q207aep10q.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE
SECURITIES EXCHANGE ACT OF 1934
For
The
Quarterly Period Ended June 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
July
31, 2007
|
|
|
|
|
American
Electric Power Company, Inc.
|
|
|
399,203,993
|
|
|
|
($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
June
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
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.
|
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.
|
AEP
West companies
|
|
PSO,
SWEPCo, TCC and TNC.
|
AFUDC
|
|
Allowance
for Funds Used During Construction.
|
ALJ
|
|
Administrative
Law Judge.
|
AOCI
|
|
Accumulated
Other Comprehensive Income (Loss).
|
APCo
|
|
Appalachian
Power Company, an AEP electric utility subsidiary.
|
ARO
|
|
Asset
Retirement Obligations.
|
CAA
|
|
Clean
Air Act.
|
CO2
|
|
Carbon
Dioxide.
|
Cook
Plant
|
|
Donald
C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by
I&M.
|
CSPCo
|
|
Columbus
Southern Power Company, an AEP electric utility
subsidiary.
|
CSW
|
|
Central
and South West Corporation, a subsidiary of AEP (Effective January
21,
2003, the legal name of Central and South West Corporation was changed
to
AEP Utilities, Inc.).
|
CTC
|
|
Competition
Transition Charge.
|
DETM
|
|
Duke
Energy Trading and Marketing L.L.C., a risk management
counterparty.
|
E&R
|
|
Environmental
compliance and transmission and distribution system
reliability.
|
ECAR
|
|
East
Central Area Reliability Council.
|
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.
|
IPP
|
|
Independent
Power Producer.
|
IRS
|
|
Internal
Revenue Service.
|
IURC
|
|
Indiana
Utility Regulatory Commission.
|
I&M
|
|
Indiana
Michigan Power Company, an AEP electric utility
subsidiary.
|
JMG
|
|
JMG
Funding LP.
|
KGPCo
|
|
Kingsport
Power Company, an AEP electric distribution subsidiary.
|
KPCo
|
|
Kentucky
Power Company, an AEP electric utility subsidiary.
|
KPSC
|
|
Kentucky
Public Service Commission.
|
kV
|
|
Kilovolt.
|
KWH
|
|
Kilowatthour.
|
LPSC
|
|
Louisiana
Public Service Commission.
|
MTM
|
|
Mark-to-Market.
|
MW
|
|
Megawatt.
|
MWH
|
|
Megawatthour.
|
NOx
|
|
Nitrogen
oxide.
|
Nonutility
Money Pool
|
|
AEP
System’s Nonutility Money Pool.
|
NRC
|
|
Nuclear
Regulatory Commission.
|
NSR
|
|
New
Source Review.
|
NYMEX
|
|
New
York Mercantile Exchange.
|
OATT
|
|
Open
Access Transmission Tariff.
|
OCC
|
|
Corporation
Commission of the State of Oklahoma.
|
OPCo
|
|
Ohio
Power Company, an AEP electric utility subsidiary.
|
OTC
|
|
Over
the counter.
|
OVEC
|
|
Ohio
Valley Electric Corporation, which is 43.47% owned by
AEP.
|
PJM
|
|
Pennsylvania
– New Jersey – Maryland regional transmission
organization.
|
PSO
|
|
Public
Service Company of Oklahoma, an AEP electric utility
subsidiary.
|
PUCO
|
|
Public
Utilities Commission of Ohio.
|
PUCT
|
|
Public
Utility Commission of Texas.
|
Registrant
Subsidiaries
|
|
AEP
subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO,
SWEPCo.
|
REP
|
|
Texas
Retail Electric Provider.
|
Risk
Management Contracts
|
|
Trading
and nontrading derivatives, including those derivatives designated
as cash
flow and fair value hedges.
|
Rockport
Plant
|
|
A
generating plant, consisting of two 1,300 MW coal-fired generating
units
near Rockport, Indiana owned by AEGCo and I&M.
|
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.
|
Sweeny
|
|
Sweeny
Cogeneration Limited Partnership, owner and operator of a four unit,
480
MW gas-fired generation facility, owned 50% by AEP.
|
SWEPCo
|
|
Southwestern
Electric Power Company, an AEP electric utility
subsidiary.
|
TCC
|
|
AEP
Texas Central Company, an AEP electric utility
subsidiary.
|
TEM
|
|
SUEZ
Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing,
Inc.).
|
Texas
Restructuring Legislation
|
|
Legislation
enacted in 1999 to restructure the electric utility industry in
Texas.
|
TNC
|
|
AEP
Texas North Company, an AEP electric utility
subsidiary.
|
True-up
Proceeding
|
|
A
filing made under the Texas Restructuring Legislation to finalize
the
amount of stranded costs and other true-up items and the recovery
of such
amounts.
|
Utility
Money Pool
|
|
AEP
System’s Utility Money Pool.
|
VaR
|
|
Value
at Risk, a method to quantify risk exposure.
|
Virginia
SCC
|
|
Virginia
State Corporation Commission.
|
WPCo
|
|
Wheeling
Power Company, an AEP electric distribution subsidiary.
|
WVPSC
|
|
Public
Service Commission of West
Virginia.
|
FORWARD-LOOKING
INFORMATION
This
report made by AEP and its Registrant Subsidiaries contains forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act
of
1934. Although AEP and each of its Registrant Subsidiaries believe
that their expectations are based on reasonable assumptions, any such statements
may be influenced by factors that could cause actual outcomes and results to
be
materially different from those projected. Among the factors that
could cause actual results to differ materially from those in the
forward-looking statements are:
·
|
Electric
load and customer growth.
|
·
|
Weather
conditions, including storms.
|
·
|
Available
sources and costs of, and transportation for, fuels and the
creditworthiness of fuel suppliers and transporters.
|
·
|
Availability
of generating capacity and the performance of our generating
plants.
|
·
|
Our
ability to recover regulatory assets and stranded costs in connection
with
deregulation.
|
·
|
Our
ability to recover increases in fuel and other energy costs through
regulated or competitive electric rates.
|
·
|
Our
ability to build or acquire generating capacity when needed at acceptable
prices and terms and to recover those costs through applicable rate
cases
or competitive rates.
|
·
|
New
legislation, litigation and government regulation including requirements
for reduced emissions of sulfur, nitrogen, mercury, carbon, soot
or
particulate matter and other substances.
|
·
|
Timing
and resolution of pending and future rate cases, negotiations and
other
regulatory decisions (including rate or other recovery for new
investments, transmission service and environmental
compliance).
|
·
|
Resolution
of litigation (including pending Clean Air Act enforcement actions
and
disputes arising from the bankruptcy of Enron Corp. and related
matters).
|
·
|
Our
ability to constrain operation and maintenance costs.
|
·
|
The
economic climate and growth in our service territory and changes
in market
demand and demographic patterns.
|
·
|
Inflationary
and interest rate trends.
|
·
|
Our
ability to develop and execute a strategy based on a view regarding
prices
of electricity, natural gas and other energy-related
commodities.
|
·
|
Changes
in the creditworthiness of the counterparties with whom we have
contractual arrangements, including participants in the energy trading
market.
|
·
|
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 regional transmission
organizations.
|
·
|
Accounting
pronouncements periodically issued by accounting standard-setting
bodies.
|
·
|
The
performance of our pension and other postretirement benefit
plans.
|
·
|
Prices
for power that we generate and sell at wholesale.
|
·
|
Changes
in technology, particularly with respect to new, developing or alternative
sources of generation.
|
·
|
Other
risks and unforeseen events, including wars, the effects of terrorism
(including increased security costs), embargoes and other catastrophic
events.
|
The
registrants expressly disclaim any obligation to update any
forward-looking information.
|
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS
EXECUTIVE
OVERVIEW
Regulatory
Activity
The
status of base rate filings ongoing or finalized this quarter with implemented
rates are:
Operating
Company
|
|
Jurisdiction
|
|
Revised
Annual Rate Increase Request
|
|
Implemented
Annual Rate Increase
|
|
Effective
Date of Rate Increase
|
|
|
|
|
|
(in
millions)
|
|
|
|
APCo
|
|
Virginia
|
|
$
|
198
|
(a)
|
$
|
24
|
(a)
|
October
2006
|
|
OPCo
|
|
Ohio
|
|
|
8
|
|
|
8
|
(b)
|
May
2007
|
|
CSPCo
|
|
Ohio
|
|
|
24
|
|
|
24
|
(b)
|
May
2007
|
|
TCC
|
|
Texas
|
|
|
81
|
|
|
70
|
(b)
|
June
2007
|
|
TNC
|
|
Texas
|
|
|
25
|
|
|
14
|
|
June
2007
|
|
PSO
|
|
Oklahoma
|
|
|
50
|
|
|
9
|
(b)
|
July
2007
|
|
(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 anticipates to file for recovery through the
E&R surcharge mechanism in 2008. APCo also requested a net
$50 million reduction, beginning September 1, 2007, 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)
|
Rate
increase is presently subject to refund. Proceeding is
on-going.
|
In
Virginia, APCo filed the following non-base rate requests in July 2007 with
the
Virginia SCC:
Operating
Company
|
|
Jurisdiction
|
|
Cost
Type
|
|
Request
|
|
Projected
Date of Rate Increase
|
|
|
|
|
|
|
(in
millions)
|
|
|
APCo
|
|
Virginia
|
|
Incremental
E&R
|
|
$
|
60
|
|
December
2007
|
APCo
|
|
Virginia
|
|
Fuel,
Off-system Sales
|
|
|
33
|
|
September
2007
|
West
Virginia IGCC
In
June
2007, APCo filed testimony with the WVPSC supporting construction of a 629
MW
IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
County, WV. APCo requested 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 and
operating costs and a return on equity once the facility is placed into
commercial operation. In July 2007, APCo filed a request with the
Virginia SCC to recover an estimated $45 million in financing costs on projected
IGCC construction work in progress including pre-construction development design
and planning costs from July 1, 2007 through December 31, 2009. If
APCo receives all necessary approvals, the plant could be completed as early
as
mid-2012 for an estimated cost of $2.2 billion.
Indiana
Depreciation Study
In
June
2007, the IURC approved a settlement agreement allowing I&M to implement
reduced book depreciation rates upon the filing by I&M of a general rate
petition. On June 19, 2007, I&M filed its rate petition to be
effective on July 1, 2007. The settlement agreement will result in a
reduction of book depreciation expense of $37 million primarily related to
the
Cook Plant license extension for the period from June 19, 2007 to December
31,
2007, which was offset by a $5 million regulatory liability, recorded in June
2007, to provide for an agreed-upon fuel credit. I&M expects new
base rates including the reduced depreciation to become effective in late 2008
or early 2009.
Indiana
Rate Cap
Effective
July 1, 2007, I&M’s rate cap ended for both base and fuel
rates. I&M’s fuel factor increased effective with July 2007
billings to recover the full projected cost of fuel. I&M will
resume deferring through revenues any under/over-recovered fuel costs for future
recovery/refund.
SWEPCo
Fuel Reconciliation – Texas
In
June
2007, an ALJ issued a Proposal for Decision recommending a $17 million
disallowance in SWEPCo's Texas fuel reconciliation
proceeding. Results of operations for the second quarter were
adversely affected by $25 million as a result of reflecting the ALJ’s
decision. In July 2007, the PUCT orally affirmed the ALJ
report. A final order is expected in the third quarter of
2007.
Virginia
Restructuring
In
April
2007, the Virginia legislature re-regulated electric utilities’
generation/supply rates on a cost basis effective July 1, 2007. We
recorded an extraordinary pretax reduction in APCo’s earnings of $118 million
($79 million, net of tax) from reapplication of SFAS 71 regulatory accounting
in
the second quarter of 2007 as a result of the new re-regulation
legislation.
Investment
Activity
In
the
second quarter of 2007, we completed the purchase of the 480 MW Darby Electric
Generation Station for $102 million and the purchase of the 1,096 MW
Lawrenceburg Generating Station for $325 million.
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.
|
The
table
below presents our consolidated Income Before Discontinued Operations and
Extraordinary Loss for the three and six months ended June 30, 2007 and
2006. We reclassified prior year amounts to conform to the current
year’s segment presentation.
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Utility
Operations
|
|
$ |
238
|
|
|
$ |
159
|
|
|
$ |
491
|
|
|
$ |
524
|
|
MEMCO
Operations
|
|
|
7
|
|
|
|
14
|
|
|
|
22
|
|
|
|
35
|
|
Generation
and Marketing
|
|
|
15
|
|
|
|
2
|
|
|
|
14
|
|
|
|
6
|
|
All
Other (a)
|
|
|
(3 |
) |
|
|
(3 |
) |
|
|
1
|
|
|
|
(15 |
) |
Income
Before Discontinued Operations
and
Extraordinary Loss
|
|
$ |
257
|
|
|
$ |
172
|
|
|
$ |
528
|
|
|
$ |
550
|
|
(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.
|
Second
Quarter of 2007 Compared to Second Quarter of 2006
Income
Before Discontinued Operations and Extraordinary Loss in 2007 increased $85
million compared to 2006 primarily due to an increase in Utility Operations
segment earnings of $79 million. The increase in Utility Operations
segment earnings primarily relates to higher retail margins mostly due to rate
increases and favorable weather and increased margins from off-system
sales.
Average
basic shares outstanding increased to 399 million in 2007 from 394 million
in
2006 primarily due to the issuance of shares under our incentive compensation
plans. Actual shares outstanding were 399 million as of June 30,
2007.
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Income
Before Discontinued Operations and Extraordinary Loss in 2007 decreased $22
million compared to 2006 primarily due to a decrease in Utility Operations
segment earnings of $33 million. The decrease in Utility Operations
segment earnings primarily relates to higher operation and maintenance expenses,
higher regulatory amortization expense and lower earnings-sharing payments
from
Centrica received in March 2007 representing the last payment of the
earnings-sharing agreement. These decreases in earnings were
partially offset by rate increases and favorable weather.
Average
basic shares outstanding increased to 398 million in 2007 from 394 million
in
2006 primarily due to the issuance of shares under our incentive compensation
plans. Actual shares outstanding were 399 million as of June 30,
2007.
Utility
Operations
Our
Utility Operations segment includes primarily regulated revenues with direct
and
variable offsetting expenses and net reported commodity trading
operations. We believe that a discussion of the results from our
Utility Operations segment on a gross margin basis is most appropriate in order
to further understand the key drivers of the segment. Gross margin
represents utility operating revenues less the related direct cost of fuel,
including consumption of chemicals and emissions allowances and purchased
power.
Utility
Operations Income Summary
For
the Three and Six Months Ended June 30, 2007 and 2006
|
|
Three
Months Ended
June
30,
|
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Revenues
|
|
$ |
2,954
|
|
|
$ |
2,796
|
|
|
$ |
5,987
|
|
|
$ |
5,762
|
|
Fuel
and Purchased Power
|
|
|
1,109
|
|
|
|
1,123
|
|
|
|
2,228
|
|
|
|
2,249
|
|
Gross
Margin
|
|
|
1,845
|
|
|
|
1,673
|
|
|
|
3,759
|
|
|
|
3,513
|
|
Depreciation
and Amortization
|
|
|
365
|
|
|
|
346
|
|
|
|
748
|
|
|
|
686
|
|
Other
Operating Expenses
|
|
|
957
|
|
|
|
983
|
|
|
|
1,948
|
|
|
|
1,819
|
|
Operating
Income
|
|
|
523
|
|
|
|
344
|
|
|
|
1,063
|
|
|
|
1,008
|
|
Other
Income, Net
|
|
|
27
|
|
|
|
44
|
|
|
|
45
|
|
|
|
85
|
|
Interest
Charges and Preferred Stock Dividend
Requirements
|
|
|
207
|
|
|
|
161
|
|
|
|
386
|
|
|
|
315
|
|
Income
Tax Expense
|
|
|
105
|
|
|
|
68
|
|
|
|
231
|
|
|
|
254
|
|
Income
Before Discontinued Operations and
Extraordinary
Loss
|
|
$ |
238
|
|
|
$ |
159
|
|
|
$ |
491
|
|
|
$ |
524
|
|
Summary
of Selected Sales and Weather Data
For
Utility Operations
For
the Three and Six Months Ended June 30, 2007 and 2006
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
Energy/Delivery
Summary
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
(in
millions of KWH)
|
Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
10,127
|
|
|
9,590
|
|
|
24,267
|
|
|
22,528
|
|
|
Commercial
|
|
10,227
|
|
|
9,440
|
|
|
19,586
|
|
|
18,349
|
|
|
Industrial
|
|
14,848
|
|
|
13,716
|
|
|
28,413
|
|
|
26,937
|
|
|
Miscellaneous
|
|
632
|
|
|
655
|
|
|
1,245
|
|
|
1,274
|
|
Total
Retail
|
|
35,834
|
|
|
33,401
|
|
|
73,511
|
|
|
69,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
9,376
|
|
|
10,822
|
|
|
18,154
|
|
|
21,667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivery
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
Wires – Energy delivered to customers served
by
AEP’s Texas Wires Companies
|
|
6,746
|
|
|
6,915
|
|
|
12,577
|
|
|
12,461
|
|
Total
KWHs
|
|
51,956
|
|
|
51,138
|
|
|
104,242
|
|
|
103,216
|
|
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 Six Months Ended June 30, 2007 and 2006
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
(in
degree days)
|
Weather
Summary
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern
Region
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Heating (a)
|
|
222
|
|
|
107
|
|
|
2,039
|
|
|
1,563
|
|
Normal
– Heating (b)
|
|
174
|
|
|
175
|
|
|
1,966
|
|
|
1,992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Cooling (c)
|
|
367
|
|
|
228
|
|
|
382
|
|
|
229
|
|
Normal
– Cooling (b)
|
|
275
|
|
|
279
|
|
|
278
|
|
|
282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western
Region (d)
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Heating (a)
|
|
92
|
|
|
5
|
|
|
994
|
|
|
663
|
|
Normal
– Heating (b)
|
|
33
|
|
|
33
|
|
|
991
|
|
|
1,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
– Cooling (c)
|
|
622
|
|
|
815
|
|
|
678
|
|
|
858
|
|
Normal
– Cooling (b)
|
|
656
|
|
|
652
|
|
|
674
|
|
|
669
|
|
(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.
|
Second
Quarter of 2007 Compared to Second Quarter of 2006
Reconciliation
of Second Quarter of 2006 to Second Quarter of 2007
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss
(in
millions)
Second
Quarter of 2006
|
|
|
|
|
$ |
159
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
72
|
|
|
|
|
|
Off-system
Sales
|
|
|
52
|
|
|
|
|
|
Transmission
Revenues
|
|
|
22
|
|
|
|
|
|
Other
Revenues
|
|
|
26
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
26
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(19 |
) |
|
|
|
|
Carrying
Costs Income
|
|
|
(17 |
) |
|
|
|
|
Interest
and Other Charges
|
|
|
(46 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(56 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(37 |
) |
|
|
|
|
|
|
|
|
|
Second
Quarter of 2007
|
|
|
|
|
|
$ |
238
|
|
Income
from Utility Operations Before Discontinued Operations and Extraordinary Loss
increased $79 million to $238 million in 2007. The key drivers of the
increase were a $172 million increase in Gross Margin partially offset by a
$56
million increase in Operating Expenses and Other and a $37 million increase
in
Income Tax Expense.
The
major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $72 million primarily due to the
following:
|
|
·
|
A
$36 million increase related to new rates implemented in our Ohio
jurisdictions as approved by the PUCO in our RSP’s.
|
|
·
|
A
$36 million increase related to increased residential and commercial
usage
and customer growth.
|
|
·
|
A
$24 million increase related to Ormet, a new industrial customer
in
Ohio. See “Ormet” section of Note 3.
|
|
·
|
A
$19 million increase related to increased sales to municipal, cooperative
and other customers primarily resulting from new power supply
contracts.
|
|
·
|
A
$26 million increase in usage related to weather. As compared
to the prior year, our eastern region experienced a 61% increase
in
cooling degree days partially offset by a 24% decrease in cooling
degree
days in our western region.
|
|
These
increases were partially offset by:
|
|
·
|
A
$38 million net decrease related to the APCo Virginia base rate case
which
includes a second quarter 2007 provision for revenue refund as a
result of
the final order offset by the new rates implemented. See
“Virginia Base Rate Case” section of Note 3.
|
|
·
|
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
$21 million decrease in financial transmission rights revenue, net
of
congestion, primarily due to fewer transmission constraints within
the PJM
market.
|
·
|
Margins
from Off-system Sales increased $52 million primarily due to higher
power
prices in the east and stronger trading margins offset by higher
internal
load and lower generation availability.
|
·
|
Transmission
Revenues increased $22 million primarily due to a provision recorded
in
the second quarter of 2006 related to potential SECA
refunds. See “Transmission Rate Proceedings at the FERC”
section of Note 3.
|
·
|
Other
Revenues increased $26 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 decreased $26 million primarily
due to
reduced expenses for storm restoration and lower administrative and
general expenses.
|
·
|
Depreciation
and Amortization expense increased $19 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, offset
by
adjustments related to implementation of the final order in the APCo
Virginia base rate case.
|
·
|
Carrying
Costs Income decreased $17 million because TCC started recovering
stranded
costs in October 2006, thus eliminating future TCC carrying costs
income.
|
·
|
Interest
and Other Charges increased $46 million primarily due to additional
debt
issued in the fourth quarter of 2006 including TCC securitization
bonds.
|
·
|
Income
Tax Expense increased $37 million due to an increase in pretax
income.
|
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Reconciliation
of Six Months Ended June 30, 2006 to Six Months Ended June 30,
2007
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss
(in
millions)
Six
Months Ended June 30, 2006
|
|
|
|
|
$ |
524
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
210
|
|
|
|
|
|
Off-system
Sales
|
|
|
11
|
|
|
|
|
|
Transmission
Revenues
|
|
|
(8 |
) |
|
|
|
|
Other
Revenues
|
|
|
33
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
246
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(85 |
) |
|
|
|
|
Gain
on Dispositions of Assets, Net
|
|
|
(47 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(62 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
3
|
|
|
|
|
|
Carrying
Costs Income
|
|
|
(39 |
) |
|
|
|
|
Other
Income, Net
|
|
|
(1 |
) |
|
|
|
|
Interest
and Other Charges
|
|
|
(71 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(302 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
$ |
491
|
|
Income
from Utility Operations Before Discontinued Operations and Extraordinary Loss
decreased $33 million to $491 million in 2007. The key driver of the
decrease was a $302 million increase in Operating Expenses and Other, offset
by
a $246 million increase in Gross Margin and a $23 million decrease in Income
Tax
Expense.
The
major
components of the net increase in Gross Margin were as follows:
·
|
Retail
Margins increased $210 million primarily due to the
following:
|
|
·
|
A
$71 million increase related to new rates implemented in our Ohio
jurisdictions as approved by the PUCO in our RSPs and a $20 million
increase related to new rates implemented in other east jurisdictions
of
Kentucky, West Virginia and Virginia.
|
|
·
|
A
$70 million increase related to increased residential and commercial
usage
and customer growth.
|
|
·
|
A
$66 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 67% increase in cooling degree days
which
was offset by a 21% decrease in cooling degree days in our western
region.
|
|
·
|
A
$37 million increase related to Ormet, a new industrial customer
in
Ohio. See “Ormet” section of Note 3.
|
|
These
increases were partially offset by:
|
|
·
|
A
$48 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.
|
·
|
Margins
from Off-system Sales increased $11 million primarily due to higher
power
prices in the east and stronger trading margins offset by higher
internal
load and lower generation availability.
|
·
|
Transmission
Revenues decreased $8 million primarily due to the elimination of
SECA
revenues as of April 1, 2006 offset by a provision recorded in the
second
quarter of 2006 related to potential SECA
refunds. See “Transmission Rate Proceedings at the
FERC” section of Note 3.
|
·
|
Other
Revenues increased $33 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 $85 million primarily
due to
increases in generation expenses related to plant outages, base operations
and removal costs 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 ended.
|
·
|
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.
|
·
|
Carrying
Costs Income decreased $39 million because TCC started recovering
stranded
costs in October 2006, thus eliminating future TCC carrying costs
income.
|
·
|
Interest
and Other Charges increased $71 million primarily due to additional
debt
issued in the fourth quarter of 2006 including TCC securitization
bonds.
|
·
|
Income
Tax Expense decreased $23 million due to a decrease in pretax
income.
|
MEMCO
Operations
Second
Quarter of 2007 Compared to Second Quarter of 2006
Income
Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations
segment decreased from $14 million in 2006 to $7 million in
2007. While MEMCO operated 15% more barges in the second quarter of
2007 than the same period in 2006, freight revenues remained flat as spot market
freight demand remained weaker than in 2006, primarily related to reduced steel
and cement imports. Operating expenses were up 11% over the same
period in 2006 mainly due to the increased fleet size, increased fuel costs
and
wage increases for towboat crews.
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Income
Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations
segment decreased from $35 million in 2006 to $22 million in
2007. MEMCO operated approximately 16% more barges in the first six
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 six
months of 2007 compared to 2006 primarily due to the cost of the increased
fleet
size, fuel and wage increases.
Generation
and Marketing
Second
Quarter of 2007 Compared to Second Quarter of 2006
Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment increased from $2 million in 2006 to $15 million in
2007. The increase primarily relates to favorable marketing contracts
with municipalities and cooperatives in ERCOT. Net revenues for our
Generation and Marketing segment increased primarily due to certain existing
ERCOT energy contracts which were transferred from our Utility Operations
segment on January 1, 2007.
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment increased from $6 million in 2006 to $14 million in
2007. The increase primarily relates to favorable marketing contracts
with municipalities and cooperatives in ERCOT. Net revenues for our
Generation and Marketing segment increased primarily due to certain existing
ERCOT energy contracts which were transferred from our Utility Operations
segment on January 1, 2007.
All
Other
Second
Quarter of 2007 Compared to Second Quarter of 2006
Loss
Before Discontinued Operations and Extraordinary Loss from All Other was
essentially flat at $3 million.
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Income
Before Discontinued Operations and Extraordinary Loss from All Other increased
from a $15 million loss in 2006 to income of $1 million in 2007. In
2006, we had after-tax losses of $8 million from operation of the Plaquemine
Cogeneration Facility which was sold in the fourth quarter of
2006. In 2007, we had an after-tax gain of $10 million on the sale of
investment securities.
AEP
System Income Taxes
Income
Tax Expense increased $36 million in the second quarter of 2007 compared to
the
second quarter of 2006 primarily due to an increase in pretax book
income.
Income
Tax Expense decreased $23 million for the six-month period ended June 30, 2007
compared to the six-month period ended June 30, 2006 primarily due to a decrease
in pretax book income and changes in certain book/tax differences accounted
for
on a flow-through basis.
FINANCIAL
CONDITION
We
measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.
Debt
and Equity Capitalization
|
|
June
30, 2007
|
|
|
December
31, 2006
|
|
|
|
($
in millions)
|
|
Long-term
Debt, Including Amounts Due Within One Year
|
|
$ |
14,588
|
|
|
|
59.0 |
% |
|
$ |
13,698
|
|
|
|
59.1 |
% |
Short-term
Debt
|
|
|
438
|
|
|
|
1.8
|
|
|
|
18
|
|
|
|
0.0
|
|
Total
Debt
|
|
|
15,026
|
|
|
|
60.8
|
|
|
|
13,716
|
|
|
|
59.1
|
|
Common
Equity
|
|
|
9,656
|
|
|
|
39.0
|
|
|
|
9,412
|
|
|
|
40.6
|
|
Preferred
Stock
|
|
|
61
|
|
|
|
0.2
|
|
|
|
61
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt and Equity Capitalization
|
|
$ |
24,743
|
|
|
|
100.0 |
% |
|
$ |
23,189
|
|
|
|
100.0 |
% |
Our
ratio
of debt to total capital increased, as planned, from 59.1% to 60.8% in 2007
due to our increased borrowings.
Liquidity
Liquidity,
or access to cash, is an important factor in determining our financial
stability. We are committed to maintaining adequate
liquidity.
Credit
Facilities
We
manage
our liquidity by maintaining adequate external financing
commitments. At June 30, 2007, our available liquidity was
approximately $2.7 billion as illustrated in the table below:
|
|
|
Amount
|
|
Maturity
|
|
|
|
(in
millions)
|
|
|
Commercial
Paper Backup:
|
|
|
|
|
|
|
|
Revolving
Credit Facility
|
|
|
$
|
1,500
|
|
March
2011
|
|
Revolving
Credit Facility
|
|
|
|
1,500
|
|
April
2012
|
Total
|
|
|
|
3,000
|
|
|
Cash
and Cash Equivalents
|
|
|
|
172
|
|
|
Total
Liquidity Sources
|
|
|
|
3,172
|
|
|
Less:
AEP Commercial Paper Outstanding
|
|
|
|
416
|
|
|
|
Letters
of Credit Drawn
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
Net
Available Liquidity
|
|
|
$
|
2,729
|
|
|
In
2007,
we amended the terms and extended the maturity of our two credit facilities
by
one year to March 2011 and April 2012, respectively. The facilities
are structured as two $1.5 billion credit facilities of which $300 million
may
be issued under each credit facility as letters of credit.
Debt
Covenants and Borrowing Limitations
Our
revolving credit agreements contain certain covenants and require us to maintain
our percentage of debt to total capitalization at a level that does not exceed
67.5%. The method for calculating our outstanding debt and other
capital is contractually defined in our revolving credit agreements. At June
30,
2007, this contractually-defined percentage was 56.1%. Nonperformance
of these covenants could result in an event of default under these credit
agreements. At June 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 June 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 June 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.
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
$ |
301
|
|
|
$ |
401
|
|
Net
Cash Flows From Operating Activities
|
|
|
969
|
|
|
|
1,123
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(2,127 |
) |
|
|
(1,572
|
) |
Net
Cash Flows From Financing Activities
|
|
|
1,029
|
|
|
|
297
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(129 |
) |
|
|
(152
|
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
172
|
|
|
$ |
249
|
|
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 June 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 $833 million. The
weighted-average interest rate of our commercial paper for the six months
ended June 30, 2007 was 5.40%. 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
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Net
Income
|
|
$ |
451
|
|
|
$ |
556
|
|
Less: Discontinued
Operations, Net of Tax
|
|
|
(2 |
) |
|
|
(6 |
) |
Income
Before Discontinued Operations
|
|
|
449
|
|
|
|
550
|
|
Noncash
Items Included in Earnings
|
|
|
938
|
|
|
|
617
|
|
Changes
in Assets and Liabilities
|
|
|
(418 |
) |
|
|
(44 |
) |
Net
Cash Flows From Operating Activities
|
|
$ |
969
|
|
|
$ |
1,123
|
|
Net
Cash
Flows From Operating Activities decreased in 2007 primarily due to lower fuel
costs recovery.
Net
Cash
Flows From Operating Activities were $1 billion in 2007. We produced Income
Before Discontinued Operations of $449 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 primarily to the Texas CTC refund of fuel over-recovery.
Net
Cash
Flows From Operating Activities were $1.1 billion in 2006. We
produced Income Before Discontinued Operations of $550 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 are a $185 million cash increase from net Accounts
Receivable/Accounts Payable due to a lower balance of Customer Accounts
Receivable at June 30, 2006 and a $189 million decrease in cash related to
customer deposits held for trading activities.
Investing
Activities
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Construction
Expenditures
|
|
$ |
(1,823 |
) |
|
$ |
(1,611
|
)
|
Change
in Other Temporary Investments, Net
|
|
|
(129 |
) |
|
|
3
|
|
(Purchases)/Sales
of Investment Securities, Net
|
|
|
208
|
|
|
|
(51
|
)
|
Acquisition
of Darby and Lawrenceburg Plants
|
|
|
(427 |
) |
|
|
-
|
|
Proceeds
from Sales of Assets
|
|
|
74
|
|
|
|
118
|
|
Other
|
|
|
(30 |
) |
|
|
(31
|
)
|
Net
Cash Flows Used For Investing Activities
|
|
$ |
(2,127 |
) |
|
$ |
(1,572
|
)
|
Net
Cash
Flows Used For Investing Activities were $2.1 billion in 2007 primarily due
to
Construction Expenditures for our environmental, distribution and new generation
investment plan. We paid $427 million to purchase gas-fired
generating units. In our normal course of business, we purchase
investment securities including auction rate securities and variable rate demand
notes with cash available for short-term investments. Also included
in Purchases/Sales of Investment Securities, Net are purchases and sales of
securities within our nuclear trusts.
Net
Cash
Flows Used For Investing Activities were $1.6 billion in 2006 primarily due
to
Construction Expenditures. Construction Expenditures increased due to
our environmental investment plan.
We
forecast approximately $1.7 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
through results of operations and financing activities.
Financing
Activities
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions)
|
|
Issuance
of Common Stock
|
|
$ |
90
|
|
|
$ |
6
|
|
Issuance/Retirement
of Debt, Net
|
|
|
1,294
|
|
|
|
552
|
|
Dividends
Paid on Common Stock
|
|
|
(311 |
) |
|
|
(291
|
)
|
Other
|
|
|
(44 |
) |
|
|
30
|
|
Net
Cash Flows From Financing Activities
|
|
$ |
1,029
|
|
|
$ |
297
|
|
Net
Cash
Flows From Financing Activities in 2007 were $1 billion primarily due to issuing
$1.1 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 $311
million. See Note 9 for a complete discussion of long-term debt
issuances and retirements.
Net
Cash
Flows From Financing Activities in 2006 were $297 million. During
2006, we issued $115 million of obligations relating to pollution control bonds,
issued $850 million of notes and retired $396 million of notes for a net
increase in notes outstanding of $454 million and increased our short-term
commercial paper outstanding by $144 million. The Other amount of $30
million in the above table includes $68 million received from a coal supplier,
net of an $8 million repayment, related to a long-term coal purchase contract
amended in March 2006.
Our
capital investment plans for the remainder of 2007 will require additional
funding of approximately $1.5 billion from the capital markets.
Off-balance
Sheet Arrangements
Under
a
limited set of circumstances we enter into off-balance sheet arrangements to
accelerate cash collections, reduce operational expenses and spread risk of
loss
to third parties. Our current guidelines restrict the use of
off-balance sheet financing entities or structures to only allow 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:
|
|
June
30,
2007
|
|
|
December
31,
2006
|
|
|
|
(in
millions)
|
|
AEP
Credit Accounts Receivable Purchase Commitments
|
|
$ |
549
|
|
|
$ |
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.
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
CSPCo
and
OPCo are involved in discussions with various stakeholders in Ohio about
potential legislation to address the period following the expiration of the
RSPs
on December 31, 2008. At this time, management is unable to predict
whether CSPCo and OPCo will transition to market pricing, as permitted by the
current Ohio restructuring legislation, extend their RSP rates, with or without
modification, or become subject to a legislative reinstatement of some form
of
cost-based regulation for their generation supply business on January 1, 2009
when the RSP period ends.
Texas
Restructuring
TCC
recovered its net recoverable stranded generation costs through a securitization
financing and is refunding its net other true-up items through a CTC rate rider
credit under 2006 PUCT orders. TCC appealed the PUCT stranded costs
true-up orders seeking relief in both state and federal court on the grounds
that certain aspects of the orders are contrary to the Texas Restructuring
Legislation, PUCT rulemakings, federal law and fail to fully compensate TCC
for
its net stranded cost and other true-up items. The significant items
appealed by TCC are:
·
|
The
PUCT ruling that TCC did not comply with the 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 cost, and
|
·
|
The
two federal matters regarding the allocation of off-system sales
related
to fuel recoveries and the potential tax normalization
violation.
|
Municipal
customers and other intervenors also appealed the PUCT true-up orders seeking
to
further reduce TCC’s true-up recoveries. In March 2007, the Texas
District Court judge hearing the various appeals 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 invalidated 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 rulings to the Court of
Appeals. Management cannot predict the outcome of these
proceedings. If TCC ultimately succeeds in its appeals, it could have
a favorable effect on future results of operations, cash flows and financial
condition. If municipal customers and other intervenors succeed in
their appeals, 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.
SECA
Revenue Subject to Refund
The
AEP
East companies ceased collecting T&O revenues in accordance with FERC
orders, and collected SECA rates to mitigate the loss of T&O revenues from
December 1, 2004 through March 31, 2006, when SECA rates
expired. Intervenors objected to the SECA rates, raising various
issues. As a result, the FERC set SECA rate issues for hearing and
ordered that the SECA rate revenues be collected, subject to refund or
surcharge. The AEP East companies paid SECA rates to other utilities
at considerably lesser amounts than collected. If a refund is
ordered, the AEP East companies would also receive refunds related to the SECA
rates they paid to third parties. The AEP East companies recognized
gross SECA revenues of $220 million. Approximately $19 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.
Since
the
implementation of SECA rates in December 2004, the AEP East companies recorded
approximately $220 million of gross SECA revenues, subject to
refund. In 2006, the AEP East companies provided reserves of $37
million in net refunds for current and future SECA settlements with all of
AEP’s
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 will be
adequate.
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 and cash flows.
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 practice
deferred fuel accounting. Also, under the amended restructuring law,
APCo has the right to defer incremental environmental compliance costs and
incremental E&R costs for future recovery, to the extent such costs are not
being recovered, and amortizes a portion of such deferrals commensurate with
their recovery.
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.
With
the
new re-regulation legislation, APCo’s generation business again meets 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 primarily 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 law. AOCI and Deferred
Income Taxes increased by $11 million and $6 million, respectively.
New
Generation
In
March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of
cost recovery associated with the IGCC plant: Phase 1, recovery of
$24 million in pre-construction costs during 2006; Phase 2, concurrent recovery
of construction-financing costs; and Phase 3, recovery or refund in distribution
rates of any difference between the market-based standard service offer price
for generation and the cost of operating and maintaining the plant, including
a
return on and return of the ultimate cost to construct the plant, originally
projected to be $1.2 billion, along with fuel, consumables and replacement
power
costs. The proposed recoveries in Phases 1 and 2 would be applied
against the 4% limit on additional generation rate increases CSPCo and OPCo
could request under their RSPs.
In
April
2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
1
of the cost recovery proposal. In June 2006, the PUCO issued another
order approving a tariff to recover Phase 1 pre-construction costs over a period
of no more than twelve months effective July 1, 2006. Through June
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. CSPCo and OPCo expect to incur additional pre-construction
costs equal to or greater than the $12 million each recovered. As of
June 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each
for
the over-recovered portion. The PUCO indicated that if CSPCo and OPCo
have not commenced a continuous course of construction of the IGCC plant within
five years of the June 2006 PUCO order, all amounts collected for
pre-construction costs, associated with items that may be utilized in IGCC
projects to be built by AEP 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 has scheduled 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 are $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. In July
2007, CSPCo and OPCo filed a status report with the PUCO referencing APCo’s IGCC
West Virginia filing.
In
January 2006, APCo filed a petition with the WVPSC requesting its approval
of a
Certificate of Public Convenience and Necessity (CCN) to construct a 629 MW
IGCC
plant adjacent to APCo’s existing Mountaineer Generating Station in Mason
County, 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
of equity once the facility is placed into commercial operation. If
APCo receives all necessary approvals, the plant could be completed by mid-2012
at the earliest 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 June 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.
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 IGCC
plant to be constructed in West Virginia. 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
as required by the new re-regulation legislation.
In
December 2005, SWEPCo sought proposals for new peaking, intermediate and base
load generation to be online between 2008 and 2011. In May 2006,
SWEPCo announced plans to construct new generation to satisfy the demands of
its
customers. Plans include the construction of up to 480 MW of
simple-cycle natural gas combustion turbine peaking generation in Tontitown,
Arkansas and a 480 MW combined-cycle natural gas fired intermediate plant at
its
existing Arsenal Hill Power Plant in Shreveport, Louisiana. SWEPCo
also plans to build the Turk plant, a new 600 MW base load coal plant, with
a
73% ownership share, in Hempstead County, Arkansas by 2011 to meet the long-term
generation needs of its customers. Preliminary cost estimates for
SWEPCo’s share of these new facilities are approximately $1.4 billion (this
total includes all three plants, but excludes the related transmission
investment and AFUDC). Expenditures related to construction of all of
these facilities are expected to total $349 million in 2007. These
new facilities are subject to regulatory approvals from SWEPCo’s three state
commissions. Mattison plant, the peaking generation facility in
Tontitown, Arkansas has been approved by all three state
commissions. Mattison plant Units 3 and 4 began commercial operation
in July 2007, with the remaining two units scheduled for completion in December
2007. All four units of the Mattison plant are expected to be
completed in advance of the originally planned 2008 commercial operation
date. Construction is expected to begin in the second half of 2007 on
the base load facility and in 2008 on the intermediate facility, both upon
approval from SWEPCo’s three state commissions.
In
September 2005, PSO sought proposals for new peaking generation to be online
in
2008, and in December 2005 PSO sought proposals for base load generation to
be
online in 2011. PSO received proposals and evaluated those proposals
meeting the Request for Proposal criteria with oversight from a neutral third
party. In March 2006, PSO announced plans to add 170 MW of peaking
generation to its Riverside Station plant in Jenks, Oklahoma where PSO will
construct and operate two 85 MW simple-cycle natural gas combustion
turbines. Also in March 2006, PSO announced plans to add 170 MW
of peaking generation to its Southwestern Station plant in Anadarko, Oklahoma
where they will construct and operate two 85 MW simple-cycle natural gas
combustion turbines. Construction of all four peaking units began in
the second quarter of 2007. Combined preliminary cost estimates for
these additions are approximately $120 million. In April 2007, the
OCC approved a settlement agreement in a matter involving a proposed
cogeneration facility, which included a provision regarding these new peaking
units. The settlement agreement provides for recovery of a purchase
fee of $35 million, which PSO paid to Lawton Cogeneration, LLC (Lawton) in
the
second quarter of 2007 to settle the proceeding and for all rights to Lawton’s
permits, options and engineering studies for the cogeneration
facility. In April 2007, PSO recorded with OCC approval, 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 the traditional costs associated
with plant in service of these new peaking units. Such costs will be
recovered through the rider until cost recovery occurs through base rates or
formula rates in a subsequent proceeding. PSO must file a rate case
within eighteen months of the beginning of recovery through the rider unless
the
OCC approves a formula-based rate mechanism that provides for recovery of the
peaking units.
In
July
2006, PSO announced plans to enter a joint ownership agreement with Oklahoma
Gas
and Electric Company (OG&E) and Oklahoma Municipal Power Authority (OMPA)
where OG&E will construct and operate a new 950 MW coal-fueled electricity
generating unit near Red Rock, Oklahoma. PSO will own 50% of the new
unit. PSO, OG&E and OMPA signed an agreement in February 2007
with Red Rock Power Partners to begin the first phase of the
project. Preliminary cost estimates for 100% of the new facility are
approximately $1.8 billion, and the unit is expected to be online no later
than
the first half of 2012. This new facility is subject to regulatory
approval from the OCC, which is expected later in 2007. Construction
is expected to begin in the second half of 2007. The Oklahoma Supreme
Court is addressing whether the upfront approval process is
constitutional. PSO estimates construction expenditures for all of
the new generation projects to be $167 million in 2007.
In
November 2006, CSPCo agreed to purchase Darby Electric Generating Station
(Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light
Company, for $102 million 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 purchase
of Darby is an economically efficient way to provide peaking generation to
our
customers at a cost below that of building a new, comparable plant.
In
January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station
(Lawrenceburg) from Public Service Enterprise Group (PSEG) for $325 million
and
the assumption of liabilities of $3 million. The transaction closed
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 under a FERC-approved purchase
power contract.
Electric
Transmission Texas LLC Joint Venture
In
January 2007, we signed a participation agreement with MidAmerican Energy
Holdings Company (MidAmerican) to form a joint venture company, Electric
Transmission Texas LLC (ETT), to fund, own and operate electric transmission
assets in ERCOT. ETT filed with the PUCT in January 2007 requesting
regulatory approval to operate as an electric transmission utility in Texas,
to
transfer from TCC to ETT approximately $76 million of transmission assets 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. We expect a final order from the PUCT in October
2007.
TCC
also
made a regulatory filing at the FERC in February 2007 regarding the transfer
of
certain transmission assets from TCC to ETT. In April 2007, the FERC
authorized the transfer.
Upon
receipt of all required regulatory approvals, AEP Utilities, Inc., a subsidiary
of AEP, and MEHC Texas Transco LLC, a subsidiary of MidAmerican, each will
acquire a 50 percent equity ownership in ETT. AEP and MidAmerican
plan for ETT to invest in additional transmission projects in
ERCOT. The joint venture partners anticipate investments in excess of
$1 billion of joint investment in Texas ERCOT Transmission projects that could
be constructed by ETT during the next several years. The joint
venture is anticipated to be formed and begin operations in the fourth quarter
of 2007, subject to certain closing conditions such as necessary regulatory
approvals.
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. We expect an order in
August 2007 on the designation of zones and amount of wind generation for each
zone, subsequent studies by ERCOT on specific transmission recommendations
in
late 2007 or early 2008 and selection of transmission construction designees
by
the PUCT in early 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.
AEP
Interstate Project
In
January 2006, we filed a proposal with the FERC and PJM to build a new 765
kV
550-mile transmission line from West Virginia to New Jersey. The 765
kV line is designed to reduce PJM congestion costs by substantially improving
west-east transfer capability by approximately 5,000 MW during peak loading
conditions and reducing transmission line losses by up to 280 MW. The
project would also enhance reliability of the Eastern transmission
grid. The projected cost for the project, as originally proposed to
PJM, is approximately $3 billion. The project is subject to PJM and
state approvals, and FERC approvals of incentive cost recovery
mechanisms.
We
were
the first entity to file with the Department of Energy (DOE) seeking to have
the
route of a proposed transmission project designated as a National Interest
Electric Transmission Corridor (NIETC). The Energy Policy Act of 2005
provides for NIETC designation for areas experiencing electric energy
transmission capacity constraints or congestion that adversely affects
consumers. In August 2006, the DOE issued the “National Interest
Electric Transmission Congestion Study.” In this study, DOE indicated
that the mid-Atlantic Coastal area, which the AEP Interstate Project is designed
to reinforce, is one of the two most critical congestion areas in the
nation. In April 2007, the DOE included in its draft report the
mid-Atlantic Coastal area NIETC which contains the entire proposed 765 kV
transmission line. The DOE expects to issue its final report by the
end of 2007.
In
July
2006, pursuant to our request, the FERC clarified that the project qualifies
for
incentive rate treatment, provided that the new line is included in PJM’s 2007
Regional Transmission Expansion Plan. The conditionally- approved
incentives include (a) a return on equity set at the high end of the “zone of
reasonableness”; (b) the timely recovery of the cost of capital during the
construction period; and (c) the ability to defer and recover costs incurred
during the pre-construction and pre-operating period. Since the FERC
has clarified that the project qualifies for these rate incentives, we expect
to
propose rates that will capture the incentives in a future FERC rate
filing.
In
April
2007, we signed a memorandum of understanding (MOU) with Allegheny Energy Inc.
(AYE) to form a joint venture company to build and own certain electric
transmission assets within PJM including the first half of the West Virginia
–
New Jersey line proposed by AEP in January 2006. Under the terms of
the MOU, the joint venture company will build and own approximately 300 miles
of
transmission lines from AEP’s Amos station to the Maryland
border. The MOU does not include any provisions for the remainder of
the AEP Interstate Project proposal from AYE’s Kemptown station to New
Jersey.
On
June
22, 2007, PJM’s Board authorized the construction of such 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 250 miles from AEP’s Amos substation in West Virginia to AYE’s
Kemptown station in north central Maryland. AEP and AYE continue to work on
finalizing the definitive agreements necessary to construct the line through
a
joint venture. The new line has been named the “Potomac-Appalachian
Transmission Highline” (PATH) by AEP and AYE and represents the “first leg” of
the AEP Interstate Project. The “second leg”, which would extend the
line to New Jersey, is currently under evaluation by PJM. We expect
to execute definitive agreements for the joint venture with AYE in the third
quarter of 2007 and anticipate the joint venture will begin activities in the
second half of 2007. The total PATH project is estimated to cost
approximately $1.8 billion and AEP’s estimated share will be approximately $600
million.
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. Several
similar complaints were filed in 1999 and thereafter against nonaffiliated
utilities including Allegheny Energy, Eastern Kentucky Electric Cooperative,
Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power
Company, Mirant, NRG Energy and Niagara Mohawk. Several of these
cases were resolved through consent decrees. The alleged
modifications at our power plants occurred over a 20-year period. A
bench trial on the liability issues was held during 2005. In 2006,
the judge stayed the liability decision pending the issuance of a decision
by
the U.S. Supreme Court in the Duke Energy case.
Under
the
CAA, if a plant undertakes a major modification that directly results in an
emissions increase, permitting requirements might be triggered and the plant
may
be required to install additional pollution control technology. This
requirement does not apply to activities such as routine maintenance,
replacement of degraded equipment or failed components, or other repairs needed
for the reliable, safe and efficient operation of the plant.
Courts
that considered whether the activities at issue in these cases are routine
maintenance, repair, or replacement, and therefore are excluded from NSR,
reached different conclusions. Similarly, courts that considered
whether the activities at issue increased emissions from the power plants
reached different results. Appeals on these and other issues were
filed in certain appellate courts, including a petition to appeal to the U.S.
Supreme Court that was granted in the Duke Energy case.
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 a unanimous decision, the Court ruled that
the Federal EPA was not obligated to define “major modification” in two
different CAA provisions in the same way. The Court also found that
the Fourth Circuit’s interpretation of “major modification” as applying only to
projects that increased hourly emission rates amounted to an invalidation of
the
relevant Federal EPA regulations, which under the CAA can only be challenged
in
the Court of Appeals within 60 days of the Federal EPA
rulemaking. The U.S. Supreme Court did acknowledge, however, that
Duke Energy may argue on remand that the Federal EPA has been inconsistent
in
its interpretations of the CAA and the regulations and may not retroactively
change 20 years of accepted practice.
In
addition to providing guidance on the merits of arguments in our NSR
proceedings, the U.S. Supreme Court’s issuance of a ruling in the Duke Energy
cases has an impact on the timing of our NSR proceedings. The court
indicated an intent to issue a decision on liability issues in the third quarter
of 2007. A bench trial on remedy issues, if necessary, is likely to
begin in the second half of 2007.
We
are
unable to estimate the loss or range of loss related to any contingent
liability, if any, we might have for civil penalties under the CAA
proceedings. We are also unable to predict the timing of resolution
of these matters due to the number of alleged violations and the significant
number of issues to be determined by the court. If we do not prevail,
we believe we can recover any capital and operating costs of additional
pollution control equipment that may be required through regulated rates and
market prices for electricity. If we are unable to recover such costs
or if material penalties are imposed, it would adversely affect future results
of operations, cash flows and possibly financial condition.
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 to commercial and
industrial customers and wholesale power trading and marketing contracts within
ERCOT.
We
employ
risk management contracts including physical forward purchase and sale
contracts, exchange futures and options, over-the-counter options, swaps and
other derivative contracts to offset price risk where appropriate. We
engage in risk management of electricity, 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 June 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
June
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
|
|
$ |
305
|
|
|
$ |
40
|
|
|
$ |
83
|
|
|
$ |
428
|
|
|
$ |
39
|
|
|
$ |
467
|
|
Noncurrent
Assets
|
|
|
197
|
|
|
|
46
|
|
|
|
98
|
|
|
|
341
|
|
|
|
15
|
|
|
|
356
|
|
Total
Assets
|
|
|
502
|
|
|
|
86
|
|
|
|
181
|
|
|
|
769
|
|
|
|
54
|
|
|
|
823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(215 |
) |
|
|
(50 |
) |
|
|
(83 |
) |
|
|
(348 |
) |
|
|
(3 |
) |
|
|
(351 |
) |
Noncurrent
Liabilities
|
|
|
(91 |
) |
|
|
(11 |
) |
|
|
(105 |
) |
|
|
(207 |
) |
|
|
(1 |
) |
|
|
(208 |
) |
Total
Liabilities
|
|
|
(306 |
) |
|
|
(61 |
) |
|
|
(188 |
) |
|
|
(555 |
) |
|
|
(4 |
) |
|
|
(559 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTMDerivative Contract
Net
Assets (Liabilities)
|
|
$ |
196
|
|
|
$ |
25
|
|
|
$ |
(7 |
) |
|
$ |
214
|
|
|
$ |
50
|
|
|
$ |
264
|
|
MTM
Risk Management Contract Net Assets (Liabilities)
Six
Months Ended June 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
|
|
|
(37 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(39 |
) |
Fair
Value of New Contracts at Inception When Entered
During the Period (a)
|
|
|
1
|
|
|
|
31
|
|
|
|
-
|
|
|
|
32
|
|
Net
Option Premiums Paid/(Received) for Unexercised or
Unexpired Option
Contracts Entered During The Period
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
Changes
in Fair Value Due to Valuation Methodology
Changes on Forward Contracts
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During
the Period (b)
|
|
|
8
|
|
|
|
(7 |
) |
|
|
(1 |
) |
|
|
-
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions
(c)
|
|
|
(13 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
(13 |
) |
Total
MTM Risk Management Contract Net Assets
(Liabilities) at June 30, 2007
|
|
$ |
196
|
|
|
$ |
25
|
|
|
$ |
(7 |
) |
|
|
214
|
|
Net
Cash Flow and Fair Value
Hedge Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50
|
|
Total
MTM Risk Management Contract Net Assets at
June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
264
|
|
(a)
|
Reflects
fair value on long-term contracts which are typically with customers
that
seek fixed pricing to limit their risk against fluctuating energy
prices. Inception value is only recorded if observable market
data can be obtained for valuation inputs for the entire contract
term. The contract prices are valued against market curves
associated with the delivery location and delivery
term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
“Change
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected on the Condensed
Consolidated Statements of Income. These net gains (losses) are
recorded as regulatory assets/liabilities for those subsidiaries
that
operate in regulated jurisdictions.
|
Maturity
and Source of Fair Value of MTM Risk Management Contract Net Assets
(Liabilities)
The
following table presents:
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities, to give an indication
of
when these MTM amounts will settle and generate
cash.
|
Maturity
and Source of Fair Value of MTM
Risk
Management Contract Net Assets (Liabilities)
Fair
Value of Contracts as of June 30, 2007
(in
millions)
|
|
Remainder
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
After
2011
(c)
|
|
|
Total
|
|
Utility
Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted – Exchange Traded Contracts
|
|
$ |
(6 |
) |
|
$ |
(8 |
) |
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
(14 |
) |
Prices
Provided by Other External
Sources
– OTC Broker Quotes (a)
|
|
|
73
|
|
|
|
56
|
|
|
|
37
|
|
|
|
17
|
|
|
|
-
|
|
|
|
-
|
|
|
|
183
|
|
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
(4 |
) |
|
|
(3 |
) |
|
|
8
|
|
|
|
17
|
|
|
|
4
|
|
|
|
5
|
|
|
|
27
|
|
Total
|
|
|
63
|
|
|
|
45
|
|
|
|
45
|
|
|
|
34
|
|
|
|
4
|
|
|
|
5
|
|
|
|
196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
and Marketing:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted – Exchange Traded Contracts
|
|
|
(8 |
) |
|
|
(2 |
) |
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(8 |
) |
Prices
Provided by Other External
Sources
– OTC Broker Quotes (a)
|
|
|
(5 |
) |
|
|
8
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6
|
|
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
1
|
|
|
|
2
|
|
|
|
(3 |
) |
|
|
6
|
|
|
|
5
|
|
|
|
16
|
|
|
|
27
|
|
Total
|
|
|
(12 |
) |
|
|
8
|
|
|
|
2
|
|
|
|
6
|
|
|
|
5
|
|
|
|
16
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted – Exchange Traded Contracts
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
Prices
Provided by Other External
Sources
– OTC Broker Quotes (a)
|
|
|
(1 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1 |
) |
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(4 |
) |
|
|
(4 |
) |
|
|
2
|
|
|
|
-
|
|
|
|
(8 |
) |
Total
|
|
|
-
|
|
|
|
(1 |
) |
|
|
(4 |
) |
|
|
(4 |
) |
|
|
2
|
|
|
|
-
|
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
Actively Quoted – Exchange
Traded
Contracts
|
|
|
(12 |
) |
|
|
(10 |
) |
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(20 |
) |
Prices
Provided by Other External
Sources
– OTC Broker Quotes (a)
|
|
|
67
|
|
|
|
64
|
|
|
|
40
|
|
|
|
17
|
|
|
|
-
|
|
|
|
-
|
|
|
|
188
|
|
Prices
Based on Models and Other
Valuation
Methods (b)
|
|
|
(4 |
) |
|
|
(2 |
) |
|
|
1
|
|
|
|
19
|
|
|
|
11
|
|
|
|
21
|
|
|
|
46
|
|
Total
|
|
$ |
51
|
|
|
$ |
52
|
|
|
$ |
43
|
|
|
$ |
36
|
|
|
$ |
11
|
|
|
$ |
21
|
|
|
$ |
214
|
|
(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 $21 million in individual periods beyond
2011. $10 million of this mark-to-market value is in 2012, $5
million is in 2013, and $5 million is in 2014, and $1 million for
years
2015 through 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 June 30, 2007
Commodity
|
|
Transaction
Class
|
|
Market/Region
|
|
Tenor
|
|
|
|
|
|
|
(in
Months)
|
Natural
Gas
|
|
Futures
|
|
NYMEX
/ Henry Hub
|
|
60
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
Gulf
Coast, Texas
|
|
16
|
|
|
|
|
|
|
|
|
|
Swaps
|
|
Northeast,
Mid-Continent, Gulf Coast, Texas
|
|
16
|
|
|
|
|
|
|
|
|
|
Exchange
Option Volatility
|
|
NYMEX
/ Henry Hub
|
|
12
|
|
|
|
|
|
|
|
Power
|
|
Futures
|
|
AEP
East - PJM
|
|
30
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
AEP
East
|
|
42
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
AEP
West
|
|
18
|
|
|
|
|
|
|
|
|
|
Physical
Forwards
|
|
West
Coast
|
|
30
|
|
|
|
|
|
|
|
|
|
Peak
Power Volatility (Options)
|
AEP
East - Cinergy, PJM
|
|
12
|
|
|
|
|
|
|
|
Emissions
|
|
Credits
|
|
SO2,
NOx
|
|
30
|
|
|
|
|
|
|
|
Coal
|
|
Physical
Forwards
|
|
PRB,
NYMEX, CSX
|
|
30
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI)
on
the Condensed Consolidated Balance Sheets
We
are
exposed to market fluctuations in energy commodity prices impacting our power
operations. We monitor these risks on our future operations and may
use various commodity instruments designated in qualifying cash flow hedge
strategies to mitigate the impact of these fluctuations on the future cash
flows. We do not hedge all commodity price risk.
We
use
interest rate derivative transactions to manage interest rate risk related
to
existing variable rate debt and to manage interest rate exposure on anticipated
borrowings of fixed-rate debt. We do not hedge all interest rate
exposure.
We
use
forward contracts and collars as cash flow hedges to lock in prices on certain
transactions denominated in foreign currencies where deemed
necessary. We do not hedge all foreign currency
exposure.
The
following table provides the detail on designated, effective cash flow hedges
included in AOCI on our Condensed Consolidated Balance Sheets and the reasons
for changes in cash flow hedges from December 31, 2006 to June 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
Six
Months Ended June 30, 2007
(in
millions)
|
|
Power
|
|
|
Interest
Rate and
Foreign
Currency
|
|
|
Total
|
|
Beginning
Balance in AOCI, December 31, 2006
|
|
$ |
17
|
|
|
$ |
(23 |
) |
|
$ |
(6 |
) |
Changes
in Fair Value
|
|
|
22
|
|
|
|
5
|
|
|
|
27
|
|
Reclassifications
from AOCI to Net Income for
Cash
Flow Hedges Settled
|
|
|
(13 |
) |
|
|
1
|
|
|
|
(12 |
) |
Ending
Balance in AOCI, June 30, 2007
|
|
$ |
26
|
|
|
$ |
(17 |
) |
|
$ |
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After
Tax Portion Expected to be Reclassified
to
Earnings During Next 12 Months
|
|
$ |
20
|
|
|
$ |
-
|
|
|
$ |
20
|
|
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 June 30, 2007,
our credit exposure net of credit collateral to sub investment grade
counterparties was approximately 4.9%, 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 June 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):
Counterparty
Credit Quality
|
|
Exposure
Before Credit Collateral
|
|
|
Credit
Collateral
|
|
|
Net
Exposure
|
|
|
Number
of Counterparties>10% of
Net
Exposure
|
|
|
Net
Exposure of Counterparties>10%
|
|
Investment
Grade
|
|
$ |
723
|
|
|
$ |
81
|
|
|
$ |
642
|
|
|
|
1
|
|
|
$ |
67
|
|
Split
Rating
|
|
|
20
|
|
|
|
2
|
|
|
|
18
|
|
|
|
3
|
|
|
|
17
|
|
Noninvestment
Grade
|
|
|
30
|
|
|
|
7
|
|
|
|
23
|
|
|
|
1
|
|
|
|
19
|
|
No
External Ratings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Internal
Investment Grade
|
|
|
71
|
|
|
|
-
|
|
|
|
71
|
|
|
|
1
|
|
|
|
30
|
|
Internal
Noninvestment Grade
|
|
|
17
|
|
|
|
2
|
|
|
|
15
|
|
|
|
1
|
|
|
|
11
|
|
Total
as of June 30, 2007
|
|
$ |
861
|
|
|
$ |
92
|
|
|
$ |
769
|
|
|
|
7
|
|
|
$ |
144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30, 2007
|
Remainder
|
|
|
|
|
|
2007
|
|
2008
|
|
2009
|
Estimated
Plant Output Hedged
|
94%
|
|
90%
|
|
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 June 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
Six
Months Ended
June
30, 2007
|
|
|
|
|
Twelve
Months Ended
December
31, 2006
|
(in
millions)
|
|
|
|
|
(in
millions)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$1
|
|
$6
|
|
$2
|
|
$1
|
|
|
|
|
$3
|
|
$10
|
|
$3
|
|
$1
|
The
High
VaR for 2006 occurred in mid-August during a period of high gas and power
volatility. The following day, positions were flattened and the VaR
was significantly reduced.
Interest
Rate Risk
We
utilize a VaR model to measure interest rate market risk exposure. The interest
rate VaR model is based on a Monte Carlo simulation with a 95% confidence level
and a one-year holding period. The volatilities and correlations were
based on three years of daily prices. The risk of potential loss in fair value
attributable to our exposure to interest rates, primarily related to long-term
debt with fixed interest rates, was $912 million at June 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 Six Months Ended June 30, 2007 and 2006
(in
millions, except per-share amounts and shares outstanding)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
$ |
2,818
|
|
|
$ |
2,799
|
|
|
$ |
5,704
|
|
|
$ |
5,781
|
|
Other
|
|
|
328
|
|
|
|
137
|
|
|
|
611
|
|
|
|
263
|
|
TOTAL
|
|
|
3,146
|
|
|
|
2,936
|
|
|
|
6,315
|
|
|
|
6,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
868
|
|
|
|
888
|
|
|
|
1,754
|
|
|
|
1,849
|
|
Purchased
Energy for Resale
|
|
|
291
|
|
|
|
237
|
|
|
|
537
|
|
|
|
403
|
|
Other
Operation and Maintenance
|
|
|
881
|
|
|
|
896
|
|
|
|
1,819
|
|
|
|
1,717
|
|
Gain
on Disposition of Assets, Net
|
|
|
(3 |
) |
|
|
-
|
|
|
|
(26 |
) |
|
|
(68 |
) |
Depreciation
and Amortization
|
|
|
372
|
|
|
|
354
|
|
|
|
763
|
|
|
|
702
|
|
Taxes
Other Than Income Taxes
|
|
|
188
|
|
|
|
190
|
|
|
|
374
|
|
|
|
381
|
|
TOTAL
|
|
|
2,597
|
|
|
|
2,565
|
|
|
|
5,221
|
|
|
|
4,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
549
|
|
|
|
371
|
|
|
|
1,094
|
|
|
|
1,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
and Investment Income
|
|
|
8
|
|
|
|
11
|
|
|
|
31
|
|
|
|
19
|
|
Carrying
Costs Income
|
|
|
16
|
|
|
|
33
|
|
|
|
24
|
|
|
|
63
|
|
Allowance
For Equity Funds Used During Construction
|
|
|
6
|
|
|
|
7
|
|
|
|
14
|
|
|
|
13
|
|
Gain
on Disposition of Equity Investments, Net
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST
AND OTHER CHARGES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
|
213
|
|
|
|
176
|
|
|
|
399
|
|
|
|
344
|
|
Preferred
Stock Dividend Requirements of Subsidiaries
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
TOTAL
|
|
|
213
|
|
|
|
176
|
|
|
|
400
|
|
|
|
345
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAX EXPENSE, MINORITY
INTEREST
EXPENSE AND EQUITY EARNINGS (LOSS)
|
|
|
366
|
|
|
|
246
|
|
|
|
763
|
|
|
|
813
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
108
|
|
|
|
72
|
|
|
|
238
|
|
|
|
261
|
|
Minority
Interest Expense
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
1
|
|
Equity
Earnings (Loss) of Unconsolidated Subsidiaries
|
|
|
-
|
|
|
|
(1 |
) |
|
|
5
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS AND
EXTRAORDINARY
LOSS
|
|
|
257
|
|
|
|
172
|
|
|
|
528
|
|
|
|
550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DISCONTINUED
OPERATIONS, NET OF TAX
|
|
|
2
|
|
|
|
3
|
|
|
|
2
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE EXTRAORDINARY LOSS
|
|
|
259
|
|
|
|
175
|
|
|
|
530
|
|
|
|
556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXTRAORDINARY
LOSS, NET OF TAX
|
|
|
(79 |
) |
|
|
-
|
|
|
|
(79 |
) |
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
180
|
|
|
$ |
175
|
|
|
$ |
451
|
|
|
$ |
556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
|
|
398,679,242
|
|
|
|
393,722,353
|
|
|
|
398,000,712
|
|
|
|
393,687,949
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$ |
0.64
|
|
|
$ |
0.44
|
|
|
$ |
1.33
|
|
|
$ |
1.40
|
|
Discontinued
Operations, Net of Tax
|
|
|
0.01
|
|
|
|
-
|
|
|
|
-
|
|
|
|
0.01
|
|
Income
Before Extraordinary Loss
|
|
|
0.65
|
|
|
|
0.44
|
|
|
|
1.33
|
|
|
|
1.41
|
|
Extraordinary
Loss, Net of Tax
|
|
|
(0.20 |
) |
|
|
-
|
|
|
|
(0.20 |
) |
|
|
-
|
|
TOTAL
BASIC EARNINGS PER SHARE
|
|
$ |
0.45
|
|
|
$ |
0.44
|
|
|
$ |
1.13
|
|
|
$ |
1.41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
|
|
|
399,868,900
|
|
|
|
395,500,506
|
|
|
|
399,214,277
|
|
|
|
395,540,498
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued Operations and Extraordinary Loss
|
|
$ |
0.64
|
|
|
$ |
0.43
|
|
|
$ |
1.32
|
|
|
$ |
1.39
|
|
Discontinued
Operations, Net of Tax
|
|
|
0.01
|
|
|
|
0.01
|
|
|
|
0.01
|
|
|
|
0.02
|
|
Income
Before Extraordinary Loss
|
|
|
0.65
|
|
|
|
0.44
|
|
|
|
1.33
|
|
|
|
1.41
|
|
Extraordinary
Loss, Net of Tax
|
|
|
(0.20 |
) |
|
|
-
|
|
|
|
(0.20 |
) |
|
|
-
|
|
TOTAL
DILUTED EARNINGS PER SHARE
|
|
$ |
0.45
|
|
|
$ |
0.44
|
|
|
$ |
1.13
|
|
|
$ |
1.41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
DIVIDENDS PAID PER SHARE
|
|
$ |
0.39
|
|
|
$ |
0.37
|
|
|
$ |
0.78
|
|
|
$ |
0.74
|
|
See
Condensed Notes to Condensed Consolidated Financial
Statements.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2007 and December 31, 2006
(in
millions)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
172
|
|
|
$ |
301
|
|
Other
Temporary Investments
|
|
|
337
|
|
|
|
425
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
676
|
|
|
|
676
|
|
Accrued
Unbilled Revenues
|
|
|
378
|
|
|
|
350
|
|
Miscellaneous
|
|
|
58
|
|
|
|
44
|
|
Allowance for Uncollectible Accounts
|
|
|
(40 |
) |
|
|
(30
|
)
|
Total Accounts Receivable
|
|
|
1,072
|
|
|
|
1,040
|
|
Fuel,
Materials and Supplies
|
|
|
1,038
|
|
|
|
913
|
|
Risk
Management Assets
|
|
|
467
|
|
|
|
680
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
28
|
|
|
|
38
|
|
Margin
Deposits
|
|
|
75
|
|
|
|
120
|
|
Prepayments
and Other
|
|
|
74
|
|
|
|
71
|
|
TOTAL
|
|
|
3,263
|
|
|
|
3,588
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
19,618
|
|
|
|
16,787
|
|
Transmission
|
|
|
7,275
|
|
|
|
7,018
|
|
Distribution
|
|
|
11,718
|
|
|
|
11,338
|
|
Other
(including coal mining and nuclear fuel)
|
|
|
3,320
|
|
|
|
3,405
|
|
Construction
Work in Progress
|
|
|
2,469
|
|
|
|
3,473
|
|
Total
|
|
|
44,400
|
|
|
|
42,021
|
|
Accumulated
Depreciation and Amortization
|
|
|
(15,933 |
) |
|
|
(15,240
|
)
|
TOTAL
- NET
|
|
|
28,467
|
|
|
|
26,781
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
2,405
|
|
|
|
2,477
|
|
Securitized
Transition Assets
|
|
|
2,116
|
|
|
|
2,158
|
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,311
|
|
|
|
1,248
|
|
Goodwill
|
|
|
76
|
|
|
|
76
|
|
Long-term
Risk Management Assets
|
|
|
356
|
|
|
|
378
|
|
Employee
Benefits and Pension Assets
|
|
|
303
|
|
|
|
327
|
|
Deferred
Charges and Other
|
|
|
896
|
|
|
|
910
|
|
TOTAL
|
|
|
7,463
|
|
|
|
7,574
|
|
|
|
|
|
|
|
|
|
|
Assets
Held for Sale
|
|
|
-
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
39,193
|
|
|
$ |
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
June
30, 2007 and December 31, 2006
(Unaudited)
|
|
|
|
|
2007
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
|
|
|
(in
millions)
|
|
Accounts
Payable
|
|
|
|
|
$
|
1,189
|
|
$
|
1,360
|
|
Short-term
Debt
|
|
|
|
|
|
438
|
|
|
18
|
|
Long-term
Debt Due Within One Year
|
|
|
|
|
|
1,521
|
|
|
1,269
|
|
Risk
Management Liabilities
|
|
|
|
|
|
351
|
|
|
541
|
|
Customer
Deposits
|
|
|
|
|
|
353
|
|
|
339
|
|
Accrued
Taxes
|
|
|
|
|
|
783
|
|
|
781
|
|
Accrued
Interest
|
|
|
|
|
|
291
|
|
|
186
|
|
Other
|
|
|
|
|
|
878
|
|
|
962
|
|
TOTAL
|
|
|
|
|
|
5,804
|
|
|
5,456
|
|
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
Long-term
Debt
|
|
|
|
|
|
13,067
|
|
|
12,429
|
|
Long-term
Risk Management Liabilities
|
|
|
|
|
|
208
|
|
|
260
|
|
Deferred
Income Taxes
|
|
|
|
|
|
4,536
|
|
|
4,690
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
|
|
|
2,936
|
|
|
2,910
|
|
Asset
Retirement Obligations
|
|
|
|
|
|
1,047
|
|
|
1,023
|
|
Employee
Benefits and Pension Obligations
|
|
|
|
|
|
838
|
|
|
823
|
|
Deferred
Gain on Sale and Leaseback – Rockport Plant Unit 2
|
|
|
|
|
|
143
|
|
|
148
|
|
Deferred
Credits and Other
|
|
|
|
|
|
897
|
|
|
775
|
|
TOTAL
|
|
|
|
|
|
23,672
|
|
|
23,058
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
|
|
|
29,476
|
|
|
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
|
420,689,766
|
|
418,174,728
|
|
|
|
|
|
|
|
|
|
|
|
(21,499,992
shares were held in treasury at June 30, 2007 and December 31,
2006)
|
|
|
|
|
|
2,734
|
|
|
2,718
|
|
Paid-in
Capital
|
|
|
|
|
|
4,305
|
|
|
4,221
|
|
Retained
Earnings
|
|
|
|
|
|
2,819
|
|
|
2,696
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
|
|
|
(202
|
)
|
|
(223
|
)
|
TOTAL
|
|
|
|
|
|
9,656
|
|
|
9,412
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
$
|
39,193
|
|
$
|
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 Six Months Ended June 30, 2007 and 2006
(in
millions)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
451
|
|
|
$ |
556
|
|
Less: Discontinued
Operations, Net of Tax
|
|
|
(2 |
) |
|
|
(6 |
) |
Income
Before Discontinued Operations
|
|
|
449
|
|
|
|
550
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
763
|
|
|
|
702
|
|
Deferred
Income Taxes
|
|
|
(24 |
) |
|
|
10
|
|
Deferred
Investment Tax Credits
|
|
|
(13 |
) |
|
|
(14 |
) |
Extraordinary
Loss
|
|
|
79
|
|
|
|
-
|
|
Regulatory
Provision
|
|
|
105
|
|
|
|
-
|
|
Carrying
Costs Income
|
|
|
(24 |
) |
|
|
(63 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
19
|
|
|
|
(43 |
) |
Amortization
of Nuclear Fuel
|
|
|
33
|
|
|
|
25
|
|
Deferred
Property Taxes
|
|
|
24
|
|
|
|
12
|
|
Fuel
Over/Under-Recovery, Net
|
|
|
(101 |
) |
|
|
128
|
|
Gain
on Sales of Assets and Equity Investments, Net
|
|
|
(26 |
) |
|
|
(71 |
) |
Change
in Other Noncurrent Assets
|
|
|
(53 |
) |
|
|
82
|
|
Change
in Other Noncurrent Liabilities
|
|
|
23
|
|
|
|
(12 |
) |
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(81 |
) |
|
|
202
|
|
Fuel,
Materials and Supplies
|
|
|
(90 |
) |
|
|
(140 |
) |
Margin
Deposits
|
|
|
45
|
|
|
|
67
|
|
Accounts
Payable
|
|
|
(58 |
) |
|
|
(17 |
) |
Customer
Deposits
|
|
|
14
|
|
|
|
(189 |
) |
Accrued
Taxes, Net
|
|
|
49
|
|
|
|
90
|
|
Accrued
Interest
|
|
|
67
|
|
|
|
1
|
|
Other
Current Assets
|
|
|
(21 |
) |
|
|
19
|
|
Other
Current Liabilities
|
|
|
(210 |
) |
|
|
(216 |
) |
Net
Cash Flows From Operating Activities
|
|
|
969
|
|
|
|
1,123
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(1,823 |
) |
|
|
(1,611 |
) |
Change
in Other Temporary Investments, Net
|
|
|
(129 |
) |
|
|
3
|
|
Purchases
of Investment Securities
|
|
|
(6,827 |
) |
|
|
(5,647 |
) |
Sales
of Investment Securities
|
|
|
7,035
|
|
|
|
5,596
|
|
Acquisition
of Darby and Lawrenceburg Plants
|
|
|
(427 |
) |
|
|
-
|
|
Proceeds
from Sales of Assets
|
|
|
74
|
|
|
|
118
|
|
Other
|
|
|
(30 |
) |
|
|
(31 |
) |
Net
Cash Flows Used For Investing Activities
|
|
|
(2,127 |
) |
|
|
(1,572 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Common Stock
|
|
|
90
|
|
|
|
6
|
|
Change
in Short-term Debt, Net
|
|
|
420
|
|
|
|
147
|
|
Issuance
of Long-term Debt
|
|
|
1,064
|
|
|
|
1,081
|
|
Retirement
of Long-term Debt
|
|
|
(190 |
) |
|
|
(676 |
) |
Dividends
Paid on Common Stock
|
|
|
(311 |
) |
|
|
(291 |
) |
Other
|
|
|
(44 |
) |
|
|
30
|
|
Net
Cash Flows From Financing Activities
|
|
|
1,029
|
|
|
|
297
|
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(129 |
) |
|
|
(152 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
301
|
|
|
|
401
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
172
|
|
|
$ |
249
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
304
|
|
|
$ |
316
|
|
Net
Cash Paid for Income Taxes
|
|
|
128
|
|
|
|
123
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
23
|
|
|
|
37
|
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
295
|
|
|
|
273
|
|
Acquisition
of Nuclear Fuel in Accounts Payable at June 30,
|
|
|
31
|
|
|
|
26
|
|
Noncash
Assumption of Liabilities Related to Acquisitions
|
|
|
5
|
|
|
|
-
|
|
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 Six Months Ended June 30, 2007 and 2006
(in
millions)
(Unaudited)
|
|
Common
Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Paid-in
Capital
|
|
|
Retained
Earnings
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
Total
|
|
DECEMBER
31, 2005
|
|
|
415
|
|
|
$ |
2,699
|
|
|
$ |
4,131
|
|
|
$ |
2,285
|
|
|
$ |
(27 |
) |
|
$ |
9,088
|
|
Issuance
of Common Stock
|
|
|
|
|
|
|
1
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(291 |
) |
|
|
|
|
|
|
(291 |
) |
Other
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,805
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
|
|
|
|
54
|
|
Securities
Available for Sale, Net of Tax of $6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
|
11
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
556
|
|
|
|
|
|
|
|
556
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
621
|
|
JUNE
30, 2006
|
|
|
415
|
|
|
$ |
2,700
|
|
|
$ |
4,138
|
|
|
$ |
2,550
|
|
|
$ |
38
|
|
|
$ |
9,426
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
16
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
|
|
90
|
|
Common
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(311 |
) |
|
|
|
|
|
|
(311 |
) |
Other
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Loss), Net of Tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
|
15
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
451
|
|
|
|
|
|
|
|
451
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
472
|
|
JUNE
30, 2007
|
|
|
421
|
|
|
$ |
2,734
|
|
|
$ |
4,305
|
|
|
$ |
2,819
|
|
|
$ |
(202 |
) |
|
$ |
9,656
|
|
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 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 six months ended
June 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 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 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:
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
Components
|
|
(in
millions)
|
|
Securities
Available for Sale, Net of Tax
|
|
$ |
13
|
|
|
$ |
18
|
|
Cash
Flow Hedges, Net of Tax
|
|
|
9
|
|
|
|
(6
|
)
|
SFAS
158 Costs, Net of Tax
|
|
|
(224 |
) |
|
|
(235
|
)
|
Total
|
|
$ |
(202 |
) |
|
$ |
(223
|
)
|
At
June
30, 2007, during the next twelve months, we expect to reclassify approximately
$20 million of net gains from cash flow hedges in AOCI to Net Income during
the
next twelve months at the time the hedged transactions affect Net
Income. The actual amounts that are reclassified from AOCI to Net
Income can differ as a result of market fluctuations.
At
June
30, 2007, thirty-six 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 June 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
|
$/share
|
|
|
|
|
|
$/share
|
|
Earnings
Applicable to Common Stock
|
|
$ |
180
|
|
|
|
|
|
$ |
175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Basic Shares Outstanding
|
|
|
398.7
|
|
|
$ |
0.45
|
|
|
|
393.7
|
|
|
$ |
0.44
|
|
Average
Dilutive Effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
0.6
|
|
|
|
-
|
|
|
|
1.4
|
|
|
|
-
|
|
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
|
|
|
399.9
|
|
|
$ |
0.45
|
|
|
|
395.5
|
|
|
$ |
0.44
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
|
$/share
|
|
|
|
|
|
$/share
|
|
Earnings
Applicable to Common Stock
|
|
$ |
451
|
|
|
|
|
|
$ |
556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Basic Shares Outstanding
|
|
|
398.0
|
|
|
$ |
1.13
|
|
|
|
393.7
|
|
|
$ |
1.41
|
|
Average
Dilutive Effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Share Units
|
|
|
0.6
|
|
|
|
-
|
|
|
|
1.4
|
|
|
|
-
|
|
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
|
|
|
399.2
|
|
|
$ |
1.13
|
|
|
|
395.5
|
|
|
$ |
1.41
|
|
The
assumed conversion of our share-based compensation does not affect net earnings
for purposes of calculating diluted earnings per share as of June 30,
2007.
Options
to purchase 0.1 million and 4.3 million shares of common stock were outstanding
at June 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
June
30,
|
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Related
Party Transactions
|
|
(in
millions)
|
|
|
(in
millions)
|
|
AEP
Consolidated Purchased Energy:
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
Valley Electric Corporation (43.47% Owned)
|
|
$ |
56
|
|
|
$ |
58
|
|
|
$ |
105
|
|
|
$ |
113
|
|
Sweeny
Cogeneration Limited Partnership (50% Owned)
|
|
|
29
|
|
|
|
28
|
|
|
|
59
|
|
|
|
62
|
|
AEP
Consolidated Other Revenues – Barging and Other Transportation
Services – Ohio Valley Electric Corporation (43.47%
Owned)
|
|
|
8
|
|
|
|
8
|
|
|
|
17
|
|
|
|
15
|
|
AEP
Consolidated Revenues – Utility Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
Pool Purchases – Ohio Valley Electric Corporation
(43.47%
Owned)
|
|
|
(4 |
) |
|
|
-
|
|
|
|
(4 |
) |
|
|
-
|
|
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 $13 million
for the three and six months ended June 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 $11
million and $16 million for the three and six months ended June 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 and an entity include its own credit standing in the
measurement of its liabilities and modifies the transaction price
presumption.
SFAS
157
is effective for interim and annual periods in fiscal years beginning after
November 15, 2007. We expect that the adoption of this standard will
impact MTM valuations of certain contracts, but we are unable to quantify the
effect. Although the statement is applied prospectively upon
adoption, the effect of certain transactions is applied retrospectively as
of
the beginning of the fiscal year of application, with a cumulative effect
adjustment to the appropriate balance sheet items. We will adopt SFAS
157 effective January 1, 2008.
SFAS
159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS
159)
In
February 2007, the FASB issued SFAS 159, permitting entities to choose to
measure many financial instruments and certain other items at fair
value. The standard also establishes presentation and disclosure
requirements designed to facilitate comparison between entities that choose
different measurement attributes for similar types of assets and
liabilities.
SFAS
159
is effective for annual periods in fiscal years beginning after November 15,
2007. If the fair value option is elected, the effect of the first
remeasurement to fair value is reported as a cumulative effect adjustment to
the
opening balance of retained earnings. If we elect the fair value
option promulgated by this standard, the valuations of certain assets and
liabilities may be impacted. The statement is applied prospectively
upon adoption. We will adopt SFAS 159 effective January 1,
2008. 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 effect 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”
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 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
In
January 2007, CSPCo and OPCo filed with the PUCO under the 4% provision of
their
RSPs to increase their annual generation rates for 2007 by $24 million and
$8
million, respectively, to recover governmentally-mandated
costs. Pursuant to the RSPs, CSPCo and OPCo implemented these
proposed increases effective with the first billing cycle in May
2007. These increases are subject to refund until the PUCO issues a
final order in the matter. The PUCO staff and intervenors have
proposed disallowances. The revenues collected, subject to refund,
are immaterial through June 30, 2007. Management is unable to
determine the impact, if any, of potential refunds or rider reductions on future
results of operations and cash flows. The hearing is completed
and initial post-hearing and reply briefs have been filed. A final
order is expected in late third quarter or early fourth quarter of
2007.
In
March
2007, CSPCo filed an application under the 4% provision of the RSP to adjust
the
Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in
connection with CSPCo's acquisition of Monongahela Power Company's certified
territory in Ohio and a new purchase power contract to serve the
load. 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 Supreme Court
indicated concern with the absence of a competitive bid process as an
alternative to the generation rates set by the RSP. In response, the
settling parties agreed to have CSPCo and OPCo take bids for Renewable Energy
Certificates (RECs). CSPCo and OPCo will give customers the option to
pay a generation rate premium that would encourage the development of renewable
energy sources by reimbursing CSPCo and OPCo for the cost of the RECs and the
administrative costs of the program. 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. The settlement, as
approved, fully compensates CSPCo and OPCo regarding the cost of the
program.
CSPCo
and
OPCo are involved in discussions with various stakeholders in Ohio regarding
potential legislation to address the period following the expiration of the
RSPs
on December 31, 2008. At this time, management is unable to predict
whether CSPCo and OPCo will transition to market pricing, as permitted by the
current Ohio restructuring legislation, extend their RSP rates, with or without
modification, or become subject to a legislative reinstatement of some form
of
cost-based regulation for their generation supply business on January 1, 2009
when the RSP period ends.
Customer
Choice Deferrals
As
provided in the restructuring settlement agreement approved by the PUCO in
2000,
CSPCo and OPCo established regulatory assets for customer choice implementation
costs and related carrying costs in excess of $20 million each for recovery
in
the next general base rate filing which changes distribution rates after
December 31, 2007 for OPCo and December 31, 2008 for
CSPCo. Pursuant to the RSPs, recovery of these amounts for OPCo
was further deferred until the next base rate filing to change distribution
rates after the end of the RSP period of December 31, 2008. Through
June 30, 2007, CSPCo and OPCo incurred $51 million and $52 million,
respectively, of such costs and established regulatory assets of $25 million
and
$26 million, respectively, for such costs. CSPCo and OPCo each have
not recognized $6 million of equity carrying costs, which are recognizable
when
collected. In 2007, CSPCo and OPCo incurred $2 million each of such
costs and established regulatory assets of $1 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 will 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 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 June
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. CSPCo and OPCo expect to incur additional pre-construction
costs equal to or greater than the $12 million each recovered. As of
June 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each
for
the over-recovered portion. The PUCO indicated that if CSPCo and OPCo
have not commenced a continuous course of construction of the IGCC plant within
five years of the June 2006 PUCO order, all amounts collected for
pre-construction costs, associated with items that may be utilized in IGCC
projects to be built by AEP 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 has scheduled 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 are $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. In July 2007,
CSPCo and OPCo filed a status report with the PUCO referencing APCo’s IGCC West
Virginia filing. See the “West Virginia IGCC Plant” section within
West Virginia Rate Matters of this note.
Distribution
Reliability Plan
In
January 2006, CSPCo and OPCo initiated a proceeding at the PUCO seeking a new
distribution rate rider to fund enhanced distribution reliability
programs. In the fourth quarter of 2006, as directed by the PUCO,
CSPCo and OPCo filed a proposed enhanced reliability plan. The plan
contemplated CSPCo and OPCo recovering approximately $28 million and $43
million, respectively, in additional distribution revenue during an eighteen
month period beginning July 2007. In January 2007, the Ohio
Consumers’ Counsel filed testimony, which argued that CSPCo and OPCo should be
required to improve distribution service reliability with funds from their
existing rates.
In
April
2007, CSPCo and OPCo filed a joint motion with the PUCO staff, the Ohio
Consumers’ Counsel, the Appalachian People’s Action Coalition, the Ohio Partners
for Affordable Energy and the Ohio Manufacturers Association to withdraw the
proposed enhanced reliability plan. 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, under a PUCO-encouraged settlement
agreement. The settlement agreement between CSPCo and OPCo, Ormet,
its employees’ union and certain other interested parties was approved by the
PUCO in November 2006. The settlement agreement provides for
the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between $43
per MWH to be paid by Ormet for power and a PUCO-approved market price, if
higher. The recovery will be accomplished by the amortization of a
$57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise
tax
phase-out regulatory liability recorded in 2005 and, if that is insufficient,
an
increase in RSP generation rates under the additional 4% provision of the
RSPs. The $43 per MWH price to be paid by Ormet for generation
services is above the industrial RSP generation tariff but below current market
prices. In December 2006, CSPCo and OPCo submitted a market price of
$47.69 per MWH for 2007, which was approved by the PUCO in June
2007. CSPCo and OPCo have each amortized $3 million of their Ohio
Franchise Tax phase-out tax regulatory liability to income through June 30,
2007. If the PUCO approves a lower-than-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, which could have an adverse effect on future results of
operations and cash flows.
Texas
Rate Matters
TCC
TEXAS RESTRUCTURING
Texas
District Court Appeal Proceedings
TCC
recovered its net recoverable stranded generation costs through a securitization
financing and is refunding its net other true-up items through a CTC rate rider
credit under 2006 PUCT orders. TCC appealed the PUCT stranded costs
true-up orders seeking relief in both state and federal court on the grounds
that certain aspects of the orders are contrary to the Texas Restructuring
Legislation, PUCT rulemakings 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 cost, and
|
·
|
The
two federal matters regarding the allocation of off-system sales
related
to fuel recoveries and the potential tax normalization
violation. See “TCC 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 orders seeking
to
further reduce TCC’s true-up recoveries. In March 2007, the Texas
District Court judge hearing the various appeals 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 invalidated 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 rulings to the Court of
Appeals. Management cannot predict the outcome of these
proceedings. If TCC ultimately succeeds in its appeals, it could have
a favorable effect on future results of operations, cash flows and financial
condition. If municipal customers and other intervenors succeed in
their appeals, 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 net regulatory assets
and the amount to be securitized by $51 million related to the present value
of
ADITC and by $10 million related to EDFIT associated with TCC’s generation
assets for a total reduction of $61 million.
TCC
filed
a request for a private letter ruling with the IRS in June 2005 regarding the
permissibility under the IRS rules and regulations of the ADITC and EDFIT
reduction proposed by the PUCT. The IRS issued its private letter
ruling in May 2006, which stated that the PUCT’s flow-through to customers of
the present value of the ADITC and EDFIT benefits would result in a
normalization violation. To address the matter and avoid a 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 results of operations and cash flows. However, if
such refund of ADITC and EDFIT is ultimately determined to cause a normalization
violation, TCC anticipates it will be permitted to retain the $61 million
present value of ADITC and EDFIT plus carrying costs, favorably impacting future
results of operations 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 June 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 returned to
ratepayers under a nonappealable order. 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. 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. In TNC’s case, the Court of
Appeals affirmed the District Court’s decision. In April 2007,
the PUCT petitioned the United States Supreme Court for a review of the Court
of
Appeals’ order. If the PUCT’s appeals are ultimately unsuccessful,
TCC and TNC could record income of $16 million and $8 million, respectively,
related to the reversal of the previously-recorded fuel over-recovery regulatory
liabilities related to the reallocation of off-system sales margins to TCC
and
TNC.
If
the
PUCT is unsuccessful in the federal court system, it or another interested
party
may file a complaint at the FERC to address the allocation issue. If
a complaint at the FERC results in the PUCT’s decisions being adopted by the
FERC, there could be an adverse effect on results of operations and cash
flows. An unfavorable FERC ruling may result in a retroactive
reallocation of off-system sales margins from AEP East companies to AEP West
companies under the then-existing SIA allocation method. If the
adjustments were applied retroactively, the AEP East companies may be unable
to
recover the amounts reallocated to the West companies from their customers
due
to past frozen rates, past inactive fuel clauses and fuel clauses that do not
include off-system sales credits. Although management cannot predict
the ultimate outcome of this federal litigation, management believes that the
allocations were in accordance with the then-existing FERC-approved SIA and
that
it should not be expected to reallocate additional off-system sales margins
to
the West companies including TCC and TNC.
In
January 2007, TCC began refunding as part of the CTC rate rider credit, $149
million of its $165 million over-recovered deferred fuel regulatory
liability. The remaining $16 million refund related to the favorable
Federal District Court order has been deferred pending the outcome of the
federal court appeal and would be subject to refund only upon a successful
appeal by the PUCT.
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 excess earnings
prior to and outside of the true-up process was unlawful under the Texas
Restructuring Legislation. TCC refunded $55 million of excess
earnings, including interest, of which $30 million went to the affiliated
REP. In November 2005, the PUCT filed a petition for review with the
Supreme Court of Texas seeking reversal of the Texas Court of Appeals’
decision. In June 2007, the Supreme Court of Texas declined the
petition for review. Certain intervenors have contended in the
stranded cost proceeding that a reduction to stranded cost is required, but
a
surcharge of unlawfully-refunded amounts is unnecessary. TCC believes it has
properly reflected the effects of the Court of Appeals’ ruling and the PUCT’s
rules on stranded costs. However, a ruling in favor of the intervenor’s position
could have a material adverse effect on future results of operations and cash
flow.
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 June 30, 2007, TCC has
recorded a $3 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 $3 million recorded liability, it would have an adverse
effect on future results of operations and cash flow.
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 include a return
on common equity of 11.25% and a favorable impact of an expiration of the CSW
merger savings rate credits (merger credits). In March 2007, various
intervenors and the PUCT staff filed their recommendations. Though
the recommendations varied, the range of recommended increase was $8 million
to
$30 million for TCC. 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 in June 2007. TCC was unable to settle
its proceeding.
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 June 2007, an ALJ issued
an interim order affirming the termination of the merger credits. The
PUCT affirmed the ALJ ruling. Management has evaluated its exposure
to a future refund of revenues being collected, subject to refund, and believes
it is recognizing a reasonable amount of such revenues. A decision
from the PUCT is expected in the third quarter of 2007. Management is
unable to predict the ultimate effect of this filing and any true-up of
recognized revenues collected, subject to refund, on future results of
operations, cash flows and financial condition.
SWEPCo
Fuel Reconciliation – Texas
In
June
2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas
retail operations 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
as a result of reflecting the ALJ’s decision. In July 2007, the PUCT
orally affirmed the ALJ report. A final order is expected in the
third quarter of 2007. Management is unable to predict the ultimate
outcome of this proceeding or its additional effect on future results of
operations and cash flows.
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 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, as a result of reflecting
this decision on its books. The Supreme Court of Texas has remanded
this issue to the PUCT. If the PUCT adopts a higher 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
on future results of operations and cash flows.
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 practice
deferred fuel accounting. Also, under the amended restructuring law,
APCo has the right to defer incremental environmental compliance costs and
incremental E&R costs for future recovery, to the extent such costs are not
being recovered, and amortizes a portion of such deferrals commensurate with
their recovery.
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.
With
the
return of cost-based regulation, APCo’s generation business again meets 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 primarily 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 the fuel factor where
they can be trued-up to actual. APCo also proposed to share the
off-system sales margins with customers with 40% going to reduce rates and
60%
being retained by APCo. This proposed off-system sales fuel rate
credit, which 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. The major components of the $225 million
base rate request included $73 million for the impact of removing off-system
sales margins from the rate year ending September 30, 2007, $60 million mainly
due to projected net environmental plant additions through September 30, 2007
and $48 million for return on equity.
In
May
2006, the Virginia SCC issued an order, consistent with Virginia law, placing
the net requested base rate increase of $198 million into effect on October
2,
2006, subject to refund. The $198 million base rate increase that was
collected, subject to refund, includes recovery of incremental E&R costs
projected to be incurred during the rate year beginning October
2006. These incremental E&R costs can be deferred and recovered
through the E&R surcharge mechanism if not recovered through base
rates. In October 2006, the Virginia SCC staff filed its direct
testimony recommending a base rate increase of $13 million with a return on
equity of 9.9% and no off-system sales margin sharing. Other
intervenors recommended base rate increases ranging from $42 million to $112
million. APCo filed rebuttal testimony in November
2006. Hearings were held in December 2006.
In
March
2007, the Hearing Examiner issued a report recommending a $76 million increase
in APCo’s base rates and a $45 million credit to the fuel factor for off-system
sales margins resulting in a net $31 million recommended rate
increase. 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. The final order approved a return on equity of 10.0%
and limited forward-looking ratemaking adjustments to June 30, 2006 as opposed
to September 30, 2007 as proposed. In addition, the final order
excluded a portion of APCo's requested E&R costs in base
rates. However, APCo was able to defer unrecovered incremental
E&R costs incurred after October 1, 2006 and will recover those costs
through the E&R surcharge mechanism. The order also provided for
a retroactive annual reduction in depreciation to January 1, 2006 of
approximately $11 million per year and a deferral and recovery of ARO costs
over
10 years. The final order further provides that off-system sales
margins of $101 million be credited to customers through a separate base rate
margin rider which is not trued-up to actual margins. The final order
did not implement the minimum 25% sharing percentage for off-system sales
margins embodied in the new re-regulation legislation, which is effective with
the first fuel clause filing after July 1, 2007. This sharing
requirement in the new re-regulation legislation also includes a
true-up to actual off-system sales margins.
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. In addition to the favorable effect of the base rate
increase in the second half of 2007, APCo expects to defer for future recovery
unrecovered incremental E&R costs incurred of $20 million to $25 million and
reduce depreciation and amortization expense by a net $5
million. APCo will complete the refund by August
2007. APCo’s Other Current Liabilities includes accrued refunds of
$127 million and $22 million as of June 30, 2007 and December 31, 2006,
respectively. Management expects pretax earnings for 2007 to be
favorably affected by the ordered May 2007 rate increase.
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. APCo will
file for recovery in 2008 of E&R cost deferrals incurred and recorded after
September 30, 2006.
Virginia
Fuel Clause Filing
In
July
2007, APCo filed an application with the Virginia SCC to seek an increase,
effective September 1, 2007, to the current fuel factor of $33 million in
annualized revenue requirements 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 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.
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 a 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. See “West Virginia IGCC Plant”
section within West Virginia Rate Matters below.
West
Virginia Rate Matters
APCo
and WPCo ENEC Filing
In
April
2007, the WVPSC issued an order establishing an investigation and hearing
concerning APCo’s and WPCo’s 2007 Expanded Net Energy Cost (ENEC) compliance
filing. The ENEC is an expanded form of fuel clause mechanism, which
includes all energy-related costs including fuel, purchased power expenses,
off-system sales credits and other energy/transmission
items. In the March 2007 ENEC joint filing, APCo and WPCo filed
for an increase of approximately $101 million including a $72 million increase
in ENEC and a $29 million increase in construction 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 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 June 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 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 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. As proposed, the book depreciation reduction
would increase earnings, but would not impact cash flows until rates are
revised. Base and fuel rates were frozen in Indiana through June 30,
2007. The IURC held a public hearing in April 2007. In
June 2007, the IURC approved the settlement agreement, but modified the
effective date of the new depreciation rates upon the filing by I&M of a
general rate petition. See “Indiana Rate Filing” section
below. On June 19, 2007, I&M and the OUCC notified the IURC the
parties would accept the modification to the settlement agreement and I&M
filed its rate petition.
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 depreciation
rates are subject to further review in the general rate
case. I&M’s earnings will continue to benefit until the base
rates are revised to include lower depreciation rates, at which time cash flows
will be adversely affected. Management expects new base rates will
become effective in late 2008 or 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 AEP Power Pool capacity
settlements, PJM RTO costs, reliability enhancement costs, DSM/energy efficiency
program costs, off-system sales margins, and net environmental compliance
costs. The petition requests the IURC to approve the test year period
and the inclusion of the above trackers in the rate
filing. Management expects to file the case in late 2007 or early
2008 with a decision expected in late 2008 or early 2009.
Indiana
Rate Cap
Effective
July 1, 2007, I&M’s rate cap ended for both base and fuel
rates. I&M’s fuel factor 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 impacted by fuel costs.
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 and the Kentucky Industrial Utility
Consumers (KIUC) filed an appeal with the Kentucky Court of Appeals of the
Franklin Circuit Court’s 2006 order upholding the KPSC’s 2005 Environmental
Surcharge order. In 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 costs, via the
environmental surcharge, since the KPSC’s first environmental surcharge order in
1997. KPCo presently recovers $7 million a year in environmental
surcharge revenues.
In
March
2007, the KPSC issued an order, at the request of the Kentucky Attorney General,
stating the environmental surcharge collections authorized in the January 2007
order that are associated with out-of-state generating facilities should be
collected over the six months beginning March 2007, subject to refund, pending
the outcome of the Court of Appeals process. At this time, management
is unable to predict the outcome of this proceeding and its effect on KPCo’s
current environmental surcharge revenues or on the January 2007 KPSC order
increasing KPCo’s environmental rates. If the appeal is successful,
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 January 2006, the OCC staff and
intervenors issued supplemental testimony alleging that AEP deviated from the
FERC-approved method of allocating off-system sales margins between AEP East
companies and AEP West companies and among AEP West companies. The
OCC staff proposed that the OCC offset the $42 million of under-recovered fuel
with the proposed reallocation of off-system sales margins of $27 million to
$37
million and with $9 million of purchased power reallocation attributed to
wholesale customers, which they claimed had not been refunded. In
February 2006, the OCC staff filed a report concluding that the $9 million
of
reallocated purchased power costs assigned to wholesale customers had been
refunded, thus removing that issue from its recommendation.
In
2004,
an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO
deviated from the FERC-approved allocation methodology and held that any such
complaints should be addressed at the FERC. The OCC has not ruled on
appeals by intervenors of the ALJ’s finding. The United States
District Court for the Western District of Texas issued orders in September
2005
regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel
proceeding, preempting the PUCT from reallocating off-system sales margins
between the AEP East companies and AEP West companies. The federal
court agreed that the FERC has sole jurisdiction over that
allocation. The PUCT appealed the ruling. The United States Court of
Appeals for the Fifth Circuit, issued a decision in December 2006 regarding
the
TNC fuel proceeding that affirmed the United States District Court
ruling. In April 2007, the PUCT petitioned the United States Supreme
Court for a review of the Court of Appeal’s order.
PSO
does
not agree with the intervenors’ and the OCC staff’s recommendations and
proposals other than the staff’s original recommendation that PSO be allowed to
recover the $42 million over three years and will defend its right to recover
its under-recovered fuel balance. Management believes that if the
position taken by the federal courts in the Texas proceeding is applied to
PSO’s
case, then the OCC should be preempted from disallowing fuel recoveries for
alleged improper allocations of off-system sales margins between AEP East
companies and AEP West companies. The OCC or another party could file
a complaint at the FERC alleging the allocation of off-system sales margins
to
PSO is improper, which could result in an adverse effect on future results
of
operations and cash flows for AEP and the AEP East
companies. However, to date, there has been no claim asserted at the
FERC that AEP deviated from the FERC approved allocation methodologies, but
even
if one were asserted, management believes that the OCC or another party would
not prevail.
In
June
2005, the OCC issued an order directing its staff to conduct a prudence review
of PSO’s fuel and purchased power practices for the year 2003. The
OCC staff filed testimony finding no disallowances in the test year
data. The Attorney General of Oklahoma filed testimony stating that
they could not determine if PSO’s gas procurement activities were prudent, but
did not include a recommended disallowance. However, an intervenor
filed testimony in June 2006 proposing the disallowance of $22 million in fuel
costs based on a historical review of potential hedging opportunities that
he
alleges existed during the year. A hearing was held in August 2006
and management expects a recommendation from the ALJ in the second half of
2007.
In
February 2006, a law was enacted requiring the OCC to conduct prudence reviews
on all generation and fuel procurement processes, practices and costs on either
a two or three-year cycle depending on the number of customers
served. PSO is subject to the required biennial
reviews. PSO filed its testimony in June 2007 covering the year
2005.
In
May
2007, PSO filed an application 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 current $48 million
over-recovered fuel balance. In oral discussions, the OCC staff did
not oppose the netting of the balances. The $6 million net
over-recovered fuel/purchased power cost deferral balance will be refunded
over
the twelve month period beginning June 2007. To date, no party has
objected to the offset.
Management
cannot predict the outcome of the pending fuel and purchased power costs and
prudence reviews, planned future reviews or the current fuel adjustment clause
filing, but believes that PSO’s fuel and purchased power procurement practices
and costs are prudent and properly incurred. If the OCC disagrees and
disallows fuel or purchased power costs including the pre-2002 reallocation
of
purchased power costs incurred by PSO, it would have an adverse effect on future
results of operations and cash flows.
Oklahoma
Rate Filing
In
November 2006, PSO filed a request to increase base rates by $50 million for
Oklahoma jurisdictional customers with a proposed effective date in the second
quarter of 2007. PSO sought a return on equity of
11.75%. PSO also proposed a formula rate plan that, if approved as
filed, will permit PSO to defer any unrecovered costs as a result of a revenue
deficiency that exceeds 50 basis points of the allowed return on equity for
recovery within twelve months beginning six months after the test
year. The 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 time period to be recovered in the future through
depreciation expense.
In
March
2007, the OCC staff and various intervenors filed testimony. The
recommendations were base rate reductions that ranged from $18 million to $52
million. The recommended returns on equity ranged from 9.25% to
10.09%. These recommendations included reductions in depreciation
expense of approximately $25 million, which has no earnings
impact. The OCC staff filed testimony supporting a formula rate plan,
generally similar to the one proposed by PSO. In April 2007, PSO
filed rebuttal testimony regarding various issues raised by the OCC staff and
the intervenors. In connection with the filing of rebuttal testimony,
PSO reduced its base rate request by $2 million. 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 the coal-fueled
generating unit. The OCC’s discussions during deliberations have
centered around a return on equity of 9.75%. PSO implemented interim
rates, subject to refund, for residential customers beginning July
2007. The interim rate implements a key provision of the rate case on
which there seems to be agreement at the OCC, and is estimated to increase
revenues by approximately $4 million in 2007 and $9 million on an annual
basis. Other components of the rate case will be implemented once the
OCC issues a final order, which is expected in early August 2007.
Management
is unable to predict the final outcome of these proceedings. However, if rates
are not increased in an amount sufficient to recover expected unavoidable cost
increases, future results of operations, cash flows and possibly financial
condition could be adversely affected.
Lawton
and Peaking Generation Settlement Agreement
On
November 26, 2003, pursuant to an application by Lawton Cogeneration, L.L.C.
(Lawton) seeking approval of a Power Supply Agreement (the Agreement) with
PSO
and associated avoided cost payments, the OCC issued an order approving the
Agreement and setting the avoided costs.
In
December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme
Court (the Court). In the appeal, PSO maintained that the OCC
exceeded its authority under state and federal laws to require PSO to enter
into
the Agreement. The Court issued a decision on June 21, 2005,
affirming portions of the OCC’s order and remanding certain
provisions. The Court affirmed the OCC’s finding that Lawton
established a legally-enforceable obligation and ruled that it was within the
OCC’s discretion to award a 20-year contract and to base the capacity payment on
a peaking unit. The Court directed the OCC to revisit its
determination of PSO’s avoided energy cost. Hearings were held on the remanded
issues in April and May 2006.
In
April
2007, all parties in the case filed a settlement agreement with the OCC
resolving all issues. The OCC approved the settlement agreement in April
2007. The 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. 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. Once the cost recovery for the new
peaking units begins in mid-2008, PSO expects annual revenues of an estimated
$36 million related to cost recovery of the peaking units and the purchase
fee.
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
jurisdiction customers, based on a proposed 10% return on equity. The
recommended reduction range is subject to SWEPCo validating certain ongoing
operations and maintenance expense levels. SWEPCo filed rebuttal
testimony in October 2006 strongly refuting the consultants’
recommendations. In December 2006, the LPSC staff’s consultants filed
reply testimony asserting that SWEPCo’s Louisiana base rates are excessive by
$17 million which includes a proposed return on equity of
9.8%. SWEPCo filed rebuttal testimony in January
2007. 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.
FERC
Rate Matters
Transmission
Rate Proceedings at the FERC
The
FERC PJM Regional Transmission Rate Proceeding
At
AEP’s
urging, the FERC instituted an investigation of PJM’s zonal rate regime,
indicating that the present rate regime may need to be replaced through
establishment of regional rates that would compensate AEP and other transmission
owners for the regional transmission facilities they provide to PJM, which
provides service for the benefit of customers throughout PJM. In
September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly
filed a regional transmission rate design proposal with the
FERC. This filing proposed and supported a new PJM rate regime
generally referred to as a Highway/Byway rate design.
Parties
to the regional rate proceeding proposed the following rate
regimes:
·
|
AEP/AP
proposed a Highway/Byway rate design in which:
|
|
·
|
The
cost of all transmission facilities in the PJM region operated at
345 kV
or higher would be included in a “Highway” rate that all load serving
entities (LSEs) would pay based on peak demand. The AEP/AP
proposal would produce about $125 million in net revenues per year
for AEP
from users in other zones of PJM.
|
|
·
|
The
cost of transmission facilities operating at lower voltages would
be
collected in the zones where those costs are presently charged under
PJM’s
existing rate design.
|
·
|
Two
other utilities, Baltimore Gas & Electric Company (BG&E) and Old
Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate
that
includes transmission facilities above 200 kV in the Highway rate,
which
would have produced lower net revenues for AEP than the AEP/AP
proposal.
|
·
|
In
another competing Highway/Byway proposal, a group of LSEs proposed
rates
that would include existing 500 kV and higher voltage facilities
and new
facilities above 200 kV in the Highway rate, which would also have
produced lower net revenues for AEP than the AEP/AP
proposal.
|
·
|
In
January 2006, the FERC staff issued testimony and exhibits supporting
phase-in of a PJM-wide flat rate or “Postage Stamp” type of rate design
that would socialize the cost of all transmission facilities. The
proposed
rate design would have initially produced much lower net transmission
revenues for AEP than the AEP/AP proposal, but could produce slightly
higher net revenues when fully phased
in.
|
All
of
these proposals were challenged by a majority of other transmission owners
in
the PJM region, who favored continuation of the existing PJM rate design which
provides AEP with no compensation for through and out traffic on its east zone
transmission system. Hearings were held in April 2006 and the ALJ
issued an initial decision in July 2006. The ALJ found the existing
PJM zonal rate design to be unjust and determined that it should be
replaced. The ALJ found that the Highway/Byway rates proposed by
AEP/AP and BG&E/ODEC to be just and reasonable alternatives. The
ALJ also found FERC staff’s proposed Postage Stamp rate to be just and
reasonable and recommended that it be adopted. The ALJ also found
that the effective date of the rate change should be April 1, 2006 to coincide
with SECA rate elimination. Because the Postage Stamp rate was found
to produce greater cost shifts than other proposals, the judge also recommended
that the new regional design be phased-in. Without a phase-in, the
Postage Stamp method would produce more revenue for AEP than the AEP/AP
proposal. However, the proposed phase-in of Postage Stamp rates would delay
the
full favorable impact of those new regional rates until about 2012.
AEP
filed
briefs noting exceptions to the initial decision and replies to the exceptions
of other parties. AEP argued that a phase-in should not be
required. Nevertheless, AEP argued that if the FERC adopts the
Postage Stamp rate and a phase-in plan, the revenue collections curtailed by
the
phase-in should be deferred and paid later with interest.
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 and Michigan
to recover lost through-and-out transmission service (T&O) and SECA
revenues.
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 although others use them. 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 their future construction of new east transmission
facilities, results of operations, cash flows and financial
condition.
The
AEP
East companies presently recover from retail customers approximately 85% of
the
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 and Michigan until
these lost T&O/SECA transmission revenues are recovered in retail
rates.
SECA
Revenue Subject to Refund
The
AEP
East companies ceased collecting T&O revenues in accordance with FERC
orders, and collected SECA rates to mitigate the loss of T&O revenues from
December 1, 2004 through March 31, 2006, when SECA rates
expired. Intervenors objected to the SECA rates, raising various
issues. As a result, the FERC set SECA rate issues for hearing and
ordered that the SECA rate revenues be collected, subject to refund or
surcharge. The AEP East companies paid SECA rates to other utilities
at considerably lesser amounts than collected. If a refund is
ordered, the AEP East companies would also receive refunds related to the SECA
rates they paid to third parties. The AEP East companies recognized
gross SECA revenues of $220 million. Approximately $19 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.
Since
the
implementation of SECA rates in December 2004, the AEP East companies recorded
approximately $220 million of gross SECA revenues, subject to
refund. In 2006, the AEP East companies provided reserves of $37
million in net refunds for current and future SECA settlements with all of
AEP’s
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 will be
adequate.
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 and cash flows.
PSO
and SWEPCo 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 of 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. FERC could suspend the effective date until February 1,
2008. 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 Zone. 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 rates resulting from
the
filing, but will receive corresponding revenue to offset the
increase. This filing will not directly impact retail
rates.
4.
|
COMMITMENTS,
GUARANTEES AND
CONTINGENCIES
|
We
are
subject to certain claims and legal actions arising in our ordinary course
of
business. In addition, our business activities are subject to
extensive governmental regulation related to public health and the
environment. The ultimate outcome of such pending or potential
litigation against us cannot be predicted. For current proceedings
not specifically discussed below, management does not anticipate that the
liabilities, if any, arising from such proceedings would have a material adverse
effect on our financial statements. The Commitments, Guarantees and
Contingencies note within our 2006 Annual Report should be read in conjunction
with this report.
GUARANTEES
There
are
certain immaterial liabilities recorded for guarantees in accordance with FASB
Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others.” There is no collateral held in relation to any guarantees in
excess of our ownership percentages. In the event any guarantee is
drawn, there is no recourse to third parties unless specified
below.
Letters
of Credit
We
enter
into standby letters of credit (LOCs) with third parties. These LOCs
cover items such as gas and electricity risk management contracts, construction
contracts, insurance programs, security deposits, debt service reserves and
credit enhancements for issued bonds. As the parent company, we
issued all of these LOCs in our ordinary course of business on behalf of our
subsidiaries. At June 30, 2007, the maximum future payments for all
the LOCs were approximately $27 million with maturities ranging from July 2007
to July 2008.
Guarantees
of Third-Party Obligations
SWEPCo
As
part
of the process to receive a renewal of a Texas Railroad Commission permit for
lignite mining, SWEPCo provides guarantees of mine reclamation in the amount
of
approximately $85 million. Since SWEPCo uses self-bonding, the
guarantee provides for SWEPCo to commit to use its resources to complete the
reclamation in the event the work is not completed by Sabine Mining Company
(Sabine), an entity consolidated under FIN 46. This guarantee ends
upon depletion of reserves and completion of final reclamation. Based
on the latest study, we estimate the reserves will be depleted in 2029 with
final reclamation completed by 2036, at an estimated cost of approximately $39
million. As of June 30, 2007, SWEPCo has collected approximately $31
million through a rider for final mine closure costs, of which approximately
$14
million is recorded in Deferred Credits and Other and approximately $17 million
is recorded in Asset Retirement Obligations on our Condensed Consolidated
Balance Sheets.
Sabine
charges SWEPCo, its only customer, all 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 $1.9
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. At June 30, 2007, the maximum
potential loss for these lease agreements was approximately $59 million ($38
million, net of tax) assuming the fair market value of the equipment is zero
at
the end of the lease term.
Railcar
Lease
In
June
2003, we entered into an agreement with BTM Capital Corporation, as lessor,
to
lease 875 coal-transporting aluminum railcars. The lease has an
initial term of five years. At the end of each lease term, we may (a)
renew for another five-year term, not to exceed a total of twenty years; (b)
purchase the railcars for the purchase price amount specified in the lease,
projected at the lease inception to be the then fair market value; or (c) return
the railcars and arrange a third party sale (return-and-sale
option). The lease is accounted for as an operating
lease. We intend to renew the lease for the full twenty
years. This operating lease agreement allows us to avoid a large
initial capital expenditure and to spread our railcar costs evenly over the
expected twenty-year usage.
Under
the
lease agreement, the lessor is guaranteed that the sale proceeds under the
return-and-sale option discussed above will equal at least a lessee obligation
amount specified in the lease, which declines over the current lease term from
approximately 86% to 77% of the projected fair market value of the
equipment. At June 30, 2007, the maximum potential loss was
approximately $30 million ($20 million, net of tax) assuming the fair market
value of the equipment is zero at the end of the current lease
term. We have other railcar lease arrangements that do not utilize
this type of financing structure.
CONTINGENCIES
Federal
EPA Complaint and Notice of Violation
The
Federal EPA, certain special interest groups and a number of states allege
that
APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the
Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric
Company, Ohio Edison Company, Southern Indiana Gas & Electric Company,
Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company
and Duke Energy, modified certain units at coal-fired generating plants in
violation of the NSR requirements of the CAA. The Federal EPA filed
its complaints against our subsidiaries in U.S. District Court for the Southern
District of Ohio. The alleged modifications occurred at our
generating units over a 20-year period. A bench trial on the
liability issues was held during July 2005. In June 2006, the judge
stayed the liability decision pending the issuance of a decision by the U.S.
Supreme Court in the Duke Energy case.
Under
the
CAA, if a plant undertakes a major modification that results in an emissions
increase, permitting requirements might be triggered and the plant may be
required to install additional pollution control technology. This
requirement does not apply to routine maintenance, replacement of degraded
equipment or failed component or other repairs needed for the reliable, safe
and
efficient operation of the plant. The CAA authorizes civil penalties
of up to $27,500 ($32,500 after March 15, 2004) per day per violation at each
generating unit. In 2001, the District Court ruled claims for civil
penalties based on activities that occurred more than five years before the
filing date of the complaints cannot be imposed. There is no time
limit on claims for injunctive relief.
Cases
are
pending that could affect CSPCo’s share of jointly-owned units at Beckjord,
Zimmer, and Stuart Stations. Similar cases have been filed against
other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky
Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin
Electric Power Company, Mirant, NRG Energy and Niagara
Mohawk. Several of these cases were resolved through consent
decrees.
Courts
have reached different conclusions regarding whether the activities at issue
in
these cases are routine maintenance, repair or replacement, and therefore are
excluded from NSR. Similarly, courts have reached different results
regarding whether the activities at issue increased emissions from the power
plants. Appeals on these and other issues were filed in certain
appellate courts, including a petition to appeal to the U.S. Supreme Court
that
was granted in the Duke Energy case. The Federal EPA issued a final
rule that would exclude activities similar to those challenged in these cases
from NSR as “routine replacements.” In March 2006, the Court of
Appeals for the District of Columbia Circuit issued a decision vacating the
rule. The Court denied the Federal EPA’s request for rehearing, and
the Federal EPA and other parties filed a petition for review by the U.S.
Supreme Court. In April 2007, the Supreme Court denied the petition
for review. The Federal EPA also proposed a rule that would define
“emissions increases” in a way that most of the challenged activities would be
excluded from NSR.
On
April
2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’
decision that had supported the statutory construction argument of Duke Energy
in its NSR proceeding. In a unanimous decision, the Court ruled that
the Federal EPA was not obligated to define “major modification” in two
different CAA provisions in the same way. The Court also found that
the Fourth Circuit’s interpretation of “major modification” as applying only to
projects that increased hourly emission rates amounted to an invalidation of
the
relevant Federal EPA regulations, which under the CAA can only be challenged
in
the Court of Appeals within 60 days of the Federal EPA
rulemaking. The U.S. Supreme Court did acknowledge, however, that
Duke Energy may argue on remand that the Federal EPA has been inconsistent
in
its interpretations of the CAA and the regulations and may not retroactively
change 20 years of accepted practice.
In
addition to providing guidance on certain of the merits of the NSR proceedings
brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the
Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the
Duke Energy cases has an impact on the timing of our NSR
proceedings. The court that heard our trial on liability issues will
likely issue its decision during the third quarter of 2007. A bench
trial on remedy issues, if necessary, is likely to begin in 2007.
We
are
unable to estimate the loss or range of loss related to any contingent
liability, if any, we might have for civil penalties under the CAA
proceedings. We are also unable to predict the timing of resolution
of these matters due to the number of alleged violations and the significant
number of issues yet to be determined by the Court. If we do not
prevail, we believe we can recover any capital and operating costs of additional
pollution control equipment that may be required through regulated rates and
market prices of electricity. If we are unable to recover such costs
or if material penalties are imposed, it would adversely affect our future
results of operations, cash flows and possibly financial condition.
SWEPCo
Notice of Enforcement and Notice of Citizen Suit
In
March
2005, two special interest groups, Sierra Club and Public Citizen, filed a
complaint in Federal District Court for the Eastern District of Texas alleging
violations of the CAA at SWEPCo’s Welsh Plant. SWEPCo filed a
response to the complaint in May 2005. A trial in this matter is
scheduled for the third quarter of 2007.
In
2004,
the Texas Commission on Environmental Quality (TCEQ) issued a Notice of
Enforcement to SWEPCo relating to the Welsh Plant containing a summary of
findings resulting from a compliance investigation at the plant. In
April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition
recommending the entry of an enforcement order to undertake certain corrective
actions and assessing an administrative penalty of approximately $228 thousand
against SWEPCo based on alleged violations of certain representations regarding
heat input in SWEPCo’s permit application and the violations of certain
recordkeeping and reporting requirements. SWEPCo responded to the
preliminary report and petition in May 2005. The enforcement order
contains a recommendation limiting the heat input on each Welsh unit to the
referenced heat input contained within the permit application within 10 days
of
the issuance of a final TCEQ order and until a permit amendment is
issued. SWEPCo had previously requested a permit alteration to remove
the reference to a specific heat input value for each Welsh unit and to clarify
the sulfur content requirement for fuels consumed at the plant. A
permit alteration was issued in March 2007 removing the heat input references
from the Welsh permit and clarifying the sulfur content of fuels burned at
the
plant is limited to 0.5% on an as-received basis. The Sierra Club and
Public Citizen filed a motion to overturn the permit alteration. 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 our $123 million judgment for damages against TEM related to replacement
products and remanded the issue for further proceedings.
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
February 2007, the Judge in the New York action, after hearing oral argument
on
the motions for summary judgment, made a series of oral “informal findings” and
submitted a written memorandum to the parties’ counsel. In the
memorandum to counsel, the Judge stated that he was denying several of AEP’s
motions for partial summary judgment and granting several of BOA motions for
summary judgment. The substantive matters left open for further
proceedings include the issue of the nature of the gas subject to BOA security
interest and the value of that interest. The Judge stated that the
memorandum to counsel is not an opinion or an order, and that no opinion or
order will be issued until all motions pending before the Court have been
decided. The Judge heard additional arguments on the summary judgment
motions in March 2007. At this time we are unable to predict how the
Judge will rule on the pending motions due to the complexity of those issues
and
the parties’ disagreement over each issue. If the Judge issues a judgment
directing AEP to pay an amount in excess of the gain on the sale of HPL
described below and if AEP is unsuccessful in having the judgment reversed
or
modified, the judgment could have a material adverse effect on the results
of
operations, cash 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 June 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. Briefing of
this appeal was completed in December 2006. The Court of Appeals
heard oral argument in July 2007. 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. 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. In
May 2007, we, along with other sellers involved in the case, sought review
of
the Ninth Circuit’s decision by the U.S. Supreme Court. The Solicitor
General of the United States has asked the Supreme Court for an extension of
time, until August 6, 2007, to respond to the petitions for
review. 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 will sell the power to CSPCo through a FERC-approved
purchase power contract.
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.
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)
|
|
Three
Months Ended June 30,
|
|
(in
millions)
|
|
2007
Revenue
|
|
$
|
-
|
|
2007
Pretax Income
|
|
|
3
|
|
2007
Earnings, Net of Tax
|
|
|
2
|
|
|
|
|
|
|
2006
Revenue
|
|
$
|
-
|
|
2006
Pretax Income
|
|
|
4
|
|
2006
Earnings, Net of Tax
|
|
|
3
|
|
|
|
U.K.
Generation
(a)
|
|
Six
Months Ended June 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.
|
There
were no cash flows used for or provided by operating, investing or financing
activities related to our discontinued operations for the six months ended
June
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:
|
|
June
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 six months ended June 30, 2007 and 2006:
|
|
|
|
|
Other
|
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension
Plans
|
|
|
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Three
Months Ended June 30, 2007 and 2006
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
23
|
|
|
$ |
24
|
|
|
$ |
11
|
|
|
$ |
10
|
|
Interest
Cost
|
|
|
57
|
|
|
|
57
|
|
|
|
26
|
|
|
|
25
|
|
Expected
Return on Plan Assets
|
|
|
(82 |
) |
|
|
(83 |
) |
|
|
(26 |
) |
|
|
(23 |
) |
Amortization
of Transition Obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
7
|
|
|
|
7
|
|
Amortization
of Net Actuarial Loss
|
|
|
14
|
|
|
|
19
|
|
|
|
3
|
|
|
|
5
|
|
Net
Periodic Benefit Cost
|
|
$ |
12
|
|
|
$ |
17
|
|
|
$ |
21
|
|
|
$ |
24
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension
Plans
|
|
|
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Six
Months Ended June 30, 2007 and 2006
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
47
|
|
|
$ |
48
|
|
|
$ |
21
|
|
|
$ |
20
|
|
Interest
Cost
|
|
|
116
|
|
|
|
114
|
|
|
|
52
|
|
|
|
50
|
|
Expected
Return on Plan Assets
|
|
|
(167 |
) |
|
|
(166 |
) |
|
|
(52 |
) |
|
|
(46 |
) |
Amortization
of Transition Obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
14
|
|
|
|
14
|
|
Amortization
of Net Actuarial Loss
|
|
|
29
|
|
|
|
39
|
|
|
|
6
|
|
|
|
10
|
|
Net
Periodic Benefit Cost
|
|
$ |
25
|
|
|
$ |
35
|
|
|
$ |
41
|
|
|
$ |
48
|
|
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.
|
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 six
months ended June 30, 2007 and 2006 and balance sheet information as of June
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 June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$ |
2,818
|
|
|
$ |
116
|
|
|
$ |
218
|
|
|
$ |
(6 |
) |
|
$ |
-
|
|
|
$ |
3,146
|
|
Other
Operating Segments
|
|
|
136
|
|
|
|
3
|
|
|
|
(113 |
) |
|
|
12
|
|
|
|
(38 |
) |
|
|
-
|
|
Total
Revenues
|
|
$ |
2,954
|
|
|
$ |
119
|
|
|
$ |
105
|
|
|
$ |
6
|
|
|
$ |
(38 |
) |
|
$ |
3,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued
Operations
and Extraordinary Loss
|
|
$ |
238
|
|
|
$ |
7
|
|
|
$ |
15
|
|
|
$ |
(3 |
) |
|
$ |
-
|
|
|
$ |
257
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
2
|
|
Extraordinary
Loss, Net of Tax
|
|
|
(79 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(79 |
) |
Net
Income (Loss)
|
|
$ |
159
|
|
|
$ |
7
|
|
|
$ |
15
|
|
|
$ |
(1 |
) |
|
$ |
-
|
|
|
$ |
180
|
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
|
MEMCO
Operations
|
|
|
Generation
and
Marketing
|
|
|
All
Other (a)
|
|
|
Reconciling
Adjustments
|
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Three
Months Ended June 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$ |
2,799
|
|
|
$ |
117
|
|
|
$ |
20
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
2,936
|
|
Other
Operating Segments
|
|
|
(3 |
) |
|
|
2
|
|
|
|
-
|
|
|
|
15
|
|
|
|
(14 |
) |
|
|
-
|
|
Total
Revenues
|
|
$ |
2,796
|
|
|
$ |
119
|
|
|
$ |
20
|
|
|
$ |
15
|
|
|
$ |
(14 |
) |
|
$ |
2,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued
Operations
|
|
$ |
159
|
|
|
$ |
14
|
|
|
$ |
2
|
|
|
$ |
(3 |
) |
|
$ |
-
|
|
|
$ |
172
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
3
|
|
Net
Income
|
|
$ |
159
|
|
|
$ |
14
|
|
|
$ |
2
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
175
|
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
|
MEMCO
Operations
|
|
|
Generation
and
Marketing
|
|
|
All
Other (a)
|
|
|
Reconciling
Adjustments
|
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$ |
5,704
|
|
|
$ |
233
|
|
|
$ |
333
|
|
|
$ |
45
|
|
|
$ |
-
|
|
|
$ |
6,315
|
|
Other
Operating Segments
|
|
|
283
|
|
|
|
6
|
|
|
|
(186 |
) |
|
|
(33 |
) |
|
|
(70 |
) |
|
|
-
|
|
Total
Revenues
|
|
$ |
5,987
|
|
|
$ |
239
|
|
|
$ |
147
|
|
|
$ |
12
|
|
|
$ |
(70 |
) |
|
$ |
6,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Discontinued
Operations
and Extraordinary Loss
|
|
$ |
491
|
|
|
$ |
22
|
|
|
$ |
14
|
|
|
$ |
1
|
|
|
$ |
-
|
|
|
$ |
528
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
2
|
|
Extraordinary
Loss, Net of Tax
|
|
|
(79 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(79 |
) |
Net
Income
|
|
$ |
412
|
|
|
$ |
22
|
|
|
$ |
14
|
|
|
$ |
3
|
|
|
$ |
-
|
|
|
$ |
451
|
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
|
MEMCO
Operations
|
|
|
Generation
and
Marketing
|
|
|
All
Other (a)
|
|
|
Reconciling
Adjustments
|
|
|
Consolidated
|
|
|
|
(in
millions)
|
|
Six
Months Ended June 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
Customers
|
|
$ |
5,781
|
|
|
$ |
233
|
|
|
$ |
33
|
|
|
$ |
(3 |
) |
|
$ |
-
|
|
|
$ |
6,044
|
|
Other
Operating Segments
|
|
|
(19 |
) |
|
|
5
|
|
|
|
-
|
|
|
|
37
|
|
|
|
(23 |
) |
|
|
-
|
|
Total
Revenues
|
|
$ |
5,762
|
|
|
$ |
238
|
|
|
$ |
33
|
|
|
$ |
34
|
|
|
$ |
(23 |
) |
|
$ |
6,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Discontinued
Operations
|
|
$ |
524
|
|
|
$ |
35
|
|
|
$ |
6
|
|
|
$ |
(15 |
) |
|
$ |
-
|
|
|
$ |
550
|
|
Discontinued
Operations, Net of Tax
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6
|
|
|
|
-
|
|
|
|
6
|
|
Net
Income (Loss)
|
|
$ |
524
|
|
|
$ |
35
|
|
|
$ |
6
|
|
|
$ |
(9 |
) |
|
$ |
-
|
|
|
$ |
556
|
|
|
|
|
|
|
Nonutility
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Operations
|
|
|
MEMCO
Operations
|
|
|
Generation
and
Marketing
|
|
|
All
Other (a)
|
|
|
Reconciling
Adjustments
|
|
|
Consolidated
|
|
June
30, 2007
|
|
(in
millions)
|
|
Total
Property, Plant and Equipment
|
|
$ |
43,794
|
|
|
$ |
241
|
|
|
$ |
566
|
|
|
$ |
36
|
|
|
$ |
(237 |
)(b) |
|
$ |
44,400
|
|
Accumulated
Depreciation and
Amortization
|
|
|
15,781
|
|
|
|
55
|
|
|
|
97
|
|
|
|
6
|
|
|
|
(6 |
)(b) |
|
|
15,933
|
|
Total
Property, Plant and Equipment –
Net
|
|
$ |
28,013
|
|
|
$ |
186
|
|
|
$ |
469
|
|
|
$ |
30
|
|
|
$ |
(231 |
)(b) |
|
$ |
28,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
38,109
|
|
|
$ |
307
|
|
|
$ |
752
|
|
|
$ |
11,901
|
|
|
$ |
(11,875 |
)(c) |
|
$ |
39,193
|
|
|
|
|
|
|
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 June 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 business income tax
imposed at a rate of 4.95% and a modified gross receipts tax 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.
We
are in
the process of evaluating the impact of the MBT Act. It is expected
that the application of the MBT Act will not have a material effect on our
results of operation, cash flows or financial condition.
Long-term
Debt
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
Type
of Debt
|
|
(in
millions)
|
|
Senior
Unsecured Notes
|
|
$ |
9,399
|
|
|
$ |
8,653
|
|
Pollution
Control Bonds
|
|
|
2,153
|
|
|
|
1,950
|
|
First
Mortgage Bonds
|
|
|
90
|
|
|
|
90
|
|
Defeased
First Mortgage Bonds (a)
|
|
|
19
|
|
|
|
27
|
|
Notes
Payable
|
|
|
312
|
|
|
|
337
|
|
Securitization
Bonds
|
|
|
2,303
|
|
|
|
2,335
|
|
Notes
Payable To Trust
|
|
|
113
|
|
|
|
113
|
|
Spent
Nuclear Fuel Obligation (b)
|
|
|
253
|
|
|
|
247
|
|
Other
Long-term Debt
|
|
|
3
|
|
|
|
2
|
|
Unamortized
Discount (net)
|
|
|
(57 |
) |
|
|
(56 |
) |
Total
Long-term Debt Outstanding
|
|
|
14,588
|
|
|
|
13,698
|
|
Less
Portion Due Within One Year
|
|
|
1,521
|
|
|
|
1,269
|
|
Long-term
Portion
|
|
$ |
13,067
|
|
|
$ |
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
June 30, 2007 and December 31, 2006. Trust Fund Assets related
to this obligation of $23 million and $2 million at June 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 $277 million and $274 million
at June
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 six 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
|
|
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
|
|
TCC
|
|
Pollution
Control Bonds
|
|
|
6
|
|
4.45
|
|
2020
|
|
TNC
|
|
Pollution
Control Bonds
|
|
|
44
|
|
4.45
|
|
2020
|
|
Total
Issuances
|
|
|
|
$
|
1,073
|
(a)
|
|
|
|
|
The
above
borrowing arrangements do not contain guarantees, collateral or dividend
restrictions.
(a)
|
Amount
indicated on statement of cash flows of $1,064 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 June 30, 2007.
Company
|
|
Type
of Debt
|
|
Principal
Amount
Paid
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
|
(in
millions)
|
|
(%)
|
|
|
|
Retirements
and Principal Payments:
|
|
|
|
|
|
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
$
|
125
|
|
Variable
|
|
2007
|
|
OPCo
|
|
Notes
Payable
|
|
|
3
|
|
6.81
|
|
2008
|
|
OPCo
|
|
Notes
Payable
|
|
|
6
|
|
6.27
|
|
2009
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
3
|
|
4.47
|
|
2011
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
4
|
|
6.36
|
|
2007
|
|
SWEPCo
|
|
Notes
Payable
|
|
|
2
|
|
Variable
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Registrant:
|
|
|
|
|
|
|
|
|
|
|
AEP
Subsidiaries
|
|
Notes
Payable
|
|
|
3
|
|
Variable
|
|
2017
|
|
CSW
Energy, Inc.
|
|
Notes
Payable
|
|
|
4
|
|
5.88
|
|
2011
|
|
TCC
|
|
Securitization
Bonds
|
|
|
32
|
|
5.01
|
|
2008
|
|
TNC
|
|
Defeased
First Mortgage Bonds
|
|
|
8
|
|
7.75
|
|
2007
|
|
Total
Retirements and
Principal
Payments
|
|
|
$
|
190
|
|
|
|
|
|
In
July
2007, KPCo retired $125 million of 5.50% Senior Unsecured Notes due in
2007.
In
July
2007, PSO redeemed $13 million of 6.00% Pollution Control Bonds due in
2020.
In
July
2007, TCC redeemed $6 million of 6.00% Pollution Control Bonds due in
2020.
In
July
2007, TNC redeemed $44 million of 6.00% Pollution Control Bonds due in
2020.
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:
|
|
June
30, 2007
|
|
|
|
December
31, 2006
|
|
|
|
Outstanding
Amount
|
|
|
Interest
Rate
|
|
|
|
Outstanding
Amount
|
|
|
Interest
Rate
|
|
Type
of Debt
|
|
(in
millions)
|
|
|
|
|
|
|
(in
millions)
|
|
|
|
|
Commercial
Paper – AEP
|
|
$ |
416
|
|
|
|
5.40 |
% |
(a)
|
|
$ |
-
|
|
|
|
-
|
|
Commercial
Paper – JMG (b)
|
|
|
-
|
|
|
|
-
|
|
|
|
|
1
|
|
|
|
5.56 |
% |
Line
of Credit – Sabine (c)
|
|
|
22
|
|
|
|
6.20 |
% |
|
|
|
17
|
|
|
|
6.38 |
% |
Total
|
|
$ |
438
|
|
|
|
|
|
|
|
$ |
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
July
2007, we extended AEP Credit’s sale of receivables agreement. The
sale of receivables agreement provides commitments of $600 million from a bank
conduit to purchase receivables from AEP Credit. This agreement will
expire in November 2007. We intend to renew or replace this
agreement.
APPALACHIAN
POWER COMPANY
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS
Results
of Operations
Second
Quarter of 2007 Compared to Second Quarter of 2006
Reconciliation
of Second Quarter of 2006 to Second Quarter of 2007
Net
Income Before Extraordinary Loss
(in
millions)
Second
Quarter of 2006
|
|
|
|
|
$ |
10
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(39 |
) |
|
|
|
|
Off-system
Sales
|
|
|
18
|
|
|
|
|
|
Transmission
Revenues
|
|
|
7
|
|
|
|
|
|
Other
|
|
|
3
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(3 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
17
|
|
|
|
|
|
Carrying
Costs Income
|
|
|
3
|
|
|
|
|
|
Other
Income, Net
|
|
|
(5 |
) |
|
|
|
|
Interest
Expense
|
|
|
(13 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
Second Quarter of 2007
|
|
|
|
|
|
$ |
3
|
|
Net
Income Before Extraordinary Loss decreased $7 million to $3
million. The key drivers of the decrease were an $11 million decrease
in Gross Margin, 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 decreased $39 million in comparison to 2006 primarily due
to:
|
|
·
|
A
$38 million decrease in retail revenues primarily related to APCo’s
Virginia base rate case which includes a second quarter 2007 provision
for
revenue refund as a result of the final order offset by the new
rates
implemented. See “Virginia Base Rate Case” section of Note
3.
|
|
·
|
A
$24 million increase in capacity settlement expenses under the
Interconnection Agreement reflecting APCo’s new peak demand in February
2007.
|
|
·
|
A
$12 million decrease in revenues related to financial transmission
rights,
net of congestion, primarily due to fewer transmission constraints
in the
PJM market.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$16 million increase in revenues related to the Expanded Net Energy
Cost
(ENEC) mechanism with West Virginia retail
customers. The mechanism was reinstated in West Virginia
effective July 1, 2006 in conjunction with the West Virginia rate
case.
|
|
·
|
An
$18 million increase in retail sales primarily due to increased
demand in
the residential class associated with favorable weather
conditions. Cooling degree days increased approximately
54%.
|
·
|
Margins
from Off-system Sales increased $18 million primarily due to higher
power
prices in the east, higher trading margins, and an increase in
APCo’s
allocated share of off-system sales revenues due to its new peak.
|
·
|
Transmission
Revenues increased $7 million primarily due to a provision recorded
in the
second quarter of 2006 related to potential SECA refunds. See
“Transmission Rate Proceedings at the FERC” section of Note
3.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $3 million primarily
due to
the following:
|
|
·
|
A
$4 million increase in steam maintenance expenses resulting from
2007
planned outages at the Amos and Glen Lyn plants.
|
|
·
|
A
$3 million increase in customer accounts and services expense primarily
related to an increase in uncollectible accounts under a contract
dispute.
|
|
These
increases were offset by:
|
|
·
|
A
$5 million decrease in expenses related to the AEP Transmission
Equalization Agreement due to the addition of the Wyoming-Jacksons
Ferry
765 kV line which was energized and placed into service in June
2006.
|
·
|
Depreciation
and Amortization expenses decreased $17 million primarily due to
lower
Virginia depreciation rates implemented retroactively to January
2006 for
$15 million and lower amortization resulting from a net deferral
of $9
million in ARO costs as ordered in APCo’s Virginia base rate
case. These decreases were partially offset by the amortization
of carrying charges and depreciation expense of $3 million that
are being
collected through the E&R surcharge mechanism. In addition, an
increase in depreciation expense was also related to 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.
|
·
|
Carrying
Costs Income increased $3 million related to carrying costs associated
with the E&R case.
|
·
|
Other
Income, Net decreased $5 million primarily due to a $2 million
decrease in
interest income from the Utility Money Pool and a $2 million decrease
in
AFUDC resulting from a lower construction work in progress (CWIP)
balance
after the Wyoming-Jacksons Ferry 765 kv line and the Mountaineer
scrubber
were placed into service.
|
·
|
Interest
Expense increased $13 million primarily due to a $6 million decrease
in
allowance for borrowed funds used for construction, a $3 million
increase
in interest expense from the Utility Money Pool, and a $3 million
increase
in the interest on the Virginia provision for
refund.
|
Income
Taxes
Income
Tax Expense decreased $5 million primarily due to a decrease in pretax book
income.
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Reconciliation
of Six Months Ended June 30, 2006 to Six Months Ended June 30,
2007
Net
Income Before Extraordinary Loss
(in
millions)
Six
Months Ended June 30, 2006
|
|
|
|
|
$ |
83
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(10 |
) |
|
|
|
|
Off-system
Sales
|
|
|
12
|
|
|
|
|
|
Transmission
Revenues
|
|
|
(4 |
) |
|
|
|
|
Other
|
|
|
4
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(8 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
7
|
|
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
2
|
|
|
|
|
|
Other
Income, Net
|
|
|
(5 |
) |
|
|
|
|
Interest
Expense
|
|
|
(15 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(19 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2007
|
|
|
|
|
|
$ |
74
|
|
Net
Income Before Extraordinary Loss decreased $9 million to $74 million in
2007. The key drivers of the decrease were a $19 million increase in
Operating Expenses and Other, partially offset by an $8 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 decreased $10 million in comparison to 2006 primarily due
to:
|
|
·
|
A
$26 million decrease in revenues related to financial transmission
rights,
net of congestion, primarily due to fewer transmission constraints
in the
PJM market.
|
|
·
|
A
$26 million increase in capacity settlement expenses under the
Interconnection Agreement reflecting APCo’s new peak demand in February
2007.
|
|
These
decreases were partially offset by:
|
|
·
|
A
$7 million increase in revenues related to the ENEC mechanism with
West
Virginia retail customers. The mechanism was reinstated in
West Virginia effective July 1, 2006 in conjunction with the West
Virginia
rate case.
|
|
·
|
A
$27 million increase in retail sales primarily due to increased
demand in
the residential class associated with favorable weather
conditions. Heating degree days increased approximately 27% and
Cooling degree days increased approximately 62%.
|
|
·
|
A
$9 million increase in municipal and cooperative revenues primarily
due to
the addition of the Blue Ridge Power Agency customers.
|
·
|
Margins
from Off-system Sales increased $12 million primarily due to higher
power
prices in the east, higher trading margins, an increase in APCo’s
allocated share of off-system sales revenues due to its new peak,
and a
change in the allocation of off-system sales margins under the
SIA
effective April 1, 2006.
|
·
|
Transmission
Revenues decreased $4 million primarily due to the elimination
of SECA
revenues of $13 million as of April 1, 2006. See “Transmission
Rate Proceedings at the FERC” section of Note 3. This decrease
was partially offset by a provision recorded in the second quarter
of 2006
related to potential SECA refunds and additional transmission revenues
relating to dedicated energy sales of $2 million.
|
·
|
Other
revenue increased $4 primarily due to the reversal of previously
deferred
gains on sales of allowances associated with the E&R
case.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $8 million primarily
due to
the following:
|
|
·
|
A
$4 million increase in steam maintenance expenses resulting from
2007
planned outages at the Amos and Glen Lyn plants.
|
|
·
|
A
$6 million increase in expenses for distribution line right-of-way
clearing.
|
|
·
|
A
$4 million increase in uncollectible and factored accounts receivable
expense.
|
|
·
|
An
$8 million increase in employee related and various other operational
expenses.
|
|
These
increases were partially offset by:
|
|
·
|
A
$14 million decrease in expenses related to the AEP Transmission
Equalization Agreement due to the addition of the Wyoming-Jacksons
Ferry
765 kV line, which was energized and placed into service in June
2006.
|
·
|
Depreciation
and Amortization expenses decreased $7 million primarily due to
lower
Virginia depreciation rates implemented retroactively to January
2006 for
$15 million and lower amortization resulting from a net deferral
of $9
million in ARO costs as ordered in APCo’s Virginia base rate
case. These decreases were partially offset by the amortization
of carrying charges and depreciation expense of $13 million that
are being
collected through the E&R surcharges. In addition, an
increase in depreciation expense was also related to 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.
|
·
|
Other
Income, Net decreased $5 million primarily due to lower interest
income
from the Utility Money Pool of $2 million and a $2 million decrease
in
AFUDC resulting from a lower CWIP balance after the Wyoming-Jacksons
Ferry
765 kV line and the Mountaineer scrubber were placed into
service.
|
·
|
Interest
Expense increased $15 million primarily due to an $8 million increase
related to the issuance of $500 million of debt in April 2006 and
a $4
million decrease in allowance for borrowed funds used during
construction.
|
Income
Taxes
Income
Tax Expense decreased $8 million primarily due to a decrease in pretax book
income.
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 six months ended June 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
|
|
|
265,414
|
|
|
|
316,970
|
|
Investing
Activities
|
|
|
(378,985 |
) |
|
|
(618,920 |
) |
Financing
Activities
|
|
|
112,605
|
|
|
|
301,555
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(966 |
) |
|
|
(395 |
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,352
|
|
|
$ |
1,346
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $265 million in 2007. APCo
incurred a Net Loss of $5 million during the period and had noncash expense
items of $90 million for Depreciation and Amortization and $79 million for
Extraordinary Loss for the Reapplication of Regulatory Accounting for Generation
and $105 million for Regulatory Provision related to the Virginia base rate
case. 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.
Net
Cash
Flows From Operating Activities were $317 million in 2006. APCo
produced Net Income of $83 million during the period and a noncash expense
item
of $97 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 Receivable, Net decreased
$60 million primarily due to the collection of receivables related to power
sales to affiliates, settled litigation and sales on emission
allowances. Accrued Taxes, Net increased $42 million related to the
lack of federal income tax payments made in 2006.
Investing
Activities
Net
Cash
Flows Used For Investing Activities during 2007 and 2006 primarily reflect
construction expenditures of $383 million and $404 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 installation of selective
catalytic reduction equipment on certain plants and the flue gas desulfurization
project at the Amos and Mountaineer plants. In February 2007,
environmental upgrades were completed for the Mountaineer plant. For
the remainder of 2007, APCo expects construction expenditures to be
approximately $281 million. In addition, APCo’s investments in the
Utility Money Pool increased by $219 million in 2006.
Financing
Activities
Net
Cash
Flows From Financing Activities in 2007 were $113 million primarily due to
an
increase of $213 million in borrowings from the Utility Money Pool and the
issuance of $75 million of Pollution Control Bonds. These increases
were partially offset by the retirement of $125 million of Senior Notes and
payment of $25 million in dividends on common stock.
Net
Cash
Flows From Financing Activities were $302 million in 2006. In 2006,
APCo issued $500 million in Senior Notes and issued $50 million in Pollution
Control Bonds. APCo also retired First Mortgage Bonds of $100 million
and repaid short-term borrowings from the Utility Money Pool of $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 six months of 2007
were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$
|
75,000
|
|
Variable
|
|
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 issuance and retirement
discussed in “Cash Flow” and “Financing Activity” above.
Significant
Factors
New
Generation
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
of equity once the facility is placed into commercial operation. If
APCo receives all necessary approvals, the plant could be completed by mid-2012
at the earliest 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 June 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.
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
IGCC
plant to be constructed in West Virginia. 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
as required by the new Virginia Re-regulation legislation.
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 practice
deferred fuel accounting. Also, under the amended restructuring law,
APCo has the right to defer incremental environmental compliance costs and
incremental E&R costs for future recovery, to the extent such costs
are not being recovered, and amortizes a portion of such deferrals commensurate
with their recovery.
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.
With
the
new re-regulation legislation, APCo’s generation business again meets 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 primarily 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.
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 June 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 June 30, 2007
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
|
Cash
Flow &
Fair
Value Hedges
|
|
|
DETM
Assignment (a)
|
|
|
Total
|
|
Current
Assets
|
|
$ |
73,123
|
|
|
$ |
11,439
|
|
|
$ |
-
|
|
|
$ |
84,562
|
|
Noncurrent
Assets
|
|
|
84,029
|
|
|
|
2,919
|
|
|
|
-
|
|
|
|
86,948
|
|
Total
MTM Derivative Contract Assets
|
|
|
157,152
|
|
|
|
14,358
|
|
|
|
-
|
|
|
|
171,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(55,013 |
) |
|
|
(1,137 |
) |
|
|
(3,570 |
) |
|
|
(59,720 |
) |
Noncurrent
Liabilities
|
|
|
(51,130 |
) |
|
|
(87 |
) |
|
|
(7,551 |
) |
|
|
(58,768 |
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(106,143 |
) |
|
|
(1,224 |
) |
|
|
(11,121 |
) |
|
|
(118,488 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$ |
51,009
|
|
|
$ |
13,134
|
|
|
$ |
(11,121 |
) |
|
$ |
53,022
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 of the 2006 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Six
Months Ended June 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
|
|
|
(8,051
|
)
|
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
|
|
|
511
|
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
4,757
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
1,048
|
|
Total
MTM Risk Management Contract Net Assets
|
|
|
51,009
|
|
Net
Cash Flow & Fair Value Hedge Contracts
|
|
|
13,134
|
|
DETM
Assignment (d)
|
|
|
(11,121
|
)
|
Total
MTM Risk Management Contract Net Assets at June 30,
2007
|
|
$
|
53,022
|
|
(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 June 30, 2007
(in
thousands)
|
|
Remainder
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
After
2011
|
|
Total
|
|
Prices
Actively Quoted – Exchange Traded
Contracts
|
|
$ |
4,823
|
|
$ |
(3,624 |
) |
$ |
163
|
|
$ |
-
|
|
$ |
-
|
|
$ |
-
|
|
$ |
1,362
|
|
Prices
Provided by Other External Sources
–
OTC Broker Quotes
(a)
|
|
|
6,824
|
|
|
16,070
|
|
|
12,886
|
|
|
5,714
|
|
|
-
|
|
|
-
|
|
|
41,494
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(401 |
) |
|
(1,510 |
) |
|
1,682
|
|
|
5,485
|
|
|
1,248
|
|
|
1,649
|
|
|
8,153
|
|
Total
|
|
$ |
11,246
|
|
$ |
10,936
|
|
$ |
14,731
|
|
$ |
11,199
|
|
$ |
1,248
|
|
$ |
1,649
|
|
$ |
51,009
|
|
(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 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 forward contracts and collars as cash flow hedges to lock in prices
on
certain transactions denominated in foreign currencies where deemed
necessary. Management does not hedge all foreign currency
exposure.
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 June 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
Six
Months Ended June 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
|
|
|
7,980
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7,980
|
|
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
|
|
(4,067
|
)
|
|
|
3
|
|
|
|
694
|
|
|
|
(3,370
|
)
|
Ending
Balance in AOCI June 30, 2007
|
|
$
|
9,245
|
|
|
$
|
(161
|
)
|
|
$
|
(7,021
|
)
|
|
$
|
2,063
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $6,737 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 June 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:
Six
Months Ended
June
30, 2007
|
|
|
|
|
Twelve
Months Ended
December
31, 2006
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$475
|
|
$2,328
|
|
$779
|
|
$227
|
|
|
|
|
$756
|
|
$1,915
|
|
$658
|
|
$358
|
The
High
VaR for the twelve months ended December 31, 2006 occurred in the third quarter
due to volatility in the ECAR/PJM region.
VaR
Associated with Debt Outstanding
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 $178 million and $153 million at June
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 OPERATIONS
For
the Three and Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
499,189
|
|
|
$ |
464,058
|
|
|
$ |
1,100,735
|
|
|
$ |
1,024,051
|
|
Sales
to AEP Affiliates
|
|
|
55,371
|
|
|
|
48,608
|
|
|
|
116,916
|
|
|
|
120,380
|
|
Other
|
|
|
2,850
|
|
|
|
1,922
|
|
|
|
5,487
|
|
|
|
4,598
|
|
TOTAL
|
|
|
557,410
|
|
|
|
514,588
|
|
|
|
1,223,138
|
|
|
|
1,149,029
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
164,018
|
|
|
|
155,240
|
|
|
|
335,204
|
|
|
|
322,093
|
|
Purchased
Electricity for Resale
|
|
|
34,328
|
|
|
|
29,979
|
|
|
|
70,278
|
|
|
|
57,595
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
144,630
|
|
|
|
103,457
|
|
|
|
272,231
|
|
|
|
225,856
|
|
Other
Operation
|
|
|
75,125
|
|
|
|
77,156
|
|
|
|
142,754
|
|
|
|
147,057
|
|
Maintenance
|
|
|
51,414
|
|
|
|
46,668
|
|
|
|
97,167
|
|
|
|
84,507
|
|
Depreciation
and Amortization
|
|
|
31,076
|
|
|
|
48,688
|
|
|
|
90,236
|
|
|
|
96,956
|
|
Taxes
Other Than Income Taxes
|
|
|
22,975
|
|
|
|
22,799
|
|
|
|
44,250
|
|
|
|
45,891
|
|
TOTAL
|
|
|
523,566
|
|
|
|
483,987
|
|
|
|
1,052,120
|
|
|
|
979,955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
33,844
|
|
|
|
30,601
|
|
|
|
171,018
|
|
|
|
169,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
390
|
|
|
|
2,814
|
|
|
|
1,029
|
|
|
|
3,765
|
|
Carrying
Costs Income
|
|
|
10,950
|
|
|
|
7,773
|
|
|
|
14,116
|
|
|
|
13,784
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
1,581
|
|
|
|
4,083
|
|
|
|
4,358
|
|
|
|
6,559
|
|
Interest
Expense
|
|
|
(44,955 |
) |
|
|
(31,653 |
) |
|
|
(76,778 |
) |
|
|
(61,921 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
1,810
|
|
|
|
13,618
|
|
|
|
113,743
|
|
|
|
131,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense (Credit)
|
|
|
(1,471 |
) |
|
|
3,971
|
|
|
|
40,235
|
|
|
|
48,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE EXTRAORDINARY LOSS
|
|
|
3,281
|
|
|
|
9,647
|
|
|
|
73,508
|
|
|
|
83,241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extraordinary
Loss – Reapplication of Regulatory Accounting for
Generation, Net of Tax
|
|
|
(78,763 |
) |
|
|
-
|
|
|
|
(78,763 |
) |
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
|
(75,482 |
) |
|
|
9,647
|
|
|
|
(5,255 |
) |
|
|
83,241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements Including Capital
Stock Expense
|
|
|
238
|
|
|
|
238
|
|
|
|
476
|
|
|
|
476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
(LOSS) APPLICABLE TO COMMON STOCK
|
|
$ |
(75,720 |
) |
|
$ |
9,409
|
|
|
$ |
(5,731 |
) |
|
$ |
82,765
|
|
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 Six Months Ended June 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
|
|
|
|
|
|
|
|
|
|
|
(5,000 |
) |
|
|
|
|
|
|
(5,000 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(400 |
) |
|
|
|
|
|
|
(400 |
) |
Capital
Stock Expense and Other
|
|
|
|
|
|
|
80
|
|
|
|
(76 |
) |
|
|
|
|
|
|
4
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,798,305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $9,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,998
|
|
|
|
17,998
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
83,241
|
|
|
|
|
|
|
|
83,241
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2006
|
|
$ |
260,458
|
|
|
$ |
924,917
|
|
|
$ |
712,781
|
|
|
$ |
1,388
|
|
|
$ |
1,899,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
(400 |
) |
|
|
|
|
|
|
(400 |
) |
Capital
Stock Expense and Other
|
|
|
|
|
|
|
76
|
|
|
|
(76 |
) |
|
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,008,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $2,482
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,610
|
|
|
|
4,610
|
|
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
LOSS
|
|
|
|
|
|
|
|
|
|
|
(5,255 |
) |
|
|
|
|
|
|
(5,255 |
) |
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
260,458
|
|
|
$ |
1,025,070
|
|
|
$ |
772,097
|
|
|
$ |
(38,936 |
) |
|
$ |
2,018,689
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,352
|
|
|
$ |
2,318
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
176,758
|
|
|
|
180,190
|
|
Affiliated
Companies
|
|
|
76,139
|
|
|
|
98,237
|
|
Accrued
Unbilled Revenues
|
|
|
28,373
|
|
|
|
46,281
|
|
Miscellaneous
|
|
|
3,343
|
|
|
|
3,400
|
|
Allowance
for Uncollectible Accounts
|
|
|
(8,779 |
) |
|
|
(4,334 |
) |
Total
Accounts Receivable
|
|
|
275,834
|
|
|
|
323,774
|
|
Fuel
|
|
|
89,129
|
|
|
|
77,077
|
|
Materials
and Supplies
|
|
|
71,994
|
|
|
|
56,235
|
|
Risk
Management Assets
|
|
|
84,562
|
|
|
|
105,376
|
|
Accrued
Tax Benefits
|
|
|
10,095
|
|
|
|
3,748
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
6,591
|
|
|
|
29,526
|
|
Prepayments
and Other
|
|
|
17,266
|
|
|
|
20,126
|
|
TOTAL
|
|
|
556,823
|
|
|
|
618,180
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
3,487,306
|
|
|
|
2,844,803
|
|
Transmission
|
|
|
1,658,340
|
|
|
|
1,620,512
|
|
Distribution
|
|
|
2,309,637
|
|
|
|
2,237,887
|
|
Other
|
|
|
344,201
|
|
|
|
339,450
|
|
Construction
Work in Progress
|
|
|
592,554
|
|
|
|
957,626
|
|
Total
|
|
|
8,392,038
|
|
|
|
8,000,278
|
|
Accumulated
Depreciation and Amortization
|
|
|
2,554,296
|
|
|
|
2,476,290
|
|
TOTAL
- NET
|
|
|
5,837,742
|
|
|
|
5,523,988
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
675,027
|
|
|
|
622,153
|
|
Long-term
Risk Management Assets
|
|
|
86,948
|
|
|
|
88,906
|
|
Deferred
Charges and Other
|
|
|
163,892
|
|
|
|
163,089
|
|
TOTAL
|
|
|
925,867
|
|
|
|
874,148
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
7,320,432
|
|
|
$ |
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
June
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
247,616
|
|
|
$ |
34,975
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
232,509
|
|
|
|
296,437
|
|
Affiliated
Companies
|
|
|
92,697
|
|
|
|
105,525
|
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
399,144
|
|
|
|
324,191
|
|
Risk
Management Liabilities
|
|
|
59,720
|
|
|
|
81,114
|
|
Customer
Deposits
|
|
|
64,285
|
|
|
|
56,364
|
|
Accrued
Taxes
|
|
|
102,445
|
|
|
|
60,056
|
|
Other
|
|
|
260,549
|
|
|
|
172,943
|
|
TOTAL
|
|
|
1,458,965
|
|
|
|
1,131,605
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
2,050,742
|
|
|
|
2,174,473
|
|
Long-term
Debt – Affiliated
|
|
|
100,000
|
|
|
|
100,000
|
|
Long-term
Risk Management Liabilities
|
|
|
58,768
|
|
|
|
64,909
|
|
Deferred
Income Taxes
|
|
|
892,735
|
|
|
|
957,229
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
487,643
|
|
|
|
309,724
|
|
Deferred
Credits and Other
|
|
|
235,127
|
|
|
|
224,439
|
|
TOTAL
|
|
|
3,825,015
|
|
|
|
3,830,774
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
5,283,980
|
|
|
|
4,962,379
|
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
17,763
|
|
|
|
17,763
|
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
|
Common
Stock – No Par Value:
|
|
|
|
|
|
|
|
|
Authorized
– 30,000,000 Shares
|
|
|
|
|
|
|
|
|
Outstanding
– 13,499,500 Shares
|
|
|
260,458
|
|
|
|
260,458
|
|
Paid-in
Capital
|
|
|
1,025,070
|
|
|
|
1,024,994
|
|
Retained
Earnings
|
|
|
772,097
|
|
|
|
805,513
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(38,936 |
) |
|
|
(54,791 |
) |
TOTAL
|
|
|
2,018,689
|
|
|
|
2,036,174
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
7,320,432
|
|
|
$ |
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 Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$ |
(5,255 |
) |
|
$ |
83,241
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
90,236
|
|
|
|
96,956
|
|
Deferred
Income Taxes
|
|
|
(17,439 |
) |
|
|
(1,466 |
) |
Extraordinary
Loss, Net of Tax
|
|
|
78,763
|
|
|
|
-
|
|
Regulatory
Provision
|
|
|
105,110
|
|
|
|
-
|
|
Carrying
Costs Income
|
|
|
(14,116 |
) |
|
|
(13,784 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
1,377
|
|
|
|
147
|
|
Change
in Other Noncurrent Assets
|
|
|
(12,254 |
) |
|
|
5,690
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(1,239 |
) |
|
|
17,986
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
31,483
|
|
|
|
60,345
|
|
Fuel,
Materials and Supplies
|
|
|
(20,654 |
) |
|
|
(8,611 |
) |
Margin
Deposits
|
|
|
6,798
|
|
|
|
27,872
|
|
Accounts
Payable
|
|
|
(26,786 |
) |
|
|
14,993
|
|
Customer
Deposits
|
|
|
7,921
|
|
|
|
(24,824 |
) |
Accrued
Taxes, Net
|
|
|
39,168
|
|
|
|
42,357
|
|
Fuel
Over/Under Recovery, Net
|
|
|
15,221
|
|
|
|
3,636
|
|
Other
Current Assets
|
|
|
(1,833 |
) |
|
|
7,295
|
|
Other
Current Liabilities
|
|
|
(11,087 |
) |
|
|
5,137
|
|
Net
Cash Flows From Operating Activities
|
|
|
265,414
|
|
|
|
316,970
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(382,501 |
) |
|
|
(404,252 |
) |
Change
in Other Cash Deposits, Net
|
|
|
(2,678 |
) |
|
|
-
|
|
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
|
(218,702 |
) |
Proceeds
from Sales of Assets
|
|
|
6,194
|
|
|
|
4,034
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(378,985 |
) |
|
|
(618,920 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
73,438
|
|
|
|
544,364
|
|
Change
in Advances from Affiliates, Net
|
|
|
212,641
|
|
|
|
(194,133 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(125,006 |
) |
|
|
(100,005 |
) |
Retirement
of Preferred Stock
|
|
|
-
|
|
|
|
(14 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(2,200 |
) |
|
|
(2,768 |
) |
Funds
From Amended Coal Contract
|
|
|
-
|
|
|
|
68,078
|
|
Amortization
of Funds From Amended Coal Contract
|
|
|
(20,868 |
) |
|
|
(8,567 |
) |
Dividends
Paid on Common Stock
|
|
|
(25,000 |
) |
|
|
(5,000 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(400 |
) |
|
|
(400 |
) |
Net
Cash Flows From Financing Activities
|
|
|
112,605
|
|
|
|
301,555
|
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(966 |
) |
|
|
(395 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
2,318
|
|
|
|
1,741
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,352
|
|
|
$ |
1,346
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
69,823
|
|
|
$ |
51,558
|
|
Net
Cash Paid for Income Taxes
|
|
|
6,197
|
|
|
|
4,562
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,693
|
|
|
|
2,287
|
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
97,044
|
|
|
|
105,826
|
|
|
|
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 purchase power agreement (PPA)
for
the entire output from the Lawrenceburg Plant effective with AEGCo’s purchase of
the plant in May 2007. The PPA has an option for an additional
two-year period. I&M operates the plant under an agreement with
AEGCo. Under the PPA, 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
Second
Quarter of 2007 Compared to Second Quarter of 2006
Reconciliation
of Second Quarter of 2006 to Second Quarter of 2007
Net
Income
(in
millions)
Second
Quarter of 2006
|
|
|
|
|
$ |
32
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
64
|
|
|
|
|
|
Off-system
Sales
|
|
|
10
|
|
|
|
|
|
Transmission
Revenues
|
|
|
3
|
|
|
|
|
|
Other
|
|
|
1
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(8 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(3 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
6
|
|
|
|
|
|
Interest
Expense
|
|
|
1
|
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(26 |
) |
|
|
|
|
|
|
|
|
|
Second
Quarter of 2007
|
|
|
|
|
|
$ |
80
|
|
Net
Income increased $48 million to $80 million in 2007. The key driver
of the increase was a $78 million increase in Gross Margin primarily offset
by a
$26 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 $64 million primarily due to:
|
|
·
|
A
$22 million increase in rate revenues related to a $13 million
increase in
CSPCo’s RSP, a $3 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 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
$20 million decrease in capacity purchases due to changes in relative
peak
demands of AEP Power Pool members under the Interconnection
Agreement.
|
|
·
|
An
$18 million increase in residential and commercial revenue primarily
due
to a 69% increase in cooling degree days.
|
|
·
|
A
$14 million increase in industrial revenue primarily due to the
addition
of Ormet, a major industrial customer. The addition of Ormet
resulted in a $12 million increase in industrial sales. See
“Ormet” section of Note 3.
|
·
|
Margins
from Off-system Sales increased $10 million primarily due to higher
power
prices in the east and higher trading margins.
|
·
|
Transmission
Revenues increased $3 million primarily due to a provision recorded
in the
second quarter of 2006 related to potential SECA refunds. See
“Transmission Rate Proceedings at the FERC” section of Note
3.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $8 million primarily
due
to:
|
|
·
|
A
$4 million increase in expenses related to CSPCo’s PPA for AEGCo’s
Lawrenceburg Plant which began in May 2007.
|
|
·
|
A
$3 million increase in overhead line expenses due in part to the
amortization of deferred storm expenses recovered through a cost-recovery
rider. The increase in amortization of deferred storm expenses
was offset by a corresponding increase in Retail
Margins.
|
|
·
|
A
$3 million increase in net allocated transmission costs related
to the
Transmission Equalization Agreement as a result of the addition
of APCo’s
Wyoming-Jacksons Ferry 765 kV line, which was energized and placed
in
service in June 2006.
|
·
|
Depreciation
and Amortization increased $3 million due to the amortization of
IGCC
preconstruction costs in 2007. The increase in amortization of
IGCC preconstruction costs was offset by a corresponding increase
in
Retail Margins.
|
·
|
Taxes
Other Than Income Taxes decreased $6 million due to a favorable
true-up of
property taxes recorded in 2007 compared to an unfavorable true-up
recorded in 2006, partially offset by an increase in state excise
taxes.
|
Income
Taxes
Income
Tax Expense increased $26 million primarily due to an increase in pretax
book
income.
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Reconciliation
of Six Months Ended June 30, 2006 to Six Months Ended June 30,
2007
Net
Income
(in
millions)
Six
Months Ended June 30, 2006
|
|
|
|
|
$ |
84
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
91
|
|
|
|
|
|
Off-system
Sales
|
|
|
(1 |
) |
|
|
|
|
Transmission
Revenues
|
|
|
(4 |
) |
|
|
|
|
Other
|
|
|
(3 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
83
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(18 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(7 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
5
|
|
|
|
|
|
Interest
Expense
|
|
|
3
|
|
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(17 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(23 |
) |
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
$ |
127
|
|
Net
Income increased $43 million to $127 million in 2007. The key driver
of the increase was an $83 million increase in Gross Margin partially offset
by
a $23 million increase in Income Tax Expense and a $17 million increase in
Operating Expenses and Other.
The
major
components of the increase in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $91 million primarily due to:
|
|
·
|
A
$36 million increase in rate revenues related to a $18 million
increase in
CSPCo’s RSP, a $6 million increase related to recovery of storm costs
and
a $6 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.
|
|
·
|
A
$28 million increase in residential and commercial revenue primarily
due
to a 72% increase in cooling degree days.
|
|
·
|
A
$21 million increase in industrial revenue primarily due to the
addition
of Ormet, a major industrial customer. The addition of Ormet
resulted in a $19 million increase in industrial sales. See
“Ormet” section of Note 3.
|
|
·
|
An
$18 million decrease in capacity purchases due to changes in relative
peak
demands of AEP Power Pool members under the Interconnection
Agreement.
|
·
|
Transmission
Revenues decreased $4 million primarily due to the elimination
of SECA
revenues as of April 1, 2006 offset by a provision recorded in
the second
quarter of 2006 related to potential SECA
refunds. See “Transmission Rate Proceedings at the
FERC” section of Note 3.
|
·
|
Other
revenues decreased $3 million primarily due to lower gains on sales
of
emission allowances.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $18 million primarily
due
to:
|
|
·
|
An
$8 million increase in overhead line expenses primarily due to
a $6
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
$6 million increase in net allocated transmission costs related
to the
Transmission Equalization Agreement as a result of the addition
of APCo’s
Wyoming-Jacksons Ferry 765 kV line, which was energized and placed
in
service in June 2006.
|
|
·
|
A
$4 million increase in expenses related to CSPCo’s PPA for AEGCo’s
Lawrenceburg Plant which began in May 2007.
|
·
|
Depreciation
and Amortization increased $7 million primarily due to the amortization
of
IGCC preconstruction costs of $6 million in 2007. The increase
in amortization of IGCC preconstruction costs was offset by a
corresponding increase in Retail Margins.
|
·
|
Taxes
Other Than Income Taxes decreased $5 million due to a favorable
true-up of
property taxes recorded in 2007 compared to an unfavorable true-up
recorded in 2006, partially offset by an increase in state excise
taxes.
|
·
|
Interest
Expense decreased $3 million primarily due to an increase in allowance
for
borrowed funds used during
construction.
|
Income
Taxes
Income
Tax Expense increased $23 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 $82 million and $70 million at June 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 Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
469,648
|
|
|
$ |
394,110
|
|
|
$ |
893,114
|
|
|
$ |
807,779
|
|
Sales
to AEP Affiliates
|
|
|
35,356
|
|
|
|
21,762
|
|
|
|
58,369
|
|
|
|
35,531
|
|
Other
|
|
|
1,018
|
|
|
|
1,237
|
|
|
|
2,451
|
|
|
|
2,567
|
|
TOTAL
|
|
|
506,022
|
|
|
|
417,109
|
|
|
|
953,934
|
|
|
|
845,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
76,342
|
|
|
|
71,213
|
|
|
|
152,204
|
|
|
|
141,033
|
|
Purchased
Electricity for Resale
|
|
|
32,835
|
|
|
|
27,688
|
|
|
|
64,146
|
|
|
|
52,453
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
87,788
|
|
|
|
87,188
|
|
|
|
171,329
|
|
|
|
169,665
|
|
Other
Operation
|
|
|
62,516
|
|
|
|
57,860
|
|
|
|
123,675
|
|
|
|
113,805
|
|
Maintenance
|
|
|
26,723
|
|
|
|
23,502
|
|
|
|
49,287
|
|
|
|
41,436
|
|
Depreciation
and Amortization
|
|
|
49,446
|
|
|
|
46,540
|
|
|
|
99,743
|
|
|
|
92,368
|
|
Taxes
Other Than Income Taxes
|
|
|
35,796
|
|
|
|
41,787
|
|
|
|
76,378
|
|
|
|
81,289
|
|
TOTAL
|
|
|
371,446
|
|
|
|
355,778
|
|
|
|
736,762
|
|
|
|
692,049
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
134,576
|
|
|
|
61,331
|
|
|
|
217,172
|
|
|
|
153,828
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
194
|
|
|
|
475
|
|
|
|
616
|
|
|
|
930
|
|
Carrying
Costs Income
|
|
|
1,139
|
|
|
|
1,320
|
|
|
|
2,231
|
|
|
|
2,036
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
620
|
|
|
|
343
|
|
|
|
1,392
|
|
|
|
807
|
|
Interest
Expense
|
|
|
(16,382 |
) |
|
|
(16,914 |
) |
|
|
(31,663 |
) |
|
|
(34,434 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
120,147
|
|
|
|
46,555
|
|
|
|
189,748
|
|
|
|
123,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
40,125
|
|
|
|
14,293
|
|
|
|
62,745
|
|
|
|
39,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME |
|
|
80,022 |
|
|
|
32,262 |
|
|
|
127,003 |
|
|
|
83,599 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
Stock Expense
|
|
|
40
|
|
|
|
40
|
|
|
|
79
|
|
|
|
79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
79,982 |
|
|
$ |
32,222 |
|
|
$ |
126,924 |
|
|
$ |
83,520 |
|
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 Six Months Ended June 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
|
|
|
|
|
|
|
|
|
|
|
(45,000 |
) |
|
|
|
|
|
|
(45,000 |
) |
Capital
Stock Expense
|
|
|
|
|
|
|
79
|
|
|
|
(79 |
) |
|
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
936,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $3,695
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,861
|
|
|
|
6,861
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
83,599
|
|
|
|
|
|
|
|
83,599
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
90,460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2006
|
|
$ |
41,026
|
|
|
$ |
580,114
|
|
|
$ |
399,885
|
|
|
$ |
5,981
|
|
|
$ |
1,027,006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
(40,000 |
) |
|
|
|
|
|
|
(40,000 |
) |
Capital
Stock Expense
|
|
|
|
|
|
|
79
|
|
|
|
(79 |
) |
|
|
|
|
|
|
-
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,012,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
669
|
|
|
|
669
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
127,003
|
|
|
|
|
|
|
|
127,003
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
127,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
41,026
|
|
|
$ |
580,271
|
|
|
$ |
540,689
|
|
|
$ |
(21,319 |
) |
|
$ |
1,140,667
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,065
|
|
|
$ |
1,319
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
51,013
|
|
|
|
49,362
|
|
Affiliated Companies
|
|
|
35,509
|
|
|
|
62,866
|
|
Accrued Unbilled Revenues
|
|
|
18,760
|
|
|
|
11,042
|
|
Miscellaneous
|
|
|
6,266
|
|
|
|
4,895
|
|
Allowance for Uncollectible Accounts
|
|
|
(707 |
) |
|
|
(546 |
) |
Total
Accounts Receivable
|
|
|
110,841
|
|
|
|
127,619
|
|
Fuel
|
|
|
41,922
|
|
|
|
37,348
|
|
Materials
and Supplies
|
|
|
36,267
|
|
|
|
31,765
|
|
Emission
Allowances
|
|
|
6,328
|
|
|
|
3,493
|
|
Risk
Management Assets
|
|
|
45,433
|
|
|
|
66,238
|
|
Prepayments
and Other
|
|
|
10,397
|
|
|
|
20,870
|
|
TOTAL
|
|
|
252,253
|
|
|
|
288,652
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
2,051,385
|
|
|
|
1,896,073
|
|
Transmission
|
|
|
491,245
|
|
|
|
479,119
|
|
Distribution
|
|
|
1,514,251
|
|
|
|
1,475,758
|
|
Other
|
|
|
202,545
|
|
|
|
191,103
|
|
Construction
Work in Progress
|
|
|
322,114
|
|
|
|
294,138
|
|
Total
|
|
|
4,581,540
|
|
|
|
4,336,191
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,647,537
|
|
|
|
1,611,043
|
|
TOTAL
- NET
|
|
|
2,934,003
|
|
|
|
2,725,148
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
271,205
|
|
|
|
298,304
|
|
Long-term
Risk Management Assets
|
|
|
46,558
|
|
|
|
56,206
|
|
Deferred
Charges and Other
|
|
|
114,735
|
|
|
|
152,379
|
|
TOTAL
|
|
|
432,498
|
|
|
|
506,889
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
3,618,754
|
|
|
$ |
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
June
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
64,003
|
|
|
$ |
696
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
104,586
|
|
|
|
112,431
|
|
Affiliated
Companies
|
|
|
42,580
|
|
|
|
59,538
|
|
Long-term
Debt Due Within One Year - Nonaffiliated
|
|
|
112,000
|
|
|
|
-
|
|
Risk
Management Liabilities
|
|
|
32,018
|
|
|
|
49,285
|
|
Customer
Deposits
|
|
|
50,686
|
|
|
|
34,991
|
|
Accrued
Taxes
|
|
|
158,915
|
|
|
|
166,551
|
|
Accrued
Interest
|
|
|
23,155
|
|
|
|
20,868
|
|
Other
|
|
|
38,262
|
|
|
|
37,143
|
|
TOTAL
|
|
|
626,205
|
|
|
|
481,503
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
985,523
|
|
|
|
1,097,322
|
|
Long-term
Debt – Affiliated
|
|
|
100,000
|
|
|
|
100,000
|
|
Long-term
Risk Management Liabilities
|
|
|
31,956
|
|
|
|
40,477
|
|
Deferred
Income Taxes
|
|
|
461,738
|
|
|
|
475,888
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
169,757
|
|
|
|
179,048
|
|
Deferred
Credits and Other
|
|
|
102,908
|
|
|
|
90,434
|
|
TOTAL
|
|
|
1,851,882
|
|
|
|
1,983,169
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,478,087
|
|
|
|
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
|
|
|
580,271
|
|
|
|
580,192
|
|
Retained
Earnings
|
|
|
540,689
|
|
|
|
456,787
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(21,319 |
) |
|
|
(21,988 |
) |
TOTAL
|
|
|
1,140,667
|
|
|
|
1,056,017
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
|
$ |
3,618,754
|
|
|
$ |
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 Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
127,003
|
|
|
$ |
83,599
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
99,743
|
|
|
|
92,368
|
|
Deferred
Income Taxes
|
|
|
(5,077 |
) |
|
|
(250 |
) |
Carrying
Costs Income
|
|
|
(2,231 |
) |
|
|
(2,036 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
5,600
|
|
|
|
(466 |
) |
Deferred
Property Taxes
|
|
|
39,063
|
|
|
|
30,201
|
|
Change
in Other Noncurrent Assets
|
|
|
(25,985 |
) |
|
|
(15,417 |
) |
Change
in Other Noncurrent Liabilities
|
|
|
(7,054 |
) |
|
|
7,111
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
7,678
|
|
|
|
29,274
|
|
Fuel,
Materials and Supplies
|
|
|
(4,740 |
) |
|
|
(14,664 |
) |
Accounts
Payable
|
|
|
(10,735 |
) |
|
|
16,866
|
|
Customer
Deposits
|
|
|
15,695
|
|
|
|
(14,843 |
) |
Accrued
Taxes, Net
|
|
|
5,493
|
|
|
|
(21,909 |
) |
Other
Current Assets
|
|
|
5,608
|
|
|
|
24,796
|
|
Other
Current Liabilities
|
|
|
(1,952 |
) |
|
|
(1,062 |
) |
Net
Cash Flows From Operating Activities
|
|
|
248,109
|
|
|
|
213,568
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(169,014 |
) |
|
|
(137,728 |
) |
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
|
(12,616 |
) |
Acquisition
of Darby Plant
|
|
|
(102,032 |
) |
|
|
-
|
|
Proceeds
from Sale of Assets
|
|
|
842
|
|
|
|
1,976
|
|
Other
|
|
|
(20 |
) |
|
|
(1,151 |
) |
Net
Cash Flows Used For Investing Activities
|
|
|
(270,224 |
) |
|
|
(149,519 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Change
in Advances from Affiliates, Net
|
|
|
63,307
|
|
|
|
(17,609 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(1,446 |
) |
|
|
(1,570 |
) |
Dividends
Paid on Common Stock
|
|
|
(40,000 |
) |
|
|
(45,000 |
) |
Net
Cash Flows From (Used For) Financing Activities
|
|
|
21,861
|
|
|
|
(64,179 |
) |
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(254 |
) |
|
|
(130 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,319
|
|
|
|
940
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,065
|
|
|
$ |
810
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
31,557
|
|
|
$ |
32,374
|
|
Net
Cash Paid for Income Taxes
|
|
|
1,704
|
|
|
|
10,713
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,347
|
|
|
|
1,648
|
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
30,659
|
|
|
|
12,601
|
|
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
Second
Quarter of 2007 Compared to Second Quarter of 2006
Reconciliation
of Second Quarter of 2006 to Second Quarter of 2007
Net
Income
(in
millions)
Second
Quarter of 2006
|
|
|
|
|
$ |
29
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(7 |
) |
|
|
|
|
FERC
Municipals and Cooperatives
|
|
|
16
|
|
|
|
|
|
Off-system
Sales
|
|
|
6
|
|
|
|
|
|
Transmission
Revenues
|
|
|
6
|
|
|
|
|
|
Other
|
|
|
2
|
|
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(13 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(3 |
) |
|
|
|
|
Other
Income
|
|
|
(1 |
) |
|
|
|
|
Interest
Expense
|
|
|
(2 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(19 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
Second
Quarter of 2007
|
|
|
|
|
|
$ |
30
|
|
Net
Income increased $1 million to $30 million in 2007. The key drivers
of the increase were a $23 million increase in Gross Margin offset by a $19
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 decreased $7 million primarily due to a $12 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 $7 million
due to
fewer constraints in the PJM market. Higher retail sales of $14
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 $16 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 $6 million primarily due to higher
power
prices in the east and higher trading margins.
|
·
|
Transmission
Revenues increased $6 million primarily due to a provision recorded
in the
second quarter of 2006 for potential SECA refunds. See
“Transmission Rate Proceedings at the FERC” section of Note
3.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $13 million primarily
due to
a $7 million increase in coal-fired steam plant maintenance expenses
resulting from a planned outage at the Rockport Plant and
a $4 million increase in transmission expense 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 increased $3 million primarily due to
a $2
million increase in amortization related to capitalized software
development costs and a $1 million increase in depreciation related
to
capital additions.
|
·
|
Interest
Expense increased $2 million primarily due to an increase in outstanding
long-term debt and higher interest
rates.
|
Income
Taxes
Income
Tax Expense increased $3 million primarily due to an increase in pretax book
income and state income taxes.
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Reconciliation
of Six Months Ended June 30, 2006 to Six Months Ended June 30,
2007
Net
Income
(in
millions)
Six
Months Ended June 30, 2006
|
|
|
|
|
$ |
86
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
(30 |
) |
|
|
|
|
FERC
Municipals and Cooperatives
|
|
|
25
|
|
|
|
|
|
Off-system
Sales
|
|
|
2
|
|
|
|
|
|
Transmission
Revenues
|
|
|
4
|
|
|
|
|
|
Other
|
|
|
(5 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(20 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(10 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
1
|
|
|
|
|
|
Other
Income
|
|
|
(2 |
) |
|
|
|
|
Interest
Expense
|
|
|
(4 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(35 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
$ |
59
|
|
Net
Income decreased $27 million to $59 million in 2007. The key drivers
of the decrease were a $4 million decrease in Gross Margin and a $35 million
increase in Operating Expenses and Other partially offset by a $12 million
decrease in Income Tax Expense.
The
major
components of the decrease in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power, were as follows:
·
|
Retail
Margins decreased $30 million primarily due to a $35 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 $16 million
due to
fewer constraints in the PJM market. Higher retail sales of $27
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 $25 million due to
the
addition of new municipal contracts including new rates and increased
demand effective July 2006 and January 2007.
|
·
|
Transmission
Revenues increased $4 million primarily due to a provision recorded
in the
second quarter of 2006 for potential SECA refunds. See
“Transmission Rate Proceedings at the FERC” section of Note
3.
|
·
|
Other
revenues decreased $5 million primarily due to decreased River
Transportation Division (RTD) revenues for barging coal and decreased
gains on sales of emission allowances. RTD related expenses
which offset the RTD revenue decrease are included in Other Operation
on
the Condensed Consolidated Statements of Income resulting in earning
only
a return approved under regulatory
order.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other Operation
and Maintenance expenses increased $20 million primarily due to
a $10
million increase in coal-fired plant maintenance expenses resulting
from
planned outages at Rockport and Tanners Creek plants and a $10
million
increase in transmission expense 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 increased $10 million primarily due to
a $6
million increase in depreciation related to capital additions and
a $4
million increase in amortization related to capitalized software
development costs.
|
·
|
Interest
Expense increased $4 million primarily due to an increase in outstanding
long-term debt and higher interest
rates.
|
Income
Taxes
Income
Tax Expense decreased $12 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 $115 million and $93 million at June 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 Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
402,152
|
|
|
$ |
371,581
|
|
|
$ |
807,316
|
|
|
$ |
775,350
|
|
Sales
to AEP Affiliates
|
|
|
62,962
|
|
|
|
80,401
|
|
|
|
130,391
|
|
|
|
168,935
|
|
Other
– Affiliated
|
|
|
14,571
|
|
|
|
9,841
|
|
|
|
27,238
|
|
|
|
24,935
|
|
Other
– Nonaffiliated
|
|
|
6,352
|
|
|
|
7,631
|
|
|
|
13,961
|
|
|
|
16,013
|
|
TOTAL
|
|
|
486,037
|
|
|
|
469,454
|
|
|
|
978,906
|
|
|
|
985,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
90,650
|
|
|
|
96,147
|
|
|
|
186,767
|
|
|
|
185,599
|
|
Purchased
Electricity for Resale
|
|
|
19,310
|
|
|
|
15,533
|
|
|
|
37,250
|
|
|
|
26,543
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
75,791
|
|
|
|
80,830
|
|
|
|
153,304
|
|
|
|
167,252
|
|
Other
Operation
|
|
|
117,311
|
|
|
|
109,388
|
|
|
|
238,044
|
|
|
|
221,005
|
|
Maintenance
|
|
|
45,725
|
|
|
|
40,352
|
|
|
|
88,155
|
|
|
|
85,571
|
|
Depreciation
and Amortization
|
|
|
53,890
|
|
|
|
50,778
|
|
|
|
110,197
|
|
|
|
100,493
|
|
Taxes
Other Than Income Taxes
|
|
|
19,238
|
|
|
|
18,965
|
|
|
|
37,232
|
|
|
|
37,871
|
|
TOTAL
|
|
|
421,915
|
|
|
|
411,993
|
|
|
|
850,949
|
|
|
|
824,334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
64,122
|
|
|
|
57,461
|
|
|
|
127,957
|
|
|
|
160,899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
707
|
|
|
|
663
|
|
|
|
1,295
|
|
|
|
1,357
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
727
|
|
|
|
1,440
|
|
|
|
992
|
|
|
|
3,364
|
|
Interest
Expense
|
|
|
(19,611 |
) |
|
|
(17,902 |
) |
|
|
(39,432 |
) |
|
|
(35,435 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
45,945
|
|
|
|
41,662
|
|
|
|
90,812
|
|
|
|
130,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
15,910
|
|
|
|
13,137
|
|
|
|
31,314
|
|
|
|
43,782
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
30,035
|
|
|
|
28,525
|
|
|
|
59,498
|
|
|
|
86,403
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
85
|
|
|
|
85
|
|
|
|
170
|
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
29,950
|
|
|
$ |
28,440
|
|
|
$ |
59,328
|
|
|
$ |
86,233
|
|
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 Six Months Ended June 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
|
|
|
|
|
|
|
|
|
|
|
(20,000 |
) |
|
|
|
|
|
|
(20,000 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(170 |
) |
|
|
|
|
|
|
(170 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,199,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $4,685
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,701
|
|
|
|
8,701
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
86,403
|
|
|
|
|
|
|
|
86,403
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2006
|
|
$ |
56,584
|
|
|
$ |
861,290
|
|
|
$ |
372,020
|
|
|
$ |
5,132
|
|
|
$ |
1,295,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
(20,000 |
) |
|
|
|
|
|
|
(20,000 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(170 |
) |
|
|
|
|
|
|
(170 |
) |
Gain
on Reacquired Preferred Stock
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,269,597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,206
|
|
|
|
1,206
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
59,498
|
|
|
|
|
|
|
|
59,498
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60,704
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
56,584
|
|
|
$ |
861,291
|
|
|
$ |
426,271
|
|
|
$ |
(13,845 |
) |
|
$ |
1,330,301
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
607
|
|
|
$ |
1,369
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
74,465
|
|
|
|
82,102
|
|
Affiliated
Companies
|
|
|
68,135
|
|
|
|
108,288
|
|
Accrued
Unbilled Revenues
|
|
|
3,947
|
|
|
|
2,206
|
|
Miscellaneous
|
|
|
1,648
|
|
|
|
1,838
|
|
Allowance
for Uncollectible Accounts
|
|
|
(729 |
) |
|
|
(601 |
) |
Total
Accounts Receivable
|
|
|
147,466
|
|
|
|
193,833
|
|
Fuel
|
|
|
51,416
|
|
|
|
64,669
|
|
Materials
and Supplies
|
|
|
137,849
|
|
|
|
129,953
|
|
Risk
Management Assets
|
|
|
47,684
|
|
|
|
69,752
|
|
Accrued
Tax Benefits
|
|
|
-
|
|
|
|
27,378
|
|
Prepayments
and Other
|
|
|
9,740
|
|
|
|
15,170
|
|
TOTAL
|
|
|
394,762
|
|
|
|
502,124
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
3,402,290
|
|
|
|
3,363,813
|
|
Transmission
|
|
|
1,062,935
|
|
|
|
1,047,264
|
|
Distribution
|
|
|
1,159,964
|
|
|
|
1,102,033
|
|
Other
(including nuclear fuel and coal mining)
|
|
|
556,848
|
|
|
|
529,727
|
|
Construction
Work in Progress
|
|
|
150,684
|
|
|
|
183,893
|
|
Total
|
|
|
6,332,721
|
|
|
|
6,226,730
|
|
Accumulated
Depreciation, Depletion and Amortization
|
|
|
2,970,351
|
|
|
|
2,914,131
|
|
TOTAL
- NET
|
|
|
3,362,370
|
|
|
|
3,312,599
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
274,468
|
|
|
|
314,805
|
|
Spent
Nuclear Fuel and Decommissioning Trusts
|
|
|
1,310,871
|
|
|
|
1,248,319
|
|
Long-term
Risk Management Assets
|
|
|
48,908
|
|
|
|
59,137
|
|
Deferred
Charges and Other
|
|
|
108,343
|
|
|
|
109,453
|
|
TOTAL
|
|
|
1,742,590
|
|
|
|
1,731,714
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
5,499,722
|
|
|
$ |
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
June
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
14,941
|
|
|
$ |
91,173
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
120,551
|
|
|
|
146,733
|
|
Affiliated
Companies
|
|
|
53,583
|
|
|
|
65,497
|
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
-
|
|
|
|
50,000
|
|
Risk
Management Liabilities
|
|
|
33,508
|
|
|
|
52,083
|
|
Customer
Deposits
|
|
|
36,490
|
|
|
|
34,946
|
|
Accrued
Taxes
|
|
|
100,860
|
|
|
|
59,652
|
|
Other
|
|
|
113,497
|
|
|
|
128,461
|
|
TOTAL
|
|
|
473,430
|
|
|
|
628,545
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
1,561,600
|
|
|
|
1,505,135
|
|
Long-term
Risk Management Liabilities
|
|
|
33,545
|
|
|
|
42,641
|
|
Deferred
Income Taxes
|
|
|
305,148
|
|
|
|
335,000
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
784,082
|
|
|
|
753,402
|
|
Asset
Retirement Obligations
|
|
|
831,051
|
|
|
|
809,853
|
|
Deferred
Credits and Other
|
|
|
172,485
|
|
|
|
174,340
|
|
TOTAL
|
|
|
3,687,911
|
|
|
|
3,620,371
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,161,341
|
|
|
|
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
|
|
|
426,271
|
|
|
|
386,616
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(13,845 |
) |
|
|
(15,051 |
) |
TOTAL
|
|
|
1,330,301
|
|
|
|
1,289,439
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
5,499,722
|
|
|
$ |
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 Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
59,498
|
|
|
$ |
86,403
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
110,197
|
|
|
|
100,493
|
|
Deferred
Income Taxes
|
|
|
(9,547 |
) |
|
|
9,562
|
|
Deferred
Investment Tax Credits
|
|
|
(3,471 |
) |
|
|
(3,640 |
) |
Amortization
(Deferral) of Incremental Nuclear Refueling Outage Expenses,
Net
|
|
|
23,099
|
|
|
|
(12,111 |
) |
Amortization
of Nuclear Fuel
|
|
|
33,003
|
|
|
|
24,928
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
5,607
|
|
|
|
(634 |
) |
Change
in Other Noncurrent Assets
|
|
|
(12,308 |
) |
|
|
7,630
|
|
Change
in Other Noncurrent Liabilities
|
|
|
22,896
|
|
|
|
14,701
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
36,805
|
|
|
|
56,894
|
|
Fuel,
Materials and Supplies
|
|
|
9,911
|
|
|
|
(12,092 |
) |
Accounts
Payable
|
|
|
(46,049 |
) |
|
|
4,221
|
|
Customer
Deposits
|
|
|
1,544
|
|
|
|
(14,867 |
) |
Accrued
Taxes, Net
|
|
|
72,977
|
|
|
|
28,256
|
|
Other
Current Assets
|
|
|
4,595
|
|
|
|
21,921
|
|
Other
Current Liabilities
|
|
|
(17,858 |
) |
|
|
(21,559 |
) |
Net
Cash Flows From Operating Activities
|
|
|
290,899
|
|
|
|
290,106
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(124,252 |
) |
|
|
(169,491 |
) |
Purchases
of Investment Securities
|
|
|
(409,163 |
) |
|
|
(434,212 |
) |
Sales
of Investment Securities
|
|
|
370,986
|
|
|
|
405,716
|
|
Acquisitions
of Nuclear Fuel
|
|
|
(30,498 |
) |
|
|
(35,195 |
) |
Other
|
|
|
292
|
|
|
|
2,273
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(192,635 |
) |
|
|
(230,909 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
-
|
|
|
|
49,745
|
|
Change
in Advances from Affiliates, Net
|
|
|
(76,232 |
) |
|
|
(35,953 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
-
|
|
|
|
(50,000 |
) |
Retirement
of Cumulative Preferred Stock
|
|
|
(2 |
) |
|
|
-
|
|
Principal
Payments for Capital Lease Obligations
|
|
|
(2,622 |
) |
|
|
(3,139 |
) |
Dividends
Paid on Common Stock
|
|
|
(20,000 |
) |
|
|
(20,000 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(170 |
) |
|
|
(170 |
) |
Net
Cash Flows Used For Financing Activities
|
|
|
(99,026 |
) |
|
|
(59,517 |
) |
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(762 |
) |
|
|
(320 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,369
|
|
|
|
854
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
607
|
|
|
$ |
534
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
32,082
|
|
|
$ |
32,959
|
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(20,001 |
) |
|
|
12,031
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,160
|
|
|
|
3,185
|
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
24,145
|
|
|
|
18,031
|
|
Acquisition
of Nuclear Fuel in Accounts Payable at June 30,
|
|
|
30,867
|
|
|
|
25,780
|
|
|
|
|
|
|
|
|
|
|
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
Second
Quarter of 2007 Compared to Second Quarter of 2006
Reconciliation
of Second Quarter of 2006 to Second Quarter of 2007
Net
Income
(in
millions)
Second
Quarter of 2006
|
|
|
|
|
$ |
23
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
59
|
|
|
|
|
|
Off-system
Sales
|
|
|
4
|
|
|
|
|
|
Transmission
Revenues
|
|
|
4
|
|
|
|
|
|
Other
|
|
|
(4 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
63
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
33
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(7 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(2 |
) |
|
|
|
|
Interest
Expense
|
|
|
(9 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(27 |
) |
|
|
|
|
|
|
|
|
|
Second
Quarter of 2007
|
|
|
|
|
|
$ |
74
|
|
Net
Income increased $51 million to $74 million in 2007. The key drivers
of the increase were a $63 million increase in Gross Margin and a $15 million
decrease in Operating Expenses and Other offset by 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 $59 million primarily due to the
following:
|
|
·
|
A
$16 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
$14 million increase in industrial revenue primarily due to the
addition
of Ormet, a major industrial customer. The addition of Ormet
resulted in a $12 million increase in industrial sales. See
“Ormet” section of Note 3.
|
|
·
|
A
$13 million increase in rate revenues primarily related to an $11
million
increase in OPCo’s RSP, a $3 million increase related to rate recovery of
storm costs and a $3 million increase related to rate recovery
of IGCC
preconstruction costs. See “Ohio Rate Matters” section of Note
3. The increase in rate recovery of storm costs was offset by
the amortization of deferred expenses in Other Operation and
Maintenance. The increase in rate recovery of IGCC
preconstruction costs was offset by the amortization of deferred
expenses
in Depreciation and Amortization.
|
|
·
|
A
$13 million increase in residential and commercial revenue primarily
due
to a 71% increase in cooling degree days.
|
|
·
|
A
$12 million increase in fuel margins.
|
·
|
Margins
from Off-system Sales increased $4 million primarily due to a $15
million
increase in trading margins as the result of higher power prices
in the
east offset by an $8 million decrease related to OPCo’s purchase power and
sale agreement with Dow Chemical Company (Dow) which ended in November
2006 and a $3 million decrease in OPCo’s allocated share of off-system
sales revenue due to an affiliate’s new peak. Margins related
to Dow were offset by a corresponding decrease in Other Operation
and
Maintenance expenses. See “OPCo Indemnification Agreement with
AEP Resources” section of Note 16 in the 2006 Annual Report for further
discussion related to Dow.
|
·
|
Transmission
Revenues increased $4 million primarily due to a provision recorded
in the
second quarter of 2006 related to potential SECA refunds. See
“Transmission Rate Proceedings at the FERC” section of Note
3.
|
·
|
Other
revenues decreased $4 million primarily due to a $3 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 $1 million decrease in gains on sales of emission
allowances.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses decreased $33 million primarily
due
to:
|
|
·
|
An
$18 million decrease in maintenance from planned and forced outages
at the
Gavin, Muskingum River, Kammer and Sporn Plants related to boiler
tube
inspections in 2006.
|
|
·
|
An
$8 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
$5 million decrease in removal costs at the Mitchell, Sporn and
Amos
Plants related to outages in 2006.
|
|
These
amounts were offset by:
|
|
·
|
A
$3 million increase in overhead line expenses due in part to the
amortization of deferred storm expenses recovered through a cost-recovery
rider. The increase was offset by a corresponding increase in
Retail Margins.
|
·
|
Depreciation
and Amortization increased $7 million primarily due to a $6 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. These increases were offset by a $2
million decrease in 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 $9 million due to long-term debt issuances since
May
2006.
|
Income
Taxes
Income
Tax Expense increased $27 million primarily due to an increase in pretax
book
income.
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Reconciliation
of Six Months Ended June 30, 2006 to Six Months Ended June 30,
2007
Net
Income
(in
millions)
Six
Months Ended June 30, 2006
|
|
|
|
|
$ |
118
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
Margins
|
|
|
118
|
|
|
|
|
|
Off-system
Sales
|
|
|
(17 |
) |
|
|
|
|
Transmission
Revenues
|
|
|
(6 |
) |
|
|
|
|
Other
|
|
|
(14 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
81
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
5
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
(12 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(3 |
) |
|
|
|
|
Interest
Expense
|
|
|
(12 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(22 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
(23 |
) |
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
$ |
154
|
|
Net
Income increased $36 million to $154 million in 2007. The key driver
of the increase was an $81 million increase in Gross Margin offset by a $23
million increase in Income Tax Expense and a $22 million increase in Operating
Expenses and Other.
The
major
components of the increase in Gross Margin, defined as revenues less the
related
direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power were as follows:
·
|
Retail
Margins increased $118 million primarily due to the
following:
|
|
·
|
A
$41 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
$35 million increase in rate revenues primarily related to a $20
million
increase in OPCo’s RSP, a $6 million increase related to rate recovery of
storm costs and a $6 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
$20 million increase in residential and commercial revenue primarily
due
to a 73% increase in cooling degree days.
|
|
·
|
An
$18 million increase in industrial revenue due to the addition
of Ormet, a
major industrial customer. See “Ormet” section of Note
3.
|
|
These
increases were partially offset by:
|
|
·
|
An
$8 million decrease in revenues associated with SO2
allowances
received in 2006 from Buckeye Power, Inc. under the Cardinal Station
Allowances Agreement.
|
·
|
Margins
from Off-system Sales decreased $17 million primarily due to a
$20 million
decrease in OPCo’s allocated share of off-system sales revenues due to an
affiliate’s new peak and a $9 million decrease in margins related to
OPCo’s purchase power and sale agreement with Dow which ended in November
2006. These decreases were offset by higher trading margins of
$11 million as the result of higher power prices in the east and
a change
in the allocation of off-system sales margins under the SIA effective
April 1, 2006. Margins related to Dow were offset by a
corresponding decrease in Other Operation and Maintenance
expenses.
|
·
|
Transmission
Revenues decreased $6 million primarily due to the elimination
of SECA
revenues as of April 1, 2006 offset by a provision recorded in
the second
quarter of 2006 related to potential SECA refunds. See
“Transmission Rate Proceedings at the FERC” section of Note
3.
|
·
|
Other
revenues decreased $14 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 $4 million decrease in gains on sales of emission
allowances.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses decreased $5 million primarily
due to
the following:
|
|
·
|
A
$16 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
$9 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
$7 million increase in removal costs related to planned and forced
outages
at the Gavin, Mitchell and Cardinal Plants.
|
|
·
|
A
$6 million increase in overhead line expenses due in part to the
amortization of deferred storm expenses recovered through a cost-recovery
rider. The increase was offset by a corresponding increase in
Retail Margins.
|
|
·
|
A
$5 million increase due to the February 2006 adjustment of liabilities
related to sold coal companies.
|
·
|
Depreciation
and Amortization increased $12 million primarily due to a $9 million
increase in depreciation related to environmental improvements
placed in
service at the Mitchell Plant and the amortization of IGCC preconstruction
costs of $6 million in 2007. These increases were offset by a
$3 million decrease in 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 $12 million primarily due to a $15 million increase
related to long-term debt issuances since May 2006 offset by a
$5 million
increase in allowance for borrowed funds used during
construction.
|
Income
Taxes
Income
Tax Expense increased $23 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 six months ended June 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
|
|
|
279,029
|
|
|
|
321,944
|
|
Investing
Activities
|
|
|
(560,262 |
) |
|
|
(512,468 |
) |
Financing
Activities
|
|
|
282,607
|
|
|
|
190,274
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
1,374
|
|
|
|
(250 |
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
2,999
|
|
|
$ |
990
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $279 million in 2007. OPCo
produced Net Income of $154 million during the period and a noncash expense
item
of $169 million for Depreciation and Amortization. The other changes
in assets and liabilities represent items that had a current period cash
flow
impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The current period activity in working capital
relates to a number of items. Accounts Payable had a $47 million cash
outflow partially due to emission allowance payments in January
2007. Accrued Taxes, Net, had a $47 million cash inflow primarily due
to an increase of federal income tax related accruals offset by temporary
timing
differences of payments for property taxes. Fuel, Materials and
Supplies had a $42 million cash outflow primarily due to an increase in coal
inventory in preparation for the summer cooling season and an increase in
materials related to projects at the Mitchell, Amos, Gavin and Sporn
Plants.
Net
Cash
Flows From Operating Activities were $322 million in 2006. OPCo
produced Net Income of $118 million during the period and a noncash expense
item
of $157 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 prior period activity in working capital
primarily relates to a number of items. Accounts Receivable, Net had
a $98 million cash inflow primarily due to collected receivables from OPCo’s
affiliates related to power sales, settled litigation and emission
allowances. Fuel, Materials and Supplies had a $56 million cash
outflow primarily due to an increase in coal inventory in preparation for
the
summer cooling season. Accounts Payable had a $43 million cash
outflow primarily due to timing differences for payments to affiliates related
to the AEP Power Pool.
Investing
Activities
Net
Cash
Flows Used For Investing Activities were $560 million and $512 million in
2007
and 2006, respectively. Construction Expenditures were $566 million
and $482 million in 2007 and 2006, respectively, primarily related to
environmental upgrades, as well as projects to improve service reliability
for
transmission and distribution. Environmental upgrades include the
installation of selective catalytic reduction equipment and the flue gas
desulfurization projects at the Cardinal, Amos and Mitchell
Plants. In January 2007, environmental upgrades were completed for
Unit 2 at the Mitchell Plant. For the remainder of 2007, OPCo expects
construction expenditures to be approximately $265 million.
Financing
Activities
Net
Cash
Flows From Financing Activities were $283 million in 2007. OPCo
issued Senior Unsecured Notes for $400 million and $65 million of Pollution
Control Bonds. OPCo repaid borrowings of $165 million from the
Utility Money Pool.
Net
Cash
Flows From Financing Activities were $190 million for 2006. OPCo
issued Senior Unsecured Notes for $350 million and $65 million of Pollution
Control Bonds. OPCo retired Notes Payable-Affiliated of $200
million. OPCo repaid borrowings of $70 million from the Utility Money
Pool and received a Capital Contribution from Parent of $70
million.
Financing
Activity
Long-term
debt issuances and retirements during the first six months of 2007
were:
Issuances
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
Date
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Pollution
Control Bonds
|
|
$
|
65,000
|
|
4.90
|
|
2037
|
Senior
Unsecured Notes
|
|
|
400,000
|
|
Variable
|
|
2010
|
Retirements
|
|
Principal
Amount
|
|
Interest
|
|
Due
|
Type
of Debt
|
|
|
Rate
|
|
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.
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 June 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 June 30, 2007
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
|
Cash
Flow Hedges
|
|
|
DETM
Assignment (a)
|
|
|
Total
|
|
Current
Assets
|
|
$ |
50,040
|
|
|
$ |
7,267
|
|
|
$ |
-
|
|
|
$ |
57,307
|
|
Noncurrent
Assets
|
|
|
55,122
|
|
|
|
1,143
|
|
|
|
-
|
|
|
|
56,265
|
|
Total
MTM Derivative Contract Assets
|
|
|
105,162
|
|
|
|
8,410
|
|
|
|
-
|
|
|
|
113,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(40,629 |
) |
|
|
(174 |
) |
|
|
(2,315 |
) |
|
|
(43,118 |
) |
Noncurrent
Liabilities
|
|
|
(34,290 |
) |
|
|
(56 |
) |
|
|
(4,898 |
) |
|
|
(39,244 |
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(74,919 |
) |
|
|
(230 |
) |
|
|
(7,213 |
) |
|
|
(82,362 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
|
$ |
30,243
|
|
|
$ |
8,180
|
|
|
$ |
(7,213 |
) |
|
$ |
31,210
|
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 16 in the 2006 Annual
Report.
|
MTM
Risk Management Contract Net Assets
Six
Months Ended June 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
|
|
|
(5,664
|
)
|
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
|
|
311
|
|
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
|
|
332
|
|
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
|
|
-
|
|
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
|
|
2,670
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(448
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
30,243
|
|
Net
Cash Flow Hedge Contracts
|
|
|
8,180
|
|
DETM
Assignment (d)
|
|
|
(7,213
|
)
|
Total
MTM Risk Management Contract Net Assets at June 30,
2007
|
|
$
|
31,210
|
|
(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 June 30, 2007
(in
thousands)
|
|
Remainder
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
After
2011
|
|
|
Total
|
|
Prices
Actively Quoted –Exchange Traded Contracts
|
|
$ |
3,646
|
|
|
$ |
(2,762 |
) |
|
$ |
185
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
1,069
|
|
Prices
Provided by Other External Sources
–
OTC Broker Quotes (a)
|
|
|
3,153
|
|
|
|
10,662
|
|
|
|
8,581
|
|
|
|
3,706
|
|
|
|
-
|
|
|
|
-
|
|
|
|
26,102
|
|
Prices
Based on Models and Other Valuation Methods (b)
|
|
|
(1,363 |
) |
|
|
(2,084 |
) |
|
|
1,078
|
|
|
|
3,562
|
|
|
|
810
|
|
|
|
1,069
|
|
|
|
3,072
|
|
Total
|
|
$ |
5,436
|
|
|
$ |
5,816
|
|
|
$ |
9,844
|
|
|
$ |
7,268
|
|
|
$ |
810
|
|
|
$ |
1,069
|
|
|
$ |
30,243
|
|
(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 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 forward contracts and collars as cash flow hedges to lock in prices
on
certain transactions denominated in foreign currencies where deemed
necessary. Management does not hedge all foreign currency
exposure.
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 June 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
Six
Months Ended June 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
|
|
|
3,617
|
|
|
|
-
|
|
|
|
563
|
|
|
|
4,180
|
|
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
|
|
(2,810 |
) |
|
|
7
|
|
|
|
(406 |
) |
|
|
(3,209 |
) |
Ending
Balance in AOCI June 30, 2007
|
|
$ |
4,847
|
|
|
$ |
(324 |
) |
|
$ |
3,710
|
|
|
$ |
8,233
|
|
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $5,504 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 June 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:
Six
Months Ended June 30, 2007
|
|
|
|
|
Twelve
Months Ended December 31, 2006
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$360
|
|
$2,054
|
|
$679
|
|
$195
|
|
|
|
|
$573
|
|
$1,451
|
|
$500
|
|
$271
|
The
High
VaR for the twelve months ended December 31, 2006 occurred in the third quarter
due to volatility in the ECAR/PJM region.
VaR
Associated with Debt Outstanding
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 $147 million and $110 million at June 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 Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
480,445
|
|
|
$ |
453,064
|
|
|
$ |
972,979
|
|
|
$ |
997,703
|
|
Sales
to AEP Affiliates
|
|
|
180,205
|
|
|
|
154,648
|
|
|
|
359,099
|
|
|
|
303,907
|
|
Other
- Affiliated
|
|
|
6,817
|
|
|
|
3,866
|
|
|
|
10,855
|
|
|
|
7,575
|
|
Other
- Nonaffiliated
|
|
|
3,466
|
|
|
|
4,429
|
|
|
|
7,441
|
|
|
|
9,428
|
|
TOTAL
|
|
|
670,933
|
|
|
|
616,007
|
|
|
|
1,350,374
|
|
|
|
1,318,613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
201,338
|
|
|
|
211,538
|
|
|
|
399,631
|
|
|
|
446,668
|
|
Purchased
Electricity for Resale
|
|
|
27,868
|
|
|
|
26,313
|
|
|
|
52,722
|
|
|
|
48,027
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
28,745
|
|
|
|
28,091
|
|
|
|
49,711
|
|
|
|
56,663
|
|
Other
Operation
|
|
|
86,972
|
|
|
|
99,189
|
|
|
|
189,959
|
|
|
|
185,818
|
|
Maintenance
|
|
|
50,617
|
|
|
|
71,416
|
|
|
|
109,765
|
|
|
|
118,940
|
|
Depreciation
and Amortization
|
|
|
84,779
|
|
|
|
77,855
|
|
|
|
169,055
|
|
|
|
156,676
|
|
Taxes
Other Than Income Taxes
|
|
|
50,320
|
|
|
|
48,536
|
|
|
|
98,705
|
|
|
|
95,689
|
|
TOTAL
|
|
|
530,639
|
|
|
|
562,938
|
|
|
|
1,069,548
|
|
|
|
1,108,481
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
140,294
|
|
|
|
53,069
|
|
|
|
280,826
|
|
|
|
210,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Income
|
|
|
472
|
|
|
|
595
|
|
|
|
884
|
|
|
|
1,232
|
|
Carrying
Costs Income
|
|
|
3,594
|
|
|
|
3,451
|
|
|
|
7,135
|
|
|
|
6,834
|
|
Allowance
for Equity Funds Used During Construction
|
|
|
446
|
|
|
|
398
|
|
|
|
1,017
|
|
|
|
1,136
|
|
Interest
Expense
|
|
|
(33,734 |
) |
|
|
(24,437 |
) |
|
|
(59,665 |
) |
|
|
(47,851 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
111,072
|
|
|
|
33,076
|
|
|
|
230,197
|
|
|
|
171,483
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
36,732
|
|
|
|
9,677
|
|
|
|
76,596
|
|
|
|
53,052
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
74,340
|
|
|
|
23,399
|
|
|
|
153,601
|
|
|
|
118,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
183
|
|
|
|
183
|
|
|
|
366
|
|
|
|
366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
74,157
|
|
|
$ |
23,216
|
|
|
$ |
153,235
|
|
|
$ |
118,065
|
|
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 Six Months Ended June 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
|
|
|
|
|
|
|
|
|
|
|
(366 |
) |
|
|
|
|
|
|
(366 |
) |
Gain
on Reacquired Preferred Stock
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,837,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $5,708
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,600
|
|
|
|
10,600
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
118,431
|
|
|
|
|
|
|
|
118,431
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
129,031
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2006
|
|
$ |
321,201
|
|
|
$ |
536,639
|
|
|
$ |
1,097,419
|
|
|
$ |
11,355
|
|
|
$ |
1,966,614
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
(366 |
) |
|
|
|
|
|
|
(366 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,002,596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
971
|
|
|
|
971
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
153,601
|
|
|
|
|
|
|
|
153,601
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
154,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
321,201
|
|
|
$ |
536,639
|
|
|
$ |
1,355,120
|
|
|
$ |
(55,792 |
) |
|
$ |
2,157,168
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
OHIO
POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
2,999
|
|
|
$ |
1,625
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
89,097
|
|
|
|
86,116
|
|
Affiliated Companies
|
|
|
104,214
|
|
|
|
108,214
|
|
Accrued Unbilled Revenues
|
|
|
15,956
|
|
|
|
10,106
|
|
Miscellaneous
|
|
|
4,624
|
|
|
|
1,819
|
|
Allowance for Uncollectible Accounts
|
|
|
(1,004 |
) |
|
|
(824 |
) |
Total
Accounts Receivable
|
|
|
212,887
|
|
|
|
205,431
|
|
Fuel
|
|
|
159,637
|
|
|
|
120,441
|
|
Materials
and Supplies
|
|
|
85,650
|
|
|
|
74,840
|
|
Emission
Allowances
|
|
|
8,817
|
|
|
|
10,388
|
|
Risk
Management Assets
|
|
|
57,307
|
|
|
|
86,947
|
|
Accrued
Tax Benefits
|
|
|
2,747
|
|
|
|
22,909
|
|
Prepayments
and Other
|
|
|
16,524
|
|
|
|
18,416
|
|
TOTAL
|
|
|
546,568
|
|
|
|
540,997
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
5,492,398
|
|
|
|
4,413,340
|
|
Transmission
|
|
|
1,050,149
|
|
|
|
1,030,934
|
|
Distribution
|
|
|
1,355,421
|
|
|
|
1,322,103
|
|
Other
|
|
|
306,100
|
|
|
|
299,637
|
|
Construction
Work in Progress
|
|
|
620,350
|
|
|
|
1,339,631
|
|
Total
|
|
|
8,824,418
|
|
|
|
8,405,645
|
|
Accumulated
Depreciation and Amortization
|
|
|
2,871,803
|
|
|
|
2,836,584
|
|
TOTAL
- NET
|
|
|
5,952,615
|
|
|
|
5,569,061
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
366,748
|
|
|
|
414,180
|
|
Long-term
Risk Management Assets
|
|
|
56,265
|
|
|
|
70,092
|
|
Deferred
Charges and Other
|
|
|
201,227
|
|
|
|
224,403
|
|
TOTAL
|
|
|
624,240
|
|
|
|
708,675
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
7,123,423
|
|
|
$ |
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
June
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
16,583
|
|
|
$ |
181,281
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
167,508
|
|
|
|
250,025
|
|
Affiliated Companies
|
|
|
110,113
|
|
|
|
145,197
|
|
Short-term
Debt – Nonaffiliated
|
|
|
-
|
|
|
|
1,203
|
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
16,390
|
|
|
|
17,854
|
|
Risk
Management Liabilities
|
|
|
43,118
|
|
|
|
73,386
|
|
Customer
Deposits
|
|
|
40,431
|
|
|
|
31,465
|
|
Accrued
Taxes
|
|
|
187,851
|
|
|
|
165,338
|
|
Accrued
Interest
|
|
|
44,612
|
|
|
|
35,497
|
|
Other
|
|
|
108,545
|
|
|
|
123,631
|
|
TOTAL
|
|
|
735,151
|
|
|
|
1,024,877
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
2,641,779
|
|
|
|
2,183,887
|
|
Long-term
Debt – Affiliated
|
|
|
200,000
|
|
|
|
200,000
|
|
Long-term
Risk Management Liabilities
|
|
|
39,244
|
|
|
|
52,929
|
|
Deferred
Income Taxes
|
|
|
893,989
|
|
|
|
911,221
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
169,805
|
|
|
|
185,895
|
|
Deferred
Credits and Other
|
|
|
252,350
|
|
|
|
219,127
|
|
TOTAL
|
|
|
4,197,167
|
|
|
|
3,753,059
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
4,932,318
|
|
|
|
4,777,936
|
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
17,310
|
|
|
|
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
|
|
|
1,355,120
|
|
|
|
1,207,265
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(55,792 |
) |
|
|
(56,763 |
) |
TOTAL
|
|
|
2,157,168
|
|
|
|
2,008,342
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
7,123,423
|
|
|
$ |
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 Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
153,601
|
|
|
$ |
118,431
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
169,055
|
|
|
|
156,676
|
|
Deferred
Income Taxes
|
|
|
550
|
|
|
|
(8,073 |
) |
Carrying
Costs Income
|
|
|
(7,135 |
) |
|
|
(6,834 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
1,509
|
|
|
|
1,263
|
|
Deferred
Property Taxes
|
|
|
34,629
|
|
|
|
35,550
|
|
Change
in Other Noncurrent Assets
|
|
|
(18,338 |
) |
|
|
4,898
|
|
Change
in Other Noncurrent Liabilities
|
|
|
272
|
|
|
|
16,355
|
|
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
(18,273 |
) |
|
|
97,832
|
|
Fuel,
Materials and Supplies
|
|
|
(42,452 |
) |
|
|
(56,075 |
) |
Accounts
Payable
|
|
|
(46,758 |
) |
|
|
(42,878 |
) |
Accrued
Taxes, Net
|
|
|
46,587
|
|
|
|
(7,233 |
) |
Other
Current Assets
|
|
|
1,545
|
|
|
|
35,848
|
|
Other
Current Liabilities
|
|
|
4,237
|
|
|
|
(23,816 |
) |
Net
Cash Flows From Operating Activities
|
|
|
279,029
|
|
|
|
321,944
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(565,832 |
) |
|
|
(481,541 |
) |
Change
in Advances to Affiliates, Net
|
|
|
-
|
|
|
|
(36,787 |
) |
Proceeds
from Sales of Assets
|
|
|
5,594
|
|
|
|
7,511
|
|
Other
|
|
|
(24 |
) |
|
|
(1,651 |
) |
Net
Cash Flows Used For Investing Activities
|
|
|
(560,262 |
) |
|
|
(512,468 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
-
|
|
|
|
70,000
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
461,324
|
|
|
|
405,839
|
|
Change
in Short-term Debt, Net – Nonaffiliated
|
|
|
(1,203 |
) |
|
|
(5,094 |
) |
Change
in Advances from Affiliates, Net
|
|
|
(164,698 |
) |
|
|
(70,071 |
) |
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(8,927 |
) |
|
|
(6,177 |
) |
Retirement
of Long-term Debt – Affiliated
|
|
|
-
|
|
|
|
(200,000 |
) |
Retirement
of Cumulative Preferred Stock
|
|
|
(2 |
) |
|
|
(8 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(3,521 |
) |
|
|
(3,849 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(366 |
) |
|
|
(366 |
) |
Net
Cash Flows From Financing Activities
|
|
|
282,607
|
|
|
|
190,274
|
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
1,374
|
|
|
|
(250 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,625
|
|
|
|
1,240
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
2,999
|
|
|
$ |
990
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
51,991
|
|
|
$ |
43,794
|
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(9,193 |
) |
|
|
24,077
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
1,036
|
|
|
|
1,662
|
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
65,936
|
|
|
|
97,389
|
|
|
|
|
|
|
|
|
|
|
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
Second
Quarter of 2007 Compared to Second Quarter of 2006
Reconciliation
of Second Quarter of 2006 to Second Quarter of 2007
Net
Income
(in
millions)
Second
Quarter of 2006
|
|
|
|
|
$ |
15
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
(2 |
) |
|
|
|
|
Transmission
Revenues
|
|
|
(1 |
) |
|
|
|
|
Other
|
|
|
(2 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(3 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(1 |
) |
|
|
|
|
Interest
Expense
|
|
|
(3 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
Second
Quarter of 2007
|
|
|
|
|
|
$ |
6
|
|
Net
Income decreased $9 million to $6 million in 2007. The key drivers of
the decreased income were a $5 million decrease in Gross Margin and a $7
million
increase in Operating Expenses and Other, partially offset by a $3 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 $2 million primarily due
to a
decrease in retail margins resulting from a 28% decrease in cooling
days,
partially offset by an increase in Off-system Sales Margins, 75%
of which
flows through the fuel adjustment clause to retail
customers.
|
·
|
Other
revenues decreased $2 million primarily due to lower gains on sales
of
emission allowances and lower billings to outside parties for construction
services.
|
Operating
Expenses and Other increased between years as follows:
·
|
Other
Operation and Maintenance expenses increased $3 million primarily
due to
an $8 million increase in generation operation and maintenance
expense
primarily during planned outages at PSO’s Northeastern and Southwestern
plants. This increase was partially offset by a $5 million
decrease in distribution expenses, mostly due to a $7 million adjustment
to capitalize costs related to a January 2007 ice
storm.
|
·
|
Interest
Expense increased $3 million primarily due to increased
borrowings.
|
Income
Taxes
Income
Tax Expense decreased $3 million primarily due to a decrease in pretax book
income, offset in part by state income taxes.
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Reconciliation
of Six Months Ended June 30, 2006 to Six Months Ended June 30,
2007
Net
Income (Loss)
(in
millions)
Six
Months Ended June 30, 2006
|
|
|
|
|
$ |
9
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins
|
|
|
2
|
|
|
|
|
|
Transmission
Revenues
|
|
|
1
|
|
|
|
|
|
Other
|
|
|
(3 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(29 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(3 |
) |
|
|
|
|
Interest
Expense
|
|
|
(5 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(37 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
$ |
(14 |
) |
Net
Income decreased $23 million to a $14 million loss in 2007. The key
driver of the decreased income was a $37 million increase in Operating Expenses
and Other, partially offset by a $14 million decrease in Income Tax
Expense.
The
major
changes 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 $2 million primarily due
to an
increase in margins from Off-System Sales, 75% of which flows through
the
fuel adjustment clause to retail customers, partially offset by
a decrease
in retail margins resulting from a 25% decrease in cooling degree
days.
|
·
|
Other
revenues decreased $3 million primarily due to lower billings to
outside
parties for construction services, as well as the absence of a 2006
settlement received from an electric
cooperative.
|
Operating
Expenses and Other increased between years as follows:
·
|
Other
Operation and Maintenance expenses increased $29 million primarily
due to
a $15 million increase in distribution maintenance expense primarily
due
to a January 2007 ice storm and a $10 million increase in generation
operation and maintenance expense primarily during planned outages
at
PSO’s Oklaunion, Riverside, Northeastern and Southwestern
plants.
|
·
|
Depreciation
and Amortization increased $3 million due to higher depreciable
asset
balances.
|
·
|
Interest
Expense increased $5 million primarily due to increased
borrowings.
|
Income
Taxes
Income
Tax Expense decreased $14 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 $46 million and $39 million at June 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 OPERATIONS
For
the Three and Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
304,820
|
|
|
$ |
333,313
|
|
|
$ |
594,900
|
|
|
$ |
672,914
|
|
Sales
to AEP Affiliates
|
|
|
16,275
|
|
|
|
12,545
|
|
|
|
40,868
|
|
|
|
26,613
|
|
Other
|
|
|
544
|
|
|
|
1,188
|
|
|
|
1,184
|
|
|
|
2,248
|
|
TOTAL
|
|
|
321,639
|
|
|
|
347,046
|
|
|
|
636,952
|
|
|
|
701,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
113,633
|
|
|
|
150,976
|
|
|
|
256,148
|
|
|
|
364,149
|
|
Purchased
Electricity for Resale
|
|
|
70,145
|
|
|
|
56,358
|
|
|
|
137,554
|
|
|
|
89,575
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
18,979
|
|
|
|
15,880
|
|
|
|
32,463
|
|
|
|
37,111
|
|
Other
Operation
|
|
|
42,345
|
|
|
|
39,985
|
|
|
|
83,352
|
|
|
|
76,741
|
|
Maintenance
|
|
|
22,177
|
|
|
|
22,033
|
|
|
|
65,262
|
|
|
|
42,340
|
|
Depreciation
and Amortization
|
|
|
22,992
|
|
|
|
21,713
|
|
|
|
45,698
|
|
|
|
42,845
|
|
Taxes
Other Than Income Taxes
|
|
|
9,890
|
|
|
|
10,077
|
|
|
|
20,184
|
|
|
|
20,153
|
|
TOTAL
|
|
|
300,161
|
|
|
|
317,022
|
|
|
|
640,661
|
|
|
|
672,914
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME (LOSS)
|
|
|
21,478
|
|
|
|
30,024
|
|
|
|
(3,709 |
) |
|
|
28,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income
|
|
|
562
|
|
|
|
211
|
|
|
|
1,208
|
|
|
|
780
|
|
Interest
Expense
|
|
|
(12,785 |
) |
|
|
(9,634 |
) |
|
|
(24,168 |
) |
|
|
(18,769 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
|
|
9,255
|
|
|
|
20,601
|
|
|
|
(26,669 |
) |
|
|
10,872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense (Credit)
|
|
|
2,960
|
|
|
|
5,963
|
|
|
|
(12,538 |
) |
|
|
1,591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
|
6,295
|
|
|
|
14,638
|
|
|
|
(14,131 |
) |
|
|
9,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
53
|
|
|
|
53
|
|
|
|
106
|
|
|
|
106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
(LOSS) APPLICABLE TO COMMON STOCK
|
|
$ |
6,242
|
|
|
$ |
14,585
|
|
|
$ |
(14,237 |
) |
|
$ |
9,175
|
|
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 Six Months Ended June 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
|
|
|
|
|
|
|
|
|
|
|
(106 |
) |
|
|
|
|
|
|
(106 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
548,491
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
696
|
|
|
|
696
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
9,281
|
|
|
|
|
|
|
|
9,281
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,977
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2006
|
|
$ |
157,230
|
|
|
$ |
230,016
|
|
|
$ |
171,790
|
|
|
$ |
(568 |
) |
|
$ |
558,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DECEMBER
31, 2006
|
|
$ |
157,230
|
|
|
$ |
230,016
|
|
|
$ |
199,262
|
|
|
$ |
(1,070 |
) |
|
$ |
585,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN
48 Adoption, Net of Tax
|
|
|
|
|
|
|
|
|
|
|
(386 |
) |
|
|
|
|
|
|
(386 |
) |
Capital
Contribution from Parent
|
|
|
|
|
|
|
40,000
|
|
|
|
|
|
|
|
|
|
|
|
40,000
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(106 |
) |
|
|
|
|
|
|
(106 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
624,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
|
|
|
|
91
|
|
NET
LOSS
|
|
|
|
|
|
|
|
|
|
|
(14,131 |
) |
|
|
|
|
|
|
(14,131 |
) |
TOTAL
COMPREHENSIVE LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,040 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
157,230
|
|
|
$ |
270,016
|
|
|
$ |
184,639
|
|
|
$ |
(979 |
) |
|
$ |
610,906
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
PUBLIC
SERVICE COMPANY OF OKLAHOMA
CONDENSED
BALANCE SHEETS
ASSETS
June
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
908
|
|
|
$ |
1,651
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
52,773
|
|
|
|
70,319
|
|
Affiliated
Companies
|
|
|
68,499
|
|
|
|
73,318
|
|
Miscellaneous
|
|
|
13,251
|
|
|
|
10,270
|
|
Allowance
for Uncollectible Accounts
|
|
|
(34 |
) |
|
|
(5 |
) |
Total
Accounts Receivable
|
|
|
134,489
|
|
|
|
153,902
|
|
Fuel
|
|
|
22,063
|
|
|
|
20,082
|
|
Materials
and Supplies
|
|
|
54,818
|
|
|
|
48,375
|
|
Risk
Management Assets
|
|
|
54,372
|
|
|
|
100,802
|
|
Accrued
Tax Benefits
|
|
|
26,900
|
|
|
|
4,679
|
|
Regulatory
Asset for Under-Recovered Fuel Costs
|
|
|
21,069
|
|
|
|
7,557
|
|
Margin
Deposits
|
|
|
18,284
|
|
|
|
35,270
|
|
Prepayments
and Other
|
|
|
17,849
|
|
|
|
5,732
|
|
TOTAL
|
|
|
350,752
|
|
|
|
378,050
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
1,109,356
|
|
|
|
1,091,910
|
|
Transmission
|
|
|
543,722
|
|
|
|
503,638
|
|
Distribution
|
|
|
1,284,347
|
|
|
|
1,215,236
|
|
Other
|
|
|
240,542
|
|
|
|
234,227
|
|
Construction
Work in Progress
|
|
|
151,764
|
|
|
|
141,283
|
|
Total
|
|
|
3,329,731
|
|
|
|
3,186,294
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,203,048
|
|
|
|
1,187,107
|
|
TOTAL
- NET
|
|
|
2,126,683
|
|
|
|
1,999,187
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
153,154
|
|
|
|
142,905
|
|
Long-term
Risk Management Assets
|
|
|
9,200
|
|
|
|
17,066
|
|
Employee
Benefits and Pension Assets
|
|
|
29,362
|
|
|
|
30,161
|
|
Deferred
Charges and Other
|
|
|
27,832
|
|
|
|
11,677
|
|
TOTAL
|
|
|
219,548
|
|
|
|
201,809
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
2,696,983
|
|
|
$ |
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
June
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
216,239
|
|
|
$ |
76,323
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
168,779
|
|
|
|
165,618
|
|
Affiliated
Companies
|
|
|
80,116
|
|
|
|
65,134
|
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
12,660
|
|
|
|
-
|
|
Risk
Management Liabilities
|
|
|
42,748
|
|
|
|
88,469
|
|
Customer
Deposits
|
|
|
42,435
|
|
|
|
51,335
|
|
Accrued
Taxes
|
|
|
34,327
|
|
|
|
19,984
|
|
Other
|
|
|
33,671
|
|
|
|
58,651
|
|
TOTAL
|
|
|
630,975
|
|
|
|
525,514
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
670,087
|
|
|
|
669,998
|
|
Long-term
Risk Management Liabilities
|
|
|
6,481
|
|
|
|
11,448
|
|
Deferred
Income Taxes
|
|
|
417,789
|
|
|
|
414,197
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
295,381
|
|
|
|
315,584
|
|
Deferred
Credits and Other
|
|
|
60,102
|
|
|
|
51,605
|
|
TOTAL
|
|
|
1,449,840
|
|
|
|
1,462,832
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,080,815
|
|
|
|
1,988,346
|
|
|
|
|
|
|
|
|
|
|
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
|
|
5,262
|
|
|
|
5,262
|
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON
SHAREHOLDER’S EQUITY
|
|
|
|
|
|
|
|
|
Common
Stock – $15 Par Value Per Share:
|
|
|
|
|
|
|
|
|
Authorized
– 11,000,000 Shares
|
|
|
|
|
|
|
|
|
Issued
– 10,482,000 Shares
|
|
|
|
|
|
|
|
|
Outstanding
– 9,013,000 Shares
|
|
|
157,230
|
|
|
|
157,230
|
|
Paid-in
Capital
|
|
|
270,016
|
|
|
|
230,016
|
|
Retained
Earnings
|
|
|
184,639
|
|
|
|
199,262
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(979 |
) |
|
|
(1,070 |
) |
TOTAL
|
|
|
610,906
|
|
|
|
585,438
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
2,696,983
|
|
|
$ |
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 Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$ |
(14,131 |
) |
|
$ |
9,281
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
45,698
|
|
|
|
42,845
|
|
Deferred
Income Taxes
|
|
|
11,059
|
|
|
|
(22,319 |
) |
Mark-to-Market
of Risk Management Contracts
|
|
|
3,608
|
|
|
|
(11,979 |
) |
Deferred
Property Taxes
|
|
|
(16,539 |
) |
|
|
(16,196 |
) |
Change
in Other Noncurrent Assets
|
|
|
(26,291 |
) |
|
|
9,441
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(22,811 |
) |
|
|
(8,232 |
) |
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
19,413
|
|
|
|
8,080
|
|
Fuel,
Materials and Supplies
|
|
|
(8,414 |
) |
|
|
(6,816 |
) |
Margin
Deposits
|
|
|
16,986
|
|
|
|
(46,917 |
) |
Accounts
Payable
|
|
|
11,810
|
|
|
|
28,517
|
|
Customer
Deposits
|
|
|
(8,900 |
) |
|
|
1,495
|
|
Accrued
Taxes, Net
|
|
|
(6,888 |
) |
|
|
33,976
|
|
Fuel
Over/Under Recovery, Net |
|
|
(13,512 |
) |
|
|
75,097 |
|
Other
Current Assets
|
|
|
597
|
|
|
|
1,655
|
|
Other
Current Liabilities
|
|
|
(22,228 |
) |
|
|
(19,221 |
) |
Net
Cash Flows From (Used For) Operating Activities
|
|
|
(30,543 |
) |
|
|
78,707
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(151,973 |
) |
|
|
(91,617 |
) |
Change
in Other Cash Deposits, Net
|
|
|
(12,896 |
) |
|
|
6
|
|
Other
|
|
|
3,109
|
|
|
|
-
|
|
Net
Cash Flows Used For Investing Activities
|
|
|
(161,760 |
) |
|
|
(91,611 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
40,000
|
|
|
|
-
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
12,495
|
|
|
|
-
|
|
Change
in Advances from Affiliates, Net
|
|
|
139,916
|
|
|
|
63,948
|
|
Retirement
of Long-term Debt – Affiliated
|
|
|
-
|
|
|
|
(50,000 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(745 |
) |
|
|
(457 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(106 |
) |
|
|
(106 |
) |
Net
Cash Flows From Financing Activities
|
|
|
191,560
|
|
|
|
13,385
|
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(743 |
) |
|
|
481
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,651
|
|
|
|
1,520
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
908
|
|
|
$ |
2,001
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
21,339
|
|
|
$ |
17,461
|
|
Net
Cash Paid (Received) for Income Taxes
|
|
|
(2,353 |
) |
|
|
5,656
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
434
|
|
|
|
1,780
|
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
21,261
|
|
|
|
5,943
|
|
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
Second
Quarter of 2007 Compared to Second Quarter of 2006
Reconciliation
of Second Quarter of 2006 to Second Quarter of 2007
Net
Income
(in
millions)
Second
Quarter of 2006
|
|
|
|
|
$ |
28
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
(28 |
) |
|
|
|
|
Transmission
Revenues
|
|
|
(1 |
) |
|
|
|
|
Other
|
|
|
(3 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(32 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(4 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(2 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1 |
) |
|
|
|
|
Other
Income
|
|
|
2
|
|
|
|
|
|
Interest
Expense
|
|
|
(3 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(8 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
Second
Quarter of 2007
|
|
|
|
|
|
$ |
2
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income decreased $26 million to $2 million in 2007. The key drivers
of the decrease were a $32 million decrease in Gross Margin and an $8 million
increase in Operating Expenses and Other, partially offset by a $14 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 $28 million primarily due
to a $25
million provision related to a SWEPCo Texas fuel reconciliation
proceeding. See “SWEPCo Fuel Reconciliation – Texas” section of
Note 3.
|
·
|
Other
revenues decreased $3 million primarily due to a $4 million decrease
in
revenue from coal deliveries from SWEPCo's mining subsidiary, Dolet
Hills Lignite Company, LLC, to outside parties. The decrease
was offset by a corresponding decrease in Other Operation and Maintenance
expenses from mining operations as discussed
below.
|
Operating
Expenses and Other changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $4 million due to
a $7
million increase in generation operation and maintenance expenses
and a $4
million increase in distribution expenses due to higher overhead
line
maintenance, partially offset by a $5 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.
|
·
|
Interest
Expense increased $3 million primarily due to increased
borrowings.
|
Income
Taxes
Income
Tax Expense decreased $14 million primarily due to a decrease in pretax book
income.
Six
Months Ended June 30, 2007 Compared to Six Months Ended June 30,
2006
Reconciliation
of Six Months Ended June 30, 2006 to Six Months Ended June 30,
2007
Net
Income
(in
millions)
Six
Months Ended June 30, 2006
|
|
|
|
|
$ |
46
|
|
|
|
|
|
|
|
|
|
Changes
in Gross Margin:
|
|
|
|
|
|
|
|
Retail
and Off-system Sales Margins (a)
|
|
|
(29 |
) |
|
|
|
|
Transmission
Revenues
|
|
|
(1 |
) |
|
|
|
|
Other
|
|
|
(8 |
) |
|
|
|
|
Total
Change in Gross Margin
|
|
|
|
|
|
|
(38 |
) |
|
|
|
|
|
|
|
|
|
Changes
in Operating Expenses and Other:
|
|
|
|
|
|
|
|
|
Other
Operation and Maintenance
|
|
|
(10 |
) |
|
|
|
|
Depreciation
and Amortization
|
|
|
(3 |
) |
|
|
|
|
Taxes
Other Than Income Taxes
|
|
|
(1 |
) |
|
|
|
|
Other
Income
|
|
|
3
|
|
|
|
|
|
Interest
Expense
|
|
|
(6 |
) |
|
|
|
|
Total
Change in Operating Expenses and Other
|
|
|
|
|
|
|
(17 |
) |
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
$ |
11
|
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
Net
Income decreased $35 million to $11 million in 2007. The key drivers
of the decrease were a $38 million decrease in Gross Margin and a $17 million
increase in Operating Expenses and Other, offset by a $20 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 $25
million provision related to a SWEPCo Texas fuel reconciliation
proceeding. See “SWEPCo Fuel Reconciliation – Texas” section of
Note 3.
|
·
|
Other
revenues decreased $8 million primarily due to a $6 million decrease
in
revenue from coal deliveries from SWEPCo's mining subsidiary, Dolet
Hills Lignite Company, LLC, to outside parties and a $2 million
decrease
in gains on sales of emission allowances. 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 changed between years as follows:
·
|
Other
Operation and Maintenance expenses increased $10 million primarily
due to
an $8 million increase in generation operation and maintenance,
a $5
million increase in distribution expenses due to higher overhead
line
maintenance and a $3 million increase in transmission expenses
related to
higher SPP administration fees, partially offset by a $6 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.
|
·
|
Interest
Expense increased $6 million primarily due to increased
borrowings.
|
Income
Taxes
Income
Tax Expense decreased $20 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
|
|
|
|
|
|
|
First
Mortgage Bonds
|
A3
|
|
A-
|
|
A
|
Senior
Unsecured Debt
|
Baa1
|
|
BBB
|
|
A-
|
Cash
Flow
Cash
flows for the six months ended June 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
|
|
|
120,597
|
|
|
|
76,154
|
|
Investing
Activities
|
|
|
(253,267 |
) |
|
|
(123,275 |
) |
Financing
Activities
|
|
|
131,610
|
|
|
|
46,180
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(1,060 |
) |
|
|
(941 |
) |
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,558
|
|
|
$ |
2,108
|
|
Operating
Activities
Net
Cash
Flows From Operating Activities were $121 million in 2007. SWEPCo
produced Net Income of $11 million during the period and noncash expense
items
of $69 million for Depreciation and Amortization and $25 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 $36 million inflow from Accrued Taxes, Net was the
result of increased accruals related to property and income
taxes. The $27 million inflow from Accounts Receivable, Net was
primarily due to the assignment of certain ERCOT contracts to an affiliate
company. The $20 million inflow from Margin Deposits was due to
decreased trading-related deposits resulting from normal trading
activities.
Net
Cash
Flows From Operating Activities were $76 million in 2006. SWEPCo
produced Net Income of $46 million during the period and noncash expense
items
of $66 million for Depreciation and Amortization. The other changes
in assets and liabilities represent items that had a current period cash
flow
impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The current period activity in working capital
relates to a number of items. The $60 million inflow from Accounts
Payable was the result of higher energy purchases. The $53 million
outflow from Margin Deposits was due to increased trading-related deposits
resulting from the amended SIA. In addition, SWEPCo’s $37 million
inflow related to Fuel Over/Under Recovery, Net was primarily due to the
new
fuel surcharges effective December 2005 in its Arkansas service territory
and in
January 2006 in its Texas service territory. The $23 million outflow
from Fuel, Materials and Supplies was the result of increased fuel
purchases.
Investing
Activities
Cash
Flows Used For Investing Activities during 2007 and 2006 were $253 million
and
$123 million, respectively. The $250 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.
Financing
Activities
Cash
Flows From Financing Activities were $132 million during 2007. SWEPCo
issued $250 million of Senior Unsecured Notes and had a net decrease of $135
million in borrowings from the Utility Money Pool. SWEPCo received
$25 million of capital contributions from Parent Company.
Cash
Flows From Financing Activities were $46 million during 2006. SWEPCo
refinanced $82 million of Pollution Control Bonds and retired $87 million
of
long-term debt. SWEPCo had a net increase of $65 million in
borrowings from the Utility Money Pool and paid $20 million in common stock
dividends.
Financing
Activity
Long-term
debt issuances and retirements during the first six 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
|
|
$
|
3,109
|
|
4.47
|
|
2011
|
Notes
Payable – Nonaffiliated
|
|
|
4,000
|
|
6.36
|
|
2007
|
Notes
Payable – Nonaffiliated
|
|
|
1,500
|
|
Variable
|
|
2008
|
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 issuance
and
retirements discussed in “Cash Flow” and “Financing Activity” above and Energy
and Capacity Purchase Contracts. 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.
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.
New
Generation
In
December 2005, SWEPCo sought proposals for new peaking, intermediate and
base
load generation to be online between 2008 and 2011. In May 2006,
SWEPCo announced plans to construct new generation to satisfy the demands
of its
customers. Plans include the construction of up to 480 MW of
simple-cycle natural gas combustion turbine peaking generation in Tontitown,
Arkansas and a 480 MW combined-cycle natural gas fired intermediate plant
at its
existing Arsenal Hill Power Plant in Shreveport, Louisiana. SWEPCo
also plans to build the Turk plant, a new 600 MW base load coal plant, with
a
73% ownership share, in Hempstead County, Arkansas by 2011 to meet the long-term
generation needs of its customers. Preliminary cost estimates for
SWEPCo’s share of these new facilities are approximately $1.4 billion (this
total includes all three plants, but excludes the related transmission
investment and AFUDC). Expenditures related to construction of all of
these facilities are expected to total $349 million in 2007. These
new facilities are subject to regulatory approvals from SWEPCo’s three state
commissions. Mattison plant, the peaking generation facility in
Tontitown, Arkansas has been approved by all three state
commissions. Mattison plant, Units 3 and 4 began commercial operation
in July 2007, with the remaining two units scheduled for completion in December
2007. All four units of the Mattison plant are expected to be
completed in advance of the originally planned 2008 commercial operation
date. Construction is expected to begin in the second half of 2007 on
the base load facility and in 2008 on the intermediate facility, both upon
approval from SWEPCo’s three state commissions.
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 June 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 June 30, 2007
(in
thousands)
|
|
MTM
Risk Management Contracts
|
|
|
Cash
Flow Hedges
|
|
|
Total
|
|
Current
Assets
|
|
$ |
64,354
|
|
|
$ |
8
|
|
|
$ |
64,362
|
|
Noncurrent
Assets
|
|
|
10,929
|
|
|
|
50
|
|
|
|
10,979
|
|
Total
MTM Derivative Contract Assets
|
|
|
75,283
|
|
|
|
58
|
|
|
|
75,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
(51,054 |
) |
|
|
(12 |
) |
|
|
(51,066 |
) |
Noncurrent
Liabilities
|
|
|
(7,822 |
) |
|
|
-
|
|
|
|
(7,822 |
) |
Total
MTM Derivative Contract Liabilities
|
|
|
(58,876 |
) |
|
|
(12 |
) |
|
|
(58,888 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
MTM Derivative Contract Net Assets (Liabilities)
|
|
$ |
16,407
|
|
|
$ |
46
|
|
|
$ |
16,453
|
|
MTM
Risk Management Contract Net Assets
Six
Months Ended June 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
|
|
|
(2,885
|
)
|
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)
|
|
|
1,853
|
|
Changes
in Fair Value Allocated to Regulated Jurisdictions (c)
|
|
|
(2,727
|
)
|
Total
MTM Risk Management Contract Net Assets
|
|
|
16,407
|
|
Net
Cash Flow Hedge Contracts
|
|
|
46
|
|
Total
MTM Risk Management Contract Net Assets at June 30,
2007
|
|
$
|
16,453
|
|
(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 June 30, 2007
(in
thousands)
|
|
Remainder
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
After
2011
|
|
|
Total
|
|
Prices
Actively Quoted – Exchange Traded
Contracts
|
|
$ |
(10,100 |
) |
|
$ |
1,544
|
|
|
$ |
(247 |
) |
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
(8,803 |
) |
Prices
Provided by Other External Sources
-
OTC Broker Quotes
(a)
|
|
|
21,341
|
|
|
|
4,080
|
|
|
|
(711 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
24,710
|
|
Prices
Based on Models and Other Valuation
Methods (b)
|
|
|
(1,494 |
) |
|
|
521
|
|
|
|
1,471
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
500
|
|
Total
|
|
$ |
9,747
|
|
|
$ |
6,145
|
|
|
$ |
513
|
|
|
$ |
2
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
16,407
|
|
(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 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 forward contracts and collars as cash flow hedges to lock in prices
on
certain transactions denominated in foreign currencies where deemed
necessary. Management does not hedge all foreign currency
exposure.
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 June 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
Six
Months Ended June 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 |
) |
|
|
549
|
|
|
|
(470 |
) |
Reclassifications
from AOCI to Net Income for
Cash Flow Hedges Settled
|
|
|
391
|
|
|
|
-
|
|
|
|
391
|
|
Ending
Balance in AOCI June 30, 2007
|
|
$ |
(7,063 |
) |
|
$ |
574
|
|
|
$ |
(6,489 |
) |
The
portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $249 thousand loss.
Credit
Risk
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 June 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:
Six
Months Ended June 30, 2007
|
|
|
|
|
Twelve
Months Ended December 31, 2006
|
(in
thousands)
|
|
|
|
|
(in
thousands)
|
End
|
|
High
|
|
Average
|
|
Low
|
|
|
|
|
End
|
|
High
|
|
Average
|
|
Low
|
$118
|
|
$245
|
|
$97
|
|
$25
|
|
|
|
|
$447
|
|
$2,171
|
|
$794
|
|
$68
|
The
High
VaR for the twelve months ended December 31, 2006 occurred in the fourth
quarter
due to volatility in the ERCOT region.
VaR
Associated with Debt Outstanding
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 $44 million and $25 million
at
June 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 Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
Generation, Transmission and Distribution
|
|
$ |
329,250
|
|
|
$ |
349,650
|
|
|
$ |
656,534
|
|
|
$ |
643,643
|
|
Sales
to AEP Affiliates
|
|
|
16,237
|
|
|
|
9,414
|
|
|
|
32,652
|
|
|
|
20,179
|
|
Other
|
|
|
535
|
|
|
|
420
|
|
|
|
935
|
|
|
|
794
|
|
TOTAL
|
|
|
346,022
|
|
|
|
359,484
|
|
|
|
690,121
|
|
|
|
664,616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and Other Consumables Used for Electric Generation
|
|
|
125,994
|
|
|
|
118,271
|
|
|
|
237,981
|
|
|
|
208,932
|
|
Purchased
Electricity for Resale
|
|
|
56,870
|
|
|
|
44,884
|
|
|
|
109,368
|
|
|
|
74,102
|
|
Purchased
Electricity from AEP Affiliates
|
|
|
16,085
|
|
|
|
16,826
|
|
|
|
39,002
|
|
|
|
40,163
|
|
Other
Operation
|
|
|
50,204
|
|
|
|
53,216
|
|
|
|
103,987
|
|
|
|
102,916
|
|
Maintenance
|
|
|
29,721
|
|
|
|
22,231
|
|
|
|
56,060
|
|
|
|
46,888
|
|
Depreciation
and Amortization
|
|
|
34,668
|
|
|
|
32,959
|
|
|
|
68,790
|
|
|
|
65,576
|
|
Taxes
Other Than Income Taxes
|
|
|
17,540
|
|
|
|
16,165
|
|
|
|
33,531
|
|
|
|
32,147
|
|
TOTAL
|
|
|
331,082
|
|
|
|
304,552
|
|
|
|
648,719
|
|
|
|
570,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
14,940
|
|
|
|
54,932
|
|
|
|
41,402
|
|
|
|
93,892
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income
|
|
|
3,338
|
|
|
|
840
|
|
|
|
5,434
|
|
|
|
1,568
|
|
Interest
Expense
|
|
|
(17,235 |
) |
|
|
(14,073 |
) |
|
|
(32,725 |
) |
|
|
(26,844 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES AND
MINORITY
INTEREST EXPENSE
|
|
|
1,043
|
|
|
|
41,699
|
|
|
|
14,111
|
|
|
|
68,616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense (Credit)
|
|
|
(1,553 |
) |
|
|
12,491
|
|
|
|
1,068
|
|
|
|
21,314
|
|
Minority
Interest Expense
|
|
|
972
|
|
|
|
896
|
|
|
|
1,814
|
|
|
|
1,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
1,624
|
|
|
|
28,312
|
|
|
|
11,229
|
|
|
|
46,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements
|
|
|
57
|
|
|
|
58
|
|
|
|
114
|
|
|
|
115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
APPLICABLE TO COMMON STOCK
|
|
$ |
1,567
|
|
|
$ |
28,254
|
|
|
$ |
11,115
|
|
|
$ |
46,069
|
|
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 Six Months Ended June 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
|
|
|
|
|
|
|
|
|
|
|
(20,000 |
) |
|
|
|
|
|
|
(20,000 |
) |
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(115 |
) |
|
|
|
|
|
|
(115 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
762,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income, Net of
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
964
|
|
|
|
964
|
|
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
46,184
|
|
|
|
|
|
|
|
46,184
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2006
|
|
$ |
135,660
|
|
|
$ |
245,003
|
|
|
$ |
433,913
|
|
|
$ |
(5,165 |
) |
|
$ |
809,411
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Company
|
|
|
|
|
|
|
25,000
|
|
|
|
|
|
|
|
|
|
|
|
25,000
|
|
Preferred
Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
(114 |
) |
|
|
|
|
|
|
(114 |
) |
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
844,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Hedges, Net of Tax of $172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(79 |
) |
|
|
(79 |
) |
NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
11,229
|
|
|
|
|
|
|
|
11,229
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JUNE
30, 2007
|
|
$ |
135,660
|
|
|
$ |
270,003
|
|
|
$ |
468,811
|
|
|
$ |
(18,878 |
) |
|
$ |
855,596
|
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED
CONSOLIDATED BALANCE SHEETS
ASSETS
June
30, 2007 and December 31, 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$ |
1,558
|
|
|
$ |
2,618
|
|
Accounts
Receivable:
|
|
|
|
|
|
|
|
|
Customers
|
|
|
66,047
|
|
|
|
88,245
|
|
Affiliated
Companies
|
|
|
54,004
|
|
|
|
59,679
|
|
Miscellaneous
|
|
|
9,473
|
|
|
|
8,595
|
|
Allowance
for Uncollectible Accounts
|
|
|
(32 |
) |
|
|
(130 |
) |
Total
Accounts Receivable
|
|
|
129,492
|
|
|
|
156,389
|
|
Fuel
|
|
|
77,717
|
|
|
|
69,426
|
|
Materials
and Supplies
|
|
|
48,847
|
|
|
|
46,001
|
|
Risk
Management Assets
|
|
|
64,362
|
|
|
|
120,036
|
|
Margin
Deposits
|
|
|
21,940
|
|
|
|
41,579
|
|
Prepayments
and Other
|
|
|
22,284
|
|
|
|
18,256
|
|
TOTAL
|
|
|
366,200
|
|
|
|
454,305
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
Production
|
|
|
1,596,040
|
|
|
|
1,576,200
|
|
Transmission
|
|
|
710,732
|
|
|
|
668,008
|
|
Distribution
|
|
|
1,279,426
|
|
|
|
1,228,948
|
|
Other
|
|
|
615,126
|
|
|
|
595,429
|
|
Construction
Work in Progress
|
|
|
392,402
|
|
|
|
259,662
|
|
Total
|
|
|
4,593,726
|
|
|
|
4,328,247
|
|
Accumulated
Depreciation and Amortization
|
|
|
1,884,582
|
|
|
|
1,834,145
|
|
TOTAL
- NET
|
|
|
2,709,144
|
|
|
|
2,494,102
|
|
|
|
|
|
|
|
|
|
|
OTHER
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Regulatory
Assets
|
|
|
138,155
|
|
|
|
156,420
|
|
Long-term
Risk Management Assets
|
|
|
10,979
|
|
|
|
20,531
|
|
Employee
Benefits and Pension Assets
|
|
|
24,576
|
|
|
|
26,029
|
|
Deferred
Charges and Other
|
|
|
62,266
|
|
|
|
39,581
|
|
TOTAL
|
|
|
235,976
|
|
|
|
242,561
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
3,311,320
|
|
|
$ |
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
June
30, 2007 and December 31, 2006
(Unaudited)
|
|
2007
|
|
|
2006
|
|
CURRENT
LIABILITIES
|
|
(in
thousands)
|
|
Advances
from Affiliates
|
|
$ |
53,955
|
|
|
$ |
188,965
|
|
Accounts
Payable:
|
|
|
|
|
|
|
|
|
General
|
|
|
157,564
|
|
|
|
140,424
|
|
Affiliated
Companies
|
|
|
70,842
|
|
|
|
68,680
|
|
Short-term
Debt – Nonaffiliated
|
|
|
22,373
|
|
|
|
17,143
|
|
Long-term
Debt Due Within One Year – Nonaffiliated
|
|
|
97,406
|
|
|
|
102,312
|
|
Risk
Management Liabilities
|
|
|
51,066
|
|
|
|
109,578
|
|
Customer
Deposits
|
|
|
38,233
|
|
|
|
48,277
|
|
Accrued
Taxes
|
|
|
67,335
|
|
|
|
31,591
|
|
Regulatory
Liability for Over-Recovered Fuel Costs
|
|
|
51,805
|
|
|
|
26,012
|
|
Other
|
|
|
75,835
|
|
|
|
85,086
|
|
TOTAL
|
|
|
686,414
|
|
|
|
818,068
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES
|
|
|
|
|
|
|
|
|
Long-term
Debt – Nonaffiliated
|
|
|
819,450
|
|
|
|
576,694
|
|
Long-term
Debt – Affiliated
|
|
|
50,000
|
|
|
|
50,000
|
|
Long-term
Risk Management Liabilities
|
|
|
7,822
|
|
|
|
14,083
|
|
Deferred
Income Taxes
|
|
|
348,760
|
|
|
|
374,548
|
|
Regulatory
Liabilities and Deferred Investment Tax Credits
|
|
|
339,243
|
|
|
|
346,774
|
|
Deferred
Credits and Other
|
|
|
197,615
|
|
|
|
183,087
|
|
TOTAL
|
|
|
1,762,890
|
|
|
|
1,545,186
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
2,449,304
|
|
|
|
2,363,254
|
|
|
|
|
|
|
|
|
|
|
Minority
Interest
|
|
|
1,723
|
|
|
|
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
|
|
|
270,003
|
|
|
|
245,003
|
|
Retained
Earnings
|
|
|
468,811
|
|
|
|
459,338
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
(18,878 |
) |
|
|
(18,799 |
) |
TOTAL
|
|
|
855,596
|
|
|
|
821,202
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
3,311,320
|
|
|
$ |
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 Six Months Ended June 30, 2007 and 2006
(in
thousands)
(Unaudited)
|
|
2007
|
|
|
2006
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
|
$ |
11,229
|
|
|
$ |
46,184
|
|
Adjustments
for Noncash Items:
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
68,790
|
|
|
|
65,576
|
|
Deferred
Income Taxes
|
|
|
(21,658 |
) |
|
|
(15,511 |
) |
Provision
for Fuel Disallowance
|
|
|
24,500
|
|
|
|
-
|
|
Mark-to-Market
of Risk Management Contracts
|
|
|
3,759
|
|
|
|
(14,213 |
) |
Deferred
Property Taxes
|
|
|
(19,210 |
) |
|
|
(18,593 |
) |
Change
in Other Noncurrent Assets
|
|
|
(107 |
) |
|
|
16,538
|
|
Change
in Other Noncurrent Liabilities
|
|
|
(7,932 |
) |
|
|
(16,419 |
) |
Changes
in Certain Components of Working Capital:
|
|
|
|
|
|
|
|
|
Accounts
Receivable, Net
|
|
|
26,897
|
|
|
|
(15,662 |
) |
Fuel,
Materials and Supplies
|
|
|
(11,126 |
) |
|
|
(23,003 |
) |
Margin
Deposits
|
|
|
19,639
|
|
|
|
(52,838 |
) |
Accounts
Payable
|
|
|
8,388
|
|
|
|
60,158
|
|
Customer
Deposits
|
|
|
(10,044 |
) |
|
|
3,763
|
|
Accrued
Taxes, Net
|
|
|
36,445
|
|
|
|
19,153
|
|
Fuel Over/Under Recovery, Net |
|
|
1,293 |
|
|
|
37,377 |
|
Other
Current Assets
|
|
|
1,266
|
|
|
|
3,560
|
|
Other
Current Liabilities
|
|
|
(11,532 |
) |
|
|
(19,916 |
) |
Net
Cash Flows From Operating Activities
|
|
|
120,597
|
|
|
|
76,154
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
Expenditures
|
|
|
(250,409 |
) |
|
|
(122,616 |
) |
Other
|
|
|
(2,858 |
) |
|
|
(659 |
) |
Net
Cash Flows Used For Investing Activities
|
|
|
(253,267 |
) |
|
|
(123,275 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
Contribution from Parent
|
|
|
25,000
|
|
|
|
-
|
|
Issuance
of Long-term Debt – Nonaffiliated
|
|
|
247,496
|
|
|
|
80,593
|
|
Change
in Short-term Debt, Net – Nonaffiliated
|
|
|
5,230
|
|
|
|
8,855
|
|
Change
in Advances from Affiliates, Net
|
|
|
(135,010 |
) |
|
|
64,873
|
|
Retirement
of Long-term Debt – Nonaffiliated
|
|
|
(8,609 |
) |
|
|
(86,594 |
) |
Principal
Payments for Capital Lease Obligations
|
|
|
(2,383 |
) |
|
|
(1,432 |
) |
Dividends
Paid on Common Stock
|
|
|
-
|
|
|
|
(20,000 |
) |
Dividends
Paid on Cumulative Preferred Stock
|
|
|
(114 |
) |
|
|
(115 |
) |
Net
Cash Flows From Financing Activities
|
|
|
131,610
|
|
|
|
46,180
|
|
|
|
|
|
|
|
|
|
|
Net
Decrease in Cash and Cash Equivalents
|
|
|
(1,060 |
) |
|
|
(941 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
2,618
|
|
|
|
3,049
|
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1,558
|
|
|
$ |
2,108
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY
INFORMATION
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest, Net of Capitalized Amounts
|
|
$ |
25,876
|
|
|
$ |
24,840
|
|
Net
Cash Paid for Income Taxes
|
|
|
10,617
|
|
|
|
42,788
|
|
Noncash
Acquisitions Under Capital Leases
|
|
|
6,511
|
|
|
|
5,537
|
|
Construction
Expenditures Included in Accounts Payable at June 30,
|
|
|
38,630
|
|
|
|
8,326
|
|
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 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 six months ended June 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.
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 Registrant Subsidiaries own 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 June 30, 2007 and
December 31, 2006 is shown in the following table:
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
Components
|
|
(in
thousands)
|
|
Cash
Flow Hedges:
|
|
|
|
|
|
|
APCo
|
|
$ |
2,063
|
|
|
$ |
(2,547 |
) |
CSPCo
|
|
|
4,067
|
|
|
|
3,398
|
|
I&M
|
|
|
(7,756 |
) |
|
|
(8,962 |
) |
OPCo
|
|
|
8,233
|
|
|
|
7,262
|
|
PSO
|
|
|
(979 |
) |
|
|
(1,070 |
) |
SWEPCo
|
|
|
(6,489 |
) |
|
|
(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 |
) |
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 $15.9 million in the second quarter of 2007. 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 June 30, 2007
|
|
|
Net
Settlement
With
AEPEP
|
|
Third
Party Amounts
Reclassified
to Affiliate
|
|
Net
Amount included in Sales to AEP Affiliates
|
|
Company
|
(in
thousands)
|
|
PSO
|
|
$ |
33,293
|
|
|
$ |
(30,307 |
) |
|
$ |
2,986
|
|
SWEPCo
|
|
|
46,678
|
|
|
|
(43,160 |
) |
|
|
3,518
|
|
|
For
the Six Months Ended June 30,
2007
|
|
|
Net
Settlement
With
AEPEP
|
|
Third
Party Amounts
Reclassified
to Affiliate
|
|
Net
Amount included in Sales to AEP
Affiliates
|
|
Company
|
(in
thousands)
|
|
PSO
|
|
$ |
76,443
|
|
|
$ |
(66,144 |
) |
|
$ |
10,299
|
|
SWEPCo
|
|
|
93,554
|
|
|
|
(81,419 |
) |
|
|
12,135
|
|
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 June 30, 2007
|
|
|
|
PSO
|
|
|
SWEPCo
|
|
Current
|
|
(in
thousands)
|
|
Risk
Management Assets
|
|
$ |
12,513
|
|
|
$ |
14,743
|
|
Risk
Management Liabilities
|
|
|
(1,894 |
) |
|
|
(2,231 |
) |
|
|
|
|
|
|
|
|
|
Noncurrent
|
|
|
|
|
|
|
|
|
Long-term
Risk Management Assets
|
|
$ |
943
|
|
|
$ |
1,111
|
|
Long-term
Risk Management Liabilities
|
|
|
(2,946 |
) |
|
|
(3,471 |
) |
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
|
|
|
Six
Months Ended
|
|
|
June
30, 2006
|
|
|
June
30, 2006
|
|
Company
|
(in
thousands)
|
|
APCo
|
|
$ |
302
|
|
|
|
|
$ |
598
|
|
I&M
|
|
|
6,118
|
|
|
|
|
|
11,707
|
|
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 and an entity include its own credit standing in the
measurement of its liabilities and modifies the transaction price
presumption.
SFAS
157
is effective for interim and annual periods in fiscal years beginning after
November 15, 2007. Management expects that the adoption of this
standard will impact MTM valuations of certain contracts, but is unable to
quantify the effect. Although the statement is applied prospectively
upon adoption, the effect of certain transactions is applied retrospectively
as
of the beginning of the fiscal year of application, with a cumulative effect
adjustment to the appropriate balance sheet items. The Registrant
Subsidiaries will adopt SFAS 157 effective January 1, 2008.
SFAS
159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS
159)
In
February 2007, the FASB issued SFAS 159, permitting entities to choose to
measure many financial instruments and certain other items at fair
value. The standard also establishes presentation and disclosure
requirements designed to facilitate comparison between entities that choose
different measurement attributes for similar types of assets and
liabilities.
SFAS
159
is effective for annual periods in fiscal years beginning after November
15,
2007. If the fair value option is elected, the effect of the first
remeasurement to fair value is reported as a cumulative effect adjustment
to the
opening balance of retained earnings. In the event 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. 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 effect 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”
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 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
In
January 2007, CSPCo and OPCo filed with the PUCO under the 4% provision of
their
RSPs to increase their annual generation rates for 2007 by $24 million and
$8
million, respectively, to recover governmentally-mandated
costs. Pursuant to the RSPs, CSPCo and OPCo implemented these
proposed increases effective with the first billing cycle in May
2007. These increases are subject to refund until the PUCO issues a
final order in the matter. The PUCO staff and intervenors have
proposed disallowances. The revenues collected, subject to refund,
are immaterial through June 30, 2007. Management is unable to
determine the impact, if any, of potential refunds or rider reductions on
future
results of operations and cash flows. The hearing is completed
and initial post-hearing and reply briefs have been filed. A final
order is expected in late third quarter or early fourth quarter of
2007.
In
March
2007, CSPCo filed an application under the 4% provision of the RSP to adjust
the
Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in
connection with CSPCo's acquisition of Monongahela Power Company's certified
territory in Ohio and a new purchase power contract to serve the
load. 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 Supreme Court
indicated concern with the absence of a competitive bid process as an
alternative to the generation rates set by the RSP. In response, the
settling parties agreed to have CSPCo and OPCo take bids for Renewable Energy
Certificates (RECs). CSPCo and OPCo will give customers the option to
pay a generation rate premium that would encourage the development of renewable
energy sources by reimbursing CSPCo and OPCo for the cost of the RECs and
the
administrative costs of the program. 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. The settlement, as
approved, fully compensates CSPCo and OPCo regarding the cost of the
program.
CSPCo
and
OPCo are involved in discussions with various stakeholders in Ohio regarding
potential legislation to address the period following the expiration of the
RSPs
on December 31, 2008. At this time, management is unable to predict
whether CSPCo and OPCo will transition to market pricing, as permitted by
the
current Ohio restructuring legislation, extend their RSP rates, with or without
modification, or become subject to a legislative reinstatement of some form
of
cost-based regulation for their generation supply business on January 1,
2009
when the RSP period ends.
Customer
Choice Deferrals – Affecting CSPCo and OPCo
As
provided in the restructuring settlement agreement approved by the PUCO in
2000,
CSPCo and OPCo established regulatory assets for customer choice implementation
costs and related carrying costs in excess of $20 million each for recovery
in
the next general base rate filing which changes distribution rates after
December 31, 2007 for OPCo and December 31, 2008 for
CSPCo. Pursuant to the RSPs, recovery of these amounts for OPCo
was further deferred until the next base rate filing to change distribution
rates after the end of the RSP period of December 31, 2008. Through
June 30, 2007, CSPCo and OPCo incurred $51 million and $52 million,
respectively, of such costs and established regulatory assets of $25 million
and
$26 million, respectively, for such costs. CSPCo and OPCo each have
not recognized $6 million of equity carrying costs, which are recognizable
when
collected. In 2007, CSPCo and OPCo incurred $2 million each of such
costs and established regulatory assets of $1 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 will have an adverse
effect on results of operations and cash flows.
Ohio
IGCC Plant – Affecting CSPCo and OPCo
In
March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of
cost recovery associated with the IGCC plant: Phase 1, recovery of
$24 million in pre-construction costs during 2006; Phase 2, concurrent recovery
of construction-financing costs; and Phase 3, recovery or refund in distribution
rates of any difference between the market-based standard service offer price
for generation and the cost of operating and maintaining the plant, including
a
return on and return of the ultimate cost to construct the plant, originally
projected to be $1.2 billion, along with fuel, consumables and replacement
power
costs. The proposed recoveries in Phases 1 and 2 would be applied
against the 4% limit on additional generation rate increases CSPCo and OPCo
could request under their RSPs.
In
April
2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
1
of the cost recovery proposal. In June 2006, the PUCO issued another
order approving a tariff to recover Phase 1 pre-construction costs over a
period
of no more than twelve months effective July 1, 2006. Through June
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. CSPCo and OPCo expect to incur additional pre-construction
costs equal to or greater than the $12 million each recovered. As of
June 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each
for
the over-recovered portion. The PUCO indicated that if CSPCo and OPCo
have not commenced a continuous course of construction of the IGCC plant
within
five years of the June 2006 PUCO order, all amounts collected for
pre-construction costs, associated with items that may be utilized in IGCC
projects to be built by AEP 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 has scheduled 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 are $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. In July 2007,
CSPCo and OPCo filed a status report with the PUCO referencing APCo’s IGCC West
Virginia filing. See the “West Virginia IGCC Plant” section within
West Virginia Rate Matters of this note.
Distribution
Reliability Plan – Affecting CSPCo and OPCo
In
January 2006, CSPCo and OPCo initiated a proceeding at the PUCO seeking a
new
distribution rate rider to fund enhanced distribution reliability
programs. In the fourth quarter of 2006, as directed by the PUCO,
CSPCo and OPCo filed a proposed enhanced reliability plan. The plan
contemplated CSPCo and OPCo recovering approximately $28 million and $43
million, respectively, in additional distribution revenue during an eighteen
month period beginning July 2007. In January 2007, the Ohio
Consumers’ Counsel filed testimony, which argued that CSPCo and OPCo should be
required to improve distribution service reliability with funds from their
existing rates.
In
April
2007, CSPCo and OPCo filed a joint motion with the PUCO staff, the Ohio
Consumers’ Counsel, the Appalachian People’s Action Coalition, the Ohio Partners
for Affordable Energy and the Ohio Manufacturers Association to withdraw
the
proposed enhanced reliability plan. 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, under a PUCO-encouraged settlement
agreement. The settlement agreement between CSPCo and OPCo, Ormet,
its employees’ union and certain other interested parties was approved by the
PUCO in November 2006. The settlement agreement provides for
the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between
$43
per MWH to be paid by Ormet for power and a PUCO-approved market price, if
higher. The recovery will be accomplished by the amortization of a
$57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise
tax
phase-out regulatory liability recorded in 2005 and, if that is insufficient,
an
increase in RSP generation rates under the additional 4% provision of the
RSPs. The $43 per MWH price to be paid by Ormet for generation
services is above the industrial RSP generation tariff but below current
market
prices. In December 2006, CSPCo and OPCo submitted a market price of
$47.69 per MWH for 2007, which was approved by the PUCO in June
2007. CSPCo and OPCo have each amortized $3 million of their Ohio
Franchise Tax phase-out tax regulatory liability to income through June 30,
2007. If the PUCO approves a lower-than-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, which could have an adverse effect on future results of
operations and cash flows.
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
as a result of reflecting the ALJ’s decision. In July 2007, the PUCT
orally affirmed the ALJ report. A final order is expected in the
third quarter of 2007. Management is unable to predict the ultimate
outcome of this proceeding or its additional effect on future results of
operations and cash flows.
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 practice
deferred fuel accounting. Also, under the amended restructuring law,
APCo has the right to defer incremental environmental compliance costs and
incremental E&R costs for future recovery, to the extent such costs are not
being recovered, and amortizes a portion of such deferrals commensurate with
their recovery.
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.
With
the new re-regulation legislation of cost-based regulation, APCo’s
generation business again meets 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 primarily
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
law. 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 the fuel factor where
they can be trued-up to actual. APCo also proposed to share the
off-system sales margins with customers with 40% going to reduce rates and
60%
being retained by APCo. This proposed off-system sales fuel rate
credit, which 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. The major components of the $225 million
base rate request included $73 million for the impact of removing off-system
sales margins from the rate year ending September 30, 2007, $60 million mainly
due to projected net environmental plant additions through September 30,
2007
and $48 million for return on equity.
In
May
2006, the Virginia SCC issued an order, consistent with Virginia law, placing
the net requested base rate increase of $198 million into effect on October
2,
2006, subject to refund. The $198 million base rate increase that was
collected, subject to refund, includes recovery of incremental E&R costs
projected to be incurred during the rate year beginning October
2006. These incremental E&R costs can be deferred and recovered
through the E&R surcharge mechanism if not recovered through base
rates. In October 2006, the Virginia SCC staff filed its direct
testimony recommending a base rate increase of $13 million with a return
on
equity of 9.9% and no off-system sales margin sharing. Other
intervenors recommended base rate increases ranging from $42 million to $112
million. APCo filed rebuttal testimony in November
2006. Hearings were held in December 2006.
In
March
2007, the Hearing Examiner issued a report recommending a $76 million increase
in APCo’s base rates and a $45 million credit to the fuel factor for off-system
sales margins resulting in a net $31 million recommended rate
increase. 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. The final order approved a return on equity of 10.0%
and limited forward-looking ratemaking adjustments to June 30, 2006 as opposed
to September 30, 2007 as proposed. In addition, the final order
excluded a portion of APCo's requested E&R costs in base
rates. However, APCo was able to defer unrecovered incremental
E&R costs incurred after October 1, 2006 and will recover those costs
through the E&R surcharge mechanism. The order also provided for
a retroactive annual reduction in depreciation to January 1, 2006 of
approximately $11 million per year and a deferral and recovery of ARO costs
over
10 years. The final order further provides that off-system sales
margins of $101 million be credited to customers through a separate base
rate
margin rider which is not trued-up to actual margins. The final order
did not implement the minimum 25% sharing percentage for off-system sales
margins embodied in the new re-regulation legislation, which is effective
with
the first fuel clause filing after July 1, 2007. This sharing
requirement in the new re-regulation legislation also includes a
true-up to actual off-system sales margins.
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. In addition to the favorable effect of the base rate
increase in the second half of 2007, APCo expects to defer for future recovery
unrecovered incremental E&R costs incurred of $20 million to $25 million and
reduce depreciation and amortization expense by a net $5
million. APCo will complete the refund by August
2007. APCo’s Other Current Liabilities includes accrued refunds of
$127 million and $22 million as of June 30, 2007 and December 31, 2006,
respectively. Management expects pretax earnings for 2007 to be
favorably affected by the ordered May 2007 rate increase.
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. APCo will
file for recovery in 2008 of E&R cost deferrals incurred and recorded after
September 30, 2006.
Virginia
Fuel Clause Filing – Affecting APCo
In
July
2007, APCo filed an application with the Virginia SCC to seek an increase,
effective September 1, 2007, to the current fuel factor of $33 million in
annualized revenue requirements 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 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.
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 a 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. See “West Virginia IGCC Plant” section within West
Virginia Rate Matters below.
West
Virginia Rate Matters
APCo
and WPCo ENEC Filing – Affecting APCo
In
April
2007, the WVPSC issued an order establishing an investigation and hearing
concerning APCo’s and WPCo’s 2007 Expanded Net Energy Cost (ENEC) compliance
filing. The ENEC is an expanded form of fuel clause mechanism, which
includes all energy-related costs including fuel, purchased power expenses,
off-system sales credits and other energy/transmission
items. In the March 2007 ENEC joint filing, APCo and WPCo filed
for an increase of approximately $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 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 June 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 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 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. As proposed, the book depreciation reduction
would increase earnings, but would not impact cash flows until rates are
revised. Base and fuel rates were frozen in Indiana through June 30,
2007. The IURC held a public hearing in April 2007. In
June 2007, the IURC approved the settlement agreement, but modified the
effective date of the new depreciation rates upon the filing by I&M of a
general rate petition. See “Indiana Rate Filing” section
below. On June 19, 2007, I&M and the OUCC notified the IURC the
parties would accept the modification to the settlement agreement and I&M
filed its rate petition.
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 depreciation
rates are subject to further review in the general rate
case. I&M’s earnings will continue to benefit until the base
rates are revised to include lower depreciation rates, at which time cash
flows
will be adversely affected. Management expects new base rates will
become effective in late 2008 or 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 AEP Power Pool capacity
settlements, PJM RTO costs, reliability enhancement costs, DSM/energy efficiency
program costs, off-system sales margins, and net environmental compliance
costs. The petition requests the IURC to approve the test year period
and the inclusion of the above trackers in the rate
filing. Management expects to file the case in late 2007 or early
2008 with a decision expected in late 2008 or early 2009.
Indiana
Rate Cap – Affecting I&M
Effective
July 1, 2007, I&M’s rate cap ended for both base and fuel
rates. I&M’s fuel factor 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 impacted by fuel costs.
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 January 2006, the OCC staff and
intervenors issued supplemental testimony alleging that AEP deviated from
the
FERC-approved method of allocating off-system sales margins between AEP East
companies and AEP West companies and among AEP West companies. The
OCC staff proposed that the OCC offset the $42 million of under-recovered
fuel
with the proposed reallocation of off-system sales margins of $27 million
to $37
million and with $9 million of purchased power reallocation attributed to
wholesale customers, which they claimed had not been refunded. In
February 2006, the OCC staff filed a report concluding that the $9 million
of
reallocated purchased power costs assigned to wholesale customers had been
refunded, thus removing that issue from its recommendation.
In
2004,
an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO
deviated from the FERC-approved allocation methodology and held that any
such
complaints should be addressed at the FERC. The OCC has not ruled on
appeals by intervenors of the ALJ’s finding. The United States
District Court for the Western District of Texas issued orders in September
2005
regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel
proceeding, preempting the PUCT from reallocating off-system sales margins
between the AEP East companies and AEP West companies. The federal
court agreed that the FERC has sole jurisdiction over that
allocation. The PUCT appealed the ruling. The United States Court of
Appeals for the Fifth Circuit, issued a decision in December 2006 regarding
the
TNC fuel proceeding that affirmed the United States District Court
ruling. In April 2007, the PUCT petitioned the United States Supreme
Court for a review of the Court of Appeal’s order.
PSO
does
not agree with the intervenors’ and the OCC staff’s recommendations and
proposals other than the staff’s original recommendation that PSO be allowed to
recover the $42 million over three years and will defend its right to recover
its under-recovered fuel balance. Management believes that if the
position taken by the federal courts in the Texas proceeding is applied to
PSO’s
case, then the OCC should be preempted from disallowing fuel recoveries for
alleged improper allocations of off-system sales margins between AEP East
companies and AEP West companies. The OCC or another party could file
a complaint at the FERC alleging the allocation of off-system sales margins
to
PSO is improper, which could result in an adverse effect on future results
of
operations and cash flows for AEP and the AEP East
companies. However, to date, there has been no claim asserted at the
FERC that AEP deviated from the FERC approved allocation methodologies, but
even
if one were asserted, management believes that the OCC or another party would
not prevail.
In
June
2005, the OCC issued an order directing its staff to conduct a prudence review
of PSO’s fuel and purchased power practices for the year 2003. The
OCC staff filed testimony finding no disallowances in the test year
data. The Attorney General of Oklahoma filed testimony stating that
they could not determine if PSO’s gas procurement activities were prudent, but
did not include a recommended disallowance. However, an intervenor
filed testimony in June 2006 proposing the disallowance of $22 million in
fuel
costs based on a historical review of potential hedging opportunities that
he
alleges existed during the year. A hearing was held in August 2006
and management expects a recommendation from the ALJ in the second half of
2007.
In
February 2006, a law was enacted requiring the OCC to conduct prudence reviews
on all generation and fuel procurement processes, practices and costs on
either
a two or three-year cycle depending on the number of customers
served. PSO is subject to the required biennial
reviews. PSO filed its testimony in June 2007 covering the year
2005.
In
May
2007, PSO filed an application 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 current $48 million
over-recovered fuel balance. In oral discussions, the OCC staff did
not oppose the netting of the balances. The $6 million net
over-recovered fuel/purchased power cost deferral balance will be refunded
over
the twelve month period beginning June 2007. To date, no party has
objected to the offset.
Management
cannot predict the outcome of the pending fuel and purchased power costs
and
prudence reviews, planned future reviews or the current fuel adjustment clause
filing, but believes that PSO’s fuel and purchased power procurement practices
and costs are prudent and properly incurred. If the OCC disagrees and
disallows fuel or purchased power costs including the pre-2002 reallocation
of
purchased power costs incurred by PSO, it would have an adverse effect on
future
results of operations and cash flows.
Oklahoma
Rate Filing – Affecting PSO
In
November 2006, PSO filed a request to increase base rates by $50 million
for
Oklahoma jurisdictional customers with a proposed effective date in the second
quarter of 2007. PSO sought a return on equity of
11.75%. PSO also proposed a formula rate plan that, if approved as
filed, will permit PSO to defer any unrecovered costs as a result of a revenue
deficiency that exceeds 50 basis points of the allowed return on equity for
recovery within twelve months beginning six months after the test
year. The 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 time period to be recovered in the future through
depreciation expense.
In
March
2007, the OCC staff and various intervenors filed testimony. The
recommendations were base rate reductions that ranged from $18 million to
$52
million. The recommended returns on equity ranged from 9.25% to
10.09%. These recommendations included reductions in depreciation
expense of approximately $25 million, which has no earnings
impact. The OCC staff filed testimony supporting a formula rate plan,
generally similar to the one proposed by PSO. In April 2007, PSO
filed rebuttal testimony regarding various issues raised by the OCC staff
and
the intervenors. In connection with the filing of rebuttal testimony,
PSO reduced its base rate request by $2 million. 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 the coal-fueled
generating unit. The OCC’s discussions during deliberations have
centered around a return on equity of 9.75%. PSO implemented interim
rates, subject to refund, for residential customers beginning July
2007. The interim rate implements a key provision of the rate case on
which there seems to be agreement at the OCC, and is estimated to increase
revenues by approximately $4 million in 2007 and $9 million on an annual
basis. Other components of the rate case will be implemented once the
OCC issues a final order, which is expected in early August 2007.
Management
is unable to predict the final outcome of these proceedings. However, if
rates
are not increased in an amount sufficient to recover expected unavoidable
cost
increases, future results of operations, cash flows and possibly financial
condition could be adversely affected.
Lawton
and Peaking Generation Settlement Agreement – Affecting
PSO
On
November 26, 2003, pursuant to an application by Lawton Cogeneration, L.L.C.
(Lawton) seeking approval of a Power Supply Agreement (the Agreement) with
PSO
and associated avoided cost payments, the OCC issued an order approving the
Agreement and setting the avoided costs.
In
December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme
Court (the Court). In the appeal, PSO maintained that the OCC
exceeded its authority under state and federal laws to require PSO to enter
into
the Agreement. The Court issued a decision on June 21, 2005,
affirming portions of the OCC’s order and remanding certain
provisions. The Court affirmed the OCC’s finding that Lawton
established a legally-enforceable obligation and ruled that it was within
the
OCC’s discretion to award a 20-year contract and to base the capacity payment
on
a peaking unit. The Court directed the OCC to revisit its
determination of PSO’s avoided energy cost. Hearings were held on the remanded
issues in April and May 2006.
In
April
2007, all parties in the case filed a settlement agreement with the OCC
resolving all issues. The OCC approved the settlement agreement in April
2007. The 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. 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. Once the cost recovery for the new
peaking units begins in mid-2008, PSO expects annual revenues of an estimated
$36 million related to cost recovery of the peaking units and the purchase
fee.
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
jurisdiction customers, based on a proposed 10% return on equity. The
recommended reduction range is subject to SWEPCo validating certain ongoing
operations and maintenance expense levels. SWEPCo filed rebuttal
testimony in October 2006 strongly refuting the consultants’
recommendations. In December 2006, the LPSC staff’s consultants filed
reply testimony asserting that SWEPCo’s Louisiana base rates are excessive by
$17 million which includes a proposed return on equity of
9.8%. SWEPCo filed rebuttal testimony in January
2007. 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.
FERC
Rate Matters
Transmission
Rate Proceedings at the FERC – Affecting APCo, CSPCo, I&M and
OPCo
The
FERC PJM Regional Transmission Rate Proceeding
At
AEP’s
urging, the FERC instituted an investigation of PJM’s zonal rate regime,
indicating that the present rate regime may need to be replaced through
establishment of regional rates that would compensate AEP and other transmission
owners for the regional transmission facilities they provide to PJM, which
provides service for the benefit of customers throughout PJM. In
September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly
filed a regional transmission rate design proposal with the
FERC. This filing proposed and supported a new PJM rate regime
generally referred to as a Highway/Byway rate design.
Parties
to the regional rate proceeding proposed the following rate
regimes:
·
|
AEP/AP proposed a Highway/Byway rate design
in
which:
|
|
·
|
The cost of all transmission facilities in
the PJM
region operated at 345 kV or higher would be included in a “Highway” rate
that all load serving entities (LSEs) would pay based on peak
demand. The AEP/AP proposal would produce about $125 million in
net revenues per year for AEP from users in other zones of
PJM.
|
|
·
|
The cost of transmission facilities operating
at lower
voltages would be collected in the zones where those costs are
presently
charged under PJM’s existing rate design.
|
·
|
Two other utilities, Baltimore Gas & Electric
Company (BG&E) and Old Dominion Electric Cooperative (ODEC), proposed
a Highway/Byway rate that includes transmission facilities above
200 kV in
the Highway rate, which would have produced lower net revenues
for AEP
than the AEP/AP proposal.
|
·
|
In another competing Highway/Byway proposal,
a group of
LSEs proposed rates that would include existing 500 kV and higher
voltage
facilities and new facilities above 200 kV in the Highway rate,
which
would also have produced lower net revenues for AEP than the AEP/AP
proposal.
|
·
|
In January 2006, the FERC staff issued testimony
and
exhibits supporting phase-in of a PJM-wide flat rate or “Postage Stamp”
type of rate design that would socialize the cost of all transmission
facilities. The proposed rate design would have initially
produced much lower net transmission revenues for AEP than the
AEP/AP
proposal, but could produce slightly higher net revenues when fully
phased
in.
|
All
of
these proposals were challenged by a majority of other transmission owners
in
the PJM region, who favored continuation of the existing PJM rate design
which
provides AEP with no compensation for through and out traffic on its east
zone
transmission system. Hearings were held in April 2006 and the ALJ
issued an initial decision in July 2006. The ALJ found the existing
PJM zonal rate design to be unjust and determined that it should be
replaced. The ALJ found that the Highway/Byway rates proposed by
AEP/AP and BG&E/ODEC to be just and reasonable alternatives. The
ALJ also found FERC staff’s proposed Postage Stamp rate to be just and
reasonable and recommended that it be adopted. The ALJ also found
that the effective date of the rate change should be April 1, 2006 to coincide
with SECA rate elimination. Because the Postage Stamp rate was found
to produce greater cost shifts than other proposals, the judge also recommended
that the new regional design be phased-in. Without a phase-in, the
Postage Stamp method would produce more revenue for AEP than the AEP/AP
proposal. However, the proposed phase-in of Postage Stamp rates would delay
the
full favorable impact of those new regional rates until about 2012.
AEP
filed
briefs noting exceptions to the initial decision and replies to the exceptions
of other parties. AEP argued that a phase-in should not be
required. Nevertheless, AEP argued that if the FERC adopts the
Postage Stamp rate and a phase-in plan, the revenue collections curtailed
by the
phase-in should be deferred and paid later with interest.
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 and Michigan
to recover lost through-and-out transmission service (T&O) and SECA
revenues.
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 although others use them. 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 their future construction of new east transmission
facilities, results of operations, cash flows and financial
condition.
The
AEP
East companies presently recover from retail customers approximately 85%
of the
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 and Michigan
until
these lost T&O/SECA transmission revenues are recovered in retail
rates.
SECA
Revenue Subject to Refund
The
AEP
East companies ceased collecting T&O revenues in accordance with FERC
orders, and collected SECA rates to mitigate the loss of T&O revenues from
December 1, 2004 through March 31, 2006, when SECA rates
expired. Intervenors objected to the SECA rates, raising various
issues. As a result, the FERC set SECA rate issues for hearing and
ordered that the SECA rate revenues be collected, subject to refund or
surcharge. The AEP East companies paid SECA rates to other utilities
at considerably lesser amounts than collected. If a refund is
ordered, the AEP East companies would also receive refunds related to the
SECA
rates they paid to third parties. The AEP East companies recognized
gross SECA revenues 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
$19 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.
Since
the
implementation of SECA rates in December 2004, the AEP East companies recorded
approximately $220 million of gross SECA revenues, subject to
refund. In 2006, the AEP East companies provided reserves of $37
million in net refunds for current and future SECA settlements with all of
AEP’s
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 will be
adequate.
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 and cash flows.
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 of 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. FERC could suspend the effective date until February 1,
2008. 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 Zone. 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 rates resulting from
the
filing, but will receive corresponding revenue to offset the
increase. This filing will not directly impact retail
rates.
4.
|
COMMITMENTS, GUARANTEES AND
CONTINGENCIES
|
The
Registrant Subsidiaries are subject to certain claims and legal actions arising
in their ordinary course of business. In addition, their business
activities are subject to extensive governmental regulation related to public
health and the environment. The ultimate outcome of such pending or
potential litigation cannot be predicted. For current proceedings not
specifically discussed below, management does not anticipate that the
liabilities, if any, arising from such proceedings would have a material
adverse
effect on the financial statements. The Commitments, Guarantees and
Contingencies note within the 2006 Annual Report should be read in conjunction
with this report.
GUARANTEES
There
are
certain immaterial liabilities recorded for guarantees in accordance with
FASB
Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others.” There is no collateral held in relation to any
guarantees. In the event any guarantee is drawn, there is no recourse
to third parties unless specified below.
Letters
of Credit
Certain
Registrant Subsidiaries enter into standby letters of credit (LOCs) with
third
parties. These LOCs cover items such as insurance programs, security
deposits, debt service reserves and credit enhancements for issued
bonds. All of these LOCs were issued in the subsidiaries’ ordinary
course of business. At June 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 $85 million. Since SWEPCo uses self-bonding, the
guarantee provides for SWEPCo to commit to use its resources to complete
the
reclamation in the event the work is not completed by Sabine Mining Company
(Sabine), an entity consolidated under FIN 46. This guarantee ends
upon depletion of reserves and completion of final reclamation. Based
on the latest study, it is estimated the reserves will be depleted in 2029
with
final reclamation completed by 2036, at an estimated cost of approximately
$39
million. As of June 30, 2007, SWEPCo collected approximately $31
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 June 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. At June 30, 2007, the maximum potential loss by subsidiary
for these lease agreements assuming the fair market value of the equipment
is
zero at the end of the lease term was as follows:
|
|
Maximum
Potential Loss
|
|
Company
|
|
(in
millions)
|
|
APCo
|
|
$ |
8
|
|
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. A bench trial on the
liability issues was held during July 2005. In June 2006, the judge
stayed the liability decision pending the issuance of a decision by the U.S.
Supreme Court in the Duke Energy case.
Under
the
CAA, if a plant undertakes a major modification that results in an emissions
increase, permitting requirements might be triggered and the plant may be
required to install additional pollution control technology. This
requirement does not apply to routine maintenance, replacement of degraded
equipment or failed components or other repairs needed for the reliable,
safe
and efficient operation of the plant. The CAA authorizes civil
penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation
at each generating unit. In 2001, the District Court ruled claims for
civil penalties based on activities that occurred more than five years before
the filing date of the complaints cannot be imposed. There is no time
limit on claims for injunctive relief.
The
Federal EPA and eight northeastern states each filed an additional complaint
containing additional allegations against the Amos and Conesville
plants. APCo and CSPCo filed an answer to the northeastern states’
complaint and the Federal EPA’s complaint, denying the allegations and stating
their defenses. Cases are also pending that could affect CSPCo’s
share of jointly-owned units at Beckjord (12.5% owned), Zimmer (25.4% owned),
and Stuart (26% owned) Stations. Similar cases have been filed
against other nonaffiliated utilities, including Allegheny Energy, Eastern
Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper,
Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara
Mohawk. Several of these cases were resolved through consent
decrees.
Courts
have reached different conclusions regarding whether the activities at issue
in
these cases are routine maintenance, repair, or replacement, and therefore
are
excluded from NSR. Similarly, courts have reached different results
regarding whether the activities at issue increased emissions from the power
plants. Appeals on these and other issues were filed in certain
appellate courts, including a petition to appeal to the U.S. Supreme Court
that
was granted in the Duke Energy case. The Federal EPA issued a final
rule that would exclude activities similar to those challenged in these cases
from NSR as “routine replacements.” In March 2006, the Court of
Appeals for the District of Columbia Circuit issued a decision vacating the
rule. The Court denied the Federal EPA’s request for rehearing, and
the Federal EPA and other parties filed a petition for review by the U.S.
Supreme Court. In April 2007, the Supreme Court denied the petition
for review. The Federal EPA also proposed a rule that would define
“emissions increases” in a way that most of the challenged activities would be
excluded from NSR.
On
April
2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’
decision that had supported the statutory construction argument of Duke Energy
in its NSR proceeding. In a unanimous decision, the Court ruled that
the Federal EPA was not obligated to define “major modification” in two
different CAA provisions in the same way. The Court also found that
the Fourth Circuit’s interpretation of “major modification” as applying only to
projects that increased hourly emission rates amounted to an invalidation
of the
relevant Federal EPA regulations, which under the CAA can only be challenged
in
the Court of Appeals within 60 days of the Federal EPA
rulemaking. The U.S. Supreme Court did acknowledge, however, that
Duke Energy may argue on remand that the Federal EPA has been inconsistent
in
its interpretations of the CAA and the regulations and may not retroactively
change 20 years of accepted practice.
In
addition to providing guidance on certain of the merits of the NSR proceedings
brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the
Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the
Duke Energy cases has an impact on the timing of the NSR
proceedings. The court that heard the trial on liability issues will
likely issue its decision during the third quarter of 2007. A bench
trial on remedy issues, if necessary, is likely to begin in the second half
of
2007.
Management
is unable to estimate the loss or range of loss related to any contingent
liability, if any, AEP subsidiaries might have for civil penalties under
the CAA
proceedings. Management is also unable to predict the timing of
resolution of these matters due to the number of alleged violations and the
significant number of issues yet to be determined by the Court. If
AEP subsidiaries do not prevail, management believes AEP subsidiaries can
recover any capital and operating costs of additional pollution control
equipment that may be required through regulated rates and market prices
for
electricity. If any of the AEP subsidiaries are unable to recover
such costs or if material penalties are imposed, it would adversely affect
future results of operations, cash flows and possibly financial condition.
Notice
of Enforcement and Notice of Citizen Suit – Affecting
SWEPCo
In
March
2005, two special interest groups, Sierra Club and Public Citizen, filed
a
complaint in Federal District Court for the Eastern District of Texas alleging
violations of the CAA at SWEPCo’s Welsh Plant. SWEPCo filed a
response to the complaint in May 2005. A trial in this matter is
scheduled for the third quarter of 2007.
In
2004,
the Texas Commission on Environmental Quality (TCEQ) issued a Notice of
Enforcement to SWEPCo relating to the Welsh Plant containing a summary of
findings resulting from a compliance investigation at the plant. In
April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition
recommending the entry of an enforcement order to undertake certain corrective
actions and assessing an administrative penalty of approximately $228 thousand
against SWEPCo based on alleged violations of certain representations regarding
heat input in SWEPCo’s permit application and the violations of certain
recordkeeping and reporting requirements. SWEPCo responded to the
preliminary report and petition in May 2005. The enforcement order
contains a recommendation that would limit the heat input on each Welsh unit
to
the referenced heat input contained within the permit application within
10 days
of the issuance of a final TCEQ order and until a permit amendment is
issued. SWEPCo had previously requested a permit alteration to remove
the reference to a specific heat input value for each Welsh unit and to clarify
the sulfur content requirement for fuels consumed at the plant. A
permit alteration was issued in March 2007 removing the heat input references
from the Welsh permit and clarifying the sulfur content of fuels burned at
the
plant is limited to 0.5% on an as-received basis. The Sierra Club and
Public Citizen filed a motion to overturn the permit alteration. 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 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 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 OPCo’s $123 million judgment for damages against TEM related to
replacement products and remanded the issue for further
proceedings.
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
and the dispute is pending before the Surface Transportation
Board. Based upon a weighted average probability analysis of possible
outcomes, PSO, as operator of the plant, recorded provisions for possible
loss
in 2004, 2005, 2006 and the first six months of 2007. The provision
was deferred as a regulatory asset under PSO’s fuel mechanism and immaterially
affected income for TCC and TNC for their respective ownership
shares. Management continues to work toward mitigating the disputed
amounts to the extent possible.
Coal
Transportation Rate Dispute - Affecting PSO
In
1985,
the Burlington Northern Railroad Co. (now BNSF) entered into a coal
transportation agreement with PSO. The agreement contained a base
rate subject to adjustment, a rate floor, a reopener provision and an
arbitration provision. In 1992, PSO reopened the pricing
provision. The parties failed to reach an agreement and the matter
was arbitrated, with the arbitration panel establishing a lowered rate as
of
July 1, 1992 (the 1992 Rate), and modifying the rate adjustment
formula. The decision did not mention the rate floor. From
April 1996 through the contract termination in December 2001, the 1992 Rate
exceeded the adjusted rate, determined according to the decision. PSO
paid the adjusted rate and contended that the panel eliminated the rate
floor. BNSF invoiced at the 1992 Rate and contended that the 1992
Rate was the new rate floor. At the end of 1991, PSO terminated the
contract by paying a termination fee, as required by the
agreement. BNSF contends that the termination fee should have been
calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment
of approximately $9.5 million, including interest.
This
matter was submitted to an arbitration board. In April 2006, the
arbitration board filed its decision, denying BNSF’s underpayments
claim. PSO filed a request for an order confirming the arbitration
award and a request for entry of judgment on the award with the U.S. District
Court for the Northern District of Oklahoma. On July 14, 2006, the
U.S. District Court issued an order confirming the arbitration
award. On July 24, 2006, BNSF filed a Motion to Reconsider the July
14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion
to
Vacate and Correct the Arbitration Award with the U.S. District
Court. In February 2007, the U.S. District Court granted BNSF’s
Motion to Reconsider. PSO filed a substantive response to BNSF’s
motion and BNSF filed a reply. Management continues to work toward
mitigating the disputed amounts to the extent possible.
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. In May 2007, the Registrant Subsidiaries, along with
other sellers involved in the case, sought review of the Ninth Circuit’s
decision by the U.S. Supreme Court. The Solicitor General of the
United States has asked the Supreme Court for an extension of time, until
August
6, 2007, to respond to the petitions for review. 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 six months ended June 30, 2007 and
2006:
|
|
|
|
|
Other
|
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension
Plans
|
|
|
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Three
Months Ended June 30, 2007 and 2006
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
23
|
|
|
$ |
24
|
|
|
$ |
11
|
|
|
$ |
10
|
|
Interest
Cost
|
|
|
57
|
|
|
|
57
|
|
|
|
26
|
|
|
|
25
|
|
Expected
Return on Plan Assets
|
|
|
(82 |
) |
|
|
(83 |
) |
|
|
(26 |
) |
|
|
(23 |
) |
Amortization
of Transition Obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
7
|
|
|
|
7
|
|
Amortization
of Net Actuarial Loss
|
|
|
14
|
|
|
|
19
|
|
|
|
3
|
|
|
|
5
|
|
Net
Periodic Benefit Cost
|
|
$ |
12
|
|
|
$ |
17
|
|
|
$ |
21
|
|
|
$ |
24
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension
Plans
|
|
|
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Six
Months Ended June 30, 2007 and 2006
|
|
(in
millions)
|
|
Service
Cost
|
|
$ |
47
|
|
|
$ |
48
|
|
|
$ |
21
|
|
|
$ |
20
|
|
Interest
Cost
|
|
|
116
|
|
|
|
114
|
|
|
|
52
|
|
|
|
50
|
|
Expected
Return on Plan Assets
|
|
|
(167 |
) |
|
|
(166 |
) |
|
|
(52 |
) |
|
|
(46 |
) |
Amortization
of Transition Obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
14
|
|
|
|
14
|
|
Amortization
of Net Actuarial Loss
|
|
|
29
|
|
|
|
39
|
|
|
|
6
|
|
|
|
10
|
|
Net
Periodic Benefit Cost
|
|
$ |
25
|
|
|
$ |
35
|
|
|
$ |
41
|
|
|
$ |
48
|
|
The
following table provides the net periodic benefit cost (credit) for the plans
by
Registrant Subsidiary for the three and six months ended June 30, 2007 and
2006:
|
|
Pension
Plans
|
|
|
Other
Postretirement
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Three
Months Ended June 30, 2007 and 2006
|
|
(in
thousands)
|
|
APCo
|
|
$ |
842
|
|
|
$ |
1,469
|
|
|
$ |
3,560
|
|
|
$ |
4,489
|
|
CSPCo
|
|
|
(258 |
) |
|
|
205
|
|
|
|
1,491
|
|
|
|
1,805
|
|
I&M
|
|
|
1,900
|
|
|
|
2,330
|
|
|
|
2,531
|
|
|
|
2,953
|
|
OPCo
|
|
|
245
|
|
|
|
829
|
|
|
|
2,801
|
|
|
|
3,396
|
|
PSO
|
|
|
424
|
|
|
|
979
|
|
|
|
1,430
|
|
|
|
1,588
|
|
SWEPCo
|
|
|
747
|
|
|
|
1,225
|
|
|
|
1,419
|
|
|
|
1,578
|
|
|
|
Pension
Plans
|
|
|
Other
Postretirement
Benefit
Plans
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Six
Months Ended June 30, 2007 and 2006
|
|
(in
thousands)
|
|
APCo
|
|
$ |
1,684
|
|
|
$ |
2,937
|
|
|
$ |
7,120
|
|
|
$ |
8,978
|
|
CSPCo
|
|
|
(515 |
) |
|
|
410
|
|
|
|
2,982
|
|
|
|
3,610
|
|
I&M
|
|
|
3,800
|
|
|
|
4,661
|
|
|
|
5,061
|
|
|
|
5,906
|
|
OPCo
|
|
|
490
|
|
|
|
1,655
|
|
|
|
5,603
|
|
|
|
6,792
|
|
PSO
|
|
|
848
|
|
|
|
1,956
|
|
|
|
2,861
|
|
|
|
3,176
|
|
SWEPCo
|
|
|
1,493
|
|
|
|
2,450
|
|
|
|
2,838
|
|
|
|
3,156
|
|
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 business income tax
imposed at a rate of 4.95% and a modified gross receipts tax 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.
I&M
is in the process of evaluating the impact of the MBT Act. It is
expected that the application of the MBT Act will not materially affect
I&M’s 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 six months of 2007 were:
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Issuances:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
Pollution
Control Bonds
|
|
$
|
75,000
|
|
Variable
|
|
2037
|
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 June 30, 2007.
Company
|
|
Type
of Debt
|
|
Principal
Amount
|
|
Interest
Rate
|
|
Due
Date
|
|
|
|
|
(in
thousands)
|
|
(%)
|
|
|
Retirements
and
Principal
Payments:
|
|
|
|
|
|
|
|
|
|
APCo
|
|
Senior
Unsecured Notes
|
|
$
|
125,000
|
|
Variable
|
|
2007
|
APCo
|
|
Other
|
|
|
6
|
|
13.718
|
|
2026
|
OPCo
|
|
Notes
Payable
|
|
|
2,927
|
|
6.81
|
|
2008
|
OPCo
|
|
Notes
Payable
|
|
|
6,000
|
|
6.27
|
|
2009
|
SWEPCo
|
|
Notes
Payable
|
|
|
3,109
|
|
4.47
|
|
2011
|
SWEPCo
|
|
Notes
Payable
|
|
|
4,000
|
|
6.36
|
|
2007
|
SWEPCo
|
|
Notes
Payable
|
|
|
1,500
|
|
Variable
|
|
2008
|
In
July
2007, PSO redeemed $13 million of 6.00% Pollution Control Bonds due in
2020.
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 June 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 six months ended June 30, 2007 are described in the following
table:
|
|
Maximum
Borrowings
from
Utility
Money
Pool
|
|
|
Maximum
Loans
to
Utility
Money
Pool
|
|
|
Average
Borrowings
from
Utility
Money
Pool
|
|
|
Average
Loans
to
Utility
Money
Pool
|
|
|
Borrowings
from
Utility Money Pool as of
June
30, 2007
|
|
|
Authorized
Short-Term
Borrowing
Limit
|
|
Company
|
|
(in
thousands)
|
|
APCo
|
|
$ |
247,616
|
|
|
$ |
-
|
|
|
$ |
103,925
|
|
|
$ |
-
|
|
|
$ |
247,616
|
|
|
$ |
600,000
|
|
CSPCo
|
|
|
117,890
|
|
|
|
35,270
|
|
|
|
53,692
|
|
|
|
13,190
|
|
|
|
64,003
|
|
|
|
350,000
|
|
I&M
|
|
|
100,374
|
|
|
|
-
|
|
|
|
60,659
|
|
|
|
-
|
|
|
|
14,941
|
|
|
|
500,000
|
|
OPCo
|
|
|
447,335
|
|
|
|
1,564
|
|
|
|
209,965
|
|
|
|
1,564
|
|
|
|
16,583
|
|
|
|
600,000
|
|
PSO
|
|
|
216,239
|
|
|
|
-
|
|
|
|
111,567
|
|
|
|
-
|
|
|
|
216,239
|
|
|
|
300,000
|
|
SWEPCo
|
|
|
240,786
|
|
|
|
48,979
|
|
|
|
70,927
|
|
|
|
29,653
|
|
|
|
53,955
|
|
|
|
350,000
|
|
The
maximum and minimum interest rates for funds either borrowed from or loaned
to
the Utility Money Pool were as follows:
|
|
Six
Months Ended June 30,
|
|
|
|
2007
|
|
|
2006
|
|
Maximum
Interest Rate
|
|
|
5.46 |
% |
|
|
5.39 |
% |
Minimum
Interest Rate
|
|
|
5.30 |
% |
|
|
4.19 |
% |
The
average interest rates for funds borrowed from and loaned to the Utility
Money
Pool for the six months ended June 30, 2007 and 2006 are summarized for all
Registrant Subsidiaries in the following table:
|
|
Average
Interest Rate for Funds
Borrowed
from the Utility Money Pool for
Six
Months Ended June 30,
|
|
|
Average
Interest Rate for Funds
Loaned
to the Utility Money Pool for
Six
Months Ended June 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Company
|
|
(in
percentage)
|
|
APCo
|
|
|
5.36
|
|
|
|
4.62
|
|
|
|
-
|
|
|
|
5.05
|
|
CSPCo
|
|
|
5.37
|
|
|
|
4.73
|
|
|
|
5.33
|
|
|
|
4.91
|
|
I&M
|
|
|
5.35
|
|
|
|
4.76
|
|
|
|
-
|
|
|
|
-
|
|
OPCo
|
|
|
5.35
|
|
|
|
4.86
|
|
|
|
5.43
|
|
|
|
5.30
|
|
PSO
|
|
|
5.36
|
|
|
|
4.91
|
|
|
|
-
|
|
|
|
-
|
|
SWEPCo
|
|
|
5.36
|
|
|
|
4.92
|
|
|
|
5.34
|
|
|
|
-
|
|
Short-term
Debt
The
Registrant Subsidiaries’ outstanding short-term debt was as
follows:
|
|
|
June
30, 2007
|
|
December
31, 2006
|
|
|
|
Type
of Debt
|
Outstanding
Amount
|
|
|
Interest
Rate
|
|
Outstanding
Amount
|
|
|
Interest
Rate
|
|
Company
|
|
|
(in
millions)
|
|
|
|
|
(in
millions)
|
|
|
|
|
OPCo
|
|
Commercial
Paper – JMG
|
|
|
$ |
-
|
|
|
|
-
|
|
|
|
$ |
1
|
|
|
|
5.56 |
% |
SWEPCo
|
|
Line
of Credit – Sabine
|
|
|
|
22
|
|
|
|
6.20 |
% |
|
|
|
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
July
2007, AEP extended AEP Credit’s sale of receivables agreement. The
sale of receivables agreement provides commitments of $600 million from a
bank
conduit to purchase receivables from AEP Credit. This agreement will
expire in November 2007. AEP intends to renew or replace this
agreement. 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
CSPCo
and
OPCo are involved in discussions with various stakeholders in Ohio about
potential legislation to address the period following the expiration of the
RSPs
on December 31, 2008. At this time, management is unable to predict
whether CSPCo and OPCo will transition to market pricing, as permitted by
the
current Ohio restructuring legislation, extend their RSP rates, with or without
modification, or become subject to a legislative reinstatement of some form
of
cost-based regulation for their generation supply business on January 1,
2009
when the RSP period ends.
Ohio
New Generation
In
March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. The application proposed three phases of
cost recovery associated with the IGCC plant: Phase 1, recovery of
$24 million in pre-construction costs during 2006; Phase 2, concurrent recovery
of construction-financing costs; and Phase 3, recovery or refund in distribution
rates of any difference between the market-based standard service offer price
for generation and the cost of operating and maintaining the plant, including
a
return on and return of the ultimate cost to construct the plant, originally
projected to be $1.2 billion, along with fuel, consumables and replacement
power
costs. The proposed recoveries in Phases 1 and 2 would be applied
against the 4% limit on additional generation rate increases CSPCo and OPCo
could request under their RSPs.
In
April
2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase
1
of the cost recovery proposal. In June 2006, the PUCO issued another
order approving a tariff to recover Phase 1 pre-construction costs over a
period
of no more than twelve months effective July 1, 2006. Through June
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. CSPCo and OPCo expect to incur additional pre-construction
costs equal to or greater than the $12 million each recovered. As of
June 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each
for
the over-recovered portion. The PUCO indicated that if CSPCo and OPCo
have not commenced a continuous course of construction of the IGCC plant
within
five years of the June 2006 PUCO order, all charges collected for
pre-construction costs, associated with items that may be utilized in IGCC
projects to be built by AEP 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 has scheduled 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 are $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. In July
2007, CSPCo and OPCo filed a status report with the PUCO referencing APCo’s IGCC
West Virginia filing.
SECA
Revenue Subject to Refund
The
AEP
East companies ceased collecting T&O revenues in accordance with FERC
orders, and collected SECA rates to mitigate the loss of T&O revenues from
December 1, 2004 through March 31, 2006, when SECA rates
expired. Intervenors objected to the SECA rates, raising various
issues. As a result, the FERC set SECA rate issues for hearing and
ordered that the SECA rate revenues be collected, subject to refund or
surcharge. The AEP East companies paid SECA rates to other utilities
at considerably lesser amounts than collected. If a refund is
ordered, the AEP East companies would also receive refunds related to the
SECA
rates they paid to third parties. The AEP East companies recognized
gross SECA revenues 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
$19 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.
Since
the
implementation of SECA rates in December 2004, the AEP East companies recorded
approximately $220 million of gross SECA revenues, subject to
refund. In 2006, the AEP East companies provided reserves of $37
million in net refunds for current and future SECA settlements with all of
AEP’s
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 will be
adequate.
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 and cash flows.
Environmental
Matters
The
Registrant Subsidiaries are implementing a substantial capital investment
program and incurring additional operational costs to comply with new
environmental control requirements. The sources of these requirements
include:
·
|
Requirements
under the Clean Air Act (CAA) to reduce
emissions of sulfur dioxide (SO2), nitrogen oxide
(NOx), particulate matter (PM) and mercury from fossil
fuel-fired power plants; and
|
·
|
Requirements
under the Clean Water Act (CWA) to reduce the
impacts of water intake structures on aquatic species at certain
power
plants.
|
In
addition, the Registrant Subsidiaries are engaged in litigation with respect
to
certain environmental matters, have been notified of potential responsibility
for the clean-up of contaminated sites and incur costs for disposal of spent
nuclear fuel and future decommissioning of I&M’s nuclear
units. Management also monitors possible future requirements to
reduce carbon dioxide (CO2) emissions to address concerns about
global climate change. 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. Several
similar complaints were filed in 1999 and thereafter against nonaffiliated
utilities including Allegheny Energy, Eastern Kentucky Electric Cooperative,
Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power
Company, Mirant, NRG Energy and Niagara Mohawk. Several of these
cases were resolved through consent decrees. The alleged
modifications at the Registrant Subsidiaries’ power plants occurred over a
20-year period. A bench trial on the liability issues was held during
2005. In June 2006, the judge stayed the liability decision pending
the issuance of a decision by the U.S. Supreme Court in the Duke Energy
case.
Under
the
CAA, if a plant undertakes a major modification that directly results in
an
emissions increase, permitting requirements might be triggered and the plant
may
be required to install additional pollution control technology. This
requirement does not apply to activities such as routine maintenance,
replacement of degraded equipment or failed components, or other repairs
needed
for the reliable, safe and efficient operation of the plant.
Courts
that considered whether the activities at issue in these cases are routine
maintenance, repair, or replacement, and therefore are excluded from NSR,
reached different conclusions. Similarly, courts that considered
whether the activities at issue increased emissions from the power plants
have
reached different results. Appeals on these and other issues were
filed in certain appellate courts, including a petition to appeal to the
U.S.
Supreme Court that was granted in the Duke Energy case.
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 a unanimous decision, the Court ruled that
the Federal EPA was not obligated to define “major modification” in two
different CAA provisions in the same way. The Court also found that
the Fourth Circuit’s interpretation of “major modification” as applying only to
projects that increased hourly emission rates amounted to an invalidation
of the
relevant Federal EPA regulations, which under the CAA can only be challenged
in
the Court of Appeals within 60 days of the Federal EPA
rulemaking. The U.S. Supreme Court did acknowledge, however, that
Duke Energy may argue on remand that the Federal EPA has been inconsistent
in
its interpretations of the CAA and the regulations and may not retroactively
change 20 years of accepted practice.
In
addition to providing guidance on certain of the merits of the NSR proceedings
brought against APCo, CSPCo, I&M and OPCo, the U.S. Supreme Court’s issuance
of a ruling in the Duke Energy cases has an impact on the timing of the NSR
proceedings. The court indicated an intent to issue a decision on
liability in the third quarter of 2007. A bench trial on remedy
issues, if necessary, is likely to begin in the second half of
2007.
Management
is unable to estimate the loss or range of loss related to any contingent
liability, if any, the Registrant Subsidiaries might have for civil penalties
under the CAA proceedings. Management is also unable to predict the
timing of resolution of these matters due to the number of alleged violations
and the significant number of issues to be determined by the
court. If the Registrant Subsidiaries do not prevail, management
believes the Registrant Subsidiaries can recover any capital and operating
costs
of additional pollution control equipment that may be required through regulated
rates and market prices for electricity. If the Registrant
Subsidiaries are unable to recover such costs or if material penalties are
imposed, it would adversely affect future results of operations, cash flows
and
possibly financial condition.
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 second 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
June 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 second 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 additional costs may not be approved in
Texas.(Applies to AEP.)
TCC
has
filed a request with the PUCT to increase its transmission and distribution
rates. The rate request includes the amounts charged for the delivery
of electricity over TCC´s transmission and distribution lines. TCC is seeking
approval of an $81 million increase, which includes the expiration of $20
million in billing credits that the PUCT required in approving the merger
of CSW
into AEP. The credits have been in place since 2000. TCC is
requesting a return on equity of 11.25% with a capital structure of
approximately 60% debt/40% equity. As part of rebuttal testimony
filed in April 2007, TCC reduced its base rate request by $11 million and
reduced its return on equity by 0.5%. If the PUCT denies the
requested rate recovery, it could adversely impact future results of operations,
cash flows and financial condition.
Our
request for rate recovery of additional costs may not be approved in
Oklahoma.(Applies to AEP and PSO.)
PSO
filed
a request with the OCC in November 2006 seeking approval of a $50 million
overall increase in base rates, an annually adjusted rate mechanism to recover
the expected significant investment PSO will be making in new facilities,
several new and restructured tariffs to allow PSO to begin to reduce the
relationship between its revenues and its sales volumes, and to implement
some
demand side management tariffs. PSO´s planned investments over the
next five years include new generation facilities ($1.12 billion), new and
refurbished transmission substations and lines ($302 million) and new
distribution lines and equipment ($582 million). In April 2007, PSO
filed rebuttal testimony regarding various issues raised by the OCC Staff
and
the intervenors. As part of rebuttal testimony, PSO reduced its base
rate request by $2 million. If the OCC denies the requested rate
recovery, it could adversely impact future results of operations, cash flows
and
financial condition.
The
amount we charged third parties for using our transmission facilities has
been
reduced, is subject to refund and may not be completely restored in the
future. (Applies to AEP, 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 $19
million of the SECA revenues that we billed were never collected. AEP
filed a motion with the FERC to force payment of these SECA
billings.
A
hearing
was held in May 2006 to determine whether any of the SECA revenues should
be
refunded. In August 2006, the ALJ issued an initial decision, finding that
the
rate design for the recovery of SECA charges was flawed and that a large
portion
of the “lost revenues” reflected in the SECA rates was not recoverable. The ALJ
found that the SECA rates charged were unfair, unjust and discriminatory,
and
that new compliance filings and refunds should be made. The ALJ also found
that
unpaid SECA rates must be paid in the recommended reduced amount. The
FERC has not ruled on the matter. If the FERC upholds the decision of
the ALJ, it would disallow $90 million of the AEP East companies’ remaining $135
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.
We
are exposed to losses resulting from the bankruptcy of Enron
Corp. (Applies to AEP.)
On
June
1, 2001, we purchased HPL from Enron Corp. (Enron). Later that year, Enron
and
its subsidiaries filed bankruptcy proceedings in the U.S. Bankruptcy Court
for
the Southern District of New York. Various HPL-related contingencies and
indemnities from Enron remained unsettled at the date of Enron’s
bankruptcy. In connection with the 2001 acquisition of HPL, we
entered into an agreement with BAM Lease Company, which granted HPL the
exclusive right to use approximately 65 BCF of cushion gas required for the
normal operation of the Bammel gas storage facility. At the time of
our acquisition of HPL, Bank of America (BOA) and certain other banks (together
with BOA, BOA Syndicate) and Enron entered into an agreement granting HPL
the
exclusive use of 65 BCF of cushion gas. Additionally, Enron and the
BOA Syndicate released HPL from all prior and future liabilities and obligations
in connection with the financing arrangement. After the Enron
bankruptcy, HPL was informed by the BOA Syndicate of a purported default
by
Enron under the terms of the financing arrangement. We purchased 10
BCF of gas from Enron and are currently litigating the rights to the remaining
55 BCF of cushion gas.
In
February 2004, in connection with BOA’s dispute, Enron filed Notices of
Rejection regarding the cushion gas use agreement and other incidental
agreements. We have objected to Enron’s attempted rejection of these
agreements. In 2005, we sold HPL, including the Bammel gas storage
facility. We indemnified the purchaser for damages, if any, arising
from the litigation with BOA. Management is unable to predict the
final resolution of these disputes, however the impact on results of operations,
cash flows and financial condition could be material.
Risks
Relating To State Restructuring
In
Ohio, our costs may not be recovered and rates may be reduced.
(Applies to AEP, OPCo and CSPCo.)
In
January 2007, CSPCo and OPCo filed with the PUCO under the 4% provision of
their
RSPs to increase their annual generation rates for 2007 by $24 million and
$8
million, respectively, to recover governmentally-mandated
costs. Pursuant to the RSPs, CSPCo and OPCo implemented these
proposed increases effective with the first billing cycle in May
2007. These increases are subject to refund until the PUCO issues a
final order in the matter. The PUCO staff and intervenors have
proposed disallowances. Management is unable to determine the impact
of any potential refunds or rider reductions on future results of operations
and
cash flows.
In
March
2007, CSPCo filed an application under the 4% provision of the RSP to adjust
the
Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in
connection with CSPCo's acquisition of Monongahela Power Company's certified
territory in Ohio and a new purchase power contract to serve the
load. The PUCO approved an adjustment to the PAR, which is expected
to increase CSPCo's revenues by $22 million and $38 million for 2007 and
2008,
respectively.
CSPCo
and
OPCo are involved in discussions with various stakeholders in Ohio about
potential legislation to address the period following the expiration of the
RSPs
on December 31, 2008. At this time, management is unable to predict
whether CSPCo and OPCo will transition to market pricing, as permitted by
the
current Ohio restructuring legislation, extend their RSP rates, with or without
modification, or become subject to a legislative reinstatement of some form
of
cost-based regulation for their generation supply business on January 1,
2009
when the RSP period ends.
Some
laws and regulations governing restructuring in Virginia have not yet been
interpreted and could harm our business, operating results and financial
condition. (Applies to AEP and APCo.)
Virginia
restructuring legislation was enacted in 1999 providing for retail choice
of
generation suppliers to be phased in over two years beginning January 1,
2002. It required jurisdictional utilities to unbundle their power
supply and energy delivery rates and to file functional separation plans
by
January 1, 2002. APCo filed its plan with the Virginia SCC and,
following Virginia SCC approval of a settlement agreement, now operates in
Virginia as a functionally separated electric utility charging unbundled
rates
for its retail sales of electricity. The settlement agreement
addressed functional separation, leaving decisions related to legal separation
for later Virginia SCC consideration. While the electric
restructuring law in Virginia established the general framework governing
the
retail electric market, it required the Virginia SCC to issue rules and
determinations implementing the law.
In
April
2007, Virginia enacted a law providing for cost-based regulation of electric
utilities’ generation/supply rates. Results of operations and
financial condition could be adversely affected when APCo complies with new
re-regulation legislation applicable to its generation and supply
business.
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. A bench trial on the liability issues was held during July
2005. Briefing has concluded and the court has indicated an intent to
issue a decision on liability. Additionally, in July 2004 attorneys
general of eight states and others sued AEP and other utilities alleging
that
CO2 emissions from power generating facilities constitute a public
nuisance under federal common law. The trial court dismissed the
suits and plaintiffs have appealed the dismissal. While we believe
the claims are without merit, the costs associated with reducing CO2
emissions could harm our business and our results of operations and financial
position.
If
these
or other future actions are resolved against us, substantial modifications
of
our existing coal-fired power plants could be required. In addition,
we could be required to invest significantly in additional emission control
equipment, accelerate the timing of capital expenditures, pay penalties and/or
halt operations. Moreover, our results of operations and financial
position could be reduced due to the timing of recovery of these investments
and
the expense of ongoing litigation.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
The
following table provides information about purchases by AEP (or its
publicly-traded subsidiaries) during the quarter ended June 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
|
|
04/01/07
–
04/30/07
|
|
|
-
|
|
|
|
$ |
-
|
|
|
|
-
|
|
|
$ |
-
|
|
05/01/07
–
05/31/07
|
|
|
2
|
|
(a)
|
|
|
73
|
|
|
|
-
|
|
|
|
-
|
|
06/01/07
–
06/30/07
|
|
|
20
|
|
(b)
|
|
|
70
|
|
|
|
-
|
|
|
|
-
|
|
(a)
|
I&M repurchased 2 shares of its 4.13% cumulative
preferred stock, in a privately-negotiated transaction outside
of an
announced program.
|
(b)
|
I&M repurchased 20 shares of its 4.13% cumulative
preferred stock, in privately-negotiated transactions outside of
an
announced program.
|
Item
4. Submission of Matters to a Vote of Security
Holders
AEP
The
annual meeting of shareholders was held in Shreveport, Louisiana, on April
24,
2007. The holders of shares entitled to vote at the meeting or their
proxies cast votes at the meeting with respect to the following three matters,
as indicated below:
1.
|
Election
of thirteen directors to hold office until the next
annual meeting and until their successors are duly
elected. Each nominee for director received the votes of
shareholders as follows:
|
|
|
Number
of Shares Voted For
|
|
|
Number
of Shares Abstaining
|
|
|
|
|
|
|
|
|
E.
R. Brooks
|
|
|
334,998,592
|
|
|
|
8,663,576
|
|
Donald
M. Carlton
|
|
|
336,014,182
|
|
|
|
7,647,986
|
|
Ralph
D. Crosby, Jr.
|
|
|
335,978,026
|
|
|
|
7,684,142
|
|
John
P. DesBarres
|
|
|
335,974,155
|
|
|
|
7,688,013
|
|
Robert
W. Fri
|
|
|
332,637,218
|
|
|
|
11,024,950
|
|
Linda
A. Goodspeed
|
|
|
336,200,472
|
|
|
|
7,461,696
|
|
William
R. Howell
|
|
|
335,739,069
|
|
|
|
7,923,099
|
|
Lester
A. Hudson, Jr.
|
|
|
333,116,412
|
|
|
|
10,545,756
|
|
Michael
G. Morris
|
|
|
332,139,748
|
|
|
|
11,522,420
|
|
Lionel
L. Nowell, III
|
|
|
336,254,000
|
|
|
|
7,408,168
|
|
Richard
L. Sandor
|
|
|
332,152,005
|
|
|
|
11,510,163
|
|
Donald
G. Smith
|
|
|
333,270,480
|
|
|
|
10,391,688
|
|
Kathryn
D. Sullivan
|
|
|
336,273,055
|
|
|
|
7,389,113
|
|
|
2.
|
Approval
of the AEP Senior Officer Incentive Plan. The proposal was
approved by a vote of the shareholders as
follows:
|
Votes
FOR
|
|
317,166,316
|
|
Votes
AGAINST
|
|
20,791,784
|
|
Votes
ABSTAINED
|
|
5,704,068
|
|
|
3.
|
Ratification
of the appointment of the firm of Deloitte & Touche LLP as the
independent registered public accounting firm for 2007. The
proposal was approved by a vote of the shareholders as
follows:
|
Votes
FOR
|
|
335,620,502
|
|
Votes
AGAINST
|
|
4,752,625
|
|
Votes
ABSTAINED
|
|
3,289,041
|
|
APCo
The
annual meeting of stockholders was held on April 24, 2007 at 1 Riverside
Plaza,
Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR each
of the following nine persons for election as directors and there were no
votes
withheld and such persons were elected directors to hold office for one year
or
until their successors are elected and qualify:
Nicholas
K. Akins
|
|
Robert
P. Powers
|
|
Carl
L. English
|
|
Stephen
P. Smith
|
|
John
B. Keane
|
|
Susan
Tomasky
|
|
Holly
K. Koeppel
|
|
Dennis
E. Welch
|
|
Michael
G. Morris
|
|
|
|
I&M
Pursuant
to action by written consent in lieu of an annual meeting of the sole
shareholder dated April 24, 2007, the following thirteen persons were elected
directors to hold office for one year or until their successors are elected
and
qualify:
Nicholas
K. Akins
|
|
Marc
E. Lewis
|
|
Karl
G. Boyd
|
|
Susanne
M. Moorman Rowe
|
|
Carl
L. English
|
|
Michael
G. Morris
|
|
Allen
R. Glassburn
|
|
Helen
J. Murray
|
|
JoAnn
M. Grevenow
|
|
Robert
P. Powers
|
|
Patrick
C. Hale
|
|
Susan
Tomasky
|
|
Holly
K. Koeppel
|
|
|
|
OPCo
The
annual meeting of shareholders was held on May 1, 2007 at 1 Riverside Plaza,
Columbus, Ohio. At the meeting there were 27,952,473 votes cast FOR
each of the following nine persons for election as directors and there were
no
votes withheld and such persons were elected directors to hold office for
one
year or until their successors are elected and qualify:
Nicholas
K. Akins
|
|
Robert
P. Powers
|
|
Carl
L. English
|
|
Stephen
P. Smith
|
|
John
B. Keane
|
|
Susan
Tomasky
|
|
Holly
K. Koeppel
|
|
Dennis
E. Welch
|
|
Michael
G. Morris
|
|
|
|
SWEPCo
Pursuant
to action by written consent in lieu of an annual meeting of the sole
shareholder dated April 11, 2007, the following nine persons were elected
directors to hold office for one year or until their successors are elected
and
qualify:
Nicholas
K. Akins
|
|
Holly
K. Koeppel
|
|
Carl
L. English
|
|
Stephen
P. Smith
|
|
Thomas
M. Hagan
|
|
Susan
Tomasky
|
|
John
B. Keane
|
|
Dennis
E. Welch
|
|
Michael
G. Morris
|
|
|
|
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: August
3, 2007 |