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
|
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)
|
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.
|
Term
|
Meaning
|
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.
|
·
|
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.
|
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.
|
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
|
·
|
Generation
of electricity for sale to U.S. retail and wholesale
customers.
|
·
|
Electricity
transmission and distribution in the
U.S.
|
·
|
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.
|
·
|
IPPs,
wind farms and marketing and risk management activities primarily
in
ERCOT.
|
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.
|
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
|
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
|
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 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
|
·
|
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.
|
·
|
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, 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
|
·
|
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.
|
·
|
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 $23 million due to a decrease in pretax
income.
|
June
30, 2007
|
December
31, 2006
|
|||||||||||||||
($
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 | % |
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
|
Moody’s
|
S&P
|
Fitch
|
||||||||||||||||||||||
AEP
Short Term Debt
|
P-2
|
A-2
|
F-2
|
|||||||||||||||||||||
AEP
Senior Unsecured Debt
|
Baa2
|
BBB
|
BBB
|
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
|
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
|
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
|
)
|
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
|
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
|
·
|
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.
|
·
|
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.
|
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
|
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.
|
·
|
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.
|
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.
|
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
|
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
|
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
|
Remainder
|
|||||
2007
|
2008
|
2009
|
|||
Estimated
Plant Output Hedged
|
94%
|
90%
|
91%
|
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
|