management does not
hedge all interest rate risk.
Management
uses foreign currency derivatives to lock in prices on certain transactions
denominated in foreign currencies where deemed necessary, and designate
qualifying instruments as cash flow hedge strategies. Management does
not hedge all foreign currency.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on the Condensed Consolidated Balance Sheets and the reasons
for the changes from December 31, 2006 to September 30, 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
Nine
Months Ended September 30, 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
|
|
|
537
|
|
|
|
(4 |
) |
|
|
(139 |
) |
|
|
394
|
|
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
|
|
(3,280 |
) |
|
|
10
|
|
|
|
(610 |
) |
|
|
(3,880 |
) |
Ending
Balance in AOCI September 30, 2007
|
|
$ |
1,297
|
|
|
$ |
(325 |
) |
|
$ |
2,804
|
|
|
$ |
3,776
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,576 thousand gain.
Credit
Risk
Counterparty
credit quality and exposure is generally consistent with that of
AEP.
VaR
Associated with Risk Management Contracts
Management
uses a risk measurement model, which calculates Value at Risk (VaR) to measure
commodity price risk in the risk management portfolio. The VaR is
based on the variance-covariance method using historical prices to estimate
volatilities and correlations and assumes a 95% confidence level and a one-day
holding period. Based on this VaR analysis, at September 30, 2007, a
near term typical change in commodity prices is not expected to have a material
effect on results of operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended September 30, 2007
|
|
|
Twelve
Months Ended December 31, 2006
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
End
|
|
|
High
|
|
|
Average
|
|
|
Low
|
|
|
End
|
|
|
High
|
|
|
Average
|
|
|
Low
|
|
$ |
208
|
|
|
$ |
2,054
|
|
|
$ |
594
|
|
|
$ |
159
|
|
|
$ |
573
|
|
|
$ |
1,451
|
|
|
$ |
500
|
|
|
$ |
271
|
|
VaR
Associated with Debt Outstanding
Management
utilizes 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
exposure to interest rates primarily related to long-term debt with fixed
interest rates was $138 million and $110 million at September 30, 2007 and
December 31, 2006, respectively. Management would not expect to
liquidate the entire debt portfolio in a one-year holding period; therefore,
a
near term change in interest rates should not negatively affect results of
operations or consolidated financial position.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2007 and
2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
543,404
|
|
|
$ |
558,490
|
|
|
$ |
1,516,383
|
|
|
$ |
1,556,193
|
|
Sales
to AEP Affiliates
|
|
|
205,193
|
|
|
|
198,640
|
|
|
|
564,292
|
|
|
|
502,547
|
|
Other
- Affiliated
|
|
|
5,749
|
|
|
|
4,400
|
|
|
|
16,604
|
|
|
|
11,975
|
|
Other
- Nonaffiliated
|
|
|
3,397
|
|
|
|
3,378
|
|
|
|
10,838
|
|
|
|
12,806
|
|
TOTAL
|
|
|
757,743
|
|
|
|
764,908
|
|
|
|
2,108,117
|
|
|
|
2,083,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
254,310
|
|
|
|
280,593
|
|
|
|
653,941
|
|
|
|
727,261
|
|
Purchased
Electricity for Resale
|
|
|
33,178
|
|
|
|
28,324
|
|
|
|
85,900
|
|
|
|
76,351
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
43,147
|
|
|
|
35,423
|
|
|
|
92,858
|
|
|
|
92,086
|
|
Other
Operation
|
|
|
102,850
|
|
|
|
100,265
|
|
|
|
292,809
|
|
|
|
286,083
|
|
Maintenance
|
|
|
45,663
|
|
|
|
44,503
|
|
|
|
155,428
|
|
|
|
163,443
|
|
Depreciation
and Amortization
|
|
|
84,400
|
|
|
|
82,755
|
|
|
|
253,455
|
|
|
|
239,431
|
|
Taxes
Other Than Income Taxes
|
|
|
47,506
|
|
|
|
47,945
|
|
|
|
146,211
|
|
|
|
143,634
|
|
TOTAL
|
|
|
611,054
|
|
|
|
619,808
|
|
|
|
1,680,602
|
|
|
|
1,728,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
146,689
|
|
|
|
145,100
|
|
|
|
427,515
|
|
|
|
355,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
108
|
|
|
|
840
|
|
|
|
992
|
|
|
|
2,072
|
|
Carrying
Costs Income
|
|
|
3,644
|
|
|
|
3,502
|
|
|
|
10,779
|
|
|
|
10,336
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
590
|
|
|
|
755
|
|
|
|
1,607
|
|
|
|
1,891
|
|
Interest
Expense
|
|
|
(36,262 |
) |
|
|
(24,610 |
) |
|
|
(95,927 |
) |
|
|
(72,461 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
114,769
|
|
|
|
125,587
|
|
|
|
344,966
|
|
|
|
297,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
39,507
|
|
|
|
42,245
|
|
|
|
116,103
|
|
|
|
95,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
75,262
|
|
|
|
83,342
|
|
|
|
228,863
|
|
|
|
201,773
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
183
|
|
|
|
183
|
|
|
|
549
|
|
|
|
549
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
75,079
|
|
|
$ |
83,159
|
|
|
$ |
228,314
|
|
|
$ |
201,224
|
|
The
common stock of OPCo is wholly-owned by AEP.
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Nine Months Ended September 30, 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
|
|
|
|
|
|
|
70,000
|
|
|
|
|
|
|
|
|
|
|
|
70,000
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(549 |
) |
|
|
|
|
|
|
(549 |
) |
Gain
on Reacquired Preferred Stock
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,837,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $3,393
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,300
|
|
|
|
6,300
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
201,773
|
|
|
|
|
|
|
|
201,773
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
208,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$ |
321,201
|
|
|
$ |
536,639
|
|
|
$ |
1,180,578
|
|
|
$ |
7,055
|
|
|
$ |
2,045,473
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$ |
321,201
|
|
|
$ |
536,639
|
|
|
$ |
1,207,265
|
|
|
$ |
(56,763 |
) |
|
$ |
2,008,342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(5,380 |
) |
|
|
|
|
|
|
(5,380 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(549 |
) |
|
|
|
|
|
|
(549 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,002,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $1,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,486 |
) |
|
|
(3,486 |
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
228,863
|
|
|
|
|
|
|
|
228,863
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
225,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
321,201
|
|
|
$ |
536,639
|
|
|
$ |
1,430,199
|
|
|
$ |
(60,249 |
) |
|
$ |
2,227,790
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
12,726
|
|
|
$ |
1,625
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
96,217
|
|
|
|
86,116
|
|
Affiliated Companies
|
|
|
102,771
|
|
|
|
108,214
|
|
Accrued Unbilled Revenues
|
|
|
28,193
|
|
|
|
10,106
|
|
Miscellaneous
|
|
|
1,235
|
|
|
|
1,819
|
|
Allowance for Uncollectible Accounts
|
|
|
(1,079 |
) |
|
|
(824 |
) |
Total
Accounts Receivable
|
|
|
227,337
|
|
|
|
205,431
|
|
Fuel
|
|
|
125,583
|
|
|
|
120,441
|
|
Materials
and Supplies
|
|
|
82,377
|
|
|
|
74,840
|
|
Emission
Allowances
|
|
|
6,218
|
|
|
|
10,388
|
|
Risk
Management Assets
|
|
|
47,023
|
|
|
|
86,947
|
|
Accrued
Tax Benefits
|
|
|
8,476
|
|
|
|
22,909
|
|
Prepayments
and Other
|
|
|
27,332
|
|
|
|
18,416
|
|
TOTAL
|
|
|
537,072
|
|
|
|
540,997
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
5,553,893
|
|
|
|
4,413,340
|
|
Transmission
|
|
|
1,059,631
|
|
|
|
1,030,934
|
|
Distribution
|
|
|
1,372,724
|
|
|
|
1,322,103
|
|
Other
|
|
|
312,305
|
|
|
|
299,637
|
|
Construction
Work in Progress
|
|
|
676,841
|
|
|
|
1,339,631
|
|
Total
|
|
|
8,975,394
|
|
|
|
8,405,645
|
|
Accumulated
Depreciation and Amortization
|
|
|
2,921,494
|
|
|
|
2,836,584
|
|
TOTAL
- NET
|
|
|
6,053,900
|
|
|
|
5,569,061
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
354,499
|
|
|
|
414,180
|
|
Long-term
Risk Management Assets
|
|
|
56,399
|
|
|
|
70,092
|
|
Deferred
Charges and Other
|
|
|
176,964
|
|
|
|
224,403
|
|
TOTAL
|
|
|
587,862
|
|
|
|
708,675
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
7,178,834
|
|
|
$ |
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
September
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
85,341
|
|
|
$ |
181,281
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
136,467
|
|
|
|
250,025
|
|
Affiliated Companies
|
|
|
104,106
|
|
|
|
145,197
|
|
Short-term
Debt – Nonaffiliated
|
|
|
2,097
|
|
|
|
1,203
|
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
22,390
|
|
|
|
17,854
|
|
Risk
Management Liabilities
|
|
|
38,023
|
|
|
|
73,386
|
|
Customer
Deposits
|
|
|
36,407
|
|
|
|
31,465
|
|
Accrued
Taxes
|
|
|
126,995
|
|
|
|
165,338
|
|
Accrued
Interest
|
|
|
45,151
|
|
|
|
35,497
|
|
Other
|
|
|
119,987
|
|
|
|
123,631
|
|
TOTAL
|
|
|
716,964
|
|
|
|
1,024,877
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
2,635,957
|
|
|
|
2,183,887
|
|
Long-term
Debt – Affiliated
|
|
|
200,000
|
|
|
|
200,000
|
|
Long-term
Risk Management Liabilities
|
|
|
38,679
|
|
|
|
52,929
|
|
Deferred
Income Taxes
|
|
|
895,839
|
|
|
|
911,221
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
167,182
|
|
|
|
185,895
|
|
Deferred
Credits and Other
|
|
|
263,136
|
|
|
|
219,127
|
|
TOTAL
|
|
|
4,200,793
|
|
|
|
3,753,059
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,917,757
|
|
|
|
4,777,936
|
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
16,660
|
|
|
|
15,825
|
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
16,627
|
|
|
|
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
|
|
|
1,430,199
|
|
|
|
1,207,265
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(60,249 |
) |
|
|
(56,763 |
) |
TOTAL
|
|
|
2,227,790
|
|
|
|
2,008,342
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
7,178,834
|
|
|
$ |
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 Nine Months Ended September 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
228,863
|
|
|
$ |
201,773
|
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
253,455
|
|
|
|
239,431
|
|
Deferred
Income Taxes
|
|
|
3,938
|
|
|
|
(18,399 |
) |
Carrying
Costs Income
|
|
|
(10,779 |
) |
|
|
(10,336 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
(424 |
) |
|
|
668
|
|
Deferred
Property Taxes
|
|
|
54,036
|
|
|
|
54,073
|
|
Change
in Other Noncurrent Assets
|
|
|
(21,882 |
) |
|
|
1,732
|
|
Change
in Other Noncurrent Liabilities
|
|
|
8,026
|
|
|
|
15,923
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(32,723 |
) |
|
|
78,307
|
|
Fuel,
Materials and Supplies
|
|
|
(1,245 |
) |
|
|
(25,375 |
) |
Accounts
Payable
|
|
|
(59,925 |
) |
|
|
(44,817 |
) |
Accrued
Taxes, Net
|
|
|
(19,997 |
) |
|
|
(27,733 |
) |
Other
Current Assets
|
|
|
(10,544 |
) |
|
|
36,333
|
|
Other
Current Liabilities
|
|
|
12,181
|
|
|
|
(31,400 |
) |
Net
Cash Flows From Operating Activities
|
|
|
402,980
|
|
|
|
470,180
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(751,161 |
) |
|
|
(715,200 |
) |
Proceeds
From Sales of Assets
|
|
|
7,924
|
|
|
|
13,301
|
|
Other
|
|
|
(23 |
) |
|
|
(1,651 |
) |
Net
Cash Flows Used For Investing Activities
|
|
|
(743,260 |
) |
|
|
(703,550 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
-
|
|
|
|
70,000
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
461,324
|
|
|
|
405,841
|
|
Change
in Short-term Debt, Net – Nonaffiliated
|
|
|
895
|
|
|
|
(3,264 |
) |
Change
in Advances from Affiliates, Net
|
|
|
(95,940 |
) |
|
|
(21,908 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(8,927 |
) |
|
|
(10,890 |
) |
Retirement
of Long-term Debt – Affiliated
|
|
|
-
|
|
|
|
(200,000 |
) |
Retirement
of Cumulative Preferred Stock
|
|
|
(2 |
) |
|
|
(7 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(5,420 |
) |
|
|
(5,768 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(549 |
) |
|
|
(549 |
) |
Net
Cash Flows From Financing Activities
|
|
|
351,381
|
|
|
|
233,455
|
|
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
11,101
|
|
|
|
85
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,625
|
|
|
|
1,240
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
12,726
|
|
|
$ |
1,325
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
85,851
|
|
|
$ |
71,666
|
|
Net
Cash Paid for Income Taxes
|
|
|
61,459
|
|
|
|
72,175
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,620
|
|
|
|
2,529
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
42,055
|
|
|
|
117,638
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
OHIO
POWER COMPANY CONSOLIDATED
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to OPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to
OPCo.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S
NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Third
Quarter of 2007 Compared to Third Quarter of 2006
Reconciliation
of Third Quarter of 2006 to Third Quarter of 2007
Net
Income
(in
millions)
Third
Quarter of 2006
|
|
|
|
|
$ |
42
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
1
|
|
|
|
|
|
Transmission
Revenues, Net
|
|
|
1
|
|
|
|
|
|
Other
|
|
|
2
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(3 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(2 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(6 |
) |
|
|
|
|
Interest
Expense
|
|
|
(1 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(12 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2007
|
|
|
|
|
|
$ |
37
|
|
Net
Income decreased $5 million to $37 million in 2007. The key drivers
of the decrease were a $12 million increase in Operating Expenses and Other,
partially offset by a $4 million increase in Gross Margin and a $3 million
decrease in Income Tax Expense .
The
major
components of the change in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions allowances
and purchased power were as follows:
·
|
Retail
and Off-system Sales Margins increased $1 million primarily due
to an
increase in retail margins attributable to new base rates partially
offset
by a reduction in off-system sales volumes.
|
·
|
Other
revenues increased $2 million primarily due to higher gains on
sales of
emission allowances.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $3 million primarily
due to
an increase in transmission expense resulting from higher SPP
administration fees and transmission services from other
utilities.
|
·
|
Taxes
Other Than Income Taxes increased $6 million primarily due to a sales
and use tax adjustment recorded in 2006.
|
·
|
Income
Tax Expense decreased $3 million primarily due to a decrease in
pretax
book income.
|
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Reconciliation
of Nine Months Ended September 30, 2006 to Nine Months Ended September 30,
2007
Net
Income
(in
millions)
Nine
Months Ended September 30, 2006
|
|
|
|
|
$ |
51
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
3
|
|
|
|
|
|
Transmission
Revenues, Net
|
|
|
2
|
|
|
|
|
|
Other
|
|
|
(1 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(32 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(5 |
) |
|
|
|
|
Taxes
Other than Income Taxes
|
|
|
(6 |
) |
|
|
|
|
Interest
Expense
|
|
|
(7 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(50 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
$ |
22
|
|
Net
Income decreased $29 million to $22 million in 2007. The key drivers
of the decrease were a $50 million increase in Operating Expenses and Other,
partially offset by a $17 million decrease in Income Tax Expense and a $4
million increase in Gross Margin.
The
major
components of the change in Gross Margin, defined as revenues less the related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
and Off-system Sales Margins increased $3 million primarily due
to an
increase in retail margins attributable to new base
rates.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $32 million primarily
due to
an $18 million increase in distribution expense resulting primarily
from
the January 2007 ice storm and a $9 million increase in generation
expense
primarily due to scheduled maintenance outages. Transmission
expense increased $5 million primarily due to $4 million in higher
SPP
administration fees and transmission services from other utilities
and $1
million in higher overhead line maintenance.
|
·
|
Depreciation
and Amortization increased $5 million primarily due to higher depreciable
asset balances.
|
·
|
Taxes
Other Than Income Taxes increased $6 million primarily due to a sales
and use tax adjustment recorded in 2006.
|
·
|
Interest
Expense increased $7 million primarily due to increased
borrowings.
|
·
|
Income
Tax Expense decreased $17 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 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
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See 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
Management
utilizes 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 exposure to interest rates primarily related to long-term
debt with fixed interest rates was $42 million and $39 million at September
30,
2007 and December 31, 2006, respectively. Management would not expect
to liquidate the entire debt portfolio in a one-year holding period; therefore,
a near term change in interest rates should not negatively affect results
of
operations or financial position.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2007 and
2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
433,737
|
|
|
$ |
443,593
|
|
|
$ |
1,028,637
|
|
|
$ |
1,116,507
|
|
Sales
to AEP Affiliates
|
|
|
12,737
|
|
|
|
14,034
|
|
|
|
53,605
|
|
|
|
40,647
|
|
Other
|
|
|
1,562
|
|
|
|
814
|
|
|
|
2,746
|
|
|
|
3,062
|
|
TOTAL
|
|
|
448,036
|
|
|
|
458,441
|
|
|
|
1,084,988
|
|
|
|
1,160,216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
182,680
|
|
|
|
202,836
|
|
|
|
438,828
|
|
|
|
566,985
|
|
Purchased
Electricity for Resale
|
|
|
75,875
|
|
|
|
68,547
|
|
|
|
213,429
|
|
|
|
158,122
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
16,216
|
|
|
|
17,706
|
|
|
|
48,679
|
|
|
|
54,817
|
|
Other
Operation
|
|
|
44,030
|
|
|
|
40,644
|
|
|
|
127,382
|
|
|
|
117,385
|
|
Maintenance
|
|
|
24,128
|
|
|
|
25,072
|
|
|
|
89,390
|
|
|
|
67,412
|
|
Depreciation
and Amortization
|
|
|
24,430
|
|
|
|
22,215
|
|
|
|
70,128
|
|
|
|
65,060
|
|
Taxes
Other Than Income Taxes
|
|
|
10,007
|
|
|
|
3,844
|
|
|
|
30,191
|
|
|
|
23,997
|
|
TOTAL
|
|
|
377,366
|
|
|
|
380,864
|
|
|
|
1,018,027
|
|
|
|
1,053,778
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
70,670
|
|
|
|
77,577
|
|
|
|
66,961
|
|
|
|
106,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income
|
|
|
1,086
|
|
|
|
1,050
|
|
|
|
2,294
|
|
|
|
1,830
|
|
Interest
Expense
|
|
|
(12,381 |
) |
|
|
(10,954 |
) |
|
|
(36,549 |
) |
|
|
(29,723 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
59,375
|
|
|
|
67,673
|
|
|
|
32,706
|
|
|
|
78,545
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
22,804
|
|
|
|
25,650
|
|
|
|
10,266
|
|
|
|
27,241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
36,571
|
|
|
|
42,023
|
|
|
|
22,440
|
|
|
|
51,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
53
|
|
|
|
53
|
|
|
|
159
|
|
|
|
159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
36,518
|
|
|
$ |
41,970
|
|
|
$ |
22,281
|
|
|
$ |
51,145
|
|
The
common stock of PSO is owned by a wholly-owned subsidiary of
AEP.
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Nine Months Ended September 30, 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
|
|
|
|
|
|
|
|
|
|
|
(159 |
) |
|
|
|
|
|
|
(159 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
548,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4 |
) |
|
|
(4 |
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
51,304
|
|
|
|
|
|
|
|
51,304
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$ |
157,230
|
|
|
$ |
230,016
|
|
|
$ |
213,760
|
|
|
$ |
(1,268 |
) |
|
$ |
599,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$ |
157,230
|
|
|
$ |
230,016
|
|
|
$ |
199,262
|
|
|
$ |
(1,070 |
) |
|
$ |
585,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(386 |
) |
|
|
|
|
|
|
(386 |
) |
Capital
Contributions from Parent
|
|
|
|
|
|
|
60,000
|
|
|
|
|
|
|
|
|
|
|
|
60,000
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(159 |
) |
|
|
|
|
|
|
(159 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
644,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
137
|
|
|
|
137
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
22,440
|
|
|
|
|
|
|
|
22,440
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
157,230
|
|
|
$ |
290,016
|
|
|
$ |
221,157
|
|
|
$ |
(933 |
) |
|
$ |
667,470
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
BALANCE SHEETS
ASSETS
September
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,490
|
|
|
$ |
1,651
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
42,848
|
|
|
|
70,319
|
|
Affiliated Companies
|
|
|
94,920
|
|
|
|
73,318
|
|
Miscellaneous
|
|
|
47,769
|
|
|
|
10,270
|
|
Allowance for Uncollectible Accounts
|
|
|
(18 |
) |
|
|
(5 |
) |
Total
Accounts Receivable
|
|
|
185,519
|
|
|
|
153,902
|
|
Fuel
|
|
|
17,922
|
|
|
|
20,082
|
|
Materials
and Supplies
|
|
|
52,655
|
|
|
|
48,375
|
|
Risk
Management Assets
|
|
|
43,004
|
|
|
|
100,802
|
|
Accrued
Tax Benefits
|
|
|
9,499
|
|
|
|
4,679
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
15,817
|
|
|
|
7,557
|
|
Margin
Deposits
|
|
|
2,526
|
|
|
|
35,270
|
|
Prepayments
and Other
|
|
|
4,424
|
|
|
|
5,732
|
|
TOTAL
|
|
|
332,856
|
|
|
|
378,050
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
1,106,110
|
|
|
|
1,091,910
|
|
Transmission
|
|
|
556,760
|
|
|
|
503,638
|
|
Distribution
|
|
|
1,311,738
|
|
|
|
1,215,236
|
|
Other
|
|
|
243,575
|
|
|
|
234,227
|
|
Construction
Work in Progress
|
|
|
158,499
|
|
|
|
141,283
|
|
Total
|
|
|
3,376,682
|
|
|
|
3,186,294
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,212,294
|
|
|
|
1,187,107
|
|
TOTAL
- NET
|
|
|
2,164,388
|
|
|
|
1,999,187
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
156,708
|
|
|
|
142,905
|
|
Long-term
Risk Management Assets
|
|
|
5,329
|
|
|
|
17,066
|
|
Employee
Benefits and Pension Assets
|
|
|
28,962
|
|
|
|
30,161
|
|
Deferred
Charges and Other
|
|
|
17,386
|
|
|
|
11,677
|
|
TOTAL
|
|
|
208,385
|
|
|
|
201,809
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
2,705,629
|
|
|
$ |
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
September
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
187,492
|
|
|
$ |
76,323
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
173,364
|
|
|
|
165,618
|
|
Affiliated
Companies
|
|
|
69,044
|
|
|
|
65,134
|
|
Risk
Management Liabilities
|
|
|
31,867
|
|
|
|
88,469
|
|
Customer
Deposits
|
|
|
42,891
|
|
|
|
51,335
|
|
Accrued
Taxes
|
|
|
43,540
|
|
|
|
19,984
|
|
Other
|
|
|
32,376
|
|
|
|
58,651
|
|
TOTAL
|
|
|
580,574
|
|
|
|
525,514
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
670,132
|
|
|
|
669,998
|
|
Long-term
Risk Management Liabilities
|
|
|
5,483
|
|
|
|
11,448
|
|
Deferred
Income Taxes
|
|
|
430,307
|
|
|
|
414,197
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
284,970
|
|
|
|
315,584
|
|
Deferred
Credits and Other
|
|
|
61,431
|
|
|
|
51,605
|
|
TOTAL
|
|
|
1,452,323
|
|
|
|
1,462,832
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,032,897
|
|
|
|
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 – Par Value – $15 Per Share:
|
|
|
|
|
|
|
|
|
Authorized
– 11,000,000 Shares
|
|
|
|
|
|
|
|
|
Issued
– 10,482,000 Shares
|
|
|
|
|
|
|
|
|
Outstanding
– 9,013,000 Shares
|
|
|
157,230
|
|
|
|
157,230
|
|
Paid-in
Capital
|
|
|
290,016
|
|
|
|
230,016
|
|
Retained
Earnings
|
|
|
221,157
|
|
|
|
199,262
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(933 |
) |
|
|
(1,070 |
) |
TOTAL
|
|
|
667,470
|
|
|
|
585,438
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
2,705,629
|
|
|
$ |
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 Nine Months Ended September 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
22,440
|
|
|
$ |
51,304
|
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
70,128
|
|
|
|
65,060
|
|
Deferred
Income Taxes
|
|
|
23,220
|
|
|
|
(18,661 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
6,968
|
|
|
|
8,901
|
|
Deferred
Property Taxes
|
|
|
(8,353 |
) |
|
|
(8,098 |
) |
Change
in Other Noncurrent Assets
|
|
|
(10,050 |
) |
|
|
17,850
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(31,165 |
) |
|
|
(24,838 |
) |
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(31,617 |
) |
|
|
(2,389 |
) |
Fuel,
Materials and Supplies
|
|
|
(2,110 |
) |
|
|
(6,990 |
) |
Margin
Deposits
|
|
|
32,744
|
|
|
|
(25,811 |
) |
Accounts
Payable
|
|
|
10,226
|
|
|
|
1,585
|
|
Customer
Deposits
|
|
|
(8,444 |
) |
|
|
(2,737 |
) |
Accrued
Taxes, Net
|
|
|
19,725
|
|
|
|
48,845
|
|
Fuel
Over/Under Recovery, Net
|
|
|
(8,260 |
) |
|
|
76,938
|
|
Other
Current Assets
|
|
|
177
|
|
|
|
(3,828 |
) |
Other
Current Liabilities
|
|
|
(23,587 |
) |
|
|
(13,755 |
) |
Net
Cash Flows From Operating Activities
|
|
|
62,042
|
|
|
|
163,376
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(235,089 |
) |
|
|
(140,998 |
) |
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
|
(43,538 |
) |
Other
|
|
|
3,173
|
|
|
|
6
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(231,916 |
) |
|
|
(184,530 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contributions from Parent
|
|
|
60,000
|
|
|
|
-
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
12,488
|
|
|
|
148,747
|
|
Change
in Advances from Affiliates, Net
|
|
|
111,169
|
|
|
|
(75,883 |
) |
Retirement
of Long-term Debt – Affiliated
|
|
|
(12,660 |
) |
|
|
(50,000 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(1,125 |
) |
|
|
(794 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(159 |
) |
|
|
(159 |
) |
Net
Cash Flows From Financing Activities
|
|
|
169,713
|
|
|
|
21,911
|
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(161 |
) |
|
|
757
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,651
|
|
|
|
1,520
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,490
|
|
|
$ |
2,277
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
34,427
|
|
|
$ |
25,491
|
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(18,004 |
) |
|
|
7,471
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
600
|
|
|
|
2,639
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
16,358
|
|
|
|
6,591
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
SUBSIDIARIES
The
condensed notes to PSO’s condensed financial statements are combined with the
condensed notes to condensed financial statements for other registrant
subsidiaries. Listed below are the notes that apply to
PSO.
|
Footnote Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Third
Quarter of 2007 Compared to Third Quarter of 2006
Reconciliation
of Third Quarter of 2006 to Third Quarter of 2007
Net
Income
(in
millions)
Third
Quarter of 2006
|
|
|
|
|
$ |
50
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
(1 |
) |
|
|
|
|
Transmission
Revenues, Net
|
|
|
1
|
|
|
|
|
|
Other
|
|
|
(7 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(7 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(1 |
) |
|
|
|
|
Other
Income
|
|
|
3
|
|
|
|
|
|
Interest
Expense
|
|
|
(2 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
Third
Quarter of 2007
|
|
|
|
|
|
$ |
44
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income decreased $6 million to $44 million in 2007. The key drivers
of the decrease were a $7 million decrease in Gross Margin and a $7 million
increase in Operating Expenses and Other, partially offset by an $8 million
decrease in Income Tax Expense.
The
major
components of the decrease in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Other
revenues decreased $7 million primarily due to a $5 million decrease
in
gains on sales of emission allowances and a $1 million decrease
in revenue
from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite
Company, LLC, to outside parties. The decreased revenue from
coal deliveries was offset by a corresponding decrease in Other
Operation
and Maintenance expenses from mining operations as discussed
below.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $7 million primarily
due to a
$5 million increase in transmission expenses resulting from higher
SPP
administration fees and transmission services from other utilities,
and a
$3 million increase in generation expenses due to planned and forced
outages at the Welsh, Dolet Hills, Flint Creek, Knox Lee and Pirkey
Plants. These increases were partially offset by a $1 million
decrease in expenses primarily resulting from decreased coal deliveries
from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, due to
planned and forced outages at the Dolet Hills Generating Station,
which is
jointly-owned by SWEPCo and Cleco Corporation, a nonaffiliated
entity.
|
·
|
Other
Income increased $3 million primarily due to an increase in the
equity
component of AFUDC as a result of new generation
projects.
|
·
|
Interest
Expense increased $2 million primarily due to $4 million of interest
related to increased long-term debt partially offset by a $2 million
increase in the debt component of AFUDC due to new generation
projects.
|
·
|
Income
Tax Expense decreased $8 million primarily due to a decrease in
pretax
book income and state income taxes.
|
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Reconciliation
of Nine Months Ended September 30, 2006 to Nine Months Ended September 30,
2007
Net
Income
(in
millions)
Nine
Months Ended September 30, 2006
|
|
|
|
|
$ |
96
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
(29 |
) |
|
|
|
|
Other
|
|
|
(15 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(44 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(17 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(5 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1 |
) |
|
|
|
|
Other
Income
|
|
|
7
|
|
|
|
|
|
Interest
Expense
|
|
|
(8 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
Minority
Interest Expense
|
|
|
|
|
|
|
(1 |
) |
Income
Tax Expense
|
|
|
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
$ |
55
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income decreased $41 million to $55 million in 2007. The key drivers
of the decrease were a $44 million decrease in Gross Margin and a $24 million
increase in Operating Expenses and Other, offset by a $28 million decrease
in
Income Tax Expense.
The
major
components of the decrease in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
and Off-system Sales Margins decreased $29 million primarily due
to a $24
million provision related to a SWEPCo Texas fuel reconciliation
proceeding. See “SWEPCo Fuel Reconciliation – Texas” section of
Note 3.
|
·
|
Other
revenues decreased $15 million primarily due to an $8 million decrease
in
gains on sales of emission allowances and a $7 million decrease
in revenue
from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite
Company, LLC, to outside parties. The decreased revenue from
coal deliveries was offset by a corresponding decrease in Other
Operation
and Maintenance expenses from mining operations as discussed
below.
|
Operating
Expenses and Other and Income Taxes changed between years as
follows:
·
|
Other
Operation and Maintenance expenses increased $17 million primarily
due to
the following:
|
|
·
|
A
$9 million increase in generation expenses from planned and forced
outages
at the Welsh, Dolet Hills, Flint Creek, Knox Lee and Pirkey
Plants.
|
|
·
|
An
$8 million increase in transmission expenses related to higher
SPP
administration fees and transmission services from other
utilities.
|
|
·
|
A $6
million increase in distribution expenses including increased overhead
line maintenance.
|
|
These
increases were partially offset by:
|
|
·
|
An
$8 million decrease in expenses primarily resulting from decreased
coal
deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company,
LLC, due to planned and forced outages at the Dolet Hills Generating
Station, which is jointly-owned by SWEPCo and Cleco Corporation,
a
nonaffiliated entity.
|
·
|
Other
Income increased $7 million primarily due to an increase in the
equity
component of AFUDC as a result of new generation
projects.
|
·
|
Interest
Expense increased $8 million primarily due to $13 million of interest
related to increased long-term debt partially offset by a $5 million
increase in the debt component of AFUDC due to new generation
projects.
|
·
|
Income
Tax Expense decreased $28 million primarily due to a decrease in
pretax
book income.
|
Financial
Condition
Credit
Ratings
The
rating agencies currently have SWEPCo on stable outlook. Current
ratings are as follows:
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
|
|
|
|
|
Senior
Unsecured Debt
|
Baa1
|
|
BBB
|
|
A-
|
Cash
Flow
Cash
flows for the nine months ended September 30, 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
|
|
|
180,146
|
|
|
|
242,721
|
|
Investing
Activities
|
|
|
(353,001 |
) |
|
|
(186,631 |
) |
Financing
Activities
|
|
|
172,089
|
|
|
|
(56,343 |
) |
Net
Decrease in Cash and Cash Equivalents
|
|
|
(766 |
) |
|
|
(253 |
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,852
|
|
|
$ |
2,796
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $180 million in 2007. SWEPCo
produced Net Income of $55 million during the period and had noncash expense
items of $103 million for Depreciation and Amortization and $24 million related
to the Provision for Fuel Disallowance recorded as the result of an ALJ ruling
in SWEPCo’s Texas fuel reconciliation proceeding. The other changes
in assets and liabilities represent items that had a current period cash
flow
impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The activity in working capital relates to a number
of items. The $48 million inflow from Accounts Receivable, Net was
primarily due to the assignment of certain ERCOT contracts to an affiliate
company. The $37 million inflow from Margin Deposits was due to
decreased trading-related deposits resulting from normal trading
activities. The $27 million outflow from Fuel Over/Under Recovery,
Net is due to under recovery of higher fuel costs.
Net
Cash
Flows From Operating Activities were $243 million in 2006. SWEPCo
produced Net Income of $96 million during the period and had noncash expense
items of $99 million for Depreciation and Amortization. The other
changes in assets and liabilities represent items that had a current period
cash
flow impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The activity in working capital relates to a number
of items. The $54 million inflow from Accounts Payable was the result
of higher energy purchases. The $28 million outflow for Margin
Deposits was due to increased trading-related deposits resulting from the
amended SIA. In addition, the $64 million inflow related to
Over/Under Fuel Recovery was primarily due to the new fuel surcharges effective
December 2005 in SWEPCo’s Arkansas service territory and in January 2006 in
SWEPCo’s Texas service territory. The $27 million outflow from Fuel,
Materials and Supplies was the result of increased fuel purchases.
Investing
Activities
Net
Cash
Flows Used For Investing Activities during 2007 and 2006 were $353 million
and
$187 million, respectively. The $353 million of cash flows for
Construction Expenditures during 2007 were primarily related to new generation
facilities. The cash flows during 2006 were comprised primarily of
Construction Expenditures related to projects for improved transmission and
distribution service reliability as well as projects related to generation
facilities. Based upon SWEPCo’s current forecast, SWEPCo expects
construction expenditures to be approximately $210 million for the remainder
of
2007, excluding AFUDC.
Financing
Activities
Net
Cash
Flows From Financing Activities were $172 million during 2007. SWEPCo
issued $250 million of Senior Unsecured Notes and retired $90 million of
First
Mortgage Bonds. SWEPCo received a Capital Contribution from Parent of
$55 million. SWEPCo also reduced its borrowings from the Utility
Money Pool by $33 million.
Net
Cash
Flows Used for Financing Activities were $56 million during
2006. SWEPCo refinanced $82 million of Pollution Control
Bonds. SWEPCo reduced its borrowings from the Utility Money Pool by
$28 million and paid $30 million in common stock dividends.
Financing
Activity
Long-term
debt issuances and retirements during the first nine months of 2007
were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Senior
Unsecured Notes
|
|
$
|
250,000
|
|
5.55
|
|
2017
|
Retirements
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Notes
Payable – Nonaffiliated
|
|
$
|
4,210
|
|
4.47
|
|
2011
|
Notes
Payable – Nonaffiliated
|
|
|
4,000
|
|
6.36
|
|
2007
|
Notes
Payable – Nonaffiliated
|
|
|
2,250
|
|
Variable
|
|
2008
|
First
Mortgage Bonds
|
|
|
90,000
|
|
7.00
|
|
2007
|
Liquidity
SWEPCo
has solid investment grade ratings, which provides ready access to capital
markets in order to issue new debt or refinance long-term debt
maturities. In addition, SWEPCo participates in the Utility Money
Pool, which provides access to AEP’s liquidity.
Summary
Obligation Information
A
summary
of SWEPCo’s contractual obligations is included in its 2006 Annual Report and
has not changed significantly from year-end other than the debt issuances
and
retirements discussed in “Cash Flow” and “Financing Activity” above, Energy and
Capacity Purchase Contracts, and contractual commitments related to the proposed
Turk Plant. Effective January 1, 2007, SWEPCo transferred a
significant amount of ERCOT energy marketing contracts to AEP Energy Partners
(AEPEP), thereby decreasing its future obligations in Energy and Capacity
Purchase Contracts. See “ERCOT Contracts Transferred to AEPEP”
section of Note 1. SWEPCo has entered into additional contractual
commitments related to the construction of the proposed Turk Plant announced
in
August 2006. See “Turk Plant” in the “Arkansas Rate Matters” section
of Note 3.
Significant
Factors
Litigation
and Regulatory Activity
In
the
ordinary course of business, SWEPCo is involved in employment, commercial,
environmental and regulatory litigation. Since it is difficult to
predict the outcome of these proceedings, SWEPCo 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 pending litigation and regulatory
proceedings, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and
Contingencies in the 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 SWEPCo’s 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 SWEPCo.
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
Risk
management assets and liabilities are managed by AEPSC as agent. The
related risk management policies and procedures are instituted and administered
by AEPSC. See complete discussion within AEP’s “Quantitative and
Qualitative Disclosures About Risk Management Activities”
section. The following tables provide information about AEP’s risk
management activities’ effect on SWEPCo.
MTM
Risk Management Contract Net Assets
The
following two tables summarize the various mark-to-market (MTM) positions
included in the condensed consolidated balance sheet as of September 30,
2007
and the reasons for changes in total MTM value as compared to December 31,
2006.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
As
of September 30, 2007
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
|
Cash
Flow Hedges
|
|
|
Total
|
|
Current
Assets
|
|
$ |
51,042
|
|
|
$ |
75
|
|
|
$ |
51,117
|
|
Noncurrent
Assets
|
|
|
6,481
|
|
|
|
33
|
|
|
|
6,514
|
|
Total
MTM Derivative Contract Assets
|
|
|
57,523
|
|
|
|
108
|
|
|
|
57,631
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(38,334 |
) |
|
|
(11 |
) |
|
|
(38,345 |
) |
Noncurrent
Liabilities
|
|
|
(6,729 |
) |
|
|
-
|
|
|
|
(6,729 |
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(45,063 |
) |
|
|
(11 |
) |
|
|
(45,074 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$ |
12,460
|
|
|
$ |
97
|
|
|
$ |
12,557
|
|
MTM
Risk Management Contract Net Assets
Nine
Months Ended September 30, 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
|
|
|
(3,501
|
)
|
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)
|
|
|
1,201
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(5,406
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
12,460
|
|
Net
Cash Flow Hedge Contracts
|
|
|
97
|
|
Total
MTM Risk Management Contract Net Assets at September 30,
2007
|
|
$
|
12,557
|
|
(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
total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of net assets/liabilities to give an indication
of when
these MTM amounts will settle and generate
cash.
|
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets
Fair
Value of Contracts as of September 30, 2007
(in
thousands)
|
|
Remainder
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
After
2011
|
|
Total
|
|
Prices
Actively Quoted – Exchange
Traded
Contracts
|
|
$
|
(3,730
|
)
|
$
|
1,544
|
|
$
|
(237
|
)
|
$
|
(8
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
(2,431
|
)
|
Prices
Provided by Other External
Sources
- OTC Broker Quotes (a)
|
|
|
10,247
|
|
|
5,930
|
|
|
(728
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
15,449
|
|
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
(772
|
)
|
|
(1,286
|
)
|
|
1,502
|
|
|
(2
|
)
|
|
-
|
|
|
-
|
|
|
(558
|
)
|
Total
|
|
$
|
5,745
|
|
$
|
6,188
|
|
$
|
537
|
|
$
|
(10
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
12,460
|
|
(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
independent 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 including
values determinable by other third party
transactions.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheet
SWEPCo
is
exposed to market fluctuations in energy commodity prices impacting power
operations. Management monitors these risks on future operations and
may use various commodity derivative instruments designated in qualifying
cash
flow hedge strategies to mitigate the impact of these fluctuations on the
future
cash flows. Management does not hedge all commodity price
risk.
Management
uses interest rate derivative transactions to manage interest rate risk related
to anticipated borrowings of fixed-rate debt. Management does not
hedge all interest rate risk.
Management
uses foreign currency derivatives to lock in prices on certain transactions
denominated in foreign currencies where deemed necessary, and designate
qualifying instruments as cash flow hedge strategies. Management does
not hedge all foreign currency.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on the Condensed Consolidated Balance Sheets and the reasons
for the changes from December 31, 2006 to September 30, 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
Nine
Months Ended September 30, 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 |
) |
|
|
589
|
|
|
|
(430 |
) |
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
|
|
598
|
|
|
|
-
|
|
|
|
598
|
|
Ending
Balance in AOCI September 30, 2007
|
|
$ |
(6,856 |
) |
|
$ |
614
|
|
|
$ |
(6,242 |
) |
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $829 thousand loss.
Credit
Risk
Counterparty
credit quality and exposure is generally consistent with that of
AEP.
VaR
Associated with Risk Management Contracts
Management
uses a risk measurement model, which calculates Value at Risk (VaR) to measure
commodity price risk in the risk management portfolio. The VaR is based on
the
variance-covariance method using historical prices to estimate volatilities
and
correlations and assumes a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at September 30, 2007, a near
term typical change in commodity prices is not expected to have a material
effect on results of operations, cash flows or financial condition.
The
following table shows the end, high, average, and low market risk as measured
by
VaR for the periods indicated:
Nine
Months Ended September 30, 2007
|
|
|
Twelve
Months Ended December 31, 2006
|
|
(in
thousands)
|
|
|
(in
thousands)
|
|
End
|
|
|
High
|
|
|
Average
|
|
|
Low
|
|
|
End
|
|
|
High
|
|
|
Average
|
|
|
Low
|
|
$ |
26
|
|
|
$ |
245
|
|
|
$ |
92
|
|
|
$ |
23
|
|
|
$ |
447
|
|
|
$ |
2,171
|
|
|
$ |
794
|
|
|
$ |
68
|
|
VaR
Associated with Debt Outstanding
Management
also utilizes 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 exposure to interest rates primarily related
to long-term debt with fixed interest rates was $41 million and $25 million
at
September 30, 2007 and December 31, 2006, respectively. Management
would not expect to liquidate the entire debt portfolio in a one-year holding
period; therefore, a near term change in interest rates should not negatively
affect results of operations or consolidated financial position.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
For
the Three and Nine Months Ended September 30, 2007 and
2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
445,169
|
|
|
$ |
440,542
|
|
|
$ |
1,101,703
|
|
|
$ |
1,084,185
|
|
Sales
to AEP Affiliates
|
|
|
2,839
|
|
|
|
14,692
|
|
|
|
35,491
|
|
|
|
34,871
|
|
Other
|
|
|
502
|
|
|
|
1,466
|
|
|
|
1,437
|
|
|
|
2,260
|
|
TOTAL
|
|
|
448,510
|
|
|
|
456,700
|
|
|
|
1,138,631
|
|
|
|
1,121,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
141,837
|
|
|
|
158,992
|
|
|
|
379,818
|
|
|
|
367,924
|
|
Purchased
Electricity for Resale
|
|
|
73,438
|
|
|
|
61,816
|
|
|
|
182,806
|
|
|
|
135,918
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
22,282
|
|
|
|
18,140
|
|
|
|
61,284
|
|
|
|
58,303
|
|
Other
Operation
|
|
|
59,759
|
|
|
|
55,173
|
|
|
|
163,746
|
|
|
|
158,089
|
|
Maintenance
|
|
|
23,205
|
|
|
|
21,120
|
|
|
|
79,265
|
|
|
|
68,008
|
|
Depreciation
and Amortization
|
|
|
34,605
|
|
|
|
33,079
|
|
|
|
103,395
|
|
|
|
98,655
|
|
Taxes
Other Than Income Taxes
|
|
|
16,767
|
|
|
|
17,107
|
|
|
|
50,298
|
|
|
|
49,254
|
|
TOTAL
|
|
|
371,893
|
|
|
|
365,427
|
|
|
|
1,020,612
|
|
|
|
936,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
76,617
|
|
|
|
91,273
|
|
|
|
118,019
|
|
|
|
185,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
518
|
|
|
|
822
|
|
|
|
1,999
|
|
|
|
2,277
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
3,681
|
|
|
|
287
|
|
|
|
7,634
|
|
|
|
400
|
|
Interest
Expense
|
|
|
(15,966 |
) |
|
|
(13,844 |
) |
|
|
(48,691 |
) |
|
|
(40,688 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES AND MINORITY
INTEREST EXPENSE
|
|
|
64,850
|
|
|
|
78,538
|
|
|
|
78,961
|
|
|
|
147,154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
19,811
|
|
|
|
27,873
|
|
|
|
20,879
|
|
|
|
49,187
|
|
Minority
Interest Expense
|
|
|
919
|
|
|
|
959
|
|
|
|
2,733
|
|
|
|
2,077
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
44,120
|
|
|
|
49,706
|
|
|
|
55,349
|
|
|
|
95,890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
58
|
|
|
|
57
|
|
|
|
172
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
44,062
|
|
|
$ |
49,649
|
|
|
$ |
55,177
|
|
|
$ |
95,718
|
|
The
common stock of SWEPCo is owned by a wholly-owned subsidiary of
AEP.
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For
the Nine Months Ended September 30, 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
|
|
|
|
|
|
|
|
|
|
|
(30,000 |
) |
|
|
|
|
|
|
(30,000 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(172 |
) |
|
|
|
|
|
|
(172 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
752,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,516 |
) |
|
|
(1,516 |
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
95,890
|
|
|
|
|
|
|
|
95,890
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2006
|
|
$ |
135,660
|
|
|
$ |
245,003
|
|
|
$ |
473,562
|
|
|
$ |
(7,645 |
) |
|
$ |
846,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$ |
135,660
|
|
|
$ |
245,003
|
|
|
$ |
459,338
|
|
|
$ |
(18,799 |
) |
|
$ |
821,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(1,642 |
) |
|
|
|
|
|
|
(1,642 |
) |
Capital
Contribution from Parent
|
|
|
|
|
|
|
55,000
|
|
|
|
|
|
|
|
|
|
|
|
55,000
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(172 |
) |
|
|
|
|
|
|
(172 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
874,388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168
|
|
|
|
168
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
55,349
|
|
|
|
|
|
|
|
55,349
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEPTEMBER
30, 2007
|
|
$ |
135,660
|
|
|
$ |
300,003
|
|
|
$ |
512,873
|
|
|
$ |
(18,631 |
) |
|
$ |
929,905
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
September
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,852
|
|
|
$ |
2,618
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
50,382
|
|
|
|
88,245
|
|
Affiliated Companies
|
|
|
47,982
|
|
|
|
59,679
|
|
Miscellaneous
|
|
|
10,057
|
|
|
|
8,595
|
|
Allowance for Uncollectible Accounts
|
|
|
(24 |
) |
|
|
(130 |
) |
Total
Accounts Receivable
|
|
|
108,397
|
|
|
|
156,389
|
|
Fuel
|
|
|
78,295
|
|
|
|
69,426
|
|
Materials
and Supplies
|
|
|
48,716
|
|
|
|
46,001
|
|
Risk
Management Assets
|
|
|
51,117
|
|
|
|
120,036
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
7,300
|
|
|
|
-
|
|
Margin
Deposits
|
|
|
4,199
|
|
|
|
41,579
|
|
Prepayments
and Other
|
|
|
19,925
|
|
|
|
18,256
|
|
TOTAL
|
|
|
319,801
|
|
|
|
454,305
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
1,650,597
|
|
|
|
1,576,200
|
|
Transmission
|
|
|
719,033
|
|
|
|
668,008
|
|
Distribution
|
|
|
1,298,926
|
|
|
|
1,228,948
|
|
Other
|
|
|
627,145
|
|
|
|
595,429
|
|
Construction
Work in Progress
|
|
|
412,704
|
|
|
|
259,662
|
|
Total
|
|
|
4,708,405
|
|
|
|
4,328,247
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,910,411
|
|
|
|
1,834,145
|
|
TOTAL
- NET
|
|
|
2,797,994
|
|
|
|
2,494,102
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
131,264
|
|
|
|
156,420
|
|
Long-term
Risk Management Assets
|
|
|
6,514
|
|
|
|
20,531
|
|
Deferred
Charges and Other
|
|
|
75,529
|
|
|
|
65,610
|
|
TOTAL
|
|
|
213,307
|
|
|
|
242,561
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
3,331,102
|
|
|
$ |
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
September
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
155,869
|
|
|
$ |
188,965
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
136,071
|
|
|
|
140,424
|
|
Affiliated
Companies
|
|
|
65,692
|
|
|
|
68,680
|
|
Short-term
Debt – Nonaffiliated
|
|
|
25,897
|
|
|
|
17,143
|
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
6,655
|
|
|
|
102,312
|
|
Risk
Management Liabilities
|
|
|
38,345
|
|
|
|
109,578
|
|
Customer
Deposits
|
|
|
39,225
|
|
|
|
48,277
|
|
Accrued
Taxes
|
|
|
54,784
|
|
|
|
31,591
|
|
Regulatory
Liability for Over-Recovered Fuel Costs
|
|
|
30,495
|
|
|
|
26,012
|
|
Other
|
|
|
67,680
|
|
|
|
85,086
|
|
TOTAL
|
|
|
620,713
|
|
|
|
818,068
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
818,429
|
|
|
|
576,694
|
|
Long-term
Debt – Affiliated
|
|
|
50,000
|
|
|
|
50,000
|
|
Long-term
Risk Management Liabilities
|
|
|
6,729
|
|
|
|
14,083
|
|
Deferred
Income Taxes
|
|
|
354,175
|
|
|
|
374,548
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
330,070
|
|
|
|
346,774
|
|
Deferred
Credits and Other
|
|
|
214,505
|
|
|
|
183,087
|
|
TOTAL
|
|
|
1,773,908
|
|
|
|
1,545,186
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,394,621
|
|
|
|
2,363,254
|
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
1,879
|
|
|
|
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
|
|
|
300,003
|
|
|
|
245,003
|
|
Retained
Earnings
|
|
|
512,873
|
|
|
|
459,338
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(18,631 |
) |
|
|
(18,799 |
) |
TOTAL
|
|
|
929,905
|
|
|
|
821,202
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
3,331,102
|
|
|
$ |
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 Nine Months Ended September 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
55,349
|
|
|
$ |
95,890
|
|
Adjustments
to Reconcile Net Income to Net Cash Flows from Operating
Activities:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
103,395
|
|
|
|
98,655
|
|
Deferred
Income Taxes
|
|
|
(17,863 |
) |
|
|
(24,642 |
) |
Provision
for Fuel Disallowance
|
|
|
24,074
|
|
|
|
-
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
7,706
|
|
|
|
10,870
|
|
Deferred
Property Taxes
|
|
|
(9,172 |
) |
|
|
(9,438 |
) |
Change
in Other Noncurrent Assets
|
|
|
2,536
|
|
|
|
20,733
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(7,134 |
) |
|
|
(33,256 |
) |
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
47,992
|
|
|
|
(9,872 |
) |
Fuel,
Materials and Supplies
|
|
|
(11,572 |
) |
|
|
(26,739 |
) |
Margin
Deposits
|
|
|
37,380
|
|
|
|
(28,492 |
) |
Accounts
Payable
|
|
|
(21,603 |
) |
|
|
54,264
|
|
Accrued
Taxes, Net
|
|
|
25,556
|
|
|
|
45,514
|
|
Fuel
Over/Under Recovery, Net
|
|
|
(26,891 |
) |
|
|
63,862
|
|
Other
Current Assets
|
|
|
(687 |
) |
|
|
2,635
|
|
Other
Current Liabilities
|
|
|
(28,920 |
) |
|
|
(17,263 |
) |
Net
Cash Flows From Operating Activities
|
|
|
180,146
|
|
|
|
242,721
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(353,107 |
) |
|
|
(179,117 |
) |
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
|
(7,018 |
) |
Other
|
|
|
106
|
|
|
|
(496 |
) |
Net
Cash Flows Used For Investing Activities
|
|
|
(353,001 |
) |
|
|
(186,631 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
55,000
|
|
|
|
-
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
247,496
|
|
|
|
80,593
|
|
Change
in Short-term Debt, Net – Nonaffiliated
|
|
|
8,754
|
|
|
|
14,282
|
|
Change
in Advances from Affiliates, Net
|
|
|
(33,096 |
) |
|
|
(28,210 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(100,460 |
) |
|
|
(88,989 |
) |
Retirement
of Cumulative Preferred Stock
|
|
|
-
|
|
|
|
(2 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(5,433 |
) |
|
|
(3,845 |
) |
Dividends
Paid on Common Stock
|
|
|
-
|
|
|
|
(30,000 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(172 |
) |
|
|
(172 |
) |
Net
Cash Flows From (Used For) Financing Activities
|
|
|
172,089
|
|
|
|
(56,343 |
) |
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(766 |
) |
|
|
(253 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
2,618
|
|
|
|
3,049
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,852
|
|
|
$ |
2,796
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
44,662
|
|
|
$ |
37,372
|
|
Net
Cash Paid for Income Taxes
|
|
|
37,479
|
|
|
|
53,509
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
19,567
|
|
|
|
17,110
|
|
Construction
Expenditures Included in Accounts Payable at September 30,
|
|
|
41,978
|
|
|
|
8,924
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
INDEX
TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to SWEPCo’s condensed consolidated financial statements are
combined with the condensed notes to condensed financial statements for other
registrant subsidiaries. Listed below are the notes that apply to
SWEPCo.
|
Footnote
Reference
|
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements and Extraordinary Item
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments,
Guarantees and Contingencies
|
Note
4
|
Benefit
Plans
|
Note
6
|
Business
Segments
|
Note
7
|
Income
Taxes
|
Note
8
|
Financing
Activities
|
Note
9
|
CONDENSED
NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT
SUBSIDIARIES
The
condensed notes to condensed financial statements that follow
are a
combined presentation for the Registrant Subsidiaries. The
following list indicates the registrants to which the footnotes
apply:
|
|
|
|
1.
|
Significant
Accounting Matters
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
2.
|
New
Accounting Pronouncements and Extraordinary Item
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
3.
|
Rate
Matters
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
4.
|
Commitments,
Guarantees and Contingencies
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
5.
|
Acquisition
|
CSPCo
|
6.
|
Benefit
Plans
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
7.
|
Business
Segments
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
8.
|
Income
Taxes
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
9.
|
Financing
Activities
|
APCo,
CSPCo, I&M, OPCo, PSO, SWEPCo
|
1.
|
SIGNIFICANT
ACCOUNTING MATTERS
|
General
The
accompanying unaudited condensed financial statements and footnotes were
prepared in accordance with 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 annual financial
statements.
In
the
opinion of management, the unaudited interim financial statements reflect
all
normal and recurring accruals and adjustments necessary for a fair presentation
of the results of operations, financial position and cash flows for the
interim
periods for each Registrant Subsidiary. The results of operations for
the nine months ended September 30, 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.
Property,
Plant and Equipment and Equity Investments
Electric
utility property, plant and equipment are stated at original purchase cost.
Property, plant and equipment of nonregulated operations and other investments
are stated at fair market value at acquisition (or as adjusted for any
applicable impairments) plus the original cost of property acquired or
constructed since the acquisition, less disposals. Additions, major
replacements and betterments are added to the plant accounts. Normal
and routine retirements from the plant accounts, net of salvage, are charged
to
accumulated depreciation for both cost-based rate-regulated and nonregulated
operations under the group composite method of depreciation. The
group composite method of depreciation assumes that on average, asset components
are retired at the end of their useful lives and thus there is no gain
or
loss. The equipment in each primary electric plant account is
identified as a separate group. Under the group composite method of
depreciation, continuous interim routine replacements of items such as
boiler
tubes, pumps, motors, etc. result in the original cost, less salvage, being
charged to accumulated depreciation. For the nonregulated generation
assets, a gain or loss would be recorded if the retirement is not considered
an
interim routine replacement. The depreciation rates that are
established for the generating plants take into account the past history
of
interim capital replacements and the amount of salvage
received. These rates and the related lives are subject to periodic
review. Removal costs are charged to regulatory liabilities for
cost-based rate-regulated operations and charged to expense for nonregulated
operations. The costs of labor, materials and overhead incurred to
operate and maintain the plants are included in operating expenses.
Long-lived
assets are required to be tested for impairment when it is determined that
the
carrying value of the assets may no longer be recoverable or when the assets
meet the held for sale criteria under SFAS 144, “Accounting for the Impairment
or Disposal of Long-Lived Assets.” Equity investments are required to
be tested for impairment when it is determined there may be an other than
temporary loss in value.
The
fair
value of an asset or investment is the amount at which that asset or investment
could be bought or sold in a current transaction between willing parties,
as
opposed to a forced or liquidation sale. Quoted market prices in
active markets are the best evidence of fair value and are used as the
basis for
the measurement, if available. In the absence of quoted prices for
identical or similar assets or investments in active markets, fair value
is
estimated using various internal and external valuation methods including
cash
flow analysis and appraisals.
Inventory
Fossil
fuel inventories are carried at average cost for APCo, I&M, and
SWEPCo. OPCo and CSPCo value fossil fuel inventories at the lower of
average cost or market. PSO carries fossil fuel inventories utilizing
a LIFO method. Excess of replacement or current cost over stated LIFO
value for PSO was $9 million and $4 million as of September 30, 2007 and
December 31, 2006, respectively. The materials and supplies inventories
are
carried at average cost.
Revenue
Recognition
Traditional
Electricity Supply and Delivery Activities
Registrant
Subsidiaries recognize revenues from retail and wholesale electricity supply
sales and electricity transmission and distribution delivery
services. Registrant Subsidiaries recognize the revenues in the
financial statements upon delivery of the energy to the customer and include
unbilled as well as billed amounts. In accordance with the applicable
state commission regulatory treatment, PSO and SWEPCo do not record the
fuel
portion of unbilled revenue.
Most
of
the power produced at the generation plants of the AEP East companies is
sold to
PJM, the RTO operating in the east service territory, and the AEP East
companies
purchase power back from the same RTO to supply power to their respective
loads. These power sales and purchases are reported on a net basis as
revenues in the financial statements. Other RTOs in which the
Registrant Subsidiaries operate do not function in the same manner as
PJM. They function as balancing organizations and not as an
exchange.
Physical
energy purchases including those from all RTOs that are identified as
non-trading, but excluding PJM purchases described in the preceding paragraph,
are accounted for on a gross basis in Purchased Electricity for Resale
in the
financial statements.
In
general, Registrant Subsidiaries record expenses upon receipt of purchased
electricity and when expenses are incurred, with the exception of certain
power
purchase contracts that are derivatives and accounted for using MTM accounting
where generation/supply rates are not cost-based regulated, such as in
Ohio and
the ERCOT portion of Texas. In jurisdictions where the
generation/supply business is subject to cost-based regulation, the unrealized
MTM amounts are deferred as regulatory assets (for losses) and regulatory
liabilities (for gains).
Beginning
in July 2004, as a result of the sale of generation assets in AEP’s west zone,
AEP’s west zone is short capacity and must purchase physical power to supply
retail and wholesale customers. For power purchased under derivative
contracts in AEP’s west zone where the AEP West companies are short capacity,
they recognize as revenues the unrealized gains and losses (other than
those
subject to regulatory deferral) that result from measuring these contracts
at
fair value during the period before settlement. If the contract
results in the physical delivery of power from a RTO or any other counterparty,
the Registrant Subsidiaries reverse the previously recorded unrealized
gains and
losses from MTM valuations and record the settled amounts gross as Purchased
Energy for Resale. If the contract does not result in physical
delivery, the Registrant Subsidiaries reverse the previously recorded unrealized
gains and losses from MTM valuations and record the settled amounts as
revenues
in the financial statements on a net basis.
Energy
Marketing and Risk Management Activities
All
of
the Registrant Subsidiaries engage in wholesale electricity, coal and emission
allowances marketing and risk management activities focused on wholesale
markets
where the AEP System owns assets. Registrant Subsidiaries’ activities
include the purchase and sale of energy under forward contracts at fixed
and
variable prices and the buying and selling of financial energy contracts
which
include exchange traded futures and options, and over-the-counter options
and
swaps. The Registrant Subsidiaries engage in certain energy marketing
and risk management transactions with RTOs.
Registrant
Subsidiaries recognize revenues and expenses from wholesale marketing and
risk
management transactions that are not derivatives upon delivery of the
commodity. Registrant Subsidiaries use MTM accounting for wholesale
marketing and risk management transactions that are derivatives unless
the
derivative is designated in a qualifying cash flow or fair value hedge
relationship, or as a normal purchase or sale. The unrealized and
realized gains and losses on wholesale marketing and risk management
transactions that are accounted for using MTM are included in revenues
in the
financial statements on a net basis. In jurisdictions subject to
cost-based regulation, the unrealized MTM amounts are deferred as regulatory
assets (for losses) and regulatory liabilities (for
gains). Unrealized MTM gains and losses are included on the balance
sheets as Risk Management Assets or Liabilities as appropriate.
Certain
wholesale marketing and risk management transactions are designated as
hedges of
future cash flows as a result of forecasted transactions (cash flow hedge)
or a
hedge of a recognized asset, liability or firm commitment (fair value
hedge). The gains or losses on derivatives designated as fair value
hedges are recognized in revenues in the financial statements in the period
of
change together with the offsetting losses or gains on the hedged item
attributable to the risks being hedged. For derivatives designated as
cash flow hedges, the effective portion of the derivative’s gain or loss is
initially reported as a component of Accumulated Other Comprehensive Income
(Loss) and, depending upon the specific nature of the risk being hedged,
subsequently reclassified into revenues or expenses in the financial statements
when the forecasted transaction is realized and affects earnings. The
ineffective portion of the gain or loss is recognized in revenues in the
financial statements immediately, except in those jurisdictions subject
to
cost-based regulation. In those regulated jurisdictions the
Registrant Subsidiaries defer the ineffective portion as regulatory assets
(for
losses) and regulatory liabilities (for gains).
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 September 30, 2007
and December 31, 2006 is shown in the following table:
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
Components
|
|
(in
thousands)
|
|
Cash
Flow Hedges:
|
|
|
|
|
|
|
APCo
|
|
$ |
(3,547 |
) |
|
$ |
(2,547 |
) |
CSPCo
|
|
|
1,113
|
|
|
|
3,398
|
|
I&M
|
|
|
(10,709 |
) |
|
|
(8,962 |
) |
OPCo
|
|
|
3,776
|
|
|
|
7,262
|
|
PSO
|
|
|
(933 |
) |
|
|
(1,070 |
) |
SWEPCo
|
|
|
(6,242 |
) |
|
|
(6,410 |
) |
|
|
|
|
|
|
|
|
|
SFAS
158 Costs:
|
|
|
|
|
|
|
|
|
APCo
|
|
$ |
(40,999 |
) |
|
$ |
(52,244 |
) |
CSPCo
|
|
|
(25,386 |
) |
|
|
(25,386 |
) |
I&M
|
|
|
(6,089 |
) |
|
|
(6,089 |
) |
OPCo
|
|
|
(64,025 |
) |
|
|
(64,025 |
) |
SWEPCo
|
|
|
(12,389 |
) |
|
|
(12,389 |
) |
As
shown
in the following table, during the next twelve months, the Registrant
Subsidiaries expect to reclassify net gains and losses from cash flow hedges
in
AOCI to Net Income 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. Also shown in
the following table is the maximum length of time that the Registrant
Subsidiary’s exposure to variability in future cash flows is hedged with
contracts designated as cash flow hedges.
|
|
September
30, 2007
|
|
|
|
(in
thousands)
|
|
|
(in
months)
|
|
APCo
|
|
$ |
740
|
|
|
|
20
|
|
CSPCo
|
|
|
643
|
|
|
|
20
|
|
I&M
|
|
|
(390 |
) |
|
|
20
|
|
OPCo
|
|
|
1,576
|
|
|
|
20
|
|
PSO
|
|
|
(183 |
) |
|
|
-
|
|
SWEPCo
|
|
|
(829 |
) |
|
|
33
|
|
Related
Party Transactions
Lawrenceburg
Unit Power Agreement (UPA) between CSPCo and
AEGCo
In
March
2007, CSPCo and AEGCo entered into a 10-year UPA for the entire output
from the
Lawrenceburg Plant effective with AEGCo’s purchase of the plant in May
2007. The UPA has an option for an additional 2-year
period. I&M operates the plant under an agreement with
AEGCo.
Under
the
UPA, CSPCo pays AEGCo for the capacity, depreciation, fuel, operation and
maintenance and tax expenses. These payments are due regardless of
whether the plant is operating. The fuel and operation and
maintenance payments are based on actual costs incurred. All expenses
are trued up periodically.
CSPCo
paid AEGCo $41.9 million and $57.8 million for the three and nine months
ended
September 30, 2007, respectively. On its 2007 Condensed Consolidated
Statement of Income, CSPCo recorded these purchases in Other Operation
expense
for the capacity and depreciation portion, and in Purchased Electricity
from AEP
Affiliates for the variable cost portion.
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 September 30, 2007
|
|
|
|
|
|
Third
Party Amounts
|
|
Net
Amount
|
|
|
|
Net
Settlement
|
|
Reclassified
to
|
|
included
in Sales
|
|
|
|
With
AEPEP
|
|
Affiliate
|
|
to
AEP Affiliates
|
|
Company
|
|
(in
thousands)
|
|
PSO
|
|
$
|
61,702
|
|
$
|
(67,759
|
)
|
$
|
6,057
|
|
SWEPCo
|
|
|
77,784
|
|
|
(84,920
|
)
|
|
7,136
|
|
|
|
For
the Nine Months Ended September 30, 2007
|
|
|
|
|
|
Third
Party Amounts
|
|
Net
Amount
|
|
|
|
Net
Settlement
|
|
Reclassified
to
|
|
included
in Sales
|
|
|
|
With
AEPEP
|
|
Affiliate
|
|
to
AEP Affiliates
|
|
Company
|
|
(in
thousands)
|
|
PSO
|
|
$
|
138,145
|
|
$
|
(133,903
|
)
|
$
|
(4,242
|
)
|
SWEPCo
|
|
|
171,338
|
|
|
(166,339
|
)
|
|
(4,999
|
)
|
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 September 30, 2007
|
|
|
|
PSO
|
|
SWEPCo
|
|
Current
|
|
(in
thousands)
|
|
Risk
Management Assets
|
|
$
|
19,116
|
|
$
|
22,546
|
|
Risk
Management Liabilities
|
|
|
(520
|
)
|
|
(614
|
)
|
|
|
|
|
|
|
|
|
Noncurrent
|
|
|
|
|
|
|
|
Long-term
Risk Management Assets
|
|
$
|
2,510
|
|
$
|
2,960
|
|
Long-term
Risk Management Liabilities
|
|
|
-
|
|
|
-
|
|
Texas
Restructuring – SPP
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
|
|
Nine
Months Ended
|
|
|
|
September
30, 2006
|
|
September
30, 2006
|
|
Company
|
|
(in
thousands)
|
|
APCo
|
|
$
|
110
|
|
$
|
708
|
|
I&M
|
|
|
5,509
|
|
|
17,216
|
|
2.
|
NEW
ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY
ITEM
|
NEW
ACCOUNTING PRONOUNCEMENTS
Upon
issuance of exposure drafts or final pronouncements, management thoroughly
reviews the new accounting literature to determine the relevance, if any,
to the
Registrant Subsidiaries’ business. The following represents a summary
of new pronouncements issued or implemented in 2007 and standards issued
but not
implemented that management has determined relate to the Registrant
Subsidiaries’ 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, 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. Management
is evaluating the effect of the adoption of SFAS 157 on the Registrant
Subsidiaries’ results of operations and financial condition. 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. Although management has not completed its analysis,
management expects this cumulative effect adjustment will have an immaterial
impact on the Registrant Subsidiaries’ financial statements. 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. If the Registrant Subsidiaries
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. Although management has not
completed its analysis, management expects the adoption of this standard
to have
an immaterial impact on the financial statements.
EITF
Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based
Payment Awards” (EITF 06-11)
In
June
2007, the FASB ratified the EITF consensus on the treatment of income tax
benefits of dividends on employee share-based compensation. The issue
is how a company should recognize the income tax benefit received on dividends
that are paid to employees holding equity-classified nonvested shares,
equity-classified nonvested share units or equity-classified outstanding
share
options and charged to retained earnings under SFAS 123R, “Share-Based
Payments.” Under EITF 06-11, a realized income tax benefit from
dividends or dividend equivalents that are charged to retained earnings
and are
paid to employees for equity-classified nonvested equity shares, nonvested
equity share units and outstanding equity share options should be recognized
as
an increase to additional paid-in capital.
EITF
06-11 will be applied prospectively to the income tax benefits of dividends
on
equity-classified employee share-based payment awards that are declared
in
fiscal years beginning after September 15, 2007. Management expects
that the adoption of this standard will have an immaterial impact on the
financial statements. The Registrant Subsidiaries will adopt EITF
06-11 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” (FIN 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)
|
|
APCo
|
|
$
|
2,685
|
|
CSPCo
|
|
|
3,022
|
|
I&M
|
|
|
(327
|
)
|
OPCo
|
|
|
5,380
|
|
PSO
|
|
|
386
|
|
SWEPCo
|
|
|
1,642
|
|
FIN
39-1 “Amendment of FASB Interpretation No. 39” (FIN
39-1)
In
April
2007, the FASB issued FIN 39-1. It amends FASB Interpretation No. 39,
“Offsetting of Amounts Related to Certain Contracts” by replacing the
interpretation’s definition of contracts with the definition of derivative
instruments per SFAS 133. It also requires entities that offset fair
values of derivatives with the same party under a netting agreement to
also net
the fair values (or approximate fair values) of related cash
collateral. The entities must disclose whether or not they offset
fair values of derivatives and related cash collateral and amounts recognized
for cash collateral payables and receivables at the end of each reporting
period.
FIN
39-1
is effective for fiscal years beginning after November 15,
2007. Management expects this standard to change the method of
netting certain balance sheet amounts but is unable to quantify the
effect. It requires retrospective application as a change in
accounting principle for all periods presented. The Registrant
Subsidiaries will adopt FIN 39-1 effective January 1, 2008.
Future
Accounting Changes
The
FASB’s standard-setting process is ongoing and until new standards have been
finalized and issued by the FASB, management cannot determine the impact
on the
reporting of 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. Management also expects to see more
FASB projects as a result of its desire to converge International Accounting
Standards with GAAP. The ultimate pronouncements resulting from these
and future projects could have an impact on future results of operations
and
financial position.
EXTRAORDINARY
ITEM
APCo
recorded an extraordinary loss of $118 million ($79 million, net of tax)
during
the second quarter of 2007 for the establishment of regulatory assets and
liabilities related to the Virginia generation operations. In 2000,
APCo discontinued SFAS 71 regulatory accounting for the Virginia jurisdiction
due to the passage of legislation for customer choice and
deregulation. In April 2007, Virginia passed legislation to establish
electric regulation again. See “Virginia Restructuring” in Note
3.
As
discussed in the 2006 Annual Report, 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
Ending
December 31, 2008, the approved three-year RSPs provide CSPCo and OPCo
increases
in their generation rates by 3% and 7%, respectively, effective January
1 each
year and allow possible additional annual generation rate increases of
up to an
average of 4% per year to recover governmentally-mandated costs. In
January 2007, CSPCo and OPCo filed with the PUCO pursuant to the average
4%
generation rate provision of their RSPs to increase their annual generation
rates for 2007 by $24 million and $8 million, respectively, to recover
new
governmentally-mandated costs. CSPCo and OPCo implemented these
proposed increases in May 2007 subject to refund. In October 2007,
the PUCO issued an order in the average 4% proceeding which granted CSPCo
and
OPCo an annual generation rate increase through December 2008 of $19 million
and
$4 million, respectively. In September 2007, CSPCo and OPCo recorded
a provision for refund to adjust revenues consistent with the rate revenues
granted by the PUCO. Management expects that the average 4% rider
will be reduced to implement the required refunds, while OPCo would implement
a
credit to customers’ bills. CSPCo and OPCo intend to seek rehearing
of the PUCO decision.
In
October 2007, CSPCo and OPCo made a new filing with the PUCO pursuant to
the average 4% generation rate provision of their RSPs for an additional
increase in their annual generation rates effective January 2008 of $35
million
and $12 million, respectively, to recover governmentally-mandated costs
and
increased costs related to marginal-loss pricing. CSPCo and OPCo will
implement these proposed increases in January 2008 subject to refund until
the
PUCO issues a final order in the matter. Management is unable to
predict the outcome of this filing and its impact on future results of
operations and cash flows.
In
March
2007, CSPCo filed an application under the average 4% generation rate provision
of their RSP to adjust the Power Acquisition Rider (PAR) related to CSPCo's
acquisition of Monongahela Power Company's certified territory in Ohio.
The PAR
was increased to recover the cost of a new purchase power market contract
to
serve the load for that service territory. The PUCO approved the
requested increase in the PAR, which is expected to increase CSPCo's revenues
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 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. The Office of Consumers’
Counsel, the Ohio Partners for Affordable Energy, the Ohio Energy Group
and the
PUCO staff supported this settlement agreement. In May 2007, the PUCO
adopted the settlement agreement in its entirety.
Customer
Choice Deferrals – Affecting CSPCo and OPCo
CSPCo’s
and OPCo’s restructuring settlement agreement approved by the PUCO in 2000,
allows CSPCo and OPCo to establish 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. Through September 30, 2007, CSPCo and OPCo incurred $53
million and $54 million, respectively, of such costs and established regulatory
assets of $27 million each for the future recovery of such
costs. CSPCo and OPCo also have the right to recover $6 million and
$7 million, respectively, of equity carrying costs in addition to these
regulatory assets. In 2007, CSPCo and OPCo incurred $3 million and $4
million, respectively, of such costs and established regulatory assets
of $2
million each for such costs. 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. However, failure to recover such costs would have an adverse
effect on results of operations and cash flows.
Ohio
IGCC Plant – 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 average 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
a period
of no more than twelve months effective July 1, 2006. Through
September 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC
regulatory assets of $10 million and each collected the entire $12 million
approved by the PUCO. As of September 30, 2007, CSPCo and OPCo have
recorded a liability of $2 million each for the over-recovered portion.
CSPCo
and OPCo expect to incur additional pre-construction costs equal to or
greater
than the $12 million each recovered.
The
PUCO
indicated that if CSPCo and OPCo have not commenced a continuous course
of
construction of the proposed IGCC plant within five years of the June 2006
PUCO
order, all Phase 1 costs collected for pre-construction costs, associated
with
items that may be utilized in projects at other sites, must be refunded
to Ohio
ratepayers with interest. The PUCO deferred ruling on cost recovery
for Phases 2 and 3 until further hearings are held. A date for
further rehearings has not been set.
In
August
2006, the Ohio 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. The Ohio Supreme Court heard oral arguments
for these appeals in October 2007. 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 1 cost-related recoveries.
Pending
the outcome of the Supreme Court litigation, CSPCo and OPCo announced they
may
delay the start of construction of the IGCC plant. Recent estimates of
the cost
to build an IGCC plant have escalated to $2.2 billion. CSPCo and OPCo
may need to request an extension to the 5-year start of construction requirement
if the commencement of construction is delayed beyond 2011.
Distribution
Reliability Plan – Affecting CSPCo and OPCo
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
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. The motion was granted in May
2007. CSPCo and OPCo do not intend to implement the enhanced
reliability plan without recovery of any incremental costs.
Ormet
– Affecting CSPCo and OPCo
Effective
January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial
customer with a 520 MW load in accordance with a settlement agreement between
CSPCo and OPCo, Ormet, its employees’ union and certain other interested parties
that 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 insufficient, an increase in RSP generation rates under the additional
average 4% generation rate provision of the RSPs.
In
December 2006, CSPCo and OPCo submitted a market price of $47.69 per MWH
for
2007, which was approved by the PUCO in June 2007. CSPCo and OPCo
have each amortized $5 million of their Ohio Franchise Tax phase-out tax
regulatory liability to income through September 30, 2007. If the
PUCO approves a lower market price in 2008, it could have an adverse effect
on
future 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.
Texas
Rate Matters
SWEPCo
Fuel Reconciliation – Texas – Affecting SWEPCo
In
June
2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its
Texas
retail operations for the three-year reconciliation period ended December
31,
2005. 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 PUCT staff and intervenor disallowances ranged from
$10 million to $28 million. In June 2007, an ALJ issued a proposal
for decision recommending a $17 million disallowance. Results of
operations for the second quarter of 2007 were adversely affected by $25
million
to reflect the ALJ’s decision that apply to the reconciliation period and
subsequent periods through 2007. In August 2007, the PUCT issued a
final order affirming the ALJ report. In September 2007, SWEPCo filed
a motion for rehearing. In October 2007, the PUCT granted SWEPCo’s
motion for rehearing. The PUCT reversed its prior determination that
SO2 allowance
gains should be credited through the fuel clause. However, the PUCT
ruled SWEPCo was obligated to credit the fuel clause with gains from sales
of
emissions allowances through June 30, 2006. This change affects
allowances sold after June 2006 and its impact will be considered in the
fourth
quarter of 2007. In October 2007, the PUCT issued a revised order
which should allow SWEPCo to reverse $7 million of its earlier provision
in the
fourth quarter of 2007. SWEPCO is considering whether to challenge
other parts of the order.
Stall
Unit – Affecting SWEPCo
See
“Stall Unit” section within Louisiana Rate Matters for disclosure.
Turk
Plant – Affecting SWEPCo
See
“Turk
Plant” section within Arkansas Rate Matters for disclosure.
Virginia
Rate Matters
Virginia
Restructuring – Affecting APCo
In
April
2004, Virginia enacted legislation that amended the Virginia Electric Utility
Restructuring Act extending the transition period to market rates for the
generation and supply of electricity, including the extension of capped
rates,
through December 31, 2010. The legislation provided APCo with
specified cost recovery opportunities during the extended capped rate period,
including two optional bundled general base rate changes and an opportunity
for
timely recovery, through a separate rate mechanism, of certain unrecovered
incremental environmental and reliability costs incurred on and after July
1,
2004. Under the amended restructuring law, APCo continues to have an
active fuel clause recovery mechanism in Virginia and continues to have
the
opportunity to recover incremental E&R costs.
In
April
2007, the Virginia legislature adopted a comprehensive law providing for
the
re-regulation of electric utilities’ generation and supply
rates. These amendments shorten the transition period by two years
(from 2010 to 2008) after which rates for retail generation and supply
will
return to cost-based regulation in lieu of market-based rates. 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 investments, (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 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
with a true-up to actual. The legislation also allows APCo to
continue to defer and recover incremental environmental and reliability
costs
incurred through December 31, 2008. The new re-regulation legislation
should result in significant positive effects on APCo’s future earnings and cash
flows from the mandated enhanced future returns on equity, the reduction
of
regulatory lag from the opportunities to adjust base rates on a biennial
basis
and the new opportunities to request timely recovery of certain new costs
not
included in base rates.
With
the
new re-regulation legislation, APCo’s generation business again met the criteria
for application of regulatory accounting principles under SFAS
71. The extraordinary pretax reduction in APCo’s earnings and
shareholder’s equity from reapplication of SFAS 71 regulatory accounting of $118
million ($79 million, net of tax) was recorded in the second quarter of
2007. This extraordinary net loss relates to the reestablishment of
$139 million in net generation-related customer-provided removal costs
as a
regulatory liability, offset by the restoration of $21 million of deferred
state
income taxes as a regulatory asset. In addition, APCo established a
regulatory asset of $17 million for qualifying SFAS 158 pension costs of
the
generation operations that, for ratemaking purposes, are deferred for future
recovery under the new re-regulation legislation. AOCI and Deferred
Income Taxes increased by $11 million and $6 million, respectively.
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 its active fuel
clause. 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 was
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. In May 2006, the Virginia SCC issued an order placing the
net requested base rate increase of $198 million into effect on October
2, 2006,
subject to refund.
In
May
2007, the Virginia SCC issued a final order approving an overall annual
base
rate increase of $24 million effective as of October 2006 and approving
a return
on equity of 10.0%. As a result of the final order, APCo’s second
quarter pretax earnings decreased by approximately $3 million due to a
decrease
in revenues of $42 million net of a recorded provision for refund and related
interest offset by (a) a $15 million net effect from the deferral of unrecovered
incremental E&R costs incurred from October 1, 2006 through June 30, 2007 to
be collected in a future E&R filing, (b) a $9 million net deferral of ARO
costs to be recovered over 10 years and (c) a $15 million retroactive decrease
in depreciation expense. As a result of the Virginia SCC decision to
limit the recovery of incremental E&R costs through the new base rates, APCo
will continue to defer for future recovery unrecovered incremental E&R costs
incurred through 2008 utilizing the E&R surcharge mechanism. APCo
completed the $127 million refund in August 2007.
Virginia
E&R Costs Recovery Filing – Affecting APCo
In
July
2007, APCo filed a request with the Virginia SCC seeking recovery over
the
twelve months beginning December 1, 2007 of approximately $60 million of
unrecovered incremental E&R costs inclusive of carrying costs thereon
incurred from October 1, 2005 through September 30, 2006. In August
2007, the Virginia SCC issued a scheduling order to begin the proceeding
before
a hearing examiner on November 5, 2007. In October 2007, the Virginia
SCC staff and the Attorney General both filed testimony recommending that
APCo
recover $49 million of its $60 million of requested E&R
costs. The two differences between APCo’s request and the Virginia
SCC staff and the Attorney General’s recommendations relate to the recovery of
carrying costs on the unrecovered incremental E&R costs and the appropriate
return on equity rate. APCo intends to file in 2008 for recovery of
additional incurred incremental E&R costs recorded and deferred after
September 30, 2006.
APCo
is
currently recovering $21 million of incurred E&R costs through the initial
E&R surcharge that will expire on November 30, 2007. Through
September 30, 2007, APCo deferred $70 million in incremental E&R costs to be
recovered in the current and future E&R filings. APCo has not
recognized $15 million of equity carrying charges, which are recognizable
when
collected. The $70 million regulatory asset does not include carrying
costs on the unrecovered incremental E&R costs and is based on a return on
equity rate which approximates the Virginia SCC staff and Attorney General’s
recommendations. As a result, if APCo is awarded only $49 million for
the E&R costs incurred for the twelve months ended September 30, 2006 as
recommended by the Virginia SCC staff and the Attorney General, it will
not have
to reverse any of its regulatory asset deferrals.
Virginia
Fuel Clause Filing – Affecting APCo
In
July
2007, APCo filed an application with the Virginia SCC to seek an annualized
increase, effective September 1, 2007, of $33 million for fuel costs and
a
sharing of the benefits of off-system sales between APCo and its
customers. This filing was made in compliance with the minimum 25%
retention of off-system sales margins provision of the new re-regulation
legislation which is effective with the first fuel clause filing after
July 1,
2007. This sharing requirement in the new law also includes a true-up
to actual off-system sales margins. In addition, APCo requested
authorization to defer for future recovery the difference between off-system
sales margins credited to customers at 100% of the ordered amount through
the
current base rate margin rider and 75% of actual off-system sales margins
as
provided in the new law from July 1, 2007 until the new fuel rate becomes
effective.
In
August
2007, the Virginia SCC issued a scheduling order that implemented APCo’s
proposed termination of its base rate off-system sales margin rider on
an
interim basis, subject to refund, on September 1, 2007. The order
also implemented APCo’s proposed new fuel factor on an interim basis, effective
September 1, 2007, which includes a credit for the sharing of 75% of off-system
sales margins with customers in compliance with the new law. In
October 2007, APCo, the Virginia SCC staff and certain intervenors filed
memorandums addressing legal issues identified by the Virginia SCC regarding
the
appropriateness of the timing of the implementation of the new expanded
fuel
factor and off-system sales margins sharing with customers. Hearings
are scheduled for November 2007. In October 2007, the Virginia SCC
staff submitted testimony stating off-system sales margin sharing for July
and
August 2007 should be denied. In addition, the Virginia SCC staff
asserted that no language exists in the statute requiring implementation
of
off-system sales margin sharing any earlier than 2011. Future results
of operations and cash flows could be adversely affected if the Virginia
SCC
delays the effective date of the new expanded fuel clause beyond APCo’s filed
request.
West
Virginia IGCC Plant – Affecting APCo
In
July
2007, APCo filed a request with the Virginia SCC to recover, over the twelve
months beginning January 1, 2009, a return on projected construction work
in
progress including development, design and planning costs from July 1,
2007
through December 31, 2009 estimated to be $45 million associated with the
proposed 629 MW IGCC plant to be constructed in West Virginia for an estimated
cost of $2.2 billion. APCo is requesting authorization to defer a
return on actual pre-construction costs incurred beginning July 1, 2007
until
such costs are recovered, starting January 1, 2009 in accordance with the
new
re-regulation legislation. The new re-regulation legislation provides
for full recovery of all costs plus return on equity incentives for such
new
capacity once the plant is placed in service. See “West Virginia IGCC
Plant” section within West Virginia Rate Matters.
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
concerning APCo’s and WPCo’s 2007 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 filed for an increase of approximately $91 million including
a $65
million increase in ENEC and a $26 million increase in construction cost
surcharges to become effective July 1, 2007. In June 2007, the WVPSC
issued an order approving, without modification, a joint stipulation and
agreement for settlement reached among the parties. The settlement
agreement provided for an increase in annual non-base revenues of approximately
$77 million effective July 1, 2007. This annual revenue increase
primarily includes $50 million of ENEC and $26 million of construction
cost
surcharges. The ENEC portion of the increase is subject to a true-up,
which should avoid an earnings affect from an under-recovery of ENEC costs
if
they exceed the $50 million.
West
Virginia IGCC Plant – Affecting APCo
In
January 2006, APCo filed a petition with the WVPSC requesting its approval
of a
Certificate of Public Convenience and Necessity (CCN) to construct a 629
MW IGCC
plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
County, WV.
In
June
2007, APCo filed testimony with the WVPSC supporting the requests for a
CCN and
for pre-approval of a surcharge rate mechanism to provide for the timely
recovery of both the ongoing finance costs of the project during the
construction period as well as the capital costs, operating costs and a
return
on equity once the facility is placed into commercial operation. If
APCo receives all necessary approvals, the plant could be completed as
early as
mid-2012 and currently is expected to cost an estimated $2.2
billion. In July 2007, the WVPSC staff and
intervenors filed to delay the procedural schedule by 90 days. APCo
supported the changes to the procedural schedule. The statutory
decision deadline was revised to March 2008. In July 2007, the WVPSC
approved the revised procedural schedule. Through September 30, 2007,
APCo deferred pre-construction IGCC costs totaling $11 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
Indiana
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 (OUCC) that would provide direct benefits to I&M's
customers if new lower book depreciation rates were 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 were to be 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 and parties to
the settlement agreed to 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. In June 2007, the IURC approved the
settlement agreement, but modified the effective date of the new book
depreciation rates to the date I&M filed a general rate
petition. On June 19, 2007, I&M and the OUCC notified the IURC
that the parties would accept the modification to the settlement
agreement. Therefore, I&M filed its rate petition and reduced its
book depreciation rates as agreed upon in the settlement agreement.
The
settlement agreement modification reduced book depreciation rates, which
will
result in an increase of $37 million in pretax earnings for the period
June 19,
2007 to December 31, 2007. The $37 million increase is partially
offset by a $5 million regulatory liability, recorded in June 2007, to
provide
for the agreed-upon fuel credit. I&M’s approved book depreciation
rates are subject to further review in the general rate
case. Management expects new base rates will become effective in
early 2009.
Indiana
Rate Filing – Affecting I&M
In
June
2007, I&M filed a rate notification petition with the IURC regarding its
intent to file for a base rate increase with a proposed test year ended
September 30, 2007. The petition indicated, among other things, the
filing would include a request to implement rate tracker mechanisms for
certain
variable components of the cost of service including PJM RTO costs, reliability
enhancement costs, demand side management/energy efficiency program costs,
off-system sales margins, and net environmental compliance
costs. This filing will also reflect the revenue requirement
reduction associated with an annual reduction in book depreciation expense.
In
August 2007, the IURC approved the September 30, 2007 test year and the
inclusion of the above trackers in the rate filing with a rate case to
be filed
no later than January 31, 2008. Management expects to file the case
in early 2008 with a decision expected in early 2009.
Indiana
Rate Cap – Affecting I&M
Effective
July 1, 2007, I&M’s rate cap ended for both base and fuel rates in
Indiana. As a result, I&M’s fuel factor in Indiana increased with
the July 2007 billing month to recover the projected cost of
fuel. I&M will resume deferring through revenues any
under/over-recovered fuel costs for future recovery/refund. Under the
capped rates, I&M was unable to recover $44 million of fuel costs since 2004
of which $7 million adversely impacted 2007 pretax earnings through June
30,
2007. Future results of operations should no longer be adversely
impacted by fuel costs.
Michigan
Rate Matters
Michigan
Depreciation Study Filing– Affecting
I&M
In
December 2006, I&M filed a depreciation study in Michigan seeking to reduce
its book depreciation rates. In September 2007, the Michigan Public
Service Commission (MPSC) approved a settlement agreement authorizing I&M to
implement new book depreciation rates. Based on the depreciation
study included in the settlement, I&M agreed to decrease pretax annual
depreciation expense, on a Michigan jurisdictional basis, by approximately
$10
million. This settlement reflects 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 retail customers’ electric service
rates. In
addition and as a result of the new MPSC-approved rates, I&M will decrease
pretax annual depreciation expense, on a FERC jurisdictional basis, by
approximately $11 million which will reduce wholesale rates for customers
representing approximately half the load beginning in November 2007 and
reduce
wholesale rates for the remaining customers in June 2008.
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 purchased power costs through its fuel
clause
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
2004,
an Oklahoma ALJ found that the OCC lacks authority to examine whether AEP
deviated from the FERC-approved allocation methodology for off-system sales
margins and held that any such complaints should be addressed at the
FERC. In August 2007, the OCC issued an order adopting the ALJ’s
recommendation that the allocation of system sales/trading margins is a
FERC
jurisdictional issue. The Oklahoma Industrial Energy Customers (OIEC)
filed a motion asking the OCC to reconsider its order on the jurisdictional
issue. The OCC stayed its final order regarding the FERC
jurisdictional issue. In October 2007, the OCC lifted its stay stating
the OCC
does not have jurisdiction regarding the allocation methodology for off-system
sales margins.
The
OIEC
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 the AEP System deviated from the FERC-approved allocation
methodologies, but even if one were asserted, management believes that
its
allocation of off-system sales margins under the FERC-approved SIA agreement
was
consistent with that agreement. In October 2007, the OCC directed OCC
Staff to file a complaint at FERC concerning this matter.
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 PSO
failed
to achieve that he alleges existed during the year. In August 2007,
an ALJ issued a report recommending that PSO’s fuel procurement practices were
prudent and no adjustments were warranted. No parties appealed the
recommendation. In October 2007, the OCC issued a final order
adopting the ALJ’s report.
In
February 2006, the OCC enacted a rule, 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 periodic
reviews. PSO filed its testimony in June 2007 covering the year 2005.
The OCC Staff and intervenors filed testimony in September 2007.
In
May
2007, PSO submitted a filing to the OCC to adjust its fuel/purchase power
rates. In the filing, PSO netted the $42 million of under-recovered
pre-2002 reallocated purchased power costs against their $48 million
over-recovered fuel balance as of April 30, 2007. The $6 million net
over-recovered fuel/purchased power cost deferral balance will be refunded
over
the twelve-month period beginning June 2007. However, in August 2007,
the OIEC filed a motion asking the OCC to order a refund of the $42 million
pre-2002 reallocated purchased power costs netted against the current
over-recovered fuel balance. In October 2007, the OCC denied the
OIEC’s request for refund of the $42 million of under-recovered pre-2002
reallocated purchased power costs.
Management
cannot predict the outcome of the pending fuel and purchased power costs
and
prudence reviews, or planned future reviews, but believes that PSO’s fuel and
purchased power procurement practices and costs are prudent and properly
incurred.
Oklahoma
Rate Filing – Affecting PSO
In
November 2006, PSO filed a request to increase base rates by $50 million
for
Oklahoma jurisdictional customers and set return on equity at 11.75% with
a
proposed effective date in the second quarter of 2007. PSO also
proposed a formula rate plan that, if approved as filed, would 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 proposed formula rate
plan 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 prevent the capitalization of a significant amount of AFUDC
that
would have been recorded during the construction period and recovered in
the
future through depreciation expense.
The
ALJ
issued a report in May 2007 recommending a 10.5% return on equity but did
not
compute an overall revenue requirement. The ALJ’s report did not
recommend adopting a formula rate plan, but did recommend recovery through
a
rider of certain generation and transmission projects’ financing costs during
construction. However, the report also contained an alternative
recommendation that the OCC could delay a decision on the rider and take
up this
issue in PSO’s application seeking regulatory approval of a new coal-fueled
generating unit. PSO implemented interim rates, subject to refund,
for residential customers beginning July 2007.
In
October 2007, the OCC issued a final order providing for a $10 million
annual
increase in base rates with a return on equity of 10%. The final
order also provides for lower depreciation rates, which PSO estimates will
decrease depreciation expense by approximately $10 million on an annual
basis. PSO estimates the annual impact of this final order will
increase PSO’s pretax income by $20 million. The final order also
requires PSO to file a plan with the OCC to promote energy efficiency and
conservation programs within 60 days. PSO implemented the approved
rates in October 2007.
Lawton
and Peaking Generation Settlement Agreement – Affecting
PSO
In
November 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 in June 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 OCC staff, the Attorney General, the Oklahoma Industrial
Energy Consumers and Lawton Cogeneration, L.L.C. supported this settlement
agreement. 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 including permits,
options and engineering studies. PSO paid the $35 million purchase
fee in June 2007 and recorded the purchase fee as a regulatory asset and
will
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, currently expected to be 2008. PSO expects these
units will have a substantially lower plant-in-service cost than the proposed
Lawton Cogeneration Facility. PSO may request approval from the OCC
for recovery of costs exceeding the cost cap if special circumstances occur
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. Under the settlement, 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.
Red
Rock Generating Facility – Affecting PSO
In
July
2006, PSO announced plans to enter into an agreement with Oklahoma Gas
and
Electric (OG&E) to build a 950 MW pulverized coal ultra-supercritical
generating unit at the site of OG&E’s existing Sooner Plant near Red Rock,
in north central Oklahoma. PSO would own 50% of the new unit,
OG&E would own approximately 42% and the Oklahoma Municipal Power Authority
(OMPA) would own approximately 8%. OG&E would manage construction
of the plant. OG&E and PSO requested pre-approval to construct
the Red Rock Generating Facility and implement a recovery rider. In
March 2007, the OCC consolidated PSO’s pre-approval application with OG&E’s
request. The Red Rock Generating Facility was estimated to cost $1.8
billion and was expected to be in service in 2012. The OCC staff and
the ALJ recommended the OCC approve PSO’s and OG&E’s filing. As
of September 2007, PSO incurred approximately $20 million of pre-construction
costs and contract cancellation fees.
In
October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of
additional capacity by the year 2012, but denied PSO’s and OG&E’s
application for construction pre-approval stating PSO and OG&E failed to
fully study other alternatives. Since PSO and OG&E could not
obtain pre-approval to build the Red Rock Generating Facility, PSO and
OG&E
cancelled the third party construction contract and their joint venture
development contract. Management believes the pre-construction costs
capitalized, including any cancellation fees, were prudently incurred,
as
evidenced by the OCC staff and the ALJ’s recommendations that the OCC approve
PSO’s filing, and established a regulatory asset for future
recovery. Management believes such pre-construction costs are
probable of recovery and intends to seek full recovery of such costs in
the near
future. If recovery is denied, future results of operations and cash
flows would be adversely affected. As a result of the OCC’s decision,
PSO will consider various alternative options to meet its capacity needs
in the
future.
2007
Oklahoma Ice Storm – Affecting PSO
In
October 2007, PSO filed with the OCC requesting recovery of $13 million
of
operation and maintenance expenses related to service restoration effort
after a
January 2007 ice storm. PSO proposed to establish a regulatory asset
of $13 million and to amortize this asset coincident with the gains from
the
sale of SO2
allowances made during 2007 and thereafter until such gains provide for
the full
recovery of the regulatory asset. If the OCC adopts the PSO proposal,
it would have a favorable impact on future results of operations and cash
flows.
Louisiana
Rate Matters
Louisiana
Compliance Filing – Affecting SWEPCo
In
October 2002, SWEPCo filed detailed financial information typically utilized
in
a revenue requirement filing, including a jurisdictional cost of service,
with
the LPSC. 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
jurisdictional customers, based on a proposed 10% return on
equity. The recommended reduction range was 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. Constructive settlement negotiations are making meaningful
progress. At this time, management is unable to predict the outcome
of this proceeding. If a rate reduction is ultimately ordered, it
would adversely affect future results of operations, cash flows and possibly
financial condition.
Stall
Unit – Affecting SWEPCo
In
May
2006, SWEPCo announced plans to build a new intermediate load 480 MW natural
gas-fired combustion turbine combined cycle generating unit at its existing
Arsenal Hill Plant location in Shreveport, Louisiana. SWEPCo
submitted the appropriate filings with the PUCT and the Arkansas Public
Service
Commission (APSC) during the third quarter of 2006 and the LPSC during
the first
quarter of 2007 to seek approvals to construct the unit. The Stall
Unit is estimated to cost $375 million, excluding AFUDC, and expected to
be in
service in mid-2010. As of September 2007, SWEPCo incurred and
capitalized approximately $15 million and has contractual commitments of
an
additional $17 million.
In
March
2007, the PUCT approved SWEPCo’s request. In Louisiana, this request
has been separated from the original request, which included the Turk
Plant. Neither the LPSC nor the APSC have set a procedural schedule
for the project. The project is contingent upon obtaining
pre-approval from the APSC, the LPSC, the PUCT and the Louisiana Department
of
Environmental Quality. If SWEPCo is not authorized to build the Stall
Unit, SWEPCo would seek recovery of incurred costs including any cancellation
fees. If SWEPCo cannot recover incurred costs, including any
cancellation fees, it could adversely affect future results of operations,
cash
flows and possibly financial condition.
Turk
Plant – Affecting SWEPCo
See
“Turk
Plant” section within Arkansas Rate Matters for disclosure.
Arkansas
Rate Matters
Turk
Plant – Affecting SWEPCo
In
August
2006, SWEPCo announced plans to build a new base load 600 MW pulverized
coal
ultra-supercritical generating unit in Arkansas named Turk
Plant. SWEPCo submitted filings with the APSC in December 2006 and
the PUCT and LPSC in February 2007 to seek approvals to proceed with the
plant. In September 2007, OMPA signed a joint ownership agreement and
agreed to own approximately 7% of the Turk Plant. SWEPCo continues
discussions with Arkansas Electric Cooperative Corporation and North Texas
Electric Cooperative to become potential partners in the Turk
Plant. SWEPCo anticipates owning approximately 73% of the Turk Plant
and will operate the facility. The Turk Plant is estimated to cost
$1.3 billion in total with SWEPCo’s portion estimated to cost $950 million,
excluding AFUDC. If approved on a timely basis, the plant is expected
to be in-service in mid-2011. As of September 2007, SWEPCo incurred
and capitalized approximately $206 million and has contractual commitments
for
an additional $875 million. If SWEPCo is not authorized to build the
Turk plant, SWEPCo would seek recovery of incurred costs including any
cancellation fees. If SWEPCo cannot recover incurred cots, including
any cancellation fees, it could adversely affect future results of operations,
cash flows and possibly financial condition.
In
August
2007, hearings began before the APSC seeking pre-approval of the plant.
The APSC
staff recommended the application be approved and intervenors requested
the
motion be denied. In October 2007, final briefs and closing arguments
were completed by all parties during which the APSC staff and Attorney
General
supported the plant. A decision by the APSC will occur within 60 days
from October 22, 2007. In September 2007, the PUCT staff recommended
that SWEPCo’s application be denied suggesting the construction of the Turk
Plant would adversely impact the development of competition in the SPP
zone. The PUCT hearings were held in October 2007. The
LPSC held hearings in September 2007 and during this proceeding, the LPSC
staff
expressed support for the project. If SWEPCo is not authorized
to build the Turk plant, it could adversely affect future results of operations,
cash flows and possibly financial condition if SWEPCo cannot recover incurred
costs, including any cancellation fees.
Stall
Unit – Affecting SWEPCo
See
“Stall Unit” section within Louisiana Rate Matters for disclosure.
FERC
Rate Matters
Transmission
Rate Proceedings at the FERC – Affecting APCo, CSPCo, I&M and
OPCo
SECA
Revenue Subject to Refund
Effective
December 1, 2004, AEP and other transmission owners in the region covered
by PJM
and MISO eliminated transaction-based through-and-out transmission service
(T&O) charges in accordance with FERC orders and collected load-based
charges, referred to as RTO SECA, to mitigate the loss of T&O revenues on a
temporary basis through March 31, 2006. 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 they
collected. If a refund is ordered, the AEP East companies would also
receive refunds related to the SECA rates they paid to third
parties. The AEP East companies recognized gross SECA revenues of
$220 million. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recognized gross
SECA revenues are as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
70.2
|
|
CSPCo
|
|
|
38.8
|
|
I&M
|
|
|
41.3
|
|
OPCo
|
|
|
53.3
|
|
Approximately
$10 million of these recorded SECA revenues billed by PJM were not
collected. The AEP East companies filed a motion with the FERC to
force payment of these uncollected SECA billings.
In
August
2006, a FERC ALJ issued an initial decision, finding that the rate design
for
the recovery of SECA charges was flawed and that a large portion of the
“lost
revenues” reflected in the SECA rates 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.
In
2006,
the AEP East companies provided reserves of $37 million in net refunds
for
current and future SECA settlements with all of the AEP East companies’ SECA
customers. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the
reserve are as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
12.0
|
|
CSPCo
|
|
|
6.7
|
|
I&M
|
|
|
7.0
|
|
OPCo
|
|
|
9.1
|
|
The
AEP
East companies reached settlements with certain SECA customers related
to
approximately $69 million of such revenues for a net refund of $3
million. The AEP East companies are in the process of completing two
settlements-in-principle on an additional $36 million of SECA revenues
and
expect to make net refunds of $4 million when those settlements are
approved. Thus, completed and in-process settlements cover $105
million of SECA revenues and will consume about $7 million of the reserves
for
refunds, leaving approximately $115 million of contested SECA revenues
and $30
million of refund reserves. If the ALJ’s initial decision were upheld
in its entirety, it would disallow approximately $90 million of the AEP
East
companies’ remaining $115 million of unsettled gross SECA
revenues. Based on recent settlement experience and the expectation
that most of the $115 million of unsettled SECA revenues will be settled,
management believes that the remaining reserve of $30 million will be adequate
to cover all remaining settlements.
In
September 2006, AEP, together with Exelon Corporation 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 contradicts prior related FERC decisions,
which are presently subject to rehearing. Furthermore, management
believes the ALJ’s findings on key issues are largely without
merit. As directed by the FERC, management is working to settle the
remaining $115 million of unsettled revenues within the remaining reserve
balance. Although management believes it has meritorious arguments
and can settle with the remaining customers within the amount provided,
management cannot predict the ultimate outcome of ongoing settlement talks
and,
if necessary, any future FERC proceedings or court appeals. If the
FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of
the remaining unsettled claims within the amount provided, it will have
an
adverse effect on future results of operations, cash flows and financial
condition.
The
FERC PJM Regional Transmission Rate Proceeding
In
January 2005, certain transmission owners in PJM proposed continuation
of the
zonal rate design in PJM after the June 2005 FERC deadline. With the
elimination of T&O rates and the expiration of SECA rates, zonal rates would
provide the AEP System no revenue for use of its transmission facilities
by
other parties in PJM and the MISO. AEP protested the zonal rate
proposal and 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
the AEP
East companies 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 proposed and supported a
new PJM rate regime generally referred to as a Highway/Byway rate
design.
Hearings
were held in April 2006 and the ALJ issued an initial decision in July
2006. The ALJ found the existing PJM zonal rate design to be unjust
and determined that it should be replaced. The ALJ found the
Highway/Byway proposed rates 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.
In
April
2007, the FERC issued an order reversing the ALJ’s decision. The FERC
ruled that the current PJM rate design is just and reasonable for existing
transmission facilities. However, the FERC 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 bear the full cost of the existing AEP east transmission
zone facilities. Presently AEP is collecting the full cost of those
facilities from its retail customers with the exception of Indiana and
Michigan
customers. As a result of this order, the AEP East companies’
customers will also be charged a share of the cost of future new 500 kV
and
higher voltage transmission facilities built in PJM, most of which are
expected
to be upgrades of the facilities 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 has requested rehearing of this
order. Management cannot estimate at this time what effect, if any,
this order will have on the AEP East companies’ future construction of new east
transmission facilities, results of operations, cash flows and financial
condition. In May 2007, the AEP East companies filed for rehearing
related to this FERC decision.
Since
the
FERC’s decision in 2005 to cease through-and-out rates and replace them
temporarily with SECA rates, which ceased on April 1, 2006, the AEP East
companies increased their retail rates in all states except Indiana, Michigan
and Tennessee to recover lost T&O and SECA revenues. The AEP East
companies presently recover from retail customers approximately 85% of
the lost
T&O/SECA transmission revenues of $128 million a year. Future
results of operations, cash flows and financial condition will continue
to be
adversely affected in Indiana, Michigan and Tennessee until these lost
T&O/SECA transmission revenues are recovered in retail rates.
The
FERC PJM and MISO Regional Transmission Rate Proceeding
In
the
SECA proceedings, the FERC ordered the RTOs and transmission owners in
the
PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal
to
establish a permanent transmission rate design for the Super Region effective
February 1, 2008. All of the transmission owners in PJM and MISO,
with the exception of AEP and one MISO transmission owner, voted to continue
zonal rates in both RTOs. In September 2007, AEP filed a formal
complaint proposing a highway/byway rate design be implemented for the
Super
Region. AEP argues the use of other PJM and MISO facilities by AEP is
not as large as the use of AEP transmission by others in PJM and
MISO. Therefore a regional rate design change is required to
recognize the provision and use of transmission service in the Super Region
since it is not sufficiently uniform between transmission owners and users
to
justify zonal rates. Management is unable to predict the outcome of
this case.
SPP
Transmission Formula Rate Filing – Affecting PSO and
SWEPCo
In
June
2007, AEPSC filed revised tariff sheets on behalf of PSO and SWEPCo for
the AEP
pricing zone of the SPP OATT. The revised tariff sheets seek to
establish an up-to-date revenue requirement for SPP transmission services
over
the facilities owned by PSO and SWEPCo and implement a transmission cost
of
service formula rate.
PSO
and
SWEPCo requested an effective date of September 1, 2007 for the revised
tariff. The primary impact of the filed revised tariff will be an
increase in network transmission service revenues from nonaffiliated municipal
and rural cooperative utilities in the AEP pricing zone of SPP. If
the proposed formula rate and requested return on equity are approved,
the 2008
network transmission service revenues from nonaffiliates will increase
by
approximately $10 million compared to the revenues that would result from
the
presently approved network transmission rate. PSO and SWEPCo take
service under the same rate, and will also incur the increased OATT charges
resulting from the filing, but will receive corresponding revenue to offset
the
increase. In August 2007, the FERC issued an order conditionally
accepting PSO’s and SWEPCo’s proposed formula rate, subject to a compliance
filing, suspended the effective date until February 1, 2008 and established
hearing and settlement judge proceedings. In October 2007, AEPSC submitted
a
compliance filing on behalf of PSO and SWEPCo. Multiple intervenors
have protested or requested re-hearing of the order. Discovery and
settlement discussions have begun.
PJM
Marginal-Loss Pricing – Affecting APCo, CSPCo, I&M and
OPCo
On
June
1, 2007, in response to a 2006 FERC order, PJM revised its methodology
for
considering transmission line losses in generation dispatch and the calculation
of locational marginal prices. Marginal-loss dispatch
recognizes the varying delivery costs of transmitting electricity from
individual generator locations to the places where customers consume the
energy. Prior to the implementation of marginal-loss dispatch, PJM
used average losses in dispatch and in the calculation of locational marginal
prices. Locational marginal prices in PJM now include the real-time
impact of transmission losses from individual sources to loads. Due
to the implementation of marginal-loss pricing, for the period June 1,
2007
through September 30, 2007, AEP experienced an increase in the cost of
delivering energy from the generating plant locations to customer load
zones
partially offset by cost recoveries and increased off-system sales resulting
in
a net loss of approximately $25 million. APCo’s, CSPCo’s, I&M’s
and OPCo’s portions of the loss are as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
6
|
|
CSPCo
|
|
|
5
|
|
I&M
|
|
|
5
|
|
OPCo
|
|
|
5
|
|
AEP
has
initiated discussions with PJM regarding the impact it is experiencing
from the
change in methodology and will pursue through the appropriate stakeholder
processes a modification of such methodology. Management believes
these additional costs should be recoverable through retail and/or cost-based
wholesale rates and is seeking recovery in current and future fuel or base
rate
filings as appropriate in each of its eastern zone states. In the
interim, these costs will have an adverse effect on future results of operations
and cash flows. Management is unable to predict whether full recovery
will ultimately be approved.
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
FIN 45
“Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others.” There is no
collateral held in relation to any guarantees. In the event any
guarantee is drawn, there is no recourse to third parties unless specified
below.
Letters
of Credit
Certain
Registrant Subsidiaries 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 September 30, 2007, the maximum future
payments of the LOCs include $1 million and $4 million for I&M and SWEPCo,
respectively, with maturities ranging from December 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 $65 million. Since SWEPCo uses self-bonding, the
guarantee provides for SWEPCo to commit to use its resources to complete
the
reclamation in the event the work is not completed by Sabine Mining Company
(Sabine), an entity consolidated under FIN 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 September 30, 2007, SWEPCo collected approximately $33
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 of 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 September 30, 2007, the Registrant
Subsidiaries entered into sale agreements including indemnifications with
a
maximum exposure that was not significant for any individual Registrant
Subsidiary. There are no material liabilities recorded for any
indemnifications.
The
AEP
East companies, PSO and SWEPCo are jointly and severally liable for activity
conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo
related
to power purchase and sale activity conducted pursuant to the SIA.
Master
Operating Lease
Certain
Registrant Subsidiaries lease certain equipment under a master operating
lease. Under the lease agreement, the lessor is guaranteed to receive
up to 87% of the unamortized balance of the equipment at the end of the
lease
term. If the fair market value of the leased equipment is below the
unamortized balance at the end of the lease term, the subsidiary has committed
to pay the difference between the fair market value and the unamortized
balance,
with the total guarantee not to exceed 87% of the unamortized
balance. Assuming the fair market value of the equipment is zero at
the end of the lease term, the maximum potential loss for these lease agreements
as of September 30, 2007 was as follows:
|
|
Maximum
|
|
|
|
Potential
|
|
|
|
Loss
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
$ |
9
|
|
CSPCo
|
|
|
4
|
|
I&M
|
|
|
6
|
|
OPCo
|
|
|
8
|
|
PSO
|
|
|
5
|
|
SWEPCo
|
|
|
6
|
|
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 the AEP
System’s generating units over a 20-year period. In April 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.
On
October 9, 2007, management announced that the AEP System had entered into
a
consent decree with the Federal EPA, the DOJ, the states and the special
interest groups. Under the consent decree the AEP System agreed to annual
SO2 and
NOx emission
caps for
sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia
and
West Virginia. In addition to completing the installation of previously
announced environmental retrofit projects at many of the plants, including
the
installation of flue gas desulfurization (FGD or scrubbers) equipment at
KPCo’s
Big Sandy Plant and at OPCo’s Muskingum River Plant by the end of 2015, AEGCo
and I&M agreed to install selective catalytic reduction (SCR) and FGD
emissions control equipment on their jointly owned generating units at
the
Rockport Plant. Unit 1 at the Rockport Plant will be retrofit by the end
of
2017, and Unit 2 will be retrofit by the end of 2019. APCo also
agreed to install selective non-catalytic reduction, a NOx-reduction
technology, by the end of 2009 at the Clinch River Plant.
Since
2004, the AEP System spent nearly $2.6 billion on installation of emissions
control equipment on coal-fueled plants in Kentucky, Ohio, Virginia and
West
Virginia as part of a larger plan to invest more than $5.1 billion by 2010
to
reduce the emissions of the generating fleet. Capital amounts by
Registrant Subsidiary are as follows:
|
|
Incurred
Capital
|
|
|
|
|
|
Amount
Through
|
|
|
Budgeted
Capital
|
|
|
December
31, 2006
|
|
|
2007
- 2010
|
|
|
(in
millions)
|
APCo
|
|
$
|
923
|
|
|
$
|
944
|
CSPCo
|
|
|
194
|
|
|
|
374
|
I&M
|
|
|
98
|
|
|
|
77
|
OPCo
|
|
|
1,253
|
|
|
|
891
|
Management
agreed to operate SCRs year round during 2008 at APCo’s Mountaineer Plant,
OPCo’s Muskingum River Plant and APCo’s and OPCo’s jointly owned Amos Plant, and
agreed to plant-specific SO2 emission
limits for
Clinch River Plant and OPCo’s Kammer Plant.
Under
the
consent decree, the AEP System will pay a $15 million civil penalty and
provide
$36 million for environmental projects coordinated with the federal government
and $24 million to the states for environmental mitigation. The
Registrant Subsidiaries expensed their share of these amounts in third
quarter
of 2007 as follows:
|
|
|
|
|
Environmental
|
|
Total
Expensed in
|
|
|
Penalty
|
|
|
Mitigation
Costs
|
|
September
2007
|
|
|
(in
thousands)
|
APCo
|
|
$
|
4,974
|
|
|
$
|
20,659
|
|
$
|
25,633
|
CSPCo
|
|
|
2,883
|
|
|
|
11,973
|
|
|
14,856
|
I&M
|
|
|
2,770
|
|
|
|
11,503
|
|
|
14,273
|
OPCo
|
|
|
3,355
|
|
|
|
13,935
|
|
|
17,290
|
The
consent decree will resolve all issues related to various parties’ claims
against the Registrant Subsidiaries in the two pending NSR cases. The consent
decree has been filed with the U.S. District Court. The consent decree
is
subject to a 30-day public comment period and final approval by the
Court. A hearing on the motion to approve the consent decree is
scheduled for December 10, 2007.
Management
believes that APCo, CSPCo, I&M and OPCo can recover any capital and
operating costs of additional pollution control equipment that may be
required
as a result of the consent decree through regulated rates or market prices
of
electricity. If they are unable to recover such costs, it would
adversely affect their future results of operations, cash flows and possibly
financial condition.
Cases
are
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. No trial date has yet been established in the Stuart case,
but the units, operated by Dayton Power and Light Company, are equipped
with SCR
controls and the installation of FGD controls will be completed in
2007. The Beckjord and Zimmer case is scheduled for a liability trial
in May 2008. Zimmer is equipped with both FGD and SCR
controls. Beckjord and Zimmer are operated by Duke Energy Ohio,
Inc. 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.
Management
is unable to estimate the loss or range of loss related to any contingent
liability, if any, CSPCo might have for civil penalties under the pending
CAA
proceedings for the jointly-owned plants. 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 CSPCo does not prevail, management believes CSPCo can
recover any capital and operating costs of additional pollution control
equipment that may be required through market prices for
electricity. If any of the AEP subsidiaries are unable to recover
their capital and operating costs or if material penalties are imposed
for
CSPCo’s jointly-owned plants, 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 to commence during the first quarter of 2008.
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. In
June 2007, TCEQ denied that motion.
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 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. The Second Circuit requested supplemental briefs addressing
the impact of the Supreme Court’s decision on this case. Management
believes the actions are without merit and intends to defend against the
claims.
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
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
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 not impact OPCo’s income statement due to the indemnification agreement
with AEP Resources (AEPR), a nonutility subsidiary of AEP, whereby AEPR
held
OPCo harmless from market exposure related to the PPA.
In
May
2007, the United States Court of Appeals for the Second Circuit ruled that
the
lower court was correct in finding that TEM breached the PPA and OPCo did
not
breach the PPA. It also ruled that the lower court applied an
incorrect standard in denying OPCo any damages for TEM’s breach of the 20-year
term of the PPA holding that OPCo is entitled to the benefit of its bargain
and
that the trial court must determine damages. The Court of Appeals
vacated approximately $117 million of the $123 million judgment for damages
against TEM related to replacement products and remanded the issue for
further
proceedings to determine the correct amount of those damages. One
part of the judgment is final, that involves TEM’s liability for damages
applicable to gas peaking and post-actual commercial operation date
products. OPCo expects TEM to pay the amount of those damages,
approximately $8 million, including interest, in the fourth quarter of
2007.
Coal
Transportation Dispute – Affecting PSO
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. In September 2007, the Surface Transportation Board ruled
that the disputed rates were not unreasonable under the standalone cost
rate
test. The joint owners filed a Petition for
Reconsideration. Based upon this ruling, PSO, as operator of the
plant, adjusted the provision recorded in prior periods. PSO deferred
its immaterial share of the provision under its fuel mechanism after mitigation
by certain contractual rights.
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.
FERC
Long-term Contracts – Affecting AEP East Companies and AEP West
Companies
In
2002,
the FERC held a hearing related to a complaint filed by Nevada Power Company
and
Sierra Pacific Power Company (the Nevada utilities). The complaint
sought to break long-term contracts entered during the 2000 and 2001 California
energy price spike which the customers alleged were
“high-priced.” The complaint alleged that AEP subsidiaries sold power
at unjust and unreasonable prices because the market for power was allegedly
dysfunctional at the time such contracts were executed. An ALJ
recommended rejection of the complaint, holding 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. On September 25, 2007, the U.S. Supreme Court decided to
review the Ninth Circuit’s decision. Management is unable to predict
the outcome of these proceedings or their impact on future results of operations
and cash flows. The Registrant Subsidiaries asserted claims against
certain companies that sold power to them, which was resold to the Nevada
utilities, seeking to recover a portion of any amounts the Registrant
Subsidiaries may owe to the Nevada utilities.
Darby
Electric Generating Station – Affecting CSPCo
In
November 2006, CSPCo agreed to purchase Darby Electric Generating Station
(Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light
Company, for $102 million and the assumption of liabilities of $2
million. CSPCo completed the purchase in April 2007. The
Darby plant is located near Mount Sterling, Ohio and is a natural gas,
simple
cycle power plant with a generating capacity of 480 MW.
The
Registrant Subsidiaries 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, the Registrant Subsidiaries participate in
other postretirement benefit plans sponsored by AEP to provide medical
and death
benefits for retired employees.
The
Registrant Subsidiaries adopted SFAS 158 as of December 31, 2006. The
Registrant Subsidiaries recorded a SFAS 71 regulatory asset for qualifying
SFAS
158 costs of regulated operations that for ratemaking purposes are 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 and nine months ended September 30, 2007 and
2006:
|
|
|
|
|
Other
|
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension
Plans
|
|
|
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Three
Months Ended September 30, 2007 and 2006
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
24
|
|
|
$ |
23
|
|
|
$ |
11
|
|
|
$ |
10
|
|
Interest
Cost
|
|
|
59
|
|
|
|
57
|
|
|
|
26
|
|
|
|
26
|
|
Expected
Return on Plan Assets
|
|
|
(85 |
) |
|
|
(82 |
) |
|
|
(26 |
) |
|
|
(24 |
) |
Amortization
of Transition Obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
6
|
|
|
|
7
|
|
Amortization
of Net Actuarial Loss
|
|
|
15
|
|
|
|
20
|
|
|
|
3
|
|
|
|
5
|
|
Net
Periodic Benefit Cost
|
|
$ |
13
|
|
|
$ |
18
|
|
|
$ |
20
|
|
|
$ |
24
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension
Plans
|
|
|
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Nine
Months Ended September 30, 2007 and 2006
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
72
|
|
|
$ |
71
|
|
|
$ |
32
|
|
|
$ |
30
|
|
Interest
Cost
|
|
|
176
|
|
|
|
171
|
|
|
|
78
|
|
|
|
76
|
|
Expected
Return on Plan Assets
|
|
|
(254 |
) |
|
|
(248 |
) |
|
|
(78 |
) |
|
|
(70 |
) |
Amortization
of Transition Obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
20
|
|
|
|
21
|
|
Amortization
of Net Actuarial Loss
|
|
|
44
|
|
|
|
59
|
|
|
|
9
|
|
|
|
15
|
|
Net
Periodic Benefit Cost
|
|
$ |
38
|
|
|
$ |
53
|
|
|
$ |
61
|
|
|
$ |
72
|
|
The
following table provides the net periodic benefit cost (credit) for the
plans by
Registrant Subsidiary for the three and nine months ended September 30,
2007 and
2006:
|
|
|
|
|
Other
Postretirement
|
|
|
|
Pension
Plans
|
|
|
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Three
Months Ended September 30, 2007 and 2006
|
|
(in
thousands)
|
|
APCo
|
|
$ |
841
|
|
|
$ |
1,469
|
|
|
$ |
3,560
|
|
|
$ |
4,487
|
|
CSPCo
|
|
|
(258 |
) |
|
|
205
|
|
|
|
1,491
|
|
|
|
1,807
|
|
I&M
|
|
|
1,900
|
|
|
|
2,331
|
|
|
|
2,530
|
|
|
|
2,949
|
|
OPCo
|
|
|
362
|
|
|
|
823
|
|
|
|
2,802
|
|
|
|
3,395
|
|
PSO
|
|
|
425
|
|
|
|
979
|
|
|
|
1,431
|
|
|
|
1,588
|
|
SWEPCo
|
|
|
747
|
|
|
|
1,222
|
|
|
|
1,420
|
|
|
|
1,578
|
|
|
|
|
|
|
Other
Postretirement
|
|
|
|
Pension
Plans
|
|
|
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Nine
Months Ended September 30, 2007 and 2006
|
|
(in
thousands)
|
|
APCo
|
|
$ |
2,525
|
|
|
$ |
4,406
|
|
|
$ |
10,680
|
|
|
$ |
13,465
|
|
CSPCo
|
|
|
(773 |
) |
|
|
615
|
|
|
|
4,473
|
|
|
|
5,417
|
|
I&M
|
|
|
5,700
|
|
|
|
6,992
|
|
|
|
7,591
|
|
|
|
8,855
|
|
OPCo
|
|
|
1,088
|
|
|
|
2,478
|
|
|
|
8,405
|
|
|
|
10,187
|
|
PSO
|
|
|
1,273
|
|
|
|
2,935
|
|
|
|
4,292
|
|
|
|
4,764
|
|
SWEPCo
|
|
|
2,240
|
|
|
|
3,672
|
|
|
|
4,258
|
|
|
|
4,734
|
|
All
of
AEP’s Registrant Subsidiaries have one reportable segment. The one
reportable segment is an integrated electricity generation, transmission
and
distribution business. All of the Registrant Subsidiaries’ other
activities are insignificant. The Registrant Subsidiaries’ operations
are managed on an integrated basis because of the substantial impact of
cost-based rates and regulatory oversight on the business process, cost
structures and operating results.
The
Registrant Subsidiaries join in the filing of a consolidated federal income
tax
return with their affiliates in the AEP System. The allocation of the
AEP System’s current consolidated federal income tax to the AEP System companies
allocates the benefit of current tax losses to the AEP System companies
giving
rise to such losses in determining their current expense. The tax
benefit of the Parent is allocated to its subsidiaries with taxable
income. With the exception of the loss of the Parent, the method of
allocation approximates a separate return result for each company in the
consolidated group.
Audit
Status
The
Registrant Subsidiaries also file income tax returns in various state and
local
jurisdictions. With few exceptions, the Registrant Subsidiaries are
no longer subject to U.S. federal, state and local income tax examinations
by
tax authorities for years before 2000. The IRS and other taxing
authorities routinely examine the tax returns. Management believes
that the Registrant Subsidiaries have filed tax returns with positions
that may
be challenged by the tax authorities. The Registrant Subsidiaries are
currently under examination in several state and local
jurisdictions. However, management does not believe that the ultimate
resolution of these audits will materially impact results of
operations.
The
AEP
System settled with the IRS on all issues from the audits of consolidated
federal income tax returns for years prior to 1997. The AEP System
effectively settled all outstanding proposed IRS adjustments for years
1997
through 1999 and through June 2000 for the CSW pre-merger tax period and
anticipates payment for the agreed adjustments to occur during
2007. Returns for the years 2000 through 2005 are presently being
audited by the IRS and management anticipates that the audit of the 2000
through
2003 years will be completed by the end of 2007.
FIN
48 Adoption
The
Registrant Subsidiaries 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)
|
|
APCo
|
|
$
|
2,685
|
|
CSPCo
|
|
|
3,022
|
|
I&M
|
|
|
(327
|
)
|
OPCo
|
|
|
5,380
|
|
PSO
|
|
|
386
|
|
SWEPCo
|
|
|
1,642
|
|
At
January 1, 2007, the total amount of unrecognized tax benefits under FIN
48 for
each Registrant Subsidiary was as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
21.7
|
|
CSPCo
|
|
|
25.0
|
|
I&M
|
|
|
18.2
|
|
OPCo
|
|
|
49.8
|
|
PSO
|
|
|
8.9
|
|
SWEPCo
|
|
|
7.1
|
|
Management
believes 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)
|
|
APCo
|
|
$
|
5.5
|
|
CSPCo
|
|
|
9.3
|
|
I&M
|
|
|
6.0
|
|
OPCo
|
|
|
9.0
|
|
PSO
|
|
|
4.4
|
|
SWEPCo
|
|
|
2.8
|
|
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
|
|
OPCo
|
|
|
23.4
|
|
PSO
|
|
|
1.2
|
|
SWEPCo
|
|
|
1.2
|
|
At
January 1, 2007, tax positions for each Registrant Subsidiary, for which
the
ultimate deductibility is highly certain but the timing of such deductibility
is
uncertain, was as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
13.7
|
|
CSPCo
|
|
|
3.9
|
|
I&M
|
|
|
10.3
|
|
OPCo
|
|
|
14.2
|
|
PSO
|
|
|
7.1
|
|
SWEPCo
|
|
|
5.1
|
|
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, the Registrant Subsidiaries recorded interest and
penalty accruals related to income tax positions in tax accrual
accounts. With the adoption of FIN 48, the Registrant Subsidiaries
began recognizing interest accruals related to income tax positions in
interest
expense and penalties in Other Operations. As of January 1, 2007,
each Registrant Subsidiary accrued for the payment of uncertain interest
and
penalties as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
4.6
|
|
CSPCo
|
|
|
1.7
|
|
I&M
|
|
|
2.8
|
|
OPCo
|
|
|
4.3
|
|
PSO
|
|
|
2.7
|
|
SWEPCo
|
|
|
2.0
|
|
Michigan
Tax Restructuring (Affecting I&M)
On
July
12, 2007, the Governor of Michigan signed Michigan Senate Bill 0094 (MBT
Act)
and related companion bills into law providing a comprehensive restructuring
of
Michigan’s principal business tax. The new law is effective January
1, 2008 and replaces the Michigan Single Business Tax that is scheduled
to
expire at the end of 2007. The MBT Act is composed of a new tax which
will be calculated based upon two components: (a) a business income
tax (BIT) imposed at a rate of 4.95% and (b) a modified gross receipts
tax (GRT)
imposed at a rate of 0.80%, which will collectively be referred to as the
BIT/GRT tax calculation. The new law also includes significant
credits for engaging in Michigan-based activity.
On
September 30, 2007, the Governor of Michigan signed House Bill 5198 which
amends
the MBT Act to provide for a new deduction on the BIT and GRT tax returns
equal
to the book-tax basis difference triggered as a result of the enactment
of the
MBT Act. This new state-only temporary difference will be deducted
over a 15 year period on the MBT Act tax returns starting in
2015. The purpose of the new MBT Act state deduction was to provide
companies relief from the recordation of the SFAS 109 Income Tax
Liability. The registrant subsidiaries have evaluated the impact of
the MBT Act and the application of the MBT Act will not materially affect
their
results of operations, cash flows or financial condition.
Long-term
Debt
Long-term
debt and other securities issued, retired and principal payments made during
the
first nine months of 2007 were:
|
|
|
|
Principal
|
|
Interest
|
|
Due
|
Company
|
|
Type
of Debt
|
|
Amount
|
|
Rate
|
|
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
Pollution
Control Bonds
|
|
$
|
75,000
|
|
Variable
|
|
2037
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
250,000
|
|
5.65
|
|
2012
|
APCo
|
|
Senior
Unsecured Notes
|
|
|
250,000
|
|
6.70
|
|
2037
|
CSPCo
|
|
Pollution
Control Bonds
|
|
|
44,500
|
|
Variable
|
|
2040
|
OPCo
|
|
Pollution
Control Bonds
|
|
|
65,000
|
|
4.90
|
|
2037
|
OPCo
|
|
Senior
Unsecured Notes
|
|
|
400,000
|
|
Variable
|
|
2010
|
PSO
|
|
Pollution
Control Bonds
|
|
|
12,660
|
|
4.45
|
|
2020
|
SWEPCo
|
|
Senior
Unsecured Notes
|
|
|
250,000
|
|
5.55
|
|
2017
|
In
May
2007, I&M remarketed its outstanding $50 million Pollution Control Bonds,
resulting in a new interest rate of 4.625%. No proceeds were received
related to this remarketing. The principal amount of the Pollution
Control Bonds is reflected in Long-term Debt on I&M’s Condensed Consolidated
Balance Sheet as of September 30, 2007.
|
|
|
|
Principal
|
|
Interest
|
|
Due
|
Company
|
|
Type
of Debt
|
|
Amount
|
|
Rate
|
|
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Retirements
and Principal Payments:
|
|
|
|
|
|
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
$
|
125,000
|
|
Variable
|
|
2007
|
APCo
|
|
Other
|
|
|
9
|
|
13.718
|
|
2026
|
OPCo
|
|
Notes
Payable – Nonaffiliated
|
|
|
2,927
|
|
6.81
|
|
2008
|
OPCo
|
|
Notes
Payable – Nonaffiliated
|
|
|
6,000
|
|
6.27
|
|
2009
|
PSO
|
|
Pollution
Control Bonds
|
|
|
12,660
|
|
6.00
|
|
2020
|
SWEPCo
|
|
First
Mortgage Bonds
|
|
|
90,000
|
|
7.00
|
|
2007
|
SWEPCo
|
|
Notes
Payable – Nonaffiliated
|
|
|
4,210
|
|
4.47
|
|
2011
|
SWEPCo
|
|
Notes
Payable – Nonaffiliated
|
|
|
4,000
|
|
6.36
|
|
2007
|
SWEPCo
|
|
Notes
Payable – Nonaffiliated
|
|
|
2,250
|
|
Variable
|
|
2008
|
Lines
of Credit – AEP System
The
AEP
System uses a corporate borrowing program to meet the short-term borrowing
needs
of its subsidiaries. The corporate borrowing program includes a
Utility Money Pool, which funds the utility subsidiaries. The AEP
System corporate borrowing program operates in accordance with the terms
and
conditions approved in a regulatory order. The amount of outstanding
loans (borrowings) to/from the Utility Money Pool as of September 30, 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 nine months ended September 30, 2007 are described in the
following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loans/
|
|
|
|
|
|
|
Maximum
|
|
|
Maximum
|
|
|
Average
|
|
|
Average
|
|
|
(Borrowings)
|
|
|
Authorized
|
|
|
|
Borrowings
|
|
|
Loans
to
|
|
|
Borrowings
|
|
|
Loans
to
|
|
|
to/from
Utility
|
|
|
Short-Term
|
|
|
|
from
Utility
|
|
|
Utility
|
|
|
from
Utility
|
|
|
Utility
Money
|
|
|
Money
Pool as of
|
|
|
Borrowing
|
|
|
|
Money
Pool
|
|
|
Money
Pool
|
|
|
Money
Pool
|
|
|
Pool
|
|
|
September
30, 2007
|
|
|
Limit
|
|
Company
|
|
(in
thousands)
|
|
APCo
|
|
$ |
406,262
|
|
|
$ |
96,543
|
|
|
$ |
147,582
|
|
|
$ |
48,303
|
|
|
$ |
38,573
|
|
|
$ |
600,000
|
|
CSPCo
|
|
|
137,696
|
|
|
|
35,270
|
|
|
|
51,927
|
|
|
|
13,551
|
|
|
|
(123,043 |
) |
|
|
350,000
|
|
I&M
|
|
|
100,374
|
|
|
|
52,748
|
|
|
|
50,998
|
|
|
|
34,749
|
|
|
|
(24,234 |
) |
|
|
500,000
|
|
OPCo
|
|
|
447,335
|
|
|
|
1,564
|
|
|
|
161,746
|
|
|
|
1,564
|
|
|
|
(85,341 |
) |
|
|
600,000
|
|
PSO
|
|
|
242,097
|
|
|
|
-
|
|
|
|
133,404
|
|
|
|
-
|
|
|
|
(187,492 |
) |
|
|
300,000
|
|
SWEPCo
|
|
|
240,786
|
|
|
|
48,979
|
|
|
|
79,890
|
|
|
|
29,653
|
|
|
|
(155,869 |
) |
|
|
350,000
|
|
The
maximum and minimum interest rates for funds either borrowed from or loaned
to
the Utility Money Pool were as follows:
|
|
Nine
Months Ended September 30,
|
|
|
2007
|
|
2006
|
Maximum
Interest Rate
|
|
5.94%
|
|
5.41%
|
Minimum
Interest Rate
|
|
5.30%
|
|
3.63%
|
The
average interest rates for funds borrowed from and loaned to the Utility
Money
Pool for the nine months ended September 30, 2007 and 2006 are summarized
for
all Registrant Subsidiaries in the following table:
|
|
Average
Interest Rate for Funds
|
|
|
Average
Interest Rate for Funds
|
|
|
Borrowed
from the Utility Money
|
|
|
Loaned
to the Utility Money
|
|
|
Pool
for
|
|
|
Pool
for
|
|
|
Nine
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
|
2007
|
|
2006
|
|
|
2007
|
|
2006
|
Company
|
|
(in
percentage)
|
APCo
|
|
5.41
|
|
4.62
|
|
|
5.84
|
|
4.98
|
CSPCo
|
|
5.48
|
|
4.73
|
|
|
5.39
|
|
4.63
|
I&M
|
|
5.38
|
|
4.81
|
|
|
5.84
|
|
-
|
OPCo
|
|
5.39
|
|
4.83
|
|
|
5.43
|
|
5.12
|
PSO
|
|
5.47
|
|
5.02
|
|
|
-
|
|
4.36
|
SWEPCo
|
|
5.54
|
|
5.01
|
|
|
5.34
|
|
4.36
|
Short-term
Debt
The
Registrant Subsidiaries’ outstanding short-term debt was as
follows:
|
|
|
|
September
30, 2007
|
|
|
December
31, 2006
|
|
|
|
|
|
Outstanding
|
|
Interest
|
|
|
Outstanding
|
|
Interest
|
|
|
|
Type
of Debt
|
|
Amount
|
|
Rate
|
|
|
Amount
|
|
Rate
|
|
Company
|
|
|
|
(in
millions)
|
|
|
|
|
|
(in
millions)
|
|
|
|
|
OPCo
|
|
Commercial
Paper – JMG
|
|
$
|
2
|
|
|
5.3588
|
%
|
|
$
|
1
|
|
|
5.56
|
%
|
SWEPCo
|
|
Line
of Credit – Sabine
|
|
|
26
|
|
|
6.07
|
%
|
|
|
17
|
|
|
6.38
|
%
|
Dividend
Restrictions
Under
the
Federal Power Act, the Registrant Subsidiaries are restricted from paying
dividends out of stated capital.
Sale
of Receivables – AEP Credit
In
October 2007, AEP renewed AEP Credit’s sale of receivables
agreement. The sale of receivables agreement provides a commitment of
$650 million from a bank conduit to purchase receivables from AEP
Credit. Under the agreement, the commitment will increase to $700
million in August and September to accommodate seasonal demand. This
agreement will expire in October 2008. AEP Credit purchases accounts
receivable through purchase agreements with CSPCo, I&M, OPCo, PSO, SWEPCo
and a portion of APCo. Since APCo does not have regulatory authority
to sell accounts receivable in all of its regulatory jurisdictions, only
a
portion of APCo’s accounts receivable are sold to AEP Credit.
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
Restructuring
As
permitted by the current Ohio restructuring legislation, CSPCo and OPCo
can
implement market-based rates effective January 2009, following the expiration
of
its RSPs on December 31, 2008. In August 2007, legislation was
introduced that would significantly reduce the likelihood of CSPCo’s and OPCo’s
ability to charge market-based rates for generation at the expiration of
their
RSPs. In place of market-based rates, it is more likely that some
form of cost-based rates or hybrid-based rates would be required. The
legislation passed through the Ohio Senate and still must be considered
by the
Ohio House of Representatives. Management continues to analyze the
proposed legislation and is working with various stakeholders to achieve
a
principled, fair and well-considered approach to electric supply
pricing. At this time, management is unable to predict whether CSPCo
and OPCo will transition to market pricing, 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.
SECA
Revenue Subject to Refund
Effective
December 1, 2004, AEP and other transmission owners in the region covered
by PJM
and MISO eliminated transaction-based through-and-out transmission service
(T&O) charges in accordance with FERC orders and collected load-based
charges, referred to as RTO SECA, to mitigate the loss of T&O revenues on a
temporary basis through March 31, 2006. 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 they
collected. If a refund is ordered, the AEP East companies would also
receive refunds related to the SECA rates they paid to third
parties. The AEP East companies recognized gross SECA revenues of
$220 million. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of
recognized gross SECA revenues are as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
70.2
|
|
CSPCo
|
|
|
38.8
|
|
I&M
|
|
|
41.3
|
|
OPCo
|
|
|
53.3
|
|
Approximately
$10 million of these recorded SECA revenues billed by PJM were not
collected. The AEP East companies filed a motion with the FERC to
force payment of these uncollected SECA billings.
In
August
2006, a FERC ALJ issued an initial decision, finding that the rate design
for
the recovery of SECA charges was flawed and that a large portion of the
“lost
revenues” reflected in the SECA rates 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.
In
2006,
the AEP East companies provided reserves of $37 million in net refunds
for
current and future SECA settlements with all of the AEP East companies’ SECA
customers. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the
reserve are as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
12.0
|
|
CSPCo
|
|
|
6.7
|
|
I&M
|
|
|
7.0
|
|
OPCo
|
|
|
9.1
|
|
The
AEP
East companies reached settlements with certain SECA customers related
to
approximately $69 million of such revenues for a net refund of $3
million. The AEP East companies are in the process of completing two
settlements-in-principle on an additional $36 million of SECA revenues
and
expect to make net refunds of $4 million when those settlements are
approved. Thus, completed and in-process settlements cover $105
million of SECA revenues and will consume about $7 million of the reserves
for
refunds, leaving approximately $115 million of contested SECA revenues
and $30
million of refund reserves. If the ALJ’s initial decision were upheld
in its entirety, it would disallow approximately $90 million of the AEP
East
companies’ remaining $115 million of unsettled gross SECA
revenues. Based on recent settlement experience and the expectation
that most of the $115 million of unsettled SECA revenues will be settled,
management believes that the remaining reserve of $30 million will be adequate
to cover all remaining settlements.
In
September 2006, AEP, together with Exelon Corporation 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 contradicts prior related FERC decisions,
which are presently subject to rehearing. Furthermore, management
believes the ALJ’s findings on key issues are largely without
merit. As directed by the FERC, management is working to settle the
remaining $115 million of unsettled revenues within the remaining reserve
balance. Although management believes it has meritorious arguments
and can settle with the remaining customers within the amount provided,
management cannot predict the ultimate outcome of ongoing settlement talks
and,
if necessary, any future FERC proceedings or court appeals. If the
FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of
the remaining unsettled claims within the amount provided, it will have
an
adverse effect on future results of operations, cash flows and financial
condition.
PJM
Marginal-Loss Pricing
On
June
1, 2007, in response to a 2006 FERC order, PJM revised its methodology
for
considering transmission line losses in generation dispatch and the calculation
of locational marginal prices. Marginal-loss dispatch
recognizes the varying delivery costs of transmitting electricity from
individual generator locations to the places where customers consume the
energy. Prior to the implementation of marginal-loss dispatch, PJM
used average losses in dispatch and in the calculation of locational marginal
prices. Locational marginal prices in PJM now include the real-time
impact of transmission losses from individual sources to loads. Due
to the implementation of marginal-loss pricing, for the period June 1,
2007
through September 30, 2007, AEP experienced an increase in the cost of
delivering energy from the generating plant locations to customer load
zones
partially offset by cost recoveries and increased off-system sales resulting
in
a net loss of approximately $25 million. APCo’s, CSPCo’s, I&M’s
and OPCo’s portions of the loss are as follows:
Company
|
|
(in
millions)
|
|
APCo
|
|
$
|
6
|
|
CSPCo
|
|
|
5
|
|
I&M
|
|
|
5
|
|
OPCo
|
|
|
5
|
|
AEP
has
initiated discussions with PJM regarding the impact it is experiencing
from the
change in methodology and will pursue through the appropriate stakeholder
processes a modification of such methodology. Management believes
these additional costs should be recoverable through retail and/or cost-based
wholesale rates and is seeking recovery in current and future fuel or base
rate
filings as appropriate in each of its eastern zone states. In the
interim, these costs will have an adverse effect on future results of operations
and cash flows. Management is unable to predict whether full recovery
will ultimately be approved.
New
Generation
AEP
is in
various stages of construction of the following generation
facilities. Certain plants are pending regulatory
approval:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
Operation
|
Operating
|
|
Project
|
|
|
|
Projected
|
|
|
|
|
|
|
|
|
MW
|
|
Date
|
Company
|
|
Name
|
|
Location
|
|
Cost
(a)
|
|
CWIP
|
|
Fuel
Type
|
|
Plant
Type
|
|
Capacity
|
|
(Projected)
|
|
|
|
|
|
|
(in
millions)
|
|
(in
millions)
|
|
|
|
|
|
|
|
|
SWEPCo
|
|
Mattison
|
|
Arkansas
|
|
$
|
122
|
(b)
|
$
|
52
|
|
Gas
|
|
Simple-cycle
|
|
340
|
(b)
|
2007
|
PSO
|
|
Southwestern
|
|
Oklahoma
|
|
|
59
|
(c)
|
|
45
|
|
Gas
|
|
Simple-cycle
|
|
170
|
|
2008
|
PSO
|
|
Riverside
|
|
Oklahoma
|
|
|
58
|
(c)
|
|
45
|
|
Gas
|
|
Simple-cycle
|
|
170
|
|
2008
|
AEGCo
|
|
Dresden
|
(d)
|
Ohio
|
|
|
265
|
(d)
|
|
88
|
|
Gas
|
|
Combined-cycle
|
|
580
|
|
2009
|
SWEPCo
|
|
Stall
|
|
Louisiana
|
|
|
375
|
|
|
15
|
|
Gas
|
|
Combined-cycle
|
|
480
|
|
2010
|
SWEPCo
|
|
Turk
|
(e)
|
Arkansas
|
|
|
1,300
|
(e)
|
|
206
|
|
Coal
|
|
Ultra-supercritical
|
|
600
|
(e)
|
2011
|
APCo
|
|
Mountaineer
|
|
West
Virginia
|
|
|
2,230
|
|
|
-
|
|
Coal
|
|
IGCC
|
|
629
|
|
2012
|
CSPCo/OPCo
|
|
Great
Bend
|
|
Ohio
|
|
|
2,230
|
(f)
|
|
-
|
|
Coal
|
|
IGCC
|
|
629
|
|
2017
|
(a)
|
Amount
excludes AFUDC.
|
(b)
|
Includes
Unites 3 and 4, 150 MW, declared in commercial operation on July
12, 2007
with construction costs totaling $55 million.
|
(c)
|
In
April 2007, the OCC approved that PSO will recover through a
rider,
subject to a $135 million cost cap, all of the traditional costs
associated with plant in service at the time these units are
placed in
service.
|
(d)
|
In
September 2007, AEGCo purchased the under-construction Dresden
plant from
Dresden Energy LLC, a subsidiary of Dominion Resources, Inc.,
for $85
million, which is included in the “Total Projected Cost” section
above.
|
(e)
|
SWEPCo
plans to own approximately 73%, or 438 MW, totaling about $950
million in
capital investment. See “Turk Plant” section
below.
|
(f)
|
Front-end
engineering and design study is complete. Cost estimates are
not yet filed with the PUCO due to the pending appeals to the
Supreme
Court of Ohio resulting from the PUCO’s April 2006 opinion and
order. See “Ohio IGCC Plant” section
below.
|
AEP
acquired the following generation facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
|
|
|
|
|
|
|
|
|
MW
|
|
Purchase
|
Company
|
|
Plant
Name
|
|
Location
|
|
Cost
|
|
Fuel
Type
|
|
Plant
Type
|
|
Capacity
|
|
Date
|
|
|
|
|
|
|
(in
millions)
|
|
|
|
|
|
|
|
|
CSPCo
|
|
Darby
|
(a)
|
Ohio
|
|
$
|
102
|
|
Gas
|
|
Simple-cycle
|
|
480
|
|
April
2007
|
AEGCo
|
|
Lawrenceburg
|
(b)
|
Indiana
|
|
|
325
|
|
Gas
|
|
Combined-cycle
|
|
1,096
|
|
May
2007
|
(a)
|
CSPCo
purchased Darby Electric Generating Station (Darby) from DPL
Energy, LLC,
a subsidiary of The Dayton Power and Light Company.
|
(b)
|
AEGCo
purchased Lawrenceburg Generating Station (Lawrenceburg), adjacent
to
I&M’s Tanners Creek Plant, from an affiliate of Public Service
Enterprise Group (PSEG). AEGCo sells the power to CSPCo under a
FERC-approved unit power agreement.
|
Ohio
IGCC Plant
In
March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power
plant
using clean-coal technology. The application proposed three phases of
cost recovery associated with the IGCC plant: Phase 1, recovery of
$24 million in pre-construction costs 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 average 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
a period
of no more than twelve months effective July 1, 2006. Through
September 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC
regulatory assets of $10 million and each collected the entire $12 million
approved by the PUCO. As of September 30, 2007, CSPCo and OPCo have
recorded a liability of $2 million each for the over-recovered portion.
CSPCo and OPCo expect to incur additional pre-construction costs equal
to or
greater than the $12 million each recovered.
The
PUCO
indicated that if CSPCo and OPCo have not commenced a continuous course
of
construction of the proposed IGCC plant within five years of the June 2006
PUCO
order, all Phase 1 costs collected for pre-construction costs, associated
with
items that may be utilized in projects at other sites, must be refunded
to Ohio
ratepayers with interest. The PUCO deferred ruling on cost recovery
for Phases 2 and 3 until further hearings are held. A date for
further rehearings has not been set.
In
August
2006, the Ohio 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. The Ohio Supreme Court heard oral arguments
for these appeals in October 2007. Management believes that the
PUCO’s authorization to begin collection of Phase 1 pre-construction costs 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 1 cost-related recoveries.
Pending
the outcome of the Supreme Court litigation, CSPCo and OPCo announced they
may
delay the start of construction of the IGCC plant. Recent estimates of
the cost
to build an IGCC plant have escalated to $2.2 billion. CSPCo and OPCo
may need to request an extension to the 5-year start of construction requirement
if the commencement of construction is delayed beyond 2011.
Red
Rock Generating Facility
In
July
2006, PSO announced plans to enter into an agreement with Oklahoma Gas
and
Electric (OG&E) to build a 950 MW pulverized coal ultra-supercritical
generating unit at the site of OG&E’s existing Sooner Plant near Red Rock,
in north central Oklahoma. PSO would own 50% of the new unit,
OG&E would own approximately 42% and the Oklahoma Municipal Power Authority
(OMPA) would own approximately 8%. OG&E would manage construction
of the plant. OG&E and PSO requested pre-approval to construct
the Red Rock Generating Facility and implement a recovery rider. In
March 2007, the OCC consolidated PSO’s pre-approval application with OG&E’s
request. The Red Rock Generating Facility was estimated to cost $1.8
billion and was expected to be in service in 2012. The OCC staff and
the ALJ recommended the OCC approve PSO’s and OG&E’s filing. As
of September 2007, PSO incurred approximately $20 million of pre-construction
costs and contract cancellation fees.
In
October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of
additional capacity by the year 2012, but denied PSO’s and OG&E’s
application for construction pre-approval stating PSO and OG&E failed to
fully study other alternatives. Since PSO and OG&E could not
obtain pre-approval to build the Red Rock Generating Facility, PSO and
OG&E
cancelled the third party construction contract and their joint venture
development contract. Management believes the pre-construction costs
capitalized, including any cancellation fees, were prudently incurred,
as
evidenced by the OCC staff and the ALJ’s recommendations that the OCC approve
PSO’s filing, and established a regulatory asset for future
recovery. Management believes such pre-construction costs are
probable of recovery and intends to seek full recovery of such costs in
the near
future. If recovery is denied, future results of operations and cash
flows would be adversely affected. As a result of the OCC’s decision,
PSO will be re-considering various alternative options to meet its capacity
needs in the future.
Turk
Plant
In
August
2006, SWEPCo announced plans to build a new base load 600 MW pulverized
coal
ultra-supercritical generating unit in Arkansas named Turk
Plant. SWEPCo submitted filings with the Arkansas Public Service
Commission (APSC) in December 2006 and the PUCT and LPSC in February 2007
to
seek approvals to proceed with the plant. In September 2007, OMPA
signed a joint ownership agreement and agreed to own approximately 7% of
the
Turk Plant. SWEPCo continues discussions with Arkansas Electric
Cooperative Corporation and North Texas Electric Cooperative to become
potential
partners in the Turk Plant. SWEPCo anticipates owning approximately
73% of the Turk Plant and will operate the facility. The Turk Plant
is estimated to cost $1.3 billion in total with SWEPCo’s portion estimated to
cost $950 million, excluding AFUDC. If approved on a timely basis,
the plant is expected to be in-service in mid-2011. As of September
2007, SWEPCo incurred and capitalized approximately $206 million and has
contractual commitments for an additional $875 million. If the Turk
Plant is not approved, cancellation fees may be required to terminate SWEPCo’s
commitment.
In
August
2007, hearings began before the APSC seeking pre-approval of the plant.
The APSC
staff recommended the application be approved and intervenors requested
the
motion be denied. In October 2007, final briefs and closing arguments
were completed by all parties during which the APSC staff and Attorney
General
supported the plant. A decision by the APSC will occur within 60 days
from October 22, 2007. In September 2007, the PUCT staff recommended
that SWEPCo’s application be denied suggesting the construction of the Turk
Plant would adversely impact the development of competition in the SPP
zone. The PUCT hearings were held in October 2007. The
LPSC held hearings in September 2007 and during this proceeding, the LPSC
staff
expressed support for the project. If SWEPCo is not authorized
to build the Turk plant, SWEPCo would seek recovery of incurred costs including
any cancellation fees. If SWEPCo cannot recover incurred costs,
including any cancellation fees, it could adversely affect future results
of
operations, cash flows and possibly financial condition.
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. All of these matters
are discussed in the “Environmental Matters” section of “Combined Management’s
Discussion and Analysis of Registrant Subsidiaries” in the 2006 Annual
Report.
Environmental
Litigation
New
Source Review (NSR) Litigation: In 1999, the Federal EPA, a
number of states and certain special interest groups filed complaints alleging
that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including 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. In April
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
October 2007, management announced that the AEP System had entered into
a
consent decree with the Federal EPA, the DOJ, the states and the special
interest groups. Under the consent decree, the AEP System agreed to annual
SO2 and
NOx emission
caps for
sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia
and
West Virginia. In addition to completing the installation of previously
announced environmental retrofit projects at many of the plants, I&M agreed
to install selective catalytic reduction (SCR) and flue gas desulfurization
(FGD
or scrubbers) emissions control equipment on the Rockport Plant
units.
Since
2004, the AEP System spent nearly $2.6 billion on installation of emissions
control equipment on its coal-fueled plants in Kentucky, Ohio, Virginia
and West
Virginia as part of a larger plan to invest more than $5.1 billion by 2010
to
reduce the emissions of the generating fleet. Capital amounts by
Registrant Subsidiary are as follows:
|
|
Incurred
Capital
|
|
|
|
|
|
Amount
Through
|
|
|
Budgeted
Capital
|
|
|
December
31, 2006
|
|
|
2007
- 2010
|
|
|
(in
millions)
|
APCo
|
|
$
|
923
|
|
|
$
|
944
|
CSPCo
|
|
|
194
|
|
|
|
374
|
I&M
|
|
|
98
|
|
|
|
77
|
OPCo
|
|
|
1,253
|
|
|
|
891
|
Under
the
consent decree, the AEP System will pay a $15 million civil penalty and
provide
$36 million for environmental projects coordinated with the federal government
and $24 million to the states for environmental mitigation. The
Registrant Subsidiaries expensed their share of these amounts in September
2007
as follows:
|
|
|
|
|
Environmental
|
|
Total
Expensed in
|
|
|
Penalty
|
|
|
Mitigation
Costs
|
|
September
2007
|
|
|
(in
thousands)
|
APCo
|
|
$
|
4,974
|
|
|
$
|
20,659
|
|
$
|
25,633
|
CSPCo
|
|
|
2,883
|
|
|
|
11,973
|
|
|
14,856
|
I&M
|
|
|
2,770
|
|
|
|
11,503
|
|
|
14,273
|
OPCo
|
|
|
3,355
|
|
|
|
13,935
|
|
|
17,290
|
See
“Federal EPA Complaint and Notice of Violation” section of Note 4.
Litigation
against CSPCo’s three jointly-owned plants, operated by Duke Energy Ohio, Inc.
and Dayton Power and Light Company, continues. Management is unable
to predict the outcome of these cases. Management believes the
Registrant Subsidiaries can recover any capital and operating costs of
additional pollution control equipment that may be required through regulated
rates or 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 and cash
flows.
Clean
Water Act Regulations
In
2004,
the Federal EPA issued a final rule requiring all large existing power
plants
with once-through cooling water systems to meet certain standards to reduce
mortality of aquatic organisms pinned against the plant’s cooling water intake
screen or entrained in the cooling water. The standards vary based on
the water bodies from which the plants draw their cooling
water. Management expected additional capital and operating expenses,
which the Federal EPA estimated could be $193 million for AEP System
plants. The Registrant Subsidiaries undertook site-specific studies
and have been evaluating site-specific compliance or mitigation measures
that
could significantly change these cost estimates. The following table
shows the investment amount per Registrant Subsidiary.
|
|
Estimated
|
|
|
Compliance
|
|
|
Investments
|
Company
|
|
(in
millions)
|
APCo
|
|
$
|
21
|
CSPCo
|
|
|
19
|
I&M
|
|
|
118
|
OPCo
|
|
|
31
|
The
rule
was challenged in the courts by states, advocacy organizations and
industry. In January 2007, the Second Circuit Court of Appeals issued
a decision remanding significant portions of the rule to the Federal
EPA. In July 2007, the Federal EPA suspended the 2004 rule, except
for the requirement that permitting agencies develop best professional
judgment
(BPJ) controls for existing facility cooling water intake structures that
reflect the best technology available for minimizing adverse
environmental impact. The result is that the BPJ control standard for
cooling water intake structures in effect prior to the 2004 rule is the
applicable standard for permitting agencies pending finalization of revised
rules by the Federal EPA. Management cannot predict further action of
the Federal EPA or what effect it may have on similar requirements adopted
by
the states. Management may seek further review or relief from the
schedules included in the permits.
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” 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. The impact of this
interpretation was an unfavorable (favorable) adjustment to retained earnings
as
follows:
Company
|
|
(in
thousands)
|
|
APCo
|
|
$
|
2,685
|
|
CSPCo
|
|
|
3,022
|
|
I&M
|
|
|
(327
|
)
|
OPCo
|
|
|
5,380
|
|
PSO
|
|
|
386
|
|
SWEPCo
|
|
|
1,642
|
|
During
the third quarter of 2007, management, including the principal executive
officer
and principal financial officer of each of AEP, APCo, CSPCo, I&M, OPCo, PSO
and SWEPCo (collectively, the Registrants), evaluated the Registrants’
disclosure controls and procedures. Disclosure controls and
procedures are defined as controls and other procedures of the Registrants
that
are designed to ensure that information required to be disclosed by the
Registrants in the reports that they file or submit under the Exchange
Act are
recorded, processed, summarized and reported within the time periods specified
in the SEC’s rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure
that
information required to be disclosed by the Registrants in the reports
that they
file or submit under the Exchange Act is accumulated and communicated to
the
Registrants’ management, including the principal executive and principal
financial officers, or persons performing similar functions, as appropriate
to
allow timely decisions regarding required disclosure.
As
of
September 30, 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.
There
was
no change in the Registrants’ internal control over financial reporting (as such
term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act)
during
the third quarter of 2007 that materially affected, or is reasonably likely
to
materially affect, the Registrants’ internal control over financial
reporting.
Item
1. Legal Proceedings
For
a
discussion of material legal proceedings, see Note 4, Commitments,
Guarantees and Contingencies, incorporated herein by
reference.
Item
1A. Risk Factors
Our
Annual Report on Form 10-K for the year ended December 31, 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 plant construction costs may not be approved
for
SWEPCo. (Applies to AEP and SWEPCo.)
In
August
2006, SWEPCo announced plans to build a new base load 600 MW pulverized
coal
ultra-supercritical generating unit in Arkansas named Turk
Plant. SWEPCo submitted filings with the APSC in December 2006 and
the PUCT and LPSC in February 2007 to seek approvals to proceed with the
plant. In September 2007, OMPA signed a joint ownership agreement and
agreed to own approximately 7% of the Turk Plant. SWEPCo continues
discussions with Arkansas Electric Cooperative Corporation and North Texas
Electric Cooperative to become potential partners in the Turk
Plant. SWEPCo anticipates owning approximately 73% of the Turk Plant
and will operate the facility. The Turk Plant is estimated to cost
$1.3 billion in total with SWEPCo’s portion estimated to cost $950 million,
excluding AFUDC. If approved on a timely basis, the plant is expected
to be in-service in mid-2011. As of September 2007, SWEPCo incurred
and capitalized approximately $206 million and has contractual commitments
for
an additional $875 million. If the Turk Plant is not approved,
cancellation fees may be required to terminate SWEPCo’s commitment.
In
August
2007, hearings began before the APSC seeking pre-approval of the plant.
The APSC
staff recommended the application be approved and intervenors requested
the
motion be denied. In October 2007, final briefs and closing arguments
were completed by all parties during which the APSC staff and Attorney
General
supported the plant. A decision by the APSC will occur within 60 days
from October 22, 2007. In September 2007, the PUCT staff recommended
that SWEPCo’s application be denied suggesting the construction of the Turk
Plant would adversely impact the development of competition in the SPP
zone. The PUCT hearings were held in October 2007. The
LPSC held hearings in September 2007 and during this proceeding, the LPSC
staff
expressed support for the project. If SWEPCo is not authorized
to build the Turk plant, SWEPCo would seek recovery of incurred costs including
any cancellation fees. If SWEPCo cannot recover incurred costs,
including any cancellation fees, it could adversely affect future results
of
operations, cash flows and possibly financial condition.
Plant
pre-construction costs may not be recovered for PSO. (Applies to
AEP and PSO.)
In
July
2006, PSO announced plans to enter into an agreement with Oklahoma Gas
and
Electric (OG&E) to build a 950 MW pulverized coal ultra-supercritical
generating unit at the site of OG&E’s existing Sooner Plant near Red Rock,
in north central Oklahoma. In October 2007, the OCC issued a final
order denying PSO’s application for construction pre-approval stating PSO failed
to fully study other alternatives. As of September 2007, PSO deferred
approximately $20 million of pre-construction costs. If recovery of
pre-construction costs is denied, future results of operations and cash
flows
would be adversely affected.
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, APCo, CSPCo, I&M and
OPCo.)
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 $10
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, it would disallow $90 million of the AEP East companies’ remaining $115
million of unsettled gross SECA revenues. We have recorded provisions
in the aggregate amount of $37 million related to the potential refund
of SECA
rates. After completed and in-process settlements of SECA revenues that
will
consume about $7 million of the reserves for refunds, the AEP East companies
will have a remaining reserve balance of $30 million to settle the remaining
unsettled gross SECA revenues.
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.
The
increase in amount PJM charges for transmission line loss may not be
recoverable. (Applies to AEP, APCo, CSPCo, I&M
and OPCo.)
On
June
1, 2007, in response to a 2006 FERC order, PJM revised its methodology
for
considering transmission line losses in generation dispatch and the calculation
of locational marginal prices. Marginal-loss dispatch
recognizes the varying delivery costs of transmitting electricity from
individual generator locations to the places where customers consume the
energy. Prior to the implementation of marginal-loss dispatch, PJM
used average losses in dispatch and in the calculation of locational marginal
prices. Locational marginal prices in PJM now include the real-time
impact of transmission losses from individual sources to loads. Due
to the implementation of marginal-loss pricing, for the period June 1,
2007
through September 30, 2007, AEP experienced an increase in the cost of
delivering energy from the generating plant locations to customer load
zones
partially offset by cost recoveries and increased off-system sales resulting
in
a net loss of approximately $25 million. AEP has initiated
discussions with PJM regarding the impact it is experiencing from the change
in
methodology and will pursue through the appropriate stakeholder processes
a
modification of such methodology. Management believes these
additional costs should be recoverable through retail and/or cost-based
wholesale rates and is seeking recovery in current and future fuel or base
rate filings as appropriate in each of its eastern zone states. In
the interim, these costs will have an adverse effect on future results
of
operations and cash flows. Management is unable to predict whether
full recovery will ultimately be approved.
Our
nonstatutory surcharges in Kentucky may be invalidated. (Applies to
AEP.)
In
August
2007, the Franklin Circuit Court concluded the KPSC did not have the authority
to order a surcharge for a gas company subsidiary of Duke Energy absent
a full
cost of service rate proceeding due to the lack of statutory
authority. The ruling results from the AG’s appeal of the KPSC’s
approval of a natural gas distribution surcharge for replacement of gas
mains. The AG notified the KPSC that the Franklin County Circuit
Court judge’s order in the Duke Energy case can be interpreted to include
existing surcharges, rates or fees established outside of the context of
a
general rate case proceeding and not specifically authorized by statute,
including fuel clauses.
Although
this order is not directly applicable to KPCo, it is possible that the
AG or
another intervenor could appeal an existing surcharge KPCo is collecting
to the
Franklin County Circuit Court. KPCo’s fuel clause, annual Rockport
Plant capacity surcharge, merger surcredit and credit system sales rider
are not
specifically authorized by statute. These surcharges are currently producing
net
annual revenues of approximately $10 million. The KPSC has asked
interested parties to brief the issue in KPCo’s outstanding fuel cost
proceeding. The AG’s filed brief took the position that the KPCo fuel
clause should be invalidated because the KPSC lacked the authority by statute
to
implement a fuel clause for KPCo without a full rate case review. In
August 2007, the KPSC issued an order stating despite the Franklin County
Circuit Court decision, the KPSC has the authority to provide for surcharges
and
surcredits at least until a Court of Appeals ruling. In August 2007,
the AG agreed to stipulate to a stay order over the Franklin County Circuit
Court’s decision pending the appeal decision. KPCo’s exposure is
indeterminable at this time. If the appeal is unfavorable, future
results of operations and cash flows could be adversely affected.
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 August 2007, the judge issued a decision
granting BOA summary judgment without awarding any damages and dismissing
our
claims. The judge in the case held another hearing in September 2007
and said that he plans a further hearing on the damages issue. We
asked the judge to certify an appeal of the legal issues decided by his
summary
judgment rulings prior to any ruling on damages. At this time we are
unable to predict how the Judge will rule on the pending request. If
the judge issues a judgment directing us to pay an amount in excess of
the gain
on the sale of HPL and if we are unsuccessful in having the judgment reversed
or
modified, the judgment could have a material adverse effect on results
of
operations, cash flows, and possibly financial condition.
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
October 2007, CSPCo and OPCo made a filing with the PUCO under the average
4%
generation rate provision of their RSPs for an additional increase in
their annual generation rates effective January 2008 of $35 million and
$12
million, respectively, to recover governmentally-mandated costs and increased
costs related to marginal-loss pricing. CSPCo and OPCo will implement
these proposed increases in January 2008 and are subject to refund until
the
PUCO issues a final order in the matter. Management is unable to
predict the outcome of this filing and its impact on future results of
operations and cash flows.
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. In
August
2007, legislation was introduced that would significantly reduce the likelihood
of CSPCo’s and OPCo’s ability to charge market-based rates for generation at the
expiration of their RSPs. In place of market-based rates, it is more
likely that some form of cost-based rates or hybrid-based rates would be
required. The legislation passed through the Ohio Senate and still
must be considered by the Ohio House of Representatives. At this
time, management is unable to predict whether CSPCo and OPCo will transition
to
market pricing, 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.
There
is uncertainty as to our recovery of stranded costs resulting from industry
restructuring in Texas. (Applies to
AEP.)
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.)
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.)
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.)
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. In October 2007, we announced that we had entered into a
consent decree with the Federal EPA, the DOJ, the states and the special
interest groups. The consent decree has been filed with the U.S.
District Court. The consent decree is subject to a 30-day public comment
period
and final approval by the Court. A hearing on the motion to approve
the consent decree is scheduled for December 10, 2007. Cases are
still pending that could affect CSPCo’s share of jointly-owned units at
Beckjord, Zimmer, and Stuart stations. 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 September 30, 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
|
|
07/01/07
– 07/31/07
|
|
|
93
|
(a)
|
$
|
81.25
|
|
|
|
-
|
|
$
|
-
|
|
08/01/07
– 08/31/07
|
|
|
20
|
(b)
|
|
75
|
|
|
|
-
|
|
|
-
|
|
09/01/07
– 09/30/07
|
|
|
1
|
(c)
|
|
78
|
|
|
|
-
|
|
|
-
|
|
(a)
|
APCo
repurchased 93 shares of its 4.5% cumulative preferred stock,
in a
privately-negotiated transaction outside of an announced
program.
|
(b)
|
APCo
repurchased 20 shares of its 4.5% cumulative preferred stock,
in
privately-negotiated transactions outside of an announced
program.
|
(c)
|
APCo
repurchased 1 share of its 4.5% cumulative preferred stock, in
privately-negotiated transactions outside of an announced
program.
|
Item
4. Submission of Matters to a Vote of Security
Holders
NONE
Item
5. Other Information
NONE
Item
6. Exhibits
AEP,
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
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.
APCo,
CSPCo, I&M, OPCo, PSO and SWEPCo
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,
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
32(a)
–
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter
63
of Title 18 of the United States Code.
32(b)
–
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter
63
of Title 18 of the United States Code.
Pursuant
to the requirements of the Securities Exchange Act of 1934, each registrant
has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized. The signature for each undersigned company shall be
deemed to relate only to matters having reference to such company and any
subsidiaries thereof.
AMERICAN
ELECTRIC POWER COMPANY, INC.
By: /s/Joseph
M. Buonaiuto
Joseph
M.
Buonaiuto
Controller
and Chief Accounting Officer
APPALACHIAN
POWER COMPANY
COLUMBUS
SOUTHERN POWER COMPANY
INDIANA
MICHIGAN POWER COMPANY
OHIO
POWER COMPANY
PUBLIC
SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN
ELECTRIC POWER COMPANY
By: /s/Joseph
M. Buonaiuto
Joseph
M.
Buonaiuto
Controller
and Chief Accounting Officer
Date: November
2, 2007