Commission
|
Registrant,
State of Incorporation,
|
I.R.S.
Employer
|
||
File
Number
|
Address
of Principal Executive Offices, and Telephone Number
|
Identification
No.
|
||
1-3525
|
AMERICAN
ELECTRIC POWER COMPANY, INC. (A New York Corporation)
|
13-4922640
|
||
0-18135
|
AEP
GENERATING COMPANY (An Ohio Corporation)
|
31-1033833
|
||
0-346
|
AEP
TEXAS CENTRAL COMPANY (A Texas Corporation)
|
74-0550600
|
||
0-340
|
AEP
TEXAS NORTH COMPANY (A Texas Corporation)
|
75-0646790
|
||
1-3457
|
APPALACHIAN
POWER COMPANY (A Virginia Corporation)
|
54-0124790
|
||
1-2680
|
COLUMBUS
SOUTHERN POWER COMPANY (An Ohio Corporation)
|
31-4154203
|
||
1-3570
|
INDIANA
MICHIGAN POWER COMPANY (An Indiana Corporation)
|
35-0410455
|
||
1-6858
|
KENTUCKY
POWER COMPANY (A Kentucky Corporation)
|
61-0247775
|
||
1-6543
|
OHIO
POWER COMPANY (An Ohio Corporation)
|
31-4271000
|
||
0-343
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)
|
73-0410895
|
||
1-3146
|
SOUTHWESTERN
ELECTRIC POWER COMPANY (A Delaware Corporation)
|
72-0323455
|
||
All
Registrants
|
1
Riverside Plaza, Columbus, Ohio 43215-2373
|
|||
Telephone
(614) 716-1000
|
Indicate
by check mark whether the registrants (1) have filed all reports
required
to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934
during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been
subject
to such filing requirements for the past 90 days.
|
|
Yes
X
|
No
|
Indicate
by check mark whether American Electric Power Company, Inc. is a
large
accelerated filer, an accelerated filer, or a non-accelerated filer.
See
definition of ‘accelerated filer and large accelerated filer’ in Rule
12b-2 of the Exchange Act. (Check One)
|
Large
accelerated filer X
Accelerated filer Non-accelerated
filer
|
Indicate
by check mark whether AEP Generating Company, AEP Texas Central Company,
AEP Texas North Company, Appalachian Power Company, Columbus Southern
Power Company, Indiana Michigan Power Company, Kentucky Power Company,
Ohio Power Company, Public Service Company of Oklahoma and Southwestern
Electric Power Company, are large accelerated filers, accelerated
filers,
or non-accelerated filers. See definition of ‘accelerated filer and large
accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check
One)
|
|
Large
accelerated filer
Accelerated filer Non-accelerated
filer X
|
|
Indicate
by check mark whether the registrants are shell companies (as defined
in
Rule 12b-2 of the Exchange Act).
|
|
Yes
|
No X
|
Number
of shares of common stock outstanding of the registrants
at
October
31, 2006
|
|||
AEP
Generating Company
|
1,000
|
||
($1,000
par value)
|
|||
AEP
Texas Central Company
|
2,211,678
|
||
($25
par value)
|
|||
AEP
Texas North Company
|
5,488,560
|
||
($25
par value)
|
|||
American
Electric Power Company, Inc.
|
395,572,735
|
||
($6.50
par value)
|
|||
Appalachian
Power Company
|
13,499,500
|
||
(no
par value)
|
|||
Columbus
Southern Power Company
|
16,410,426
|
||
(no
par value)
|
|||
Indiana
Michigan Power Company
|
1,400,000
|
||
(no
par value)
|
|||
Kentucky
Power Company
|
1,009,000
|
||
($50
par value)
|
|||
Ohio
Power Company
|
27,952,473
|
||
(no
par value)
|
|||
Public
Service Company of Oklahoma
|
9,013,000
|
||
($15
par value)
|
|||
Southwestern
Electric Power Company
|
7,536,640
|
||
($18
par value)
|
Glossary
of Terms
|
|
|||
Forward-Looking
Information
|
|
|||
Part
I. FINANCIAL INFORMATION
|
||||
Items
1, 2 and 3 - Financial Statements, Management’s Financial Discussion and
Analysis and Quantitative and Qualitative Disclosures About Risk
Management Activities:
|
||||
American
Electric Power Company, Inc. and Subsidiary
Companies:
|
||||
Management’s
Financial Discussion and Analysis of Results of Operations
|
|
|||
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|||
Condensed
Consolidated Financial Statements
|
|
|||
Index
to Condensed Notes to Condensed Consolidated Financial
Statements
|
|
|||
AEP
Generating Company:
|
||||
Management’s
Narrative Financial Discussion and Analysis
|
|
|||
Condensed
Financial Statements
|
|
|||
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||
AEP
Texas Central Company and Subsidiaries:
|
||||
Management’s
Financial Discussion and Analysis
|
|
|||
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|||
Condensed
Consolidated Financial Statements
|
|
|||
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||
AEP
Texas North Company and Subsidiary:
|
||||
Management’s
Narrative Financial Discussion and Analysis
|
|
|||
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|||
Condensed
Consolidated Financial Statements
|
|
|||
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||
Appalachian
Power Company and Subsidiaries:
|
||||
Management’s
Financial Discussion and Analysis
|
|
|||
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|||
Condensed
Consolidated Financial Statements
|
|
|||
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||
Columbus
Southern Power Company and Subsidiaries:
|
||||
Management’s
Narrative Financial Discussion and Analysis
|
|
|||
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|||
Condensed
Consolidated Financial Statements
|
|
|||
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||
Indiana
Michigan Power Company and Subsidiaries:
|
||||
Management’s
Financial Discussion and Analysis
|
|
|||
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|||
Condensed
Consolidated Financial Statements
|
|
|||
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||
Kentucky
Power Company:
|
||||||||
Management’s
Narrative Financial Discussion and Analysis
|
|
|||||||
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|||||||
Condensed
Financial Statements
|
|
|||||||
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||||||
Ohio
Power Company Consolidated:
|
||||||||
Management’s
Financial Discussion and Analysis
|
|
|||||||
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|||||||
Condensed
Consolidated Financial Statements
|
|
|||||||
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||||||
Public
Service Company of Oklahoma:
|
||||||||
Management’s
Narrative Financial Discussion and Analysis
|
|
|||||||
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|||||||
Condensed
Financial Statements
|
|
|||||||
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||||||
Southwestern
Electric Power Company Consolidated:
|
||||||||
Management’s
Financial Discussion and Analysis
|
|
|||||||
Quantitative
and Qualitative Disclosures About Risk Management
Activities
|
|
|||||||
Condensed
Consolidated Financial Statements
|
|
|||||||
Index
to Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||||||
Condensed
Notes to Condensed Financial Statements of Registrant
Subsidiaries
|
|
|||||||
Combined
Management’s Discussion and Analysis of Registrant
Subsidiaries
|
|
|||||||
Item
4.
|
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., AEP Generating Company, AEP Texas Central Company, AEP Texas
North
Company, Appalachian Power Company, Columbus Southern Power Company,
Indiana Michigan Power Company, Kentucky Power Company, Ohio Power
Company, Public Service Company of Oklahoma and Southwestern Electric
Power Company. Information contained herein relating to any individual
registrant is filed by such registrant on its own behalf. Each registrant
makes no representation as to information relating to the other
registrants.
|
Term
|
Meaning
|
ADFIT
|
Accumulated
Deferred Federal Income Taxes.
|
|
ADITC
|
Accumulated
Deferred Investment Tax Credits.
|
|
AEGCo
|
AEP
Generating Company, an AEP electric generating
subsidiary.
|
|
AEP
or Parent
|
American
Electric Power Company, Inc.
|
|
AEP
Consolidated
|
AEP
and its majority owned consolidated subsidiaries and consolidated
entities.
|
|
AEP
East companies
|
APCo,
CSPCo, I&M, KPCo and OPCo.
|
|
AEPES
|
AEP
Energy Services, Inc., a subsidiary of AEP Resources,
Inc.
|
|
AEP
System or the System
|
American
Electric Power System, an integrated electric utility system, owned
and
operated by AEP’s electric utility subsidiaries.
|
|
AEP
System Power Pool or AEP
Power Pool
|
Members
are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation,
cost of generation and resultant wholesale off-system sales of the
member
companies.
|
|
AEPSC
|
American
Electric Power Service Corporation, a service subsidiary providing
management and professional services to AEP and its
subsidiaries.
|
|
AEP
West companies
|
PSO,
SWEPCo, TCC and TNC.
|
|
AFUDC
|
Allowance
for Funds Used During Construction.
|
|
ALJ
|
Administrative
Law Judge.
|
|
AOCI
|
Accumulated
Other Comprehensive Income.
|
|
APCo
|
Appalachian
Power Company, an AEP electric utility subsidiary.
|
|
CAA
|
Clean
Air Act.
|
|
Cook
Plant
|
Donald
C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by
I&M.
|
|
CSPCo
|
Columbus
Southern Power Company, an AEP electric utility
subsidiary.
|
|
CSW
|
Central
and South West Corporation, a subsidiary of AEP (Effective January
21,
2003, the legal name of Central and South West Corporation was changed
to
AEP Utilities, Inc.).
|
|
CSW
Operating Agreement
|
Agreement,
dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing
their generating capacity allocation. AEPSC acts as the
agent.
|
|
CTC
|
Competition
Transition Charge.
|
|
DETM
|
Duke
Energy Trading and Marketing L.L.C., a risk management
counterparty.
|
|
ECAR
|
East
Central Area Reliability Council.
|
|
EDFIT
|
Excess
Deferred Federal Income Taxes.
|
|
EITF
|
Financial
Accounting Standards Board’s Emerging Issues Task
Force.
|
|
EPACT
|
Energy
Policy Act of 2005.
|
|
ERCOT
|
Electric
Reliability Council of Texas.
|
|
FASB
|
Financial
Accounting Standards Board.
|
|
Federal
EPA
|
United
States Environmental Protection Agency.
|
|
FERC
|
Federal
Energy Regulatory Commission.
|
|
GAAP
|
Accounting
Principles Generally Accepted in the United States of
America.
|
|
HPL
|
Houston
Pipe Line Company LP, a former AEP subsidiary that was sold in January
2005.
|
|
IGCC
|
Integrated
Gasification Combined Cycle, technology that turns coal into a
cleaner-burning gas.
|
|
I&M
|
Indiana
Michigan Power Company, an AEP electric utility
subsidiary.
|
|
IPP
|
Independent
Power Producers.
|
|
IRS
|
Internal
Revenue Service.
|
|
IURC
|
Indiana
Utility Regulatory Commission.
|
|
KPCo
|
Kentucky
Power Company, an AEP electric utility subsidiary.
|
|
KPSC
|
Kentucky
Public Service Commission.
|
|
kV
|
Kilovolt.
|
|
KWH
|
Kilowatthour.
|
|
MISO
|
Midwest
Independent Transmission System Operator.
|
|
MTM
|
Mark-to-Market.
|
MW
|
Megawatt.
|
|
MWH
|
Megawatthour.
|
|
NOx
|
Nitrogen
oxide.
|
|
Nonutility
Money Pool
|
AEP
System’s Nonutility Money Pool.
|
|
NRC
|
Nuclear
Regulatory Commission.
|
|
NSR
|
New
Source Review.
|
|
NYMEX
|
New
York Mercantile Exchange.
|
|
OATT
|
Open
Access Transmission Tariff.
|
|
OCC
|
Corporation
Commission of the State of Oklahoma.
|
|
OPCo
|
Ohio
Power Company, an AEP electric utility subsidiary.
|
|
OTC
|
Over
the counter.
|
|
PJM
|
Pennsylvania
- New Jersey - Maryland regional transmission
organization.
|
|
PSO
|
Public
Service Company of Oklahoma, an AEP electric utility
subsidiary.
|
|
PTB
|
Price-to-Beat.
|
|
PUCO
|
Public
Utilities Commission of Ohio.
|
|
PUCT
|
Public
Utility Commission of Texas.
|
|
PURPA
|
Public
Utility Regulatory Policies Act of 1978.
|
|
Registrant
Subsidiaries
|
AEP
subsidiaries which are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC.
|
|
REP
|
Texas
Retail Electric Provider.
|
|
Risk
Management Contracts
|
Trading
and nontrading derivatives, including those derivatives designated
as cash
flow and fair value hedges.
|
|
Rockport
Plant
|
A
generating plant, consisting of two 1,300 MW coal-fired generating
units
near Rockport, Indiana owned or leased by AEGCo and
I&M.
|
|
RSP
|
Rate
Stabilization Plan.
|
|
RTO
|
Regional
Transmission Organization.
|
|
S&P
|
Standard
and Poor’s.
|
|
SEC
|
United
States Securities and Exchange Commission.
|
|
SECA
|
Seams
Elimination Cost Allocation.
|
|
SFAS
|
Statement
of Financial Accounting Standards issued by the FASB.
|
|
SFAS
133
|
Statement
of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities.”
|
|
SIA
|
System
Integration Agreement.
|
|
SO2
|
Sulfur
Dioxide.
|
|
SPP
|
Southwest
Power Pool.
|
|
STP
|
South
Texas Project Nuclear Generating Plant.
|
|
Sweeny
|
Sweeny
Cogeneration Limited Partnership, owner and operator of a four
unit, 480
MW gas-fired generation facility, owned 50% by AEP.
|
|
SWEPCo
|
Southwestern
Electric Power Company, an AEP electric utility
subsidiary.
|
|
TCC
|
AEP
Texas Central Company, an AEP electric utility subsidiary.
|
|
TEM
|
SUEZ
Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing,
Inc.).
|
|
Texas
Restructuring Legislation
|
Legislation
enacted in 1999 to restructure the electric utility industry in
Texas.
|
|
TNC
|
AEP
Texas North Company, an AEP electric utility subsidiary.
|
|
True-up
Proceeding
|
A
filing made under the Texas Restructuring Legislation to finalize
the
amount of stranded costs and other true-up items and the recovery
of such
amounts.
|
|
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.
|
·
|
Changes
in the financial markets, particularly those affecting the availability
of
capital and our ability to refinance existing debt at attractive
rates.
|
·
|
Actions
of rating agencies, including changes in the ratings of
debt.
|
·
|
Volatility
and changes in markets for electricity, natural gas and other
energy-related commodities.
|
·
|
Changes
in utility regulation, including implementation of EPACT and membership
in
and integration into regional transmission structures.
|
·
|
Accounting
pronouncements periodically issued by accounting standard-setting
bodies.
|
·
|
The
performance of our pension and other postretirement benefit
plans.
|
·
|
Prices
for power that we generate and sell at wholesale.
|
·
|
Changes
in technology, particularly with respect to new, developing or alternative
sources of generation.
|
·
|
Other
risks and unforeseen events, including wars, the effects of terrorism
(including increased security costs), embargoes and other catastrophic
events.
|
·
|
In
July 2006, an ALJ rendered an initial decision to the FERC recommending
that current transmission rates in PJM are unjust and unreasonable
and
should be redesigned to replace the PJM license plate rates effective
April 1, 2006. If approved by the FERC, the new regional rates would
result in parties outside of the AEP zone in PJM contributing a
significant portion of AEP’s transmission revenue requirement, some of
which may be treated as a refund to retail customers. The favorable
impact
of the initial ALJ decision is not determinable pending the decision
of
the FERC and subject to analysis of refunds to retail customers,
if
any.
|
·
|
In
July 2006, the FERC approved our request for use of an incentive
rate
treatment for our proposed 550-mile 765 kV transmission line project.
The
approval is conditioned upon PJM including the project in its formal
Regional Transmission Expansion Plan, which should be finalized in
early
2007.
|
·
|
In
July 2006, the West Virginia Public Service Commission approved a
settlement agreement in APCo and WPCo’s base rate case, providing for a
$44 million annual increase in rates effective July 28, 2006. These
rates
include a surcharge for recovery of the cost of the Wyoming-Jacksons
Ferry
765 kV line, which was energized and placed in service in June
2006.
|
·
|
In
August 2006, an ALJ rendered an initial decision to the FERC indicating
the rate design for recovery of SECA charges was flawed and that
the SECA
rates charged were unfair, unjust and discriminatory and that refunds
should be made. We believe this decision is contrary to other FERC
rulings
and intend to defend against a SECA rates refund.
|
·
|
In
September 2006, the Virginia SCC’s chief hearing examiner issued an
opinion recommending disallowance of our $21 million environmental
and
reliability cost recovery case filed in June 2005. We subsequently
wrote
off our related assets which reduced pretax earnings by $36 million
in the
third quarter of 2006. We believe the hearing examiner’s recommendation is
contrary to the law and have urged the Virginia SCC not to adopt
that
recommendation.
|
·
|
In
September 2006, we announced our intention to file transmission and
distribution wires rate cases in Texas in late 2006. We anticipate
requesting an $83 million increase for TCC and a $25 million increase
for
TNC.
|
·
|
In
September 2006, we filed a notice of intent in Oklahoma to file a
base
rate case in November 2006.
|
·
|
In
October 2006, we filed state environmental permit applications for
clean-coal power plants in Ohio and West Virginia, representing another
step towards the commencement of construction of our IGCC
plants.
|
·
|
In
October 2006, we implemented an interim increase in Virginia retail
base
rates, subject to refund, as ordered by the Virginia SCC related
to our
$198 million net base rate case filing from May 2006. Hearings are
scheduled for December 2006.
|
·
|
In
October 2006, TCC issued $1.74 billion senior secured transition
bonds as
previously approved by the PUCT. In October 2006, TCC repaid $345
million
of intercompany notes to AEP and also paid a special dividend of
$585
million to AEP. We will use the remaining proceeds to reduce a portion
of
TCC’s debt and equity.
|
·
|
In
October 2006, the IURC denied our request to revise I&M’s book
depreciation rates without adjusting base tariff
rates.
|
Utility
Operations
|
||
·
|
Generation
of electricity for sale to U.S. retail and wholesale
customers.
|
|
·
|
Electricity
transmission and distribution in the U.S.
|
|
Investments
- Other
|
||
·
|
Bulk
commodity barging operations, wind farms, IPPs and other energy
supply-related businesses.
|
Three
Months Ended September 30,
|
Nine
Months Ended September 30,
|
||||||||||||||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||||||||||||||
Earnings
|
EPS
(c)
|
Earnings
|
EPS
(c)
|
Earnings
|
EPS
(c)
|
Earnings
|
EPS
(c)
|
||||||||||||||||||
Utility
Operations
|
$
|
379
|
$
|
0.96
|
$
|
352
|
$
|
0.91
|
$
|
904
|
$
|
2.29
|
$
|
952
|
$
|
2.45
|
|||||||||
Investments
- Other
|
(109
|
)
(d)
|
(0.28
|
)
(d)
|
28
|
0.07
|
(80
|
)
(d)
|
(0.20
|
)
(d)
|
32
|
0.08
|
|||||||||||||
All
Other (a)
|
(2
|
)
|
-
|
(5
|
)
|
(0.01
|
)
|
(7
|
)
|
(0.02
|
)
|
(45
|
)
|
(0.12
|
)
|
||||||||||
Investments
- Gas Operations (b)
|
(3
|
)
|
(0.01
|
)
|
(10
|
)
|
(0.03
|
)
|
(2
|
)
|
-
|
(2
|
)
|
-
|
|||||||||||
Income
Before Discontinued Operations
|
$
|
265
|
$
|
0.67
|
$
|
365
|
$
|
0.94
|
$
|
815
|
$
|
2.07
|
$
|
937
|
$
|
2.41
|
|||||||||
Weighted
Average Number of Basic
Shares Outstanding
|
394
|
389
|
394
|
389
|
(a)
|
All
Other includes the parent company’s guarantee revenues, interest income
and expense, as well as other nonallocated costs.
|
|
(b)
|
We
sold our remaining gas pipeline and storage assets in
2005.
|
|
(c)
|
The
earnings per share of any segment does not represent a direct legal
interest in the assets and liabilities allocated to any one segment
but
rather represents a direct equity interest in AEP’s assets and liabilities
as a whole.
|
|
(d) | Loss primarily due to an after-tax impairment of $136 million (approximately $0.34 per share) related to our Plaquemine Cogeneration Facility. |
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(in
millions)
|
|||||||||||||
Revenues
|
$
|
3,441
|
$
|
3,237
|
$
|
9,209
|
$
|
8,623
|
|||||
Fuel
and Purchased Energy
|
1,384
|
1,252
|
3,637
|
3,163
|
|||||||||
Gross
Margin
|
2,057
|
1,985
|
5,572
|
5,460
|
|||||||||
Depreciation
and Amortization
|
369
|
328
|
1,041
|
963
|
|||||||||
Other
Operating Expenses
|
973
|
1,014
|
2,806
|
2,757
|
|||||||||
Operating
Income
|
715
|
643
|
1,725
|
1,740
|
|||||||||
Other
Income, Net
|
20
|
43
|
105
|
122
|
|||||||||
Interest
Expense and Preferred Stock Dividend Requirements
|
161
|
145
|
475
|
445
|
|||||||||
Income
Tax Expense
|
195
|
189
|
451
|
465
|
|||||||||
Income
Before Discontinued Operations
|
$
|
379
|
$
|
352
|
$
|
904
|
$
|
952
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(in
millions of KWH)
|
|||||||||||||
Energy
Summary
|
|||||||||||||
Retail:
|
|||||||||||||
Residential
|
13,482
|
14,152
|
36,010
|
37,332
|
|||||||||
Commercial
|
10,799
|
10,900
|
29,149
|
29,204
|
|||||||||
Industrial
|
13,468
|
13,380
|
40,405
|
39,633
|
|||||||||
Miscellaneous
|
677
|
682
|
1,890
|
1,968
|
|||||||||
Subtotal
|
38,426
|
39,114
|
107,454
|
108,137
|
|||||||||
Texas
Retail and Other
|
105
|
115
|
312
|
504
|
|||||||||
Total
Retail
|
38,531
|
39,229
|
107,766
|
108,641
|
|||||||||
Wholesale
|
13,465
|
13,135
|
35,131
|
37,515
|
|||||||||
Texas
Wires Delivery
|
7,877
|
8,093
|
20,338
|
20,348
|
|||||||||
Total
KWHs
|
59,873
|
60,457
|
163,235
|
166,504
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(in
degree days)
|
|||||||||||||
Weather
Summary
|
|||||||||||||
Eastern
Region
|
|||||||||||||
Actual
- Heating (a)
|
10
|
1
|
1,573
|
1,940
|
|||||||||
Normal
- Heating (b)
|
7
|
7
|
1,999
|
1,995
|
|||||||||
Actual
- Cooling (c)
|
685
|
834
|
914
|
1,122
|
|||||||||
Normal
- Cooling (b)
|
688
|
674
|
970
|
955
|
|||||||||
Western
Region
(d)
|
|||||||||||||
Actual
- Heating (a)
|
0
|
0
|
664
|
795
|
|||||||||
Normal
- Heating (b)
|
2
|
2
|
1,007
|
1,007
|
|||||||||
Actual
- Cooling (c)
|
1,468
|
1,523
|
2,325
|
2,225
|
|||||||||
Normal
- Cooling (b)
|
1,410
|
1,397
|
2,079
|
2,059
|
(a)
|
Eastern
Region and Western Region heating degree days are calculated on a
55
degree temperature base.
|
|
(b)
|
Normal
Heating/Cooling represents the 30-year average of degree
days.
|
|
(c)
|
Eastern
Region and Western Region cooling days are calculated on a 65 degree
temperature base.
|
|
(d)
|
Western
Region statistics represent PSO/SWEPCo customer base only.
|
Third
Quarter of 2005
|
$
|
352
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
29
|
||||||
Off-system
Sales
|
75
|
||||||
Transmission
Revenues
|
(38
|
)
|
|||||
Other
|
6
|
||||||
Total
Change in Gross Margin
|
72
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Maintenance
and Other Operation
|
(15
|
)
|
|||||
Asset
Impairments and Other Related Charges
|
39
|
||||||
Depreciation
and Amortization
|
(41
|
)
|
|||||
Taxes
Other Than Income Taxes
|
17
|
||||||
Other
Income, Net
|
(23
|
)
|
|||||
Interest
and Other Charges
|
(16
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(39
|
)
|
|||||
Income
Tax Expense
|
(6
|
)
|
|||||
Third
Quarter of 2006
|
$
|
379
|
·
|
Retail
Margins increased $29 million primarily due to the
following:
|
|
|
·
|
A
$72 million increase related to new rates implemented in our
Ohio
jurisdictions as approved by the PUCO in our Rate Stabilization
Plans
(RSPs) and a $12 million increase related to new rates implemented
in
Kentucky as approved in our base rate case;
|
|
·
|
A
$20 million increase related to increased sales to municipal,
cooperative
and other wholesale customers primarily as a result of new power
supply
contracts; and
|
|
·
|
An
$18 million increase related to the purchase of the Ohio service
territory
of Monongahela Power in December 2005; partially offset
by
|
|
·
|
A
$22 million decrease in financial transmission rights revenue,
net of
congestion, primarily due to fewer transmission constraints within
the PJM
market;
|
|
·
|
A
$33 million decrease related to increased refunds to retail customers
of a
portion of off-system sales margins due to higher off-system sales
and the
reinstatement of the off-system sales margins sharing mechanism
in West
Virginia effective July 1, 2006 in conjunction with the West Virginia
rate
case settlement;
|
|
·
|
A
$14 million increase in delivered fuel costs, which relates to
AEP East
companies with inactive, capped or frozen fuel clauses;
and
|
|
·
|
A
$30 million decrease in usage related to mild weather. As compared
to the
prior year, we experienced an 18% decrease in cooling degree days
in the
eastern region and a 4% decrease in the western region.
|
·
|
Margins
from Off-system Sales for 2006 increased $75 million primarily
due to
positive margins from hedges of plant output and strong physical
sales in
the east, where AEP’s generation availability factor was high in July and
August when wholesale prices were favorable.
|
|
·
|
Transmission
Revenues decreased $38 million primarily due to the elimination
of SECA
revenues as of April 1, 2006. At this time, we have a pending
proposal
with the FERC to replace SECA revenues. See the “Transmission Rate
Proceedings at the FERC” section of Note
3.
|
·
|
Maintenance
and Other Operation expenses increased $15 million primarily due
to
increases in generation expenses for base operations, maintenance
and an
abandonment of digital turbine control equipment at the Cook Plant,
increases in transmission and distribution expenses related to vegetation
management and storm restoration and the establishment of a regulatory
asset for PJM administrative fees in 2005 which reduced expenses
in the
prior period, offset by the establishment of a net regulatory asset
for
recovery of prior years’ Ohio ice storm damage costs and lower incentive
pay accruals.
|
·
|
Asset
Impairments and Other Related Charges were $39 million in 2005 due
to our
commitment to a plan in September 2005 to retire two units at our
Conesville Plant. We retired the two units effective December 29,
2005.
|
·
|
Depreciation
and Amortization expense increased $41 million primarily due to increased
Ohio regulatory asset amortization in conjunction with rate increases,
higher depreciable property balances and the write off of Virginia
environmental and reliability regulatory assets.
|
·
|
Taxes
Other Than Income Taxes decreased $17 million primarily due to adjustments
related to real and personal property taxes and sales and use
taxes.
|
·
|
Other
Income, Net decreased $23 million primarily related to the write
off of
carrying costs on Virginia environmental and reliability regulatory
assets.
|
·
|
Interest
and Other Charges increased $16 million primarily due to additional
debt
issued in late 2005 and early 2006 and an increase in regulatory
interest
related to Texas regulatory liabilities partially offset by an increase
in
allowance for borrowed funds used during construction.
|
·
|
Income
Tax Expense increased $6 million due to the increase in pretax
income.
|
Nine
Months Ended September 30, 2005
|
$
|
952
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
198
|
||||||
Off-system
Sales
|
2
|
||||||
Transmission
Revenues
|
(93
|
)
|
|||||
Other
|
5
|
||||||
Total
Change in Gross Margin
|
112
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Maintenance
and Other Operation
|
(42
|
)
|
|||||
Gain
on Disposition of Assets, Net
|
(47
|
)
|
|||||
Asset
Impairments and Other Related Charges
|
39
|
||||||
Depreciation
and Amortization
|
(78
|
)
|
|||||
Other
Income, Net
|
(16
|
)
|
|||||
Interest
and Other Charges
|
(30
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(174
|
)
|
|||||
Income
Tax Expense
|
14
|
||||||
Nine
Months Ended September 30, 2006
|
$
|
904
|
·
|
Retail
Margins increased $198 million primarily due to the
following:
|
|
|
·
|
A
$175 million increase related to new rates implemented in our
Ohio
jurisdictions as approved by the PUCO in our RSPs, a $22 million
increase
related to new rates implemented in Kentucky as approved in our
base rate
case and a $12 million increase related to new rates implemented
in
Oklahoma in June 2005;
|
|
·
|
A
$21 million increase in financial transmission rights revenue,
net of
congestion, due to improved management of price risk related
to serving
retail load within PJM under current transmission
constraints;
|
|
·
|
A
$58 million increase related to increased usage and customer
growth in the
industrial and commercial classes of which $47 million relates
to the
purchase of the Ohio service territory of Monongahela Power in
December
2005; and
|
|
·
|
A
$50 million increase related to increased sales to municipal,
cooperative
and other wholesale customers primarily as a result of new power
supply
contracts; partially offset by
|
|
·
|
An
$84 million increase in delivered fuel cost, which relates to the
AEP East
companies with inactive, capped or frozen fuel clauses;
|
|
·
|
A
$66 million decrease in usage related to mild weather. As compared
to the
prior year, our eastern region and western region experienced 19%
and 17%
declines, respectively, in heating degree days. Also compared to
the prior
year, our eastern region experienced a 19% decrease in cooling
degree
days. These decreases were partially offset by an increase of 5%
in
cooling degree days in the western region; and
|
|
·
|
A
$15 million decrease related to increased refunds to retail customers
of a
portion of off-system sales margins due to higher off-system sales
and the
reinstatement of the off-system sales margins sharing mechanism
in West
Virginia effective July 1, 2006 in conjunction with the West Virginia
rate
case settlement.
|
·
|
Transmission
Revenues decreased $93 million primarily due to the elimination
of SECA
revenues as of April 1, 2006 and a provision of $19 million recorded
in
2006 related to potential SECA refunds pending settlement negotiations
with various intervenors. At this time, we have a pending proposal
with
the FERC to replace SECA revenues. See the “Transmission Rate Proceedings
at the FERC” section of Note
3.
|
·
|
Maintenance
and Other Operation expenses increased $42 million primarily due
to
increases in generation expenses related to base operations, maintenance
and planned and forced plant outages, distribution expenses related
to
vegetation management and the establishment of a regulatory asset
for PJM
administrative fees in 2005 which reduced expenses in the prior period.
These increases were partially offset by favorable variances related
to
expenses from the January 2005 ice storm in Ohio and Indiana, decreases
related to the sale of STP in May 2005 and lower incentive
accruals.
|
·
|
Asset
Impairments and Other Related Charges were $39 million in 2005 due
to our
commitment to a plan in September 2005 to retire two units at our
Conesville Plant. We retired the two units effective December 29,
2005.
|
·
|
Gain
on Disposition of Assets, Net decreased $47 million resulting from
revenues related to the earnings sharing agreement with Centrica
as
stipulated in the purchase-and-sale agreement from the sale of our
REPs in
2002. In 2005, we reached a settlement with Centrica and received
$112
million related to two years of earnings sharing whereas in 2006
we
received $70 million related to one year of earnings
sharing.
|
·
|
Depreciation
and Amortization expense increased $78 million primarily due to increased
Ohio regulatory asset amortization in conjunction with rate increases,
higher depreciable property balances and the write off of Virginia
environmental and reliability regulatory assets.
|
·
|
Other
Income, Net decreased $16 million primarily due to the write off
of
carrying costs on Virginia environmental and reliability regulatory
assets
and a decrease in Ohio carrying costs income as a result of the
implementation of the Ohio rate stabilization plans in January 2006,
partially offset by an increase in the allowance for equity funds
used
during construction.
|
·
|
Interest
and Other Charges increased $30 million from the prior period primarily
due to additional debt issued in late 2005 and early 2006 and increasing
interest rates, partially offset by an increase in allowance for
borrowed
funds used during construction.
|
·
|
Income
Tax Expense decreased $14 million due to the decrease in pretax
income.
|
September
30, 2006
|
December
31, 2005
|
||||||||||||
Long-term
Debt, including amounts due within one year
|
$
|
12,763
|
57.0
|
%
|
$
|
12,226
|
57.2
|
%
|
|||||
Short-term
Debt
|
23
|
0.1
|
10
|
0.0
|
|||||||||
Total
Debt
|
12,786
|
57.1
|
12,236
|
57.2
|
|||||||||
Common
Equity
|
9,525
|
42.6
|
9,088
|
42.5
|
|||||||||
Preferred
Stock
|
61
|
0.3
|
61
|
0.3
|
|||||||||
Total
Debt and Equity Capitalization
|
$
|
22,372
|
100.0
|
%
|
$
|
21,385
|
100.0
|
%
|
Amount
|
Maturity
|
||||||
(in
millions)
|
|||||||
Commercial
Paper Backup:
|
|||||||
Revolving
Credit Facility
|
$
|
1,500
|
March
2010
|
||||
Revolving
Credit Facility
|
1,500
|
April
2011
|
|||||
Total
|
3,000
|
||||||
Cash
and Cash Equivalents
|
259
|
||||||
Total
Liquidity Sources
|
3,259
|
||||||
Less:
Letter of Credit Drawn
|
34
|
||||||
Net
Available Liquidity
|
$
|
3,225
|
Moody’s
|
S&P
|
Fitch
|
|||||||||||||||||||||||||
AEP
Short Term Debt
|
P-2
|
A-2
|
F-2
|
||||||||||||||||||||||||
AEP
Senior Unsecured Debt
|
Baa2
|
BBB
|
BBB
|
Nine
Months Ended
September
30,
|
|||||||
2006
|
2005
|
||||||
(in
millions)
|
|||||||
Cash
and Cash Equivalents at Beginning of Period
|
$
|
401
|
$
|
320
|
|||
Net
Cash Flows From Operating Activities
|
2,213
|
1,699
|
|||||
Net
Cash Flows Used For Investing Activities
|
(2,474
|
)
|
(60
|
)
|
|||
Net
Cash Flows From (Used For) Financing Activities
|
119
|
(1,110
|
)
|
||||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
(142
|
)
|
529
|
||||
Cash
and Cash Equivalents at End of Period
|
$
|
259
|
$
|
849
|
Nine
Months Ended
September
30,
|
|||||||
2006
|
2005
|
||||||
(in
millions)
|
|||||||
Net
Income
|
$
|
821
|
$
|
963
|
|||
Less:
Discontinued Operations, Net of Tax
|
(6
|
)
|
(26
|
)
|
|||
Income
Before Discontinued Operations
|
815
|
937
|
|||||
Noncash
Items Included in Earnings
|
1,164
|
987
|
|||||
Changes
in Assets and Liabilities
|
234
|
(225
|
)
|
||||
Net
Cash Flows From Operating Activities
|
$
|
2,213
|
$
|
1,699
|
Nine
Months Ended
September
30,
|
|||||||
2006
|
2005
|
||||||
(in
millions)
|
|||||||
Investment
Securities:
|
|||||||
Purchases
of Investment Securities
|
$
|
(8,153
|
)
|
$
|
(4,319
|
)
|
|
Sales
of Investment Securities
|
8,056
|
4,378
|
|||||
Change
in Investment Securities, Net
|
(97
|
)
|
59
|
||||
Construction
Expenditures
|
(2,445
|
)
|
(1,610
|
)
|
|||
Acquisition
of Waterford Plant
|
-
|
(218
|
)
|
||||
Change
in Other Temporary Cash Investments, Net
|
20
|
99
|
|||||
Proceeds
from Sales of Assets
|
120
|
1,599
|
|||||
Other
|
(72
|
)
|
11
|
||||
Net
Cash Flows Used for Investing Activities
|
$
|
(2,474
|
)
|
$
|
(60
|
)
|
Nine
Months Ended
September
30,
|
|||||||
2006
|
2005
|
||||||
(in
millions)
|
|||||||
Issuance
of Common Stock
|
$
|
24
|
$
|
393
|
|||
Repurchase
of Common Stock
|
-
|
(427
|
)
|
||||
Issuance/Retirement
of Debt, Net
|
529
|
(562
|
)
|
||||
Dividends
Paid on Common Stock
|
(437
|
)
|
(408
|
)
|
|||
Other
|
3
|
(106
|
)
|
||||
Net
Cash Flows From (Used for) Financing Activities
|
$
|
119
|
$
|
(1,110
|
)
|
September
30,
2006
|
December
31,
2005
|
||||||
(in
millions)
|
|||||||
AEP
Credit
|
$
|
548
|
$
|
516
|
|||
Rockport
Plant Unit 2
|
2,437
|
2,511
|
|||||
Railcars
|
31
|
31
|
(in
millions)
|
||||
Wholesale
Capacity Auction True-up
|
$
|
61
|
||
Carrying
Costs on Wholesale Capacity Auction True-up
|
31
|
|||
Retail
Clawback including Carrying Costs
|
(65
|
)
|
||
Deferred
Over-recovered Fuel Balance
|
(184
|
)
|
||
Retrospective
ADFIT Benefit
|
(77
|
)
|
||
Other
|
(4
|
)
|
||
Recorded
Net Regulatory Liabilities - Other True-up Items
|
(238
|
)
|
||
Unrecorded
Prospective ADFIT Benefit
|
(240
|
)
|
||
Gross
CTC Refund Proposed
|
(478
|
)
|
||
FERC
Jurisdictional Fuel Refund Deferral
|
16
|
|||
ADITC
and EDFIT Benefit Refund Deferral
|
98
|
|||
Net
CTC Refund Proposed, After Deferrals
|
(364
|
)
|
||
True-up
Proceeding Expense Surcharge
|
7
|
|||
Net
CTC Refund Proposed, After Deferrals and Expenses
|
$
|
(357
|
)
|
·
|
the
PUCT ruled that TCC did not comply with the statute and PUCT rules
regarding the auction of 15% of its Texas jurisdictional installed
capacity,
|
·
|
that
TCC acted in a manner that was commercially unreasonable because
it failed
to determine a minimum price at which it would reject bids for
the sale of
its nuclear generating plant and it bundled gas units with the
sale of its
coal unit,
|
·
|
and
two federal matters regarding the allocation of off-system sales
related
to fuel recoveries and the potential tax normalization
violation.
|
(in
millions)
|
||||
ADITC
and EDFIT Benefits Reducing Securitization
|
$
|
98
|
||
ADFIT
Benefit Applied to Reduce 2002 Securitization of Regulatory Assets
|
(60
|
)
|
||
Securitization
Settlement
|
(77
|
)
|
||
Unrecorded
Prospective ADFIT Benefit Increasing the CTC Refund
|
(240
|
)
|
||
Unrecorded
Equity Carrying Costs Recognized as Collected
|
224
|
|||
Future
Interest Payable on Proposed CTC Refund
|
(19
|
)
|
||
Deferred
Fuel - Federal Jurisdictional Issue
|
16
|
|||
Net
Adverse Earnings Impact Over 14 Years
|
$
|
(58
|
)
|
·
|
Requirements
under the CAA to reduce emissions of SO2,
NOx,
particulate matter and mercury from fossil fuel-fired power
plants;
|
·
|
Requirements
under the Clean Water Act to reduce the impacts of water intake structures
on aquatic species at certain of our power plants; and
|
·
|
Possible
future requirements to reduce carbon dioxide emissions to address
concerns
about global climate change.
|
Utility
Operations
|
Investments
- Gas Operations
|
Sub-Total
MTM Risk Management Contracts
|
PLUS:
MTM of Cash Flow and Fair Value Hedges
|
Total
|
||||||||||||
Current
Assets
|
$
|
444
|
$
|
99
|
$
|
543
|
$
|
26
|
$
|
569
|
||||||
Noncurrent
Assets
|
337
|
130
|
467
|
4
|
471
|
|||||||||||
Total
Assets
|
781
|
229
|
1,010
|
30
|
1,040
|
|||||||||||
Current
Liabilities
|
(373
|
)
|
(99
|
)
|
(472
|
)
|
(24
|
)
|
(496
|
)
|
||||||
Noncurrent
Liabilities
|
(184
|
)
|
(137
|
)
|
(321
|
)
|
(3
|
)
|
(324
|
) | ||||||
Total
Liabilities
|
(557
|
)
|
(236
|
)
|
(793
|
)
|
(27
|
)
|
(820
|
) | ||||||
Total
MTM Derivative
Contract Net Assets
(Liabilities)
|
$
|
224
|
$
|
(7
|
)
|
$
|
217
|
$
|
3
|
$
|
220
|
Utility
Operations
|
Investments-Gas
Operations
|
Total
|
||||||||
Total
MTM Risk Management Contract
Net Assets (Liabilities) at
December
31, 2005
|
$
|
215
|
$
|
(19
|
)
|
$
|
196
|
|||
(Gain)
Loss from Contracts Realized/Settled During
the Period and Entered in a Prior Period
|
(8
|
)
|
10
|
2
|
||||||
Fair
Value of New Contracts at Inception When
Entered During the Period (a)
|
1
|
-
|
1
|
|||||||
Net
Option Premiums Paid/(Received) for Unexercised
or Unexpired Option
Contracts
Entered During The Period
|
(1
|
)
|
-
|
(1
|
)
|
|||||
Changes
in Fair Value Due to Valuation Methodology
Changes on Forward Contracts
|
1
|
-
|
1
|
|||||||
Changes
in Fair Value due to Market Fluctuations During the Period
(b)
|
19
|
2
|
21
|
|||||||
Changes
in Fair Value Allocated to Regulated
Jurisdictions (c)
|
(3
|
)
|
-
|
(3
|
)
|
|||||
Total
MTM Risk Management Contract Net
Assets (Liabilities) at
September 30, 2006
|
$
|
224
|
$
|
(7
|
)
|
217
|
||||
Net
Cash Flow and Fair Value Hedge Contracts
|
3
|
|||||||||
Ending
Net Risk Management Assets at September
30, 2006
|
$
|
220
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected in the Condensed
Consolidated Statements of Operations. These net gains (losses) are
recorded as regulatory assets/liabilities for those subsidiaries
that
operate in regulated jurisdictions. Approximately $7 million of the
regulatory deferral change is due to the change in the SIA. See the
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities, giving an indication
of
when these MTM amounts will settle and generate
cash.
|
Remainder
2006
|
2007
|
2008
|
2009
|
2010
|
After
2010
|
Total
|
||||||||||||||||
Utility
Operations:
|
||||||||||||||||||||||
Prices
Actively Quoted - Exchange Traded Contracts
|
$
|
-
|
$
|
(9
|
)
|
$
|
22
|
$
|
(1
|
)
|
$
|
-
|
$
|
-
|
$
|
12
|
||||||
Prices
Provided by Other External
Sources
- OTC Broker Quotes
(a)
|
(4
|
)
|
119
|
29
|
23
|
-
|
-
|
167
|
||||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
(1
|
)
|
(15
|
)
|
5
|
19
|
28
|
9
|
45
|
|||||||||||||
Total
|
$
|
(5
|
)
|
$
|
95
|
$
|
56
|
$
|
41
|
$
|
28
|
$
|
9
|
$
|
224
|
|||||||
Investments
-
Gas
Operations:
|
||||||||||||||||||||||
Prices
Actively Quoted - Exchange Traded Contracts
|
$
|
-
|
$
|
7
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
7
|
||||||||
Prices
Provided by Other External
Sources
- OTC Broker Quotes (a)
|
(2
|
)
|
(4
|
)
|
-
|
-
|
-
|
-
|
(6
|
)
|
||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
-
|
-
|
(2
|
)
|
(4
|
)
|
(3
|
)
|
1
|
(8
|
)
|
|||||||||||
Total
|
$
|
(2
|
)
|
$
|
3
|
$
|
(2
|
)
|
$
|
(4
|
)
|
$
|
(3
|
)
|
$
|
1
|
$
|
(7
|
)
|
|||
Total:
|
||||||||||||||||||||||
Prices
Actively Quoted - Exchange Traded Contracts
|
$
|
-
|
$
|
(2
|
)
|
$
|
22
|
$
|
(1
|
)
|
$
|
-
|
$
|
-
|
$
|
19
|
||||||
Prices
Provided by Other External
Sources
- OTC Broker Quotes (a)
|
(6
|
)
|
115
|
29
|
23
|
-
|
-
|
161
|
||||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
(1
|
)
|
(15
|
)
|
3
|
15
|
25
|
10
|
37
|
|||||||||||||
Total
|
$
|
(7
|
)
|
$
|
98
|
$
|
54
|
$
|
37
|
$
|
25
|
$
|
10
|
$
|
217
|
(a)
|
Prices
Provided by Other External Sources - OTC Broker Quotes reflects
information obtained from over-the-counter (OTC) brokers, industry
services, or multiple-party on-line platforms.
|
(b)
|
Prices
Based on Models and Other Valuation Methods is in the absence of
pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity is limited, such valuations are classified as
modeled.
|
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.
|
Commodity
|
Transaction
Class
|
Market/Region
|
Tenor
|
|||
(in
Months)
|
||||||
Natural
Gas
|
Futures
|
NYMEX
/ Henry Hub
|
60
|
|||
Physical
Forwards
|
Gulf
Coast, Texas
|
18
|
||||
Swaps
|
Northeast,
Mid-Continent, Gulf Coast, Texas
|
18
|
||||
Exchange
Option Volatility
|
NYMEX
/ Henry Hub
|
12
|
||||
Power
|
Futures
|
AEP
East - PJM
|
36
|
|||
Physical
Forwards
|
AEP
East
|
39
|
||||
Physical
Forwards
|
AEP
West
|
39
|
||||
Physical
Forwards
|
West
Coast
|
39
|
||||
Peak
Power Volatility (Options)
|
AEP
East - Cinergy, PJM
|
12
|
||||
Emissions
|
Credits
|
SO2,
NOx
|
27
|
|||
Coal
|
Physical
Forwards
|
PRB,
NYMEX, CSX
|
27
|
Power
and
Gas
|
Interest
Rate
|
Total
|
||||||||
Beginning
Balance in AOCI, December 31, 2005
|
$
|
(6
|
)
|
$
|
(21
|
)
|
$
|
(27
|
)
|
|
Changes
in Fair Value
|
13
|
(3
|
)
|
10
|
||||||
Reclassifications
from AOCI to Net Income for Cash
Flow Hedges Settled
|
7
|
1
|
8
|
|||||||
Ending
Balance in AOCI, September 30, 2006
|
$
|
14
|
$
|
(23
|
)
|
$
|
(9
|
)
|
||
After-Tax
Portion Expected to be Reclassified to Earnings During Next 12
Months
|
$
|
15
|
$
|
(2
|
)
|
$
|
13
|
Counterparty
Credit Quality
|
Exposure
Before
Credit
Collateral
|
Credit
Collateral
|
Net
Exposure
|
Number
of
Counterparties
>10%
|
Net
Exposure
of
Counterparties
>10%
|
|||||||||||
Investment
Grade
|
$
|
802
|
$
|
140
|
$
|
662
|
1
|
$
|
70
|
|||||||
Split
Rating
|
4
|
4
|
-
|
1
|
-
|
|||||||||||
Noninvestment
Grade
|
15
|
15
|
-
|
2
|
-
|
|||||||||||
No
External Ratings:
|
||||||||||||||||
Internal
Investment Grade
|
33
|
-
|
33
|
3
|
21
|
|||||||||||
Internal
Noninvestment Grade
|
40
|
22
|
18
|
3
|
17
|
|||||||||||
Total
as of September 30, 2006
|
$
|
894
|
$
|
181
|
$
|
713
|
10
|
$
|
108
|
|||||||
As
of December 31, 2005
|
$
|
1,366
|
$
|
484
|
$
|
882
|
10
|
$
|
322
|
Remainder
2006
|
2007
|
2008
|
|||||||||||||||
Estimated
Plant Output Hedged
|
91%
|
88%
|
87%
|
Nine
Months Ended
September
30, 2006
|
Twelve
Months Ended
December
31, 2005
|
||||||||||||||||
(in
millions)
|
(in
millions)
|
||||||||||||||||
End
|
High
|
Average
|
Low
|
End
|
High
|
Average
|
Low
|
||||||||||
$2
|
$10
|
$3
|
$1
|
$3
|
$5
|
$3
|
$1
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
REVENUES
|
|||||||||||||
Utility
Operations
|
$
|
3,485
|
$
|
3,152
|
$
|
9,282
|
$
|
8,437
|
|||||
Gas
Operations
|
(47
|
)
|
73
|
(80
|
)
|
449
|
|||||||
Other
|
156
|
103
|
436
|
326
|
|||||||||
TOTAL
|
3,594
|
3,328
|
9,638
|
9,212
|
|||||||||
EXPENSES
|
|||||||||||||
Fuel
and Other Consumables Used for Electric Generation
|
1,113
|
1,066
|
2,962
|
2,659
|
|||||||||
Purchased
Energy for Resale
|
267
|
181
|
670
|
494
|
|||||||||
Purchased
Gas for Resale
|
4
|
5
|
4
|
255
|
|||||||||
Maintenance
and Other Operation
|
904
|
873
|
2,634
|
2,588
|
|||||||||
Gain/Loss
on Disposition of Assets, Net
|
-
|
(1
|
)
|
(68
|
)
|
(116
|
)
|
||||||
Asset
Impairments and Other Related Charges
|
209
|
39
|
209
|
39
|
|||||||||
Depreciation
and Amortization
|
376
|
336
|
1,065
|
988
|
|||||||||
Taxes
Other Than Income Taxes
|
186
|
205
|
567
|
566
|
|||||||||
TOTAL
|
3,059
|
2,704
|
8,043
|
7,473
|
|||||||||
OPERATING
INCOME
|
535
|
624
|
1,595
|
1,739
|
|||||||||
Interest
and Investment Income
|
22
|
18
|
41
|
43
|
|||||||||
Carrying
Costs Income
|
3
|
27
|
66
|
83
|
|||||||||
Allowance
For Equity Funds Used During Construction
|
12
|
5
|
25
|
17
|
|||||||||
Gain
on Disposition of Equity Investments, Net
|
-
|
56
|
3
|
56
|
|||||||||
Investment
Value Losses
|
-
|
(7
|
)
|
-
|
(7
|
)
|
|||||||
INTEREST
AND OTHER CHARGES
|
|||||||||||||
Interest
Expense
|
174
|
163
|
518
|
524
|
|||||||||
Preferred
Stock Dividend Requirements of Subsidiaries
|
1
|
1
|
2
|
6
|
|||||||||
TOTAL
|
175
|
164
|
520
|
530
|
|||||||||
INCOME
BEFORE INCOME TAX EXPENSE, MINORITY INTEREST EXPENSE AND
EQUITY EARNINGS
|
397
|
559
|
1,210
|
1,401
|
|||||||||
Income
Tax Expense
|
133
|
196
|
394
|
471
|
|||||||||
Minority
Interest Expense
|
1
|
1
|
2
|
3
|
|||||||||
Equity
Earnings of Unconsolidated Subsidiaries
|
2
|
3
|
1
|
10
|
|||||||||
INCOME
BEFORE DISCONTINUED OPERATIONS
|
265
|
365
|
815
|
937
|
|||||||||
DISCONTINUED
OPERATIONS, Net of Tax
|
-
|
22
|
6
|
26
|
|||||||||
NET
INCOME
|
$
|
265
|
$
|
387
|
$
|
821
|
$
|
963
|
|||||
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING
|
394
|
389
|
394
|
389
|
|||||||||
BASIC
EARNINGS PER SHARE
|
|||||||||||||
Income
Before Discontinued Operations
|
$
|
0.67
|
$
|
0.94
|
$
|
2.07
|
$
|
2.41
|
|||||
Discontinued
Operations, Net of Tax
|
-
|
0.05
|
0.01
|
0.07
|
|||||||||
TOTAL
BASIC EARNINGS PER SHARE
|
$
|
0.67
|
$
|
0.99
|
$
|
2.08
|
$
|
2.48
|
|||||
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING
|
396
|
390
|
396
|
390
|
|||||||||
DILUTED
EARNINGS PER SHARE
|
|||||||||||||
Income
Before Discontinued Operations
|
$
|
0.67
|
$
|
0.94
|
$
|
2.06
|
$
|
2.40
|
|||||
Discontinued
Operations, Net of Tax
|
-
|
0.05
|
0.01
|
0.07
|
|||||||||
TOTAL
DILUTED EARNINGS PER SHARE
|
$
|
0.67
|
$
|
0.99
|
$
|
2.07
|
$
|
2.47
|
|||||
CASH
DIVIDENDS PAID PER SHARE
|
$
|
0.37
|
$
|
0.35
|
$
|
1.11
|
$
|
1.05
|
|||||
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Cash
and Cash Equivalents
|
$
|
259
|
$
|
401
|
|||
Other
Temporary Cash Investments
|
198
|
127
|
|||||
Accounts
Receivable:
|
|||||||
Customers
|
751
|
826
|
|||||
Accrued
Unbilled Revenues
|
314
|
374
|
|||||
Miscellaneous
|
52
|
51
|
|||||
Allowance
for Uncollectible Accounts
|
(34
|
)
|
(31
|
)
|
|||
Total Receivables
|
1,083
|
1,220
|
|||||
Fuel,
Materials and Supplies
|
810
|
726
|
|||||
Risk
Management Assets
|
569
|
926
|
|||||
Margin
Deposits
|
90
|
221
|
|||||
Regulatory
Asset for Under-Recovered Fuel Costs
|
66
|
197
|
|||||
Other
|
100
|
127
|
|||||
TOTAL
|
3,175
|
3,945
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric:
|
|||||||
Production
|
16,712
|
16,653
|
|||||
Transmission
|
6,952
|
6,433
|
|||||
Distribution
|
11,179
|
10,702
|
|||||
Other
(including coal mining and nuclear fuel)
|
3,277
|
3,116
|
|||||
Construction
Work in Progress
|
2,848
|
2,217
|
|||||
Total
|
40,968
|
39,121
|
|||||
Accumulated
Depreciation and Amortization
|
15,146
|
14,837
|
|||||
TOTAL
- NET
|
25,822
|
24,284
|
|||||
OTHER
NONCURRENT ASSETS
|
|||||||
Regulatory
Assets
|
3,196
|
3,262
|
|||||
Securitized
Transition Assets and Other
|
558
|
593
|
|||||
Spent
Nuclear Fuel and Decommissioning Trusts
|
1,191
|
1,134
|
|||||
Investments
in Power and Distribution Projects
|
45
|
97
|
|||||
Goodwill
|
76
|
76
|
|||||
Long-term
Risk Management Assets
|
471
|
886
|
|||||
Employee
Benefits and Pension Assets
|
1,059
|
1,105
|
|||||
Other
|
682
|
746
|
|||||
TOTAL
|
7,278
|
7,899
|
|||||
Assets
Held for Sale
|
110
|
44
|
|||||
TOTAL
ASSETS
|
$
|
36,385
|
$
|
36,172
|
2006
|
2005
|
||||||||||||
CURRENT
LIABILITIES
|
(in
millions)
|
||||||||||||
Accounts
Payable
|
$
|
1,180
|
$
|
1,144
|
|||||||||
Short-term
Debt
|
23
|
10
|
|||||||||||
Long-term
Debt Due Within One Year
|
1,789
|
1,153
|
|||||||||||
Risk
Management Liabilities
|
496
|
906
|
|||||||||||
Accrued
Taxes
|
828
|
651
|
|||||||||||
Accrued
Interest
|
192
|
183
|
|||||||||||
Customer
Deposits
|
336
|
571
|
|||||||||||
Other
|
752
|
842
|
|||||||||||
TOTAL
|
5,596
|
5,460
|
|||||||||||
NONCURRENT
LIABILITIES
|
|||||||||||||
Long-term
Debt
|
10,974
|
11,073
|
|||||||||||
Long-term
Risk Management Liabilities
|
324
|
723
|
|||||||||||
Deferred
Income Taxes
|
4,673
|
4,810
|
|||||||||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
2,955
|
2,747
|
|||||||||||
Asset
Retirement Obligations
|
975
|
936
|
|||||||||||
Employee
Benefits and Pension Obligations
|
349
|
355
|
|||||||||||
Deferred
Gain on Sale and Leaseback - Rockport Plant Unit 2
|
150
|
157
|
|||||||||||
Deferred
Credits and Other
|
803
|
762
|
|||||||||||
TOTAL
|
21,203
|
21,563
|
|||||||||||
TOTAL
LIABILITIES
|
26,799
|
27,023
|
|||||||||||
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
61
|
61
|
|||||||||||
Commitments
and Contingencies (Note 5)
|
|||||||||||||
COMMON
SHAREHOLDERS’ EQUITY
|
|||||||||||||
Common
Stock Par Value $6.50:
|
|||||||||||||
2006
|
2005
|
||||||||||||
Shares
Authorized
|
600,000,000
|
600,000,000
|
|||||||||||
Shares
Issued
|
415,979,691
|
415,218,830
|
|||||||||||
(21,499,992
shares were held in treasury at September 30, 2006 and December
31,
2005)
|
2,704
|
2,699
|
|||||||||||
Paid-in
Capital
|
4,153
|
4,131
|
|||||||||||
Retained
Earnings
|
2,669
|
2,285
|
|||||||||||
Accumulated
Other Comprehensive Income (Loss)
|
(1
|
)
|
(27
|
)
|
|||||||||
TOTAL
|
9,525
|
9,088
|
|||||||||||
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
36,385
|
$
|
36,172
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
821
|
$
|
963
|
|||
Less:
Discontinued Operations, Net of Tax
|
(6
|
)
|
(26
|
)
|
|||
Income
Before Discontinued Operations
|
815
|
937
|
|||||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
1,065
|
988
|
|||||
Accretion
of Asset Retirement Obligations
|
47
|
50
|
|||||
Deferred
Income Taxes
|
(88
|
)
|
(33
|
)
|
|||
Deferred
Investment Tax Credits
|
(20
|
)
|
(23
|
)
|
|||
Asset
Impairments, Investment Value Losses and Other Related
Charges
|
209
|
46
|
|||||
Carrying
Costs Income
|
(66
|
)
|
(83
|
)
|
|||
Mark-to-Market
of Risk Management Contracts
|
(21
|
)
|
-
|
||||
Amortization
of Nuclear Fuel
|
38
|
42
|
|||||
Deferred
Property Taxes
|
105
|
94
|
|||||
Pension Contributions to Qualified Plan Trusts | - | (306 | ) | ||||
Fuel
Over/Under-Recovery, Net
|
158
|
(183
|
)
|
||||
Gain
on Sales of Assets and Equity Investments, Net
|
(71
|
)
|
(172
|
)
|
|||
Change
in Other Noncurrent Assets
|
72
|
(84
|
)
|
||||
Change
in Other Noncurrent Liabilities
|
(21
|
)
|
34
|
||||
Changes
in Certain Components of Working Capital:
|
|||||||
Accounts
Receivable, Net
|
139
|
5
|
|||||
Fuel,
Materials and Supplies
|
(84
|
)
|
54
|
||||
Accounts
Payable
|
(49
|
)
|
173
|
||||
Accrued
Taxes
|
176
|
118
|
|||||
Customer
Deposits
|
(235
|
)
|
311
|
||||
Other
Current Assets
|
142
|
(246
|
)
|
||||
Other
Current Liabilities
|
(98
|
)
|
(23
|
)
|
|||
Net
Cash Flows From Operating Activities
|
2,213
|
1,699
|
|||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(2,445
|
)
|
(1,610
|
)
|
|||
Acquisition
of Waterford Plant
|
-
|
(218
|
)
|
||||
Change
in Other Temporary Cash Investments, Net
|
20
|
99
|
|||||
Purchases
of Investment Securities
|
(8,153
|
)
|
(4,319
|
)
|
|||
Sales
of Investment Securities
|
8,056
|
4,378
|
|||||
Proceeds
from Sales of Assets
|
120
|
1,599
|
|||||
Other
|
(72
|
)
|
11
|
||||
Net
Cash Flows Used For Investing Activities
|
(2,474
|
)
|
(60
|
)
|
|||
FINANCING
ACTIVITIES
|
|||||||
Issuance
of Common Stock
|
24
|
393
|
|||||
Repurchase
of Common Stock
|
-
|
(427
|
)
|
||||
Change
in Short-term Debt, Net
|
11
|
(8
|
)
|
||||
Issuance
of Long-term Debt
|
1,229
|
2,045
|
|||||
Retirement
of Long-term Debt
|
(711
|
)
|
(2,599
|
)
|
|||
Dividends
Paid on Common Stock
|
(437
|
)
|
(408
|
)
|
|||
Other
|
3
|
(106
|
)
|
||||
Net
Cash Flows From (Used For) Financing Activities
|
119
|
(1,110
|
)
|
||||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
(142
|
)
|
529
|
||||
Cash
and Cash Equivalents at Beginning of Period
|
401
|
320
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
259
|
$
|
849
|
|||
SUPPLEMENTARY
INFORMATION
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
462
|
$
|
492
|
|||
Net
Cash Paid for Income Taxes
|
206
|
277
|
|||||
Noncash
Acquisitions Under Capital Leases
|
66
|
42
|
|||||
Construction
Expenditures Included in Accounts Payable at September 30,
|
334
|
182
|
|||||
Disposition
of Liabilities Related to Acquisitions/Divestitures, Net
|
-
|
20
|
Common
Stock
|
Accumulated
|
||||||||||||||||||
Shares
|
Amount
|
Paid-in
Capital
|
Retained
Earnings
|
Other
Comprehensive Income (Loss)
|
Total
|
||||||||||||||
DECEMBER
31, 2004
|
405
|
$
|
2,632
|
$
|
4,203
|
$
|
2,024
|
$
|
(344
|
)
|
$
|
8,515
|
|||||||
Issuance
of Common Stock
|
10
|
65
|
328
|
393
|
|||||||||||||||
Common
Stock Dividends
|
(408
|
)
|
(408
|
)
|
|||||||||||||||
Repurchase
of Common Stock
|
(427
|
)
|
(427
|
)
|
|||||||||||||||
Other
|
17
|
17
|
|||||||||||||||||
TOTAL
|
8,090
|
||||||||||||||||||
COMPREHENSIVE INCOME
|
|||||||||||||||||||
Other Comprehensive
Income (Loss), Net of Tax:
|
|||||||||||||||||||
Foreign
Currency Translation Adjustments,
Net of Tax of $0
|
(6
|
)
|
(6
|
)
|
|||||||||||||||
Cash
Flow Hedges, Net of Tax of $36
|
(67
|
)
|
(67
|
)
|
|||||||||||||||
Minimum
Pension Liability, Net of Tax of $0
|
4
|
4
|
|||||||||||||||||
Securities
Available for Sale, Net of Tax of $0
|
1
|
1
|
|||||||||||||||||
NET
INCOME
|
963
|
963
|
|||||||||||||||||
TOTAL COMPREHENSIVE INCOME
|
895
|
||||||||||||||||||
SEPTEMBER
30, 2005
|
415
|
$
|
2,697
|
$
|
4,121
|
$
|
2,579
|
$
|
(412
|
)
|
$
|
8,985
|
|||||||
DECEMBER
31, 2005
|
415
|
$
|
2,699
|
$
|
4,131
|
$
|
2,285
|
$
|
(27
|
)
|
$
|
9,088
|
|||||||
Issuance
of Common Stock
|
1
|
5
|
19
|
24
|
|||||||||||||||
Common
Stock Dividends
|
(437
|
)
|
(437
|
)
|
|||||||||||||||
Other
|
3
|
3
|
|||||||||||||||||
TOTAL
|
8,678
|
||||||||||||||||||
COMPREHENSIVE INCOME
|
|||||||||||||||||||
Other Comprehensive Income, Net of Tax:
|
|||||||||||||||||||
Cash
Flow Hedges, Net of Tax of $10
|
18
|
18
|
|||||||||||||||||
Securities
Available for Sale, Net of Tax of $4
|
8
|
8
|
|||||||||||||||||
NET
INCOME
|
821
|
821
|
|||||||||||||||||
TOTAL COMPREHENSIVE INCOME
|
847
|
||||||||||||||||||
SEPTEMBER
30, 2006
|
416
|
$
|
2,704
|
$
|
4,153
|
$
|
2,669
|
$
|
(1
|
)
|
$
|
9,525
|
1.
|
Significant
Accounting Matters
|
|
2.
|
New
Accounting Pronouncements
|
|
3.
|
Rate
Matters
|
|
4.
|
Customer
Choice and Industry Restructuring
|
|
5.
|
Commitments
and Contingencies
|
|
6.
|
Guarantees
|
|
7.
|
Company-wide
Staffing and Budget Review
|
|
8.
|
Acquisitions,
Dispositions, Discontinued Operations, Assets Held for Sale and Asset
Impairments
|
|
9.
|
Benefit
Plans
|
|
10.
|
Stock-Based
Compensation
|
|
11.
|
Income
Taxes
|
|
12.
|
Business
Segments
|
|
13.
|
Financing
Activities
|
September
30,
|
December
31,
|
||||||
2006
|
2005
|
||||||
Components
|
(in
millions)
|
||||||
Securities
Available for Sale, Net of Tax
|
$
|
27
|
$
|
19
|
|||
Cash
Flow Hedges, Net of Tax
|
(9
|
)
|
(27
|
)
|
|||
Minimum
Pension Liability, Net of Tax
|
(19
|
)
|
(19
|
)
|
|||
Total
|
$
|
(1
|
)
|
$
|
(27
|
)
|
Three
Months
Ended
|
Nine
Months
Ended
|
||||||
(in
millions, except per share data)
|
|||||||
Net
Income, As Reported
|
$
|
387
|
$
|
963
|
|||
Add:
Stock-based Compensation Expense Included in Reported Net Income, Net
of Related Tax Effects
|
4
|
10
|
|||||
Deduct:
Stock-based Compensation Expense Determined Under Fair Value Based
Method for All Awards,
Net of Related Tax Effects
|
(5
|
)
|
(11
|
)
|
|||
Pro
Forma Net Income
|
$
|
386
|
$
|
962
|
|||
Earnings
Per Share:
|
|||||||
Basic
- As Reported
|
$
|
0.99
|
$
|
2.48
|
|||
Basic
- Pro Forma (a)
|
$
|
0.99
|
$
|
2.48
|
|||
Diluted
- As Reported
|
$
|
0.99
|
$
|
2.47
|
|||
Diluted
- Pro Forma (a)
|
$
|
0.99
|
$
|
2.47
|
(a)
|
The
pro forma amounts are not representative of the effects on reported
net
income for future years.
|
Three
Months Ended September 30,
|
|||||||||||||
2006
|
2005
|
||||||||||||
(in
millions, except per share data)
|
|||||||||||||
$/share
|
$/share
|
||||||||||||
Earnings
applicable to common stock
|
$
|
265
|
$
|
387
|
|||||||||
Average
number of basic shares outstanding
|
393.9
|
$
|
0.67
|
388.9
|
$
|
0.99
|
|||||||
Average
dilutive effect of:
|
|||||||||||||
Performance
Share Units
|
2.0
|
-
|
1.0
|
-
|
|||||||||
Stock
Options
|
0.2
|
-
|
0.5
|
-
|
|||||||||
Restricted
Stock Units
|
0.1
|
-
|
0.1
|
-
|
|||||||||
Restricted
Shares
|
0.1
|
-
|
-
|
-
|
|||||||||
Average
number of diluted shares outstanding
|
396.3
|
$
|
0.67
|
390.5
|
$
|
0.99
|
Nine
Months Ended September 30,
|
|||||||||||||
2006
|
2005
|
||||||||||||
(in
millions, except per share data)
|
|||||||||||||
$/share
|
$/share
|
||||||||||||
Earnings
applicable to common stock
|
$
|
821
|
$
|
963
|
|||||||||
Average
number of basic shares outstanding
|
393.8
|
$
|
2.08
|
388.7
|
$
|
2.48
|
|||||||
Average
dilutive effect of:
|
|||||||||||||
Performance
Share Units
|
1.6
|
(0.01
|
)
|
0.9
|
(0.01
|
)
|
|||||||
Stock
Options
|
0.2
|
-
|
0.3
|
-
|
|||||||||
Restricted
Stock Units
|
0.1
|
-
|
0.1
|
-
|
|||||||||
Restricted
Shares
|
0.1
|
-
|
-
|
-
|
|||||||||
Average
number of diluted shares outstanding
|
395.8
|
$
|
2.07
|
390.0
|
$
|
2.47
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(in
millions)
|
|||||||||||||
AEP
Consolidated Purchased Energy:
|
|||||||||||||
Ohio
Valley Electric Corporation (43.47% Owned)
|
$
|
54
|
$
|
49
|
$
|
167
|
$
|
140
|
|||||
Sweeny
Cogeneration Limited Partnership (50% Owned)
|
30
|
38
|
92
|
98
|
|||||||||
AEP
Consolidated Other Revenues - Barging and Other Transportation
Services - Ohio Valley Electric Corporation (43.47%
Owned)
|
8
|
6
|
23
|
14
|
·
|
A
$56 million increase in Expanded Net Energy Cost (ENEC) for fuel,
purchased power expenses, off system sales credits and other energy
related costs;
|
·
|
A
$23 million special construction surcharge providing recovery of
the costs
of scrubbers and the new Wyoming-Jacksons Ferry 765 kV line to
date;
|
·
|
An
$18 million general base rate reduction resulting predominantly from
a
reduction in the return on equity to 10.5% and a $9 million reduction
in
depreciation expense which affects cash flows but not earnings;
and
|
·
|
A
$17 million credit to refund a portion of deferred prior over-recoveries
of ENEC of $51 million, recorded in regulatory liabilities on the
Condensed Consolidated Balance Sheets, which will impact cash flows
but
not earnings.
|
(in
millions)
|
||||
Three
Months Ended September 30, 2006
|
$
|
-
|
||
Three
Months Ended September 30, 2005
|
43
|
|||
Nine
Months Ended September 30, 2006 (a)
|
43
|
|||
Nine
Months Ended September 30, 2005
|
120
|
(a)
|
Represents
revenues through March 31, 2006, when SECA rates expired, and excludes
all
provisions for refund.
|
·
|
AEP/AP
proposed a Highway/Byway rate design in which:
|
|
|
·
|
The
cost of all transmission facilities in the PJM region operated
at 345 kV
or higher would be included in a “Highway” rate that all load serving
entities (LSEs) would pay based on peak demand. The AEP/AP proposal
would
produce about $125 million in additional revenues per year for
AEP from
users in other zones of PJM.
|
|
·
|
The
cost of transmission facilities operating at lower voltages would
be
collected in the zones where those costs are presently charged
under PJM’s
existing rate design.
|
·
|
Two
other utilities, Baltimore Gas & Electric Company (BG&E) and Old
Dominion Electric Cooperative (ODEC), proposed a Highway/Byway
rate that
includes transmission facilities above 200 kV, which would produce
lower
revenues than the AEP/AP proposal.
|
|
·
|
In
a competing Highway/Byway proposal, a group of LSEs proposed
rates that
would include existing 500 kV and higher voltage facilities and
new
facilities above 200 kV in the Highway rate, which would produce
considerably lower revenues than the AEP/AP proposal.
|
|
·
|
In
January 2006, the FERC staff issued testimony and exhibits supporting
a
PJM-wide flat rate or “Postage Stamp” type of rate design that would
include all transmission facilities, which would produce higher
transmission revenues than the AEP/AP
proposal.
|
·
|
In
Kentucky, KPCo settled a rate case, which provided for the recovery
of its
share of the transmission revenue reduction in new rates effective
March
30, 2006.
|
·
|
In
Ohio, CSPCo and OPCo recover the FERC-approved OATT which reflects
their
share of the full transmission revenue requirement retroactive to
April 1,
2006 under a May 2006 PUCO order.
|
·
|
In
West Virginia, APCo settled a rate case, which provided for the recovery
of its share of the T&O/SECA transmission revenue reduction beginning
July 28, 2006.
|
·
|
In
Virginia, APCo filed a request for revised rates, which includes
recovery
of its share of the T&O/SECA transmission revenue reduction starting
October 2, 2006, subject to refund.
|
·
|
In
Indiana, I&M is precluded by a rate cap from raising its rates until
July 1, 2007.
|
·
|
In
Michigan, I&M has not yet filed to seek recovery of the lost
transmission revenues.
|
(in
millions)
|
||||
Stranded
Generation Plant Costs
|
$
|
974
|
||
Net
Generation-related Regulatory Asset
|
249
|
|||
Excess
Earnings
|
(49
|
)
|
||
Recorded
Net Stranded Generation Plant Costs
|
1,174
|
|||
Recorded
Debt Carrying Costs on Net Stranded Generation Plant Costs
|
400
|
|||
Recorded
Securitizable True-up Regulatory Asset
|
1,574
|
|||
Unrecorded
But Recoverable Equity Carrying Costs
|
224
|
|||
Unrecorded
Estimated October 2006 Debt Carrying Costs
|
3
|
|||
Unrecorded
Excess Earnings, Related Carrying Costs and Other
|
53
|
|||
Unrecorded
Settlement Reduction
|
(77
|
)
|
||
Reduction
for the Present Value of ADITC and EDFIT Benefits
|
(61
|
)
|
||
Approved
Securitizable Amount as of October 11, 2006
|
1,716
|
|||
Unrecorded
Securitization Bond Issuance Costs
|
24
|
|||
Amount
Securitized on October 11, 2006
|
$
|
1,740
|
(in
millions)
|
||||
Wholesale
Capacity Auction True-up
|
$
|
61
|
||
Carrying
Costs on Wholesale Capacity Auction True-up
|
31
|
|||
Retail
Clawback including Carrying Costs
|
(65
|
)
|
||
Deferred
Over-recovered Fuel Balance
|
(184
|
)
|
||
Retrospective
ADFIT Benefit
|
(77
|
)
|
||
Other
|
(4
|
)
|
||
Recorded
Net Regulatory Liabilities - Other True-up Items
|
(238
|
)
|
||
Unrecorded
Prospective ADFIT Benefit
|
(240
|
)
|
||
Gross
CTC Refund Proposed
|
(478
|
)
|
||
FERC
Jurisdictional Fuel Refund Deferral
|
16
|
|||
ADITC
and EDFIT Benefit Refund Deferral
|
98
|
|||
Net
CTC Refund Proposed, After Deferrals
|
(364
|
)
|
||
True-up
Proceeding Expense Surcharge
|
7
|
|||
Net
CTC Refund Proposed, After Deferrals and Expenses
|
$
|
(357
|
)
|
Amount
(in
millions)
|
||||
Accrual
at December 31, 2005
|
$
|
12
|
||
Less:
Total Payments
|
8
|
|||
Less:
Accrual Adjustments
|
4
|
|||
Accrual
at September 30, 2006
|
$
|
-
|
Three
Months ended September 30, 2006 and 2005:
|
||||||||||
SEEBOARD
(a)
|
U.K.
Generation (b)
|
Total
|
||||||||
2006
Revenue
|
$
|
-
|
$
|
-
|
$
|
-
|
||||
2006
Pretax Income
|
-
|
-
|
-
|
|||||||
2006
Earnings, Net of Tax
|
-
|
-
|
-
|
|||||||
2005
Revenue
|
$
|
13
|
$
|
-
|
$
|
13
|
||||
2005
Pretax Income
|
13
|
-
|
13
|
|||||||
2005
Earnings, Net of Tax
|
20
|
2
|
22
|
|||||||
Nine Months
ended September 30, 2006 and 2005:
|
||||||||||
|
SEEBOARD (a) |
U.K.
Generation(c)
|
|
Total
|
||||||
2006
Revenue
|
$
|
-
|
$
|
-
|
$
|
-
|
||||
2006
Pretax Income
|
-
|
9
|
9
|
|||||||
2006
Earnings, Net of Tax
|
-
|
6
|
6
|
|||||||
2005
Revenue (Expense)
|
$
|
13
|
$
|
(8
|
)
|
$
|
5
|
|
||
2005
Pretax Income (Loss)
|
13
|
(8
|
)
|
5
|
|
|||||
2005
Earnings (Loss), Net of Tax
|
29
|
(3
|
)
|
26
|
(a)
|
The
amounts relate to purchase price true-up adjustments and tax adjustments
from the sale of SEEBOARD.
|
(b)
|
The
amount relates to a tax adjustment from the sale.
|
(c)
|
The
2006 amounts relate to a release of accrued liabilities for the London
office lease and tax adjustments from the sale. Amounts in 2005 relate
to
purchase price true-up adjustments and tax adjustments from the
sale.
|
September
30, 2006
|
Texas
Plants
|
Power
Generation Facility
|
Total
|
|||||||
Assets:
|
(in
millions)
|
|||||||||
Other
Current Assets
|
$
|
2
|
$
|
-
|
$
|
2
|
||||
Property,
Plant and Equipment, Net
|
44
|
64
|
108
|
|||||||
Total
Assets Held for Sale
|
$
|
46
|
$
|
64
|
$
|
110
|
December
31, 2005
|
Texas
Plants
|
|||
Assets:
|
(in
millions)
|
|||
Other
Current Assets
|
$
|
1
|
||
Property,
Plant and Equipment, Net
|
43
|
|||
Total
Assets Held for Sale
|
$
|
44
|
Pension
Plans
|
Other
Postretirement
Benefit
Plans
|
||||||||||||
Three
Months Ended September 30, 2006 and 2005:
|
2006
|
2005
|
2006
|
2005
|
|||||||||
(in
millions)
|
|||||||||||||
Service
Cost
|
$
|
23
|
$
|
23
|
$
|
10
|
$
|
10
|
|||||
Interest
Cost
|
57
|
57
|
26
|
26
|
|||||||||
Expected
Return on Plan Assets
|
(82
|
)
|
(77
|
)
|
(24
|
)
|
(23
|
)
|
|||||
Amortization
of Transition (Asset) Obligation
|
-
|
(1
|
)
|
7
|
6
|
||||||||
Amortization
of Net Actuarial Loss
|
20
|
13
|
5
|
5
|
|||||||||
Net
Periodic Benefit Cost
|
$
|
18
|
$
|
15
|
$
|
24
|
$
|
24
|
Pension
Plans
|
Other
Postretirement
Benefit
Plans
|
||||||||||||
Nine
Months Ended September 30, 2006 and 2005:
|
2006
|
2005
|
2006
|
2005
|
|||||||||
(in
millions)
|
|||||||||||||
Service
Cost
|
$
|
71
|
$
|
69
|
$
|
30
|
$
|
31
|
|||||
Interest
Cost
|
171
|
169
|
76
|
79
|
|||||||||
Expected
Return on Plan Assets
|
(248
|
)
|
(232
|
)
|
(70
|
)
|
(68
|
)
|
|||||
Amortization
of Transition (Asset) Obligation
|
-
|
(1
|
)
|
21
|
20
|
||||||||
Amortization
of Net Actuarial Loss
|
59
|
40
|
15
|
19
|
|||||||||
Net
Periodic Benefit Cost
|
$
|
53
|
$
|
45
|
$
|
72
|
$
|
81
|
Options
|
Weighted
Average Exercise Price
|
||||||
(in
thousands)
|
|||||||
Outstanding
at January 1, 2006
|
6,222
|
$
|
34.16
|
||||
Granted
|
-
|
-
|
|||||
Exercised/Converted
|
(369
|
)
|
30.17
|
||||
Expired
|
-
|
-
|
|||||
Forfeited
|
(209
|
)
|
41.62
|
||||
Outstanding
at September 30, 2006
|
5,644
|
34.15
|
|||||
Exercisable
at September 30, 2006
|
5,384
|
$
|
34.41
|
2006
Range of
Exercise
Prices
|
Number
Exercisable
|
Weighted
Average
Remaining
Life
|
Weighted
Average
Exercise
Price
|
Aggregate
Intrinsic
Value
|
|||||||||
(in
thousands)
|
(in
years)
|
(in
thousands)
|
|||||||||||
$25.73
- $27.95
|
1,359
|
5.9
|
$
|
27.38
|
$
|
12,220
|
|||||||
$30.76
- $38.65
|
3,917
|
3.2
|
35.44
|
3,665
|
|||||||||
$43.79
- $49.00
|
368
|
4.6
|
45.43
|
-
|
|||||||||
5,644
|
4.0
|
34.15
|
$
|
15,885
|
2006
Range of
Exercise
Prices
|
Number
Exercisable
|
Weighted
Average
Remaining
Life
|
Weighted
Average
Exercise
Price
|
Aggregate
Intrinsic
Value
|
|||||||||
(in
thousands)
|
(in
years)
|
(in
thousands)
|
|||||||||||
$25.73
- $27.95
|
1,158
|
5.7
|
$
|
27.29
|
$
|
10,519
|
|||||||
$30.76
- $35.63
|
3,858
|
3.2
|
35.49
|
3,386
|
|||||||||
$43.79
- $49.00
|
368
|
4.6
|
45.43
|
-
|
|||||||||
5,384
|
3.8
|
34.41
|
$
|
13,905
|
Performance
Units
|
||||
Awarded
Units (in thousands)
|
864
|
|||
Unit
Fair Value at Grant Date
|
$
|
37.36
|
||
Vesting
Period (years)
|
3
|
Performance
Units and AEP Career Shares
(Reinvested
Dividends Portion)
|
||||
Awarded
Units (in thousands)
|
91
|
|||
Weighted
Average Grant Date Fair Value
|
$
|
35.37
|
||
Vesting
Period (years) (a)
|
3
|
(a)
|
Vesting
Period (years) range from 0 to 3 years. The Vesting Period of the
reinvested dividends is equal to the remaining life of the related
performance units and AEP Career
Shares.
|
Nonvested
Restricted Shares and Restricted Stock Units
|
Shares/Units
|
Weighted
Average Grant Date Fair Value
|
|||||
|
(in
thousands)
|
||||||
Nonvested
at January 1, 2006
|
497
|
$
|
32.19
|
||||
Granted
|
47
|
35.58
|
|||||
Vested
|
(127
|
)
|
30.56
|
||||
Forfeited
|
(22
|
)
|
35.52
|
||||
Nonvested
at September 30, 2006
|
395
|
32.93
|
Share-based
Compensation Plans
|
(in
thousands)
|
|||
Compensation
Cost for Share-based Payment Arrangements (a)
|
$
|
16,671
|
||
Actual
Tax Benefit Realized
|
5,835
|
|||
Total
Compensation Cost Capitalized
|
3,746
|
(a)
|
Compensation
cost for share-based payment arrangements is included in Maintenance
and
Other Operation on our Condensed Consolidated Statements of
Operations.
|
·
|
Generation
of electricity for sale to U.S. retail and wholesale
customers.
|
·
|
Electricity
transmission and distribution in the
U.S.
|
·
|
Gas
pipeline and storage services.
|
·
|
Gas
marketing and risk management activities.
|
·
|
We
disposed of our gas pipeline and storage assets in 2005 with the
sale of
HPL (see “Dispositions” section of Note
8).
|
·
|
International
generation of electricity for sale to wholesale
customers.
|
·
|
Coal
procurement and transportation to our plants.
|
·
|
We
classified UK Operations as Discontinued Operations during 2003 and
sold
them in 2004.
|
·
|
Bulk
commodity barging operations, wind farms, IPPs and other energy
supply-related businesses.
|
Investments
|
||||||||||||||||||||||
Utility
Operations
|
Gas
Operations
|
UK
Operations
|
Other
|
All
Other (a)
|
Reconciling
Adjustments
|
Consolidated
|
||||||||||||||||
(in
millions)
|
||||||||||||||||||||||
Three
Months Ended
|
||||||||||||||||||||||
September
30, 2006
|
||||||||||||||||||||||
Revenues
from:
|
||||||||||||||||||||||
External
Customers
|
$
|
3,485
|
$
|
(47
|
)
|
$
|
-
|
$
|
156
|
$
|
-
|
$
|
-
|
$
|
3,594
|
|||||||
Other
Operating Segments
|
(44
|
)
|
51
|
-
|
4
|
1
|
(12
|
)
|
-
|
|||||||||||||
Total
Revenues
|
$
|
3,441
|
$
|
4
|
$
|
-
|
$
|
160
|
$
|
1
|
$
|
(12
|
)
|
$
|
3,594
|
|||||||
Net
Income (Loss)
|
$
|
379
|
$
|
(3
|
)
|
$
|
-
|
$
|
(109
|
)
|
$
|
(2
|
)
|
$
|
-
|
$
|
265
|
Investments
|
||||||||||||||||||||||
Utility
Operations
|
Gas
Operations
|
UK
Operations
|
Other
|
All
Other (a)
|
Reconciling
Adjustments
|
Consolidated
|
||||||||||||||||
(in
millions)
|
||||||||||||||||||||||
Three
Months Ended
|
||||||||||||||||||||||
September
30, 2005
|
||||||||||||||||||||||
Revenues
from:
|
||||||||||||||||||||||
External
Customers
|
$
|
3,152
|
$
|
73
|
|
$
|
-
|
$
|
103
|
$
|
-
|
$
|
-
|
$
|
3,328
|
|||||||
Other
Operating Segments
|
85
|
(77
|
)
|
-
|
3
|
1
|
(12
|
)
|
-
|
|||||||||||||
Total
Revenues
|
$
|
3,237
|
$
|
(4
|
)
|
$
|
-
|
$
|
106
|
$
|
1
|
$
|
(12
|
)
|
$
|
3,328
|
||||||
Income
(Loss) Before Discontinued
Operations
|
$
|
352
|
$
|
(10
|
)
|
$
|
-
|
$
|
28
|
$
|
(5
|
)
|
$
|
-
|
$
|
365
|
||||||
Discontinued
Operations, Net of Tax
|
-
|
-
|
2
|
20
|
-
|
-
|
22
|
|||||||||||||||
Net
Income (Loss)
|
$
|
352
|
$
|
(10
|
)
|
$
|
2
|
$
|
48
|
$
|
(5
|
)
|
$
|
-
|
$
|
387
|
Investments
|
||||||||||||||||||||||
Utility
Operations
|
Gas
Operations
|
UK
Operations
|
Other
|
All
Other (a)
|
Reconciling
Adjustments
|
Consolidated
|
||||||||||||||||
(in
millions)
|
||||||||||||||||||||||
Nine
Months Ended
|
||||||||||||||||||||||
September
30, 2006
|
||||||||||||||||||||||
Revenues
from:
|
||||||||||||||||||||||
External
Customers
|
$
|
9,282
|
$
|
(80
|
)
|
$
|
-
|
$
|
436
|
$
|
-
|
$
|
-
|
$
|
9,638
|
|||||||
Other
Operating Segments
|
(73
|
)
|
89
|
-
|
9
|
2
|
(27
|
)
|
-
|
|||||||||||||
Total
Revenues
|
$
|
9,209
|
$
|
9
|
$
|
-
|
$
|
445
|
$
|
2
|
$
|
(27
|
)
|
$
|
9,638
|
|||||||
Income
(Loss) Before Discontinued
Operations
|
$
|
904
|
$
|
(2
|
)
|
$
|
-
|
$
|
(80
|
)
|
$
|
(7
|
)
|
$
|
-
|
$
|
815
|
|||||
Discontinued
Operations, Net of Tax
|
-
|
-
|
6
|
-
|
-
|
-
|
6
|
|||||||||||||||
Net
Income (Loss)
|
$
|
904
|
$
|
(2
|
)
|
$
|
6
|
$
|
(80
|
)
|
$
|
(7
|
)
|
$
|
-
|
$
|
821
|
Investments
|
||||||||||||||||||||||
Utility
Operations
|
Gas
Operations
|
UK
Operations
|
Other
|
All
Other (a)
|
Reconciling
Adjustments
|
Consolidated
|
||||||||||||||||
(in
millions)
|
||||||||||||||||||||||
Nine
Months Ended
|
||||||||||||||||||||||
September
30, 2005
|
||||||||||||||||||||||
Revenues
from:
|
||||||||||||||||||||||
External
Customers
|
$
|
8,437
|
$
|
449
|
$
|
-
|
$
|
326
|
$
|
-
|
$
|
-
|
$
|
9,212
|
||||||||
Other
Operating Segments
|
186
|
(167
|
)
|
-
|
12
|
2
|
(33
|
)
|
-
|
|||||||||||||
Total
Revenues
|
$
|
8,623
|
$
|
282
|
$
|
-
|
$
|
338
|
$
|
2
|
$
|
(33
|
)
|
$
|
9,212
|
|||||||
Income
(Loss) Before Discontinued Operations
|
$
|
952
|
$
|
(2
|
)
|
$
|
-
|
$
|
32
|
$
|
(45
|
)
|
$
|
-
|
$
|
937
|
||||||
Discontinued
Operations, Net of Tax
|
-
|
-
|
(3
|
)
|
29
|
-
|
-
|
26
|
||||||||||||||
Net
Income (Loss)
|
$
|
952
|
$
|
(2
|
)
|
$
|
(3
|
)
|
$
|
61
|
$
|
(45
|
)
|
$
|
-
|
$
|
963
|
Investments
|
|
|||||||||||||||||||||||||||
Utility
Operations
|
Gas
Operations
|
|
|
UK
Operations
|
|
|
Other
|
All
Other (b)
|
Reconciling
Adjustments (b)
|
Consolidated
|
||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||||||
As
of September 30, 2006
|
||||||||||||||||||||||||||||
Total
Property, Plant and Equipment
|
$
|
40,397
|
$
|
1
|
$
|
-
|
$
|
567
|
$
|
3
|
$
|
-
|
$
|
40,968
|
||||||||||||||
Accumulated
Depreciation and Amortization
|
15,014
|
-
|
-
|
130
|
2
|
-
|
15,146
|
|||||||||||||||||||||
Total
Property, Plant and Equipment - Net
|
|
$
|
25,383
|
$
|
1
|
$
|
-
|
$
|
437
|
$
|
1
|
$
|
-
|
$
|
25,822
|
|||||||||||||
Total
Assets
|
$
|
35,185
|
$
|
591
|
(c) |
$
|
639
|
(d) |
$
|
72
|
$
|
10,372
|
$
|
(10,474
|
)
|
$
|
36,385
|
|||||||||||
Assets
Held for Sale
|
46
|
-
|
-
|
64
|
-
|
-
|
110
|
Investments
|
|
|||||||||||||||||||||||||||
Utility
Operations
|
Gas
Operations
|
|
|
UK
Operations
|
|
|
Other
|
All
Other (b)
|
Reconciling
Adjustments (b)
|
Consolidated
|
||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||||||
As
of December 31, 2005
|
||||||||||||||||||||||||||||
Total
Property, Plant and Equipment
|
$
|
38,283
|
$
|
2
|
$
|
-
|
$
|
833
|
$
|
3
|
$
|
-
|
$
|
39,121
|
||||||||||||||
Accumulated
Depreciation and Amortization
|
14,723
|
1
|
-
|
112
|
1
|
-
|
14,837
|
|||||||||||||||||||||
Total
Property, Plant and Equipment - Net
|
|
$
|
23,560
|
$
|
1
|
$
|
-
|
$
|
721
|
$
|
2
|
$
|
-
|
$
|
24,284
|
|||||||||||||
Total
Assets
|
$
|
34,339
|
$
|
1,199
|
(e) |
$
|
632
|
(f) |
$
|
509
|
$
|
9,463
|
$
|
(9,970
|
)
|
$
|
36,172
|
|||||||||||
Assets
Held for Sale
|
44
|
-
|
-
|
-
|
-
|
-
|
44
|
(a)
|
All
Other includes the parent company’s guarantee revenue, interest income and
expense, as well as other nonallocated costs.
|
(b)
|
Reconciling
Adjustments for Total Assets primarily include the elimination of
intercompany advances to affiliates and intercompany accounts receivable
along with the elimination of AEP’s investments (included in All Other) in
subsidiary companies.
|
(c)
|
Total
Assets of $591 million for the Investments-Gas Operations segment
include
$321 million in affiliated accounts receivable related to the corporate
borrowing program and risk management contracts that are eliminated
in
consolidation. The majority of the remaining $270 million in assets
represents third party risk management contracts, margin deposits
and
accounts receivable.
|
(d)
|
Total
Assets of $639 million for the Investments-UK Operations segment
include
$625 million in affiliated accounts receivable related mainly to
federal
income taxes that are eliminated in consolidation. The majority of
the
remaining $14 million in assets represents cash
equivalents.
|
(e)
|
Total
Assets of $1.2 billion for the Investments-Gas Operations segment
include
$429 million in affiliated accounts receivable related to the corporate
borrowing program and risk management contracts that are eliminated
in
consolidation. The majority of the remaining $770 million in assets
represents third party risk management contracts, margin deposits,
and
accounts receivable.
|
(f)
|
Total
Assets of $632 million for the Investments-UK Operations segment
include
$613 million in affiliated accounts receivable related to federal
income
taxes that are eliminated in consolidation. The majority of the remaining
$19 million in assets represents cash equivalents and value-added
tax
receivables.
|
September
30,
|
December
31,
|
||||||
Type
of Debt
|
2006
|
2005
|
|||||
(in
millions)
|
|||||||
Pollution
Control Bonds
|
$
|
2,051
|
$
|
1,935
|
|||
Senior
Unsecured Notes
|
8,827
|
8,226
|
|||||
First
Mortgage Bonds
|
96
|
196
|
|||||
Defeased
First Mortgage Bonds (a)
|
26
|
26
|
|||||
Notes
Payable
|
872
|
904
|
|||||
Securitization
Bonds
|
596
|
648
|
|||||
Notes
Payable To Trust
|
113
|
113
|
|||||
Other
Long-Term Debt (b)
|
247
|
236
|
|||||
Unamortized
Discount (net)
|
(65
|
)
|
(58
|
)
|
|||
Total
Long-term Debt Outstanding
|
12,763
|
12,226
|
|||||
Less
Portion Due Within One Year
|
1,789
|
1,153
|
|||||
Long-term
Portion
|
$
|
10,974
|
$
|
11,073
|
(a)
|
In
May 2004, we deposited cash and treasury securities with a trustee
to
defease all of TCC’s outstanding First Mortgage Bonds. The defeased TCC
First Mortgage Bonds had a balance of $18 million at both September
30,
2006 and December 31, 2005. Trust fund assets related to this obligation
of $2 million are included in Other Temporary Cash Investments at
both
September 30, 2006 and December 31, 2005 and $21 million is included
in
Other Noncurrent Assets in the Condensed Consolidated Balance Sheets
at
both September 30, 2006 and December 31, 2005. In December 2005,
we
deposited cash and treasury securities with a trustee to defease
the
remaining TNC outstanding First Mortgage Bond. The defeased TNC First
Mortgage Bond had a balance of $8 million at both September 30, 2006
and
December 31, 2005. Trust fund assets related to this obligation of
$9
million and $1 million at September 30, 2006 and December 31, 2005,
respectively, are included in Other Temporary Cash Investments and
$0 and
$8 million are included in Other Noncurrent Assets in the Condensed
Consolidated Balance Sheets at September 30, 2006 and December 31,
2005,
respectively. Trust fund assets are restricted for exclusive use
in
funding the interest and principal due on the First Mortgage
Bonds.
|
(b)
|
Pursuant
to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has
an obligation with the United States Department of Energy for spent
nuclear fuel disposal. The obligation includes a one-time fee for
nuclear
fuel consumed prior to April 7, 1983. Trust fund assets of $270 million
and $264 million related to this obligation are included in Spent
Nuclear
Fuel and Decommissioning Trusts in the Condensed Consolidated Balance
Sheets at September 30, 2006 and December 31, 2005,
respectively.
|
Company
|
Type
of Debt
|
Principal
Amount
|
Interest
Rate
|
Due
Date
|
||||||
(in
millions)
|
(%)
|
|||||||||
Issuances:
|
||||||||||
APCo
|
Pollution
Control Bonds
|
$
|
50
|
Variable
|
2036
|
|||||
APCo
|
Senior
Unsecured Notes
|
250
|
5.55
|
2011
|
||||||
APCo
|
Senior
Unsecured Notes
|
250
|
6.375
|
2036
|
||||||
I&M
|
Pollution
Control Bonds
|
50
|
Variable
|
2025
|
||||||
OPCo
|
Pollution
Control Bonds
|
65
|
Variable
|
2036
|
||||||
OPCo
|
Senior
Unsecured Notes
|
350
|
6.00
|
2016
|
||||||
PSO
|
Senior
Unsecured Notes
|
150
|
6.15
|
2016
|
||||||
SWEPCo
|
Pollution
Control Bonds
|
82
|
Variable
|
2018
|
||||||
Total
Issuances
|
$
|
1,247
|
(a)
|
(a)
|
Amount
indicated on statement of cash flows of $1,229 million is net of
issuance
costs and unamortized premium or
discount.
|
Company
|
Type
of Debt
|
Principal
Amount Paid
|
Interest
Rate
|
Due
Date
|
||||||
(in
millions)
|
(%)
|
|||||||||
Retirements
and Principal Payments:
|
||||||||||
AEP
|
Senior
Unsecured Notes
|
$
|
396
|
6.125
|
2006
|
|||||
APCo
|
First
Mortgage Bonds
|
100
|
6.80
|
2006
|
||||||
I&M
|
Pollution
Control Bonds
|
50
|
6.55
|
2025
|
||||||
OPCo
|
Notes
Payable
|
4
|
6.81
|
2008
|
||||||
OPCo
|
Notes
Payable
|
7
|
6.27
|
2009
|
||||||
SWEPCo
|
Notes
Payable
|
5
|
4.47
|
2011
|
||||||
SWEPCo
|
Notes
Payable
|
2
|
Variable
|
2008
|
||||||
SWEPCo
|
Pollution
Control Bonds
|
82
|
6.10
|
2018
|
||||||
TCC
|
Securitization
Bonds
|
52
|
5.01
|
2010
|
||||||
Non-Registrant:
|
||||||||||
AEP
subsidiaries
|
Notes
Payable
|
9
|
Variable
|
2017
|
||||||
CSW
Energy, Inc.
|
Notes
Payable
|
4
|
5.88
|
2011
|
||||||
Total
Retirements and Principal
Payments
|
$
|
711
|
Principal
|
Interest
|
Scheduled
Final
|
|||
Amount
|
Rate
|
Payment
Date
|
|||
(in
millions)
|
(%)
|
||||
$
|
217
|
4.98
|
2010
|
||
341
|
4.98
|
2013
|
|||
250
|
5.09
|
2015
|
|||
437
|
5.17
|
2018
|
|||
495
|
5.3063
|
2020
|
Third
Quarter of 2005
|
$
|
2.2
|
|||||
Change
in Gross Margin:
|
|||||||
Wholesale
Sales
|
0.2
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(0.7
|
)
|
|||||
Taxes
Other Than Income Taxes
|
0.7
|
||||||
Interest
Expense
|
(0.1
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(0.1
|
)
|
|||||
Income
Tax Expense
|
(0.1
|
)
|
|||||
Third
Quarter of 2006
|
$
|
2.2
|
Nine
Months Ended September 30, 2005
|
$
|
6.8
|
|||||
Changes
in Gross Margin:
|
|||||||
Wholesale
Sales
|
3.2
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(2.0
|
)
|
|||||
Taxes
Other Than Income Taxes
|
0.7
|
||||||
Interest
Expense
|
(0.3
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(1.6
|
)
|
|||||
Income
Tax Expense
|
(1.0
|
)
|
|||||
Nine
Months Ended September 30, 2006
|
$
|
7.4
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
OPERATING
REVENUES
|
$
|
74,756
|
$
|
69,640
|
$
|
230,102
|
$
|
201,268
|
|||||
EXPENSES
|
|||||||||||||
Fuel
for Electric Generation
|
42,354
|
37,403
|
131,402
|
105,771
|
|||||||||
Rent
- Rockport Plant Unit 2
|
17,070
|
17,070
|
51,212
|
51,212
|
|||||||||
Other
Operation
|
3,381
|
2,803
|
9,598
|
8,376
|
|||||||||
Maintenance
|
2,522
|
2,421
|
7,238
|
6,411
|
|||||||||
Depreciation
and Amortization
|
5,951
|
5,956
|
17,858
|
17,901
|
|||||||||
Taxes
Other Than Income Taxes
|
368
|
1,074
|
2,466
|
3,149
|
|||||||||
TOTAL
|
71,646
|
66,727
|
219,774
|
192,820
|
|||||||||
OPERATING
INCOME
|
3,110
|
2,913
|
10,328
|
8,448
|
|||||||||
Other
Income (Expense):
|
|||||||||||||
Interest
Income
|
-
|
-
|
-
|
24
|
|||||||||
Allowance
for Equity Funds Used During Construction
|
-
|
-
|
24
|
60
|
|||||||||
Interest
Expense
|
(774
|
)
|
(652
|
)
|
(2,137
|
)
|
(1,848
|
)
|
|||||
INCOME
BEFORE INCOME TAXES
|
2,336
|
2,261
|
8,215
|
6,684
|
|||||||||
Income
Tax Expense (Credit)
|
117
|
22
|
848
|
(144
|
)
|
||||||||
NET
INCOME
|
$
|
2,219
|
$
|
2,239
|
$
|
7,367
|
$
|
6,828
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
BALANCE
AT BEGINNING OF PERIOD
|
$
|
27,176
|
$
|
26,947
|
$
|
26,038
|
$
|
24,237
|
|||||
Net
Income
|
2,219
|
2,239
|
7,367
|
6,828
|
|||||||||
Cash
Dividends Declared
|
-
|
3,015
|
4,010
|
4,894
|
|||||||||
BALANCE
AT END OF PERIOD
|
$
|
29,395
|
$
|
26,171
|
$
|
29,395
|
$
|
26,171
|
The
common stock of AEGCo is wholly-owned by AEP.
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Accounts
Receivable - Affiliated Companies
|
$
|
24,356
|
$
|
29,671
|
|||
Fuel
|
24,139
|
14,897
|
|||||
Materials
and Supplies
|
7,913
|
7,017
|
|||||
Accrued
Tax Benefits
|
2,009
|
2,074
|
|||||
Prepayments
and Other
|
105
|
9
|
|||||
TOTAL
|
58,522
|
53,668
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric
- Production
|
686,025
|
684,721
|
|||||
Other
|
2,385
|
2,369
|
|||||
Construction
Work in Progress
|
11,391
|
12,252
|
|||||
Total
|
699,801
|
699,342
|
|||||
Accumulated
Depreciation and Amortization
|
393,529
|
382,925
|
|||||
TOTAL
- NET
|
306,272
|
316,417
|
|||||
Noncurrent
Assets
|
7,738
|
6,618
|
|||||
TOTAL
ASSETS
|
$
|
372,532
|
$
|
376,703
|
2006
|
2005
|
||||||
CURRENT
LIABILITIES
|
(in
thousands)
|
||||||
Advances
from Affiliates
|
$
|
14,938
|
$
|
35,131
|
|||
Accounts
Payable:
|
|||||||
General
|
1,311
|
926
|
|||||
Affiliated
Companies
|
21,018
|
22,161
|
|||||
Long-term
Debt Due Within One Year
|
-
|
44,828
|
|||||
Accrued
Taxes
|
5,880
|
3,055
|
|||||
Accrued
Rent - Rockport Plant Unit 2
|
23,427
|
4,963
|
|||||
Other
|
805
|
1,228
|
|||||
TOTAL
|
67,379
|
112,292
|
|||||
NONCURRENT
LIABILITIES
|
|||||||
Long-term
Debt
|
44,835
|
-
|
|||||
Deferred
Income Taxes
|
20,852
|
23,617
|
|||||
Asset
Retirement Obligations
|
1,399
|
1,370
|
|||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
82,331
|
82,689
|
|||||
Deferred
Gain on Sale and Leaseback - Rockport Plant Unit 2
|
90,155
|
94,333
|
|||||
Obligations
Under Capital Leases
|
11,752
|
11,930
|
|||||
TOTAL
|
251,324
|
213,939
|
|||||
TOTAL
LIABILITIES
|
318,703
|
326,231
|
|||||
Commitments
and Contingencies (Note 5)
|
|||||||
COMMON
SHAREHOLDER’S EQUITY
|
|||||||
Common
Stock - $1,000 Par Value Per Share
Authorized
and Outstanding - 1,000 Shares
|
1,000
|
1,000
|
|||||
Paid-in
Capital
|
23,434
|
23,434
|
|||||
Retained
Earnings
|
29,395
|
26,038
|
|||||
TOTAL
|
53,829
|
50,472
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
$
|
372,532
|
$
|
376,703
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
7,367
|
$
|
6,828
|
|||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
17,858
|
17,901
|
|||||
Deferred
Income Taxes
|
(3,468
|
)
|
(3,539
|
)
|
|||
Deferred
Investment Tax Credits
|
(2,482
|
)
|
(2,501
|
)
|
|||
Amortization
of Deferred Gain on Sale and Leaseback - Rockport Plant Unit
2
|
(4,178
|
)
|
(4,178
|
)
|
|||
Deferred
Property Taxes
|
(893
|
)
|
(1,010
|
)
|
|||
Changes
in Other Noncurrent Assets
|
(2,885
|
)
|
(1,736
|
)
|
|||
Changes
in Other Noncurrent Liabilities
|
2,776
|
2,201
|
|||||
Changes
in Components of Working Capital:
|
|||||||
Accounts
Receivable
|
5,315
|
(2,469
|
)
|
||||
Fuel,
Materials and Supplies
|
(10,138
|
)
|
4,278
|
||||
Accounts
Payable
|
(758
|
)
|
(1,188
|
)
|
|||
Accrued
Taxes, Net
|
2,890
|
(2,982
|
)
|
||||
Rent
Accrued - Rockport Plant Unit 2
|
18,464
|
18,464
|
|||||
Other
Current Assets
|
(96
|
)
|
(17
|
)
|
|||
Other
Current Liabilities
|
(423
|
)
|
(363
|
)
|
|||
Net
Cash Flows From Operating Activities
|
29,349
|
29,689
|
|||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(4,978
|
)
|
(9,041
|
)
|
|||
FINANCING
ACTIVITIES
|
|||||||
Change
in Advances from Affiliates, Net
|
(20,193
|
)
|
(15,601
|
)
|
|||
Principal
Payments for Capital Lease Obligations
|
(168
|
)
|
(153
|
)
|
|||
Dividends
Paid
|
(4,010
|
)
|
(4,894
|
)
|
|||
Net
Cash Flows Used For Financing Activities
|
(24,371
|
)
|
(20,648
|
)
|
|||
Net
Change in Cash and Cash Equivalents
|
-
|
-
|
|||||
Cash
and Cash Equivalents at Beginning of Period
|
-
|
-
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
-
|
$
|
-
|
|||
SUPPLEMENTARY
INFORMATION
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
2,413
|
$
|
2,104
|
|||
Net
Cash Paid for Income Taxes
|
6,037
|
11,025
|
|||||
Noncash
Acquisitions Under Capital Leases
|
78
|
31
|
Footnote
Reference
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
Third
Quarter of 2005
|
$
|
40
|
|||||
Changes
in Gross Margin:
|
|||||||
Texas
Supply
|
(4
|
)
|
|||||
Texas
Wires
|
(1
|
)
|
|||||
Off-system
Sales
|
(18
|
)
|
|||||
Transmission
Revenues
|
(3
|
)
|
|||||
Other
|
(3
|
)
|
|||||
Total
Change in Gross Margin
|
(29
|
)
|
|||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
1
|
||||||
Carrying
Costs Income
|
10
|
||||||
Other
Income
|
(7
|
)
|
|||||
Interest
Expense
|
(11
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(7
|
)
|
|||||
Income
Tax Expense
|
13
|
||||||
Third
Quarter of 2006
|
$
|
17
|
·
|
Texas
Supply margins decreased $4 million primarily due to lower nonaffiliated
sales of $3 million.
|
·
|
Margins
from Off-system Sales decreased $18 million due to an $11 million
decrease
in margin sharing under the SIA (no current margin sharing under
the CSW
Operating Agreement and the SIA) and a $7 million decrease in margins
from
optimization activities. See the “Allocation Agreement between AEP East
companies and AEP West companies and CSW Operating Agreement” section of
Note 3.
|
·
|
Transmission
Revenues decreased $3 million primarily due to lower ERCOT transmission
rates and reduced affiliated transmission fees resulting from the
elimination of the affiliated OATT in 2005.
|
·
|
Other
revenues decreased $3 million primarily due to lower securitization
revenues of $3 million. Securitization revenues represent amounts
collected to recover securitization bond principal and interest payments
related to our securitized transition assets and are fully offset
by
amortization and interest expenses.
|
·
|
Carrying
Costs Income increased $10 million primarily due to a negative adjustment
of $8 million made in the third quarter of 2005 related to our True-up
Proceeding orders received from the PUCT.
|
·
|
Other
Income decreased $7 million primarily due to interest income recorded
in
the prior year related to the 2005 Texas Court of Appeals order (see
“Texas Restructuring - Excess Earnings” section of Note
4).
|
·
|
Interest
Expense increased $11 million primarily due to a $9 million increase
in
accrued interest related to the Texas competition transition charge
liability (See “Texas Restructuring - CTC Proceeding for Other True-up
Items” section of Note 4).
|
Nine
Months Ended September 30, 2005
|
$
|
70
|
|||||
Changes
in Gross Margin:
|
|||||||
Texas
Supply
|
(78
|
)
|
|||||
Texas
Wires
|
14
|
||||||
Off-system
Sales
|
(21
|
)
|
|||||
Transmission
Revenues
|
(12
|
)
|
|||||
Other
|
(9
|
)
|
|||||
Total
Change in Gross Margin
|
(106
|
)
|
|||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
50
|
||||||
Depreciation
and Amortization
|
(6
|
)
|
|||||
Taxes
Other Than Income Taxes
|
6
|
||||||
Carrying
Costs Income
|
35
|
||||||
Other
Income
|
(13
|
)
|
|||||
Interest
Expense
|
(8
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
64
|
||||||
Income
Tax Expense
|
10
|
||||||
Nine
Months Ended September 30, 2006
|
$
|
38
|
·
|
Texas
Supply margins decreased $78 million primarily due to the sale of
STP,
which resulted in lower nonaffiliated sales of $101 million and a
$6
million provision for refund primarily due to the fuel reconciliation
adjustment in 2005. These decreases were partially offset by lower
fuel
and purchased power expenses of $30 million.
|
·
|
Texas
Wires revenues increased $14 million primarily due to favorable prices
and
a five percent increase in degree days.
|
·
|
Margins
from Off-system Sales decreased $21 million due to a $15 million
decrease
in margin sharing under the SIA and a $6 million decrease in margins
from
optimization activities. See the “Allocation Agreement between AEP East
companies and AEP West companies and CSW Operating Agreement” section of
Note 3.
|
·
|
Transmission
Revenues decreased $12 million primarily due to lower ERCOT transmission
rates and reduced affiliated transmission fees resulting from the
elimination of the affiliated OATT in 2005.
|
·
|
Other
revenues decreased $9 million primarily due to lower third party
construction project revenues of $4 million related to work performed
for
the Lower Colorado River Authority and reduced securitization revenues
of
$6 million. Securitization revenues represent amounts collected to
recover
securitization bond principal and interest payments related to our
securitized transition assets and are fully offset by amortization
and
interest expenses.
|
·
|
Other
Operation and Maintenance expenses decreased $50 million primarily
due to
a $12 million decrease in plant operations, a $14 million decrease
in
plant maintenance, a $6 million decrease in administrative and general
expenses and the absence of $7 million in accretion expense all related
to
the sale of STP. An additional $4 million decrease resulted from
lower
expenses related to construction activities performed for third parties,
primarily the Lower Colorado River Authority.
|
·
|
Depreciation
and Amortization expense increased $6 million primarily related to
the
refund and amortization of excess earnings credits in 2005 partially
offset by the recovery and amortization of securitized
assets.
|
·
|
Taxes
Other Than Income Taxes decreased $6 million primarily due to lower
property-related taxes as a result of the sale of STP in 2005 and
the
favorable settlement of a state use tax audit in 2006.
|
·
|
Carrying
Costs Income increased $35 million primarily due to negative adjustments
of $29 million and $8 million made in the first and third quarters
of
2005, respectively, related to our True-up Proceeding orders received
from
the PUCT.
|
·
|
Other
Income decreased $13 million primarily due to interest income recorded
in
the prior year related to the 2005 Texas Court of Appeals order (See
“Texas Restructuring - Excess Earnings” section of Note
4).
|
·
|
Interest
Expense increased $8 million primarily due to a $12 million increase
in
accrued interest related to the Texas CTC liability (see “Texas
Restructuring - CTC Proceeding for Other True-up Items” section of Note 4)
partially offset by a $2 million decrease in interest expense associated
with securitization revenues.
|
Moody’s
|
S&P
|
Fitch
|
|||
First
Mortgage Bonds
|
Baa1
|
BBB
|
A
|
||
Senior
Unsecured Debt
|
Baa2
|
BBB
|
A-
|
2006
|
2005
|
||||||
(in
thousands)
|
|||||||
Cash
and Cash Equivalents at Beginning of Period
|
$
|
-
|
$
|
26
|
|||
Net
Cash Flows From (Used For):
|
|||||||
Operating
Activities
|
137,471
|
(95,431
|
)
|
||||
Investing
Activities
|
(197,269
|
)
|
293,461
|
||||
Financing
Activities
|
59,803
|
(198,053
|
)
|
||||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
5
|
(23
|
)
|
||||
Cash
and Cash Equivalents at End of Period
|
$
|
5
|
$
|
3
|
Principal
Amount
|
Interest
|
Due
|
|||||
Type
of Debt
|
Rate
|
Date
|
|||||
(in
thousands)
|
(%)
|
||||||
Notes
Payable - Affiliated
|
$
|
125,000
|
5.14
|
2007
|
|||
Notes
Payable - Affiliated
|
70,000
|
5.86
|
2007
|
Principal
Amount
|
Interest
|
Due
|
|||||
Type
of Debt
|
Rate
|
Date
|
|||||
(in
thousands)
|
(%)
|
||||||
Securitization
Bonds
|
$
|
52,265
|
5.01
|
2010
|
Principal
|
Interest
|
Scheduled
Final
|
|||
Amount
|
Rate
|
Payment
Date
|
|||
(in
thousands)
|
(%)
|
||||
$
|
217,000
|
4.98
|
2010
|
||
341,000
|
4.98
|
2013
|
|||
250,000
|
5.09
|
2015
|
|||
437,000
|
5.17
|
2018
|
|||
494,700
|
5.3063
|
2020
|
Principal
Amount
|
Interest
|
Due
|
|||
Rate
|
Date
|
||||
(in
thousands)
|
(%)
|
||||
$
|
150,000
|
4.58
|
2007
|
||
125,000
|
5.14
|
2007
|
|||
70,000
|
5.86
|
2007
|
(in
millions)
|
||||
Wholesale
Capacity Auction True-up
|
$
|
61
|
||
Carrying
Costs on Wholesale Capacity Auction True-up
|
31
|
|||
Retail
Clawback including Carrying Costs
|
(65
|
)
|
||
Deferred
Over-recovered Fuel Balance
|
(184
|
)
|
||
Retrospective
ADFIT Benefit
|
(77
|
)
|
||
Other
|
(4
|
)
|
||
Recorded
Net Regulatory Liabilities - Other True-up Items
|
(238
|
)
|
||
Unrecorded
Prospective ADFIT Benefit
|
(240
|
)
|
||
Gross
CTC Refund Proposed
|
(478
|
)
|
||
FERC
Jurisdictional Fuel Refund Deferral
|
16
|
|||
ADITC
and EDFIT Benefit Refund Deferral
|
98
|
|||
Net
CTC Refund Proposed, After Deferrals
|
(364
|
)
|
||
True-up
Proceeding Expense Surcharge
|
7
|
|||
Net
CTC Refund Proposed, After Deferrals and Expenses
|
$
|
(357
|
)
|
·
|
the
PUCT ruled that TCC did not comply with the statute and PUCT rules
regarding the auction of 15% of its Texas jurisdictional installed
capacity,
|
·
|
that
TCC acted in a manner that was commercially unreasonable because
it failed
to determine a minimum price at which it would reject bids for
the sale of
its nuclear generating plant and it bundled gas units with the
sale of its
coal unit,
|
·
|
and
two federal matters regarding the allocation of off-system sales
related
to fuel recoveries and the potential tax normalization
violation.
|
(in
millions)
|
||||
ADITC
and EDFIT Benefits Reducing Securitization
|
$
|
98
|
||
ADFIT
Benefit Applied to Reduce 2002 Securitization of Regulatory Assets
|
(60
|
)
|
||
Securitization
Settlement
|
(77
|
)
|
||
Unrecorded
Prospective ADFIT Benefit Increasing the CTC Refund
|
(240
|
)
|
||
Unrecorded
Equity Carrying Costs Recognized as Collected
|
224
|
|||
Future
Interest Payable on Proposed CTC Refund
|
(19
|
)
|
||
Deferred
Fuel - Federal Jurisdictional Issue
|
16
|
|||
Net
Adverse Earnings Impact Over 14 Years
|
$
|
(58
|
)
|
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
$
|
5,426
|
||
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
(1,175
|
)
|
||
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
|
-
|
|||
Changes
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
-
|
|||
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
(3,868
|
)
|
||
Changes
Due to SIA and CSW Operating Agreement (c)
|
(383
|
)
|
||
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
-
|
|||
Total
MTM Risk Management Contract Net Assets
|
-
|
|||
Net
Cash Flow Hedge Contracts
|
-
|
|||
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
$
|
-
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies”
section of this Management’s Financial Discussion and
Analysis.
|
(d)
|
“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.
|
Power
|
||||
Beginning
Balance in AOCI December 31, 2005
|
$
|
(224
|
)
|
|
Changes
in Fair Value
|
-
|
|||
Impact
Due to Changes in SIA (a)
|
218
|
|||
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
6
|
|||
Ending
Balance in AOCI September 30, 2006
|
$
|
-
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies”
section of this Management’s Financial Discussion and
Analysis.
|
Nine
Months Ended
September
30, 2006
|
Twelve
Months Ended
December
31, 2005
|
||||||||||||||||
(in
thousands)
|
(in
thousands)
|
||||||||||||||||
End
|
High
|
Average
|
Low
|
End
|
High
|
Average
|
Low
|
||||||||||
$-
|
$11
|
$2
|
$-
|
$111
|
$184
|
$88
|
$32
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
REVENUES
|
|||||||||||||
Electric
Generation, Transmission and Distribution
|
$
|
162,902
|
$
|
192,932
|
$
|
435,801
|
$
|
559,822
|
|||||
Sales
to AEP Affiliates
|
1,559
|
2,528
|
4,703
|
12,794
|
|||||||||
Other
- Nonaffiliated
|
9,462
|
7,905
|
30,196
|
34,432
|
|||||||||
TOTAL
|
173,923
|
203,365
|
470,700
|
607,048
|
|||||||||
EXPENSES
|
|||||||||||||
Fuel
and Other Consumables for Electric Generation
|
2,006
|
1,915
|
4,728
|
12,047
|
|||||||||
Purchased
Electricity for Resale
|
725
|
1,691
|
3,557
|
27,057
|
|||||||||
Other
Operation
|
61,057
|
64,408
|
183,241
|
221,741
|
|||||||||
Maintenance
|
10,679
|
8,782
|
27,255
|
38,254
|
|||||||||
Depreciation
and Amortization
|
40,298
|
40,342
|
110,848
|
105,062
|
|||||||||
Taxes
Other Than Income Taxes
|
23,387
|
22,828
|
60,421
|
66,282
|
|||||||||
TOTAL
|
138,152
|
139,966
|
390,050
|
470,443
|
|||||||||
OPERATING
INCOME
|
35,771
|
63,399
|
80,650
|
136,605
|
|||||||||
Other
Income (Expense):
|
|||||||||||||
Interest
Income
|
560
|
8,295
|
1,592
|
15,722
|
|||||||||
Carrying
Costs Income
|
25,443
|
15,349
|
65,279
|
30,146
|
|||||||||
Allowance
for Equity Funds Used During Construction
|
667
|
(59
|
)
|
1,671
|
641
|
||||||||
Interest
Expense
|
(36,746
|
)
|
(25,374
|
)
|
(93,401
|
)
|
(85,095
|
)
|
|||||
INCOME
BEFORE INCOME TAXES
|
25,695
|
61,610
|
55,791
|
98,019
|
|||||||||
Income
Tax Expense
|
8,460
|
21,134
|
17,808
|
28,038
|
|||||||||
NET
INCOME
|
17,235
|
40,476
|
37,983
|
69,981
|
|||||||||
Preferred
Stock Dividend Requirements
|
60
|
60
|
181
|
181
|
|||||||||
EARNINGS
APPLICABLE TO COMMON STOCK
|
$
|
17,175
|
$
|
40,416
|
$
|
37,802
|
$
|
69,800
|
Common
Stock
|
Paid-in
Capital
|
Retained
Earnings
|
Accumulated
Other Comprehensive Income (Loss)
|
Total
|
||||||||||||
DECEMBER
31, 2004
|
$
|
55,292
|
$
|
132,606
|
$
|
1,084,904
|
$
|
(4,159
|
)
|
$
|
1,268,643
|
|||||
Common
Stock Dividends
|
(150,000
|
)
|
(150,000
|
)
|
||||||||||||
Preferred
Stock Dividends
|
(181
|
)
|
(181
|
)
|
||||||||||||
TOTAL
|
1,118,462
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Income (Loss), Net
of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $1,626
|
(3,021
|
)
|
(3,021
|
)
|
||||||||||||
Minimum
Pension Liability, Net of Tax of
$0
|
3,810
|
3,810
|
||||||||||||||
NET
INCOME
|
69,981
|
69,981
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
70,770
|
|||||||||||||||
SEPTEMBER
30, 2005
|
$
|
55,292
|
$
|
132,606
|
$
|
1,004,704
|
$
|
(3,370
|
)
|
$
|
1,189,232
|
|||||
DECEMBER
31, 2005
|
$
|
55,292
|
$
|
132,606
|
$
|
760,884
|
$
|
(1,152
|
)
|
$
|
947,630
|
|||||
Preferred
Stock Dividends
|
(181
|
)
|
(181
|
)
|
||||||||||||
TOTAL
|
947,449
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Income, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $121
|
224
|
224
|
||||||||||||||
NET
INCOME
|
37,983
|
37,983
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
38,207
|
|||||||||||||||
SEPTEMBER
30, 2006
|
$
|
55,292
|
$
|
132,606
|
$
|
798,686
|
$
|
(928
|
)
|
$
|
985,656
|
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Cash
and Cash Equivalents
|
$
|
5
|
$
|
-
|
|||
Other
Cash Deposits
|
41,728
|
66,153
|
|||||
Advances
to Affiliates
|
25,304
|
-
|
|||||
Accounts
Receivable:
|
|||||||
Customers
|
65,875
|
209,957
|
|||||
Affiliated
Companies
|
8,633
|
23,486
|
|||||
Accrued
Unbilled Revenues
|
25,350
|
25,606
|
|||||
Allowance
for Uncollectible Accounts
|
(217
|
)
|
(143
|
)
|
|||
Total Accounts Receivable
|
99,641
|
258,906
|
|||||
Unbilled
Construction Costs
|
6,352
|
19,440
|
|||||
Materials
and Supplies
|
24,995
|
13,897
|
|||||
Risk
Management Assets
|
-
|
14,311
|
|||||
Prepayments
and Other
|
5,645
|
5,231
|
|||||
TOTAL
|
203,670
|
377,938
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric:
|
|||||||
Transmission
|
900,774
|
817,351
|
|||||
Distribution
|
1,559,593
|
1,476,683
|
|||||
Other
|
232,023
|
233,361
|
|||||
Construction
Work in Progress
|
126,418
|
129,800
|
|||||
Total
|
2,818,808
|
2,657,195
|
|||||
Accumulated
Depreciation and Amortization
|
637,517
|
636,078
|
|||||
TOTAL
- NET
|
2,181,291
|
2,021,117
|
|||||
OTHER
NONCURRENT ASSETS
|
|||||||
Regulatory
Assets
|
1,710,352
|
1,688,787
|
|||||
Securitized
Transition Assets
|
557,520
|
593,401
|
|||||
Long-term
Risk Management Assets
|
-
|
11,609
|
|||||
Employee
Benefits and Pension Assets
|
112,594
|
114,733
|
|||||
Deferred
Charges and Other
|
57,276
|
53,011
|
|||||
TOTAL
|
2,437,742
|
2,461,541
|
|||||
Assets
Held for Sale - Texas Generation Plants
|
45,863
|
44,316
|
|||||
TOTAL
ASSETS
|
$
|
4,868,566
|
$
|
4,904,912
|
2006
|
2005
|
||||||
CURRENT
LIABILITIES
|
(in
thousands)
|
||||||
Advances
from Affiliates
|
$
|
-
|
$
|
82,080
|
|||
Accounts
Payable:
|
|||||||
General
|
20,889
|
82,666
|
|||||
Affiliated
Companies
|
18,160
|
65,574
|
|||||
Long-term
Debt Due Within One Year - Nonaffiliated
|
153,364
|
152,900
|
|||||
Long-term
Debt Due Within One Year - Affiliated
|
345,000
|
-
|
|||||
Risk
Management Liabilities
|
-
|
13,024
|
|||||
Accrued
Taxes
|
74,887
|
54,566
|
|||||
Accrued
Interest
|
16,011
|
32,497
|
|||||
Other
|
32,500
|
45,927
|
|||||
TOTAL
|
660,811
|
529,234
|
|||||
NONCURRENT
LIABILITIES
|
|||||||
Long-term
Debt - Nonaffiliated
|
1,498,031
|
1,550,596
|
|||||
Long-term
Debt - Affiliated
|
-
|
150,000
|
|||||
Long-term
Risk Management Liabilities
|
-
|
7,857
|
|||||
Deferred
Income Taxes
|
1,014,840
|
1,048,372
|
|||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
684,566
|
652,143
|
|||||
Deferred
Credits and Other
|
18,723
|
13,140
|
|||||
TOTAL
|
3,216,160
|
3,422,108
|
|||||
TOTAL
LIABILITIES
|
3,876,971
|
3,951,342
|
|||||
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
5,939
|
5,940
|
|||||
Commitments
and Contingencies (Note 5)
|
|||||||
COMMON
SHAREHOLDER’S EQUITY
|
|||||||
Common
Stock - $25 Par Value Per Share:
|
|||||||
Authorized
- 12,000,000 Shares
|
|||||||
Outstanding
- 2,211,678 Shares
|
55,292
|
55,292
|
|||||
Paid-in
Capital
|
132,606
|
132,606
|
|||||
Retained
Earnings
|
798,686
|
760,884
|
|||||
Accumulated
Other Comprehensive Income (Loss)
|
(928
|
)
|
(1,152
|
)
|
|||
TOTAL
|
985,656
|
947,630
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
4,868,566
|
$
|
4,904,912
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
37,983
|
$
|
69,981
|
|||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
110,848
|
105,062
|
|||||
Accretion
of Asset Retirement Obligations
|
55
|
7,549
|
|||||
Deferred
Income Taxes
|
5,770
|
(63,426
|
)
|
||||
Carrying
Costs on Stranded Cost Recovery
|
(65,279
|
)
|
(30,146
|
)
|
|||
Mark-to-Market
of Risk Management Contracts
|
5,426
|
(1,139
|
)
|
||||
Over/Under
Fuel Recovery
|
7,225
|
(2,000
|
)
|
||||
Deferred
Property Taxes
|
(8,296
|
)
|
(7,600
|
)
|
|||
Change
in Other Noncurrent Assets
|
17,653
|
(9,777
|
)
|
||||
Change
in Other Noncurrent Liabilities
|
(17,249
|
)
|
(1,390
|
)
|
|||
Changes
in Components of Working Capital:
|
|||||||
Accounts
Receivable, Net
|
159,265
|
(22,504
|
)
|
||||
Fuel,
Materials and Supplies
|
(11,508
|
)
|
(1,763
|
)
|
|||
Accounts
Payable
|
(107,505
|
)
|
(10,533
|
)
|
|||
Customer
Deposits
|
(6,461
|
)
|
12,844
|
||||
Accrued
Taxes, Net
|
16,387
|
(110,975
|
)
|
||||
Accrued
Interest
|
(16,486
|
)
|
(24,495
|
)
|
|||
Other
Current Assets
|
16,611
|
(13,709
|
)
|
||||
Other
Current Liabilities
|
(6,968
|
)
|
8,590
|
||||
Net
Cash Flows From (Used For) Operating Activities
|
137,471
|
(95,431
|
)
|
||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(203,116
|
)
|
(109,372
|
)
|
|||
Change
in Other Cash Deposits, Net
|
25,068
|
93,427
|
|||||
Change
in Advances to Affiliates, Net
|
(25,304
|
)
|
-
|
||||
Purchases
of Investment Securities
|
-
|
(154,364
|
)
|
||||
Sales
of Investment Securities
|
-
|
149,804
|
|||||
Proceeds
from Sale of Assets
|
6,083
|
313,966
|
|||||
Net
Cash Flows From (Used For) Investing Activities
|
(197,269
|
)
|
293,461
|
||||
FINANCING
ACTIVITIES
|
|||||||
Issuance
of Long-term Debt - Nonaffiliated
|
-
|
276,663
|
|||||
Issuance
of Long-term Debt - Affiliated
|
195,000
|
150,000
|
|||||
Change
in Advances from Affiliates, Net
|
(82,080
|
)
|
11,814
|
||||
Retirement
of Long-term Debt
|
(52,265
|
)
|
(486,007
|
)
|
|||
Retirement
of Preferred Stock
|
(1
|
)
|
-
|
||||
Principal
Payments for Capital Lease Obligations
|
(670
|
)
|
(342
|
)
|
|||
Dividends
Paid on Common Stock
|
-
|
(150,000
|
)
|
||||
Dividends
Paid on Cumulative Preferred Stock
|
(181
|
)
|
(181
|
)
|
|||
Net
Cash Flows From (Used For) Financing Activities
|
59,803
|
(198,053
|
)
|
||||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
5
|
(23
|
)
|
||||
Cash
and Cash Equivalents at Beginning of Period
|
-
|
26
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
5
|
$
|
3
|
|||
SUPPLEMENTAL
DISCLOSURE
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
93,165
|
$
|
95,066
|
|||
Net
Cash Paid (Received) for Income Taxes
|
(2,764
|
)
|
207,079
|
||||
Noncash
Acquisitions Under Capital Leases
|
3,282
|
277
|
|||||
Construction
Expenditures Included in Accounts Payable at September 30,
|
9,351
|
8,797
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
Footnote
Reference
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Customer
Choice and Industry Restructuring
|
Note
4
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Acquisitions,
Assets Held for Sale and Asset Impairments
|
Note
8
|
Benefit
Plans
|
Note
9
|
Income
Taxes
|
Note
10
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
Third
Quarter of 2005
|
$
|
22
|
|||||
Changes
in Gross Margin:
|
|||||||
Texas
Supply
|
(12
|
)
|
|||||
Texas
Wires
|
(1
|
)
|
|||||
Off-system
Sales
|
(10
|
)
|
|||||
Transmission
Revenues
|
1
|
||||||
Total
Change in Gross Margin
|
(22
|
)
|
|||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
1
|
||||||
Income
Tax Expense
|
7
|
||||||
Third
Quarter of 2006
|
$
|
8
|
·
|
Texas
Supply margins decreased $12 million primarily due to a $28 million
decrease in dedicated energy and capacity sales, offset by $16 million
of
lower fuel and purchased power costs. This decrease in Texas Supply
margins was affected by market conditions within ERCOT.
|
·
|
Margins
from Off-system Sales decreased $10 million due to a $5 million decrease
in margin sharing under the SIA (no current margin sharing under
the CSW
Operating Agreement and the SIA) and a $5 million decrease in margins
from
optimization activities. See
the “Allocation Agreement between AEP East companies and AEP West
companies and CSW Operating Agreement” section of Note
3.
|
Nine
Months Ended September 30, 2005
|
$
|
42
|
|||||
Changes
in Gross Margin:
|
|||||||
Texas
Supply
|
(29
|
)
|
|||||
Texas
Wires
|
(2
|
)
|
|||||
Off-system
Sales
|
(11
|
)
|
|||||
Transmission
Revenues
|
(5
|
)
|
|||||
Other
|
(39
|
)
|
|||||
Total
Change in Gross Margin
|
(86
|
)
|
|||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
38
|
||||||
Interest
Expense
|
1
|
||||||
Total
Change in Operating Expenses and Other
|
39
|
||||||
Income
Tax Expense
|
17
|
||||||
Nine
Months Ended September 30, 2006
|
$
|
12
|
·
|
Texas
Supply margins decreased $29 million primarily due to a $58 million
decrease in dedicated energy and capacity sales, offset by $28 million
of
lower fuel and purchased power costs. This decrease in Texas Supply
margins was affected by market conditions within ERCOT.
|
·
|
Margins
from Off-system Sales decreased $11 million due to a $6 million decrease
in margin sharing under the SIA and a $5 million decrease in margins
from
optimization activities. See
the “Allocation Agreement between AEP East companies and AEP West
companies and CSW Operating Agreement” section of Note
3.
|
·
|
Transmission
Revenues decreased $5 million primarily due to reduced affiliated
transmission fees resulting from the elimination of the affiliated
OATT in
2005.
|
·
|
Other
revenues decreased $39 million primarily resulting from the completion
of
certain third party construction projects related to work performed
for
the Lower Colorado River Authority.
|
·
|
Other
Operation and Maintenance expenses decreased $38 million primarily
due to
lower expenses related to the completion of certain third party
construction projects related to work performed for the Lower Colorado
River Authority.
|
Moody’s
|
S&P
|
Fitch
|
|||
First
Mortgage Bonds
|
A3
|
BBB
|
A
|
||
Senior
Unsecured Debt
|
Baa1
|
BBB
|
A-
|
MTM
Risk Management Contracts
|
Cash
Flow Hedges
|
Total
|
||||||||
Current
Assets
|
$
|
-
|
$
|
-
|
$
|
-
|
||||
Noncurrent
Assets
|
-
|
-
|
-
|
|||||||
Total
MTM Derivative Contract Assets
|
-
|
-
|
-
|
|||||||
Current
Liabilities
|
(2,138
|
)
|
-
|
(2,138
|
)
|
|||||
Noncurrent
Liabilities
|
-
|
(2,057
|
)
|
(2,057
|
)
|
|||||
Total
MTM Derivative Contract Liabilities
|
(2,138
|
)
|
(2,057
|
)
|
(4,195
|
)
|
||||
Total
MTM Derivative Contract Net Assets (Liabilities)
|
$
|
(2,138
|
)
|
$
|
(2,057
|
)
|
$
|
(4,195
|
)
|
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
$
|
2,698
|
||
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
(585
|
)
|
||
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)
|
(3,437
|
)
|
||
Changes
Due to SIA and CSW Operating Agreement (c)
|
(814
|
)
|
||
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
-
|
|||
Total
MTM Risk Management Contract Net Assets
(Liabilities)
|
(2,138
|
)
|
||
Net
Cash Flow Hedge Contracts
|
(2,057
|
)
|
||
Total
MTM Risk Management Contract Net Assets (Liabilities) at September
30,
2006
|
$
|
(4,195
|
)
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies”
section of this Management’s Financial Discussion and
Analysis.
|
(d)
|
“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.
|
Remainder
2006
|
2007
|
2008
|
2009
|
2010
|
After
2010
|
Total
|
||||||||||||||||
Prices
Actively Quoted - Exchange Traded
Contracts
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
||||||||
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
(2,138
|
)
|
-
|
-
|
-
|
-
|
-
|
(2,138
|
)
|
|||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||||
Total
|
$
|
(2,138
|
)
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
(2,138
|
)
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Power
|
||||
Beginning
Balance in AOCI December 31, 2005
|
$
|
(111
|
)
|
|
Changes
in Fair Value
|
(1,337
|
)
|
||
Impact
Due to Change in SIA (a)
|
98
|
|||
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
13
|
|||
Ending
Balance in AOCI September 30, 2006
|
$
|
(1,337
|
)
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies”
section of this Management’s Financial Discussion and
Analysis.
|
Nine
Months Ended
September
30, 2006
|
Twelve
Months Ended
December
31, 2005
|
||||||||||||||||
(in
thousands)
|
(in
thousands)
|
||||||||||||||||
End
|
High
|
Average
|
Low
|
End
|
High
|
Average
|
Low
|
||||||||||
$-
|
$23
|
$4
|
$-
|
$55
|
$92
|
$44
|
$16
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
REVENUES
|
|||||||||||||
Electric
Generation, Transmission and Distribution
|
$
|
79,805
|
$
|
111,107
|
$
|
219,681
|
$
|
280,195
|
|||||
Sales
to AEP Affiliates
|
7,711
|
13,019
|
25,596
|
37,189
|
|||||||||
Other
|
246
|
1,971
|
149
|
42,324
|
|||||||||
TOTAL
|
87,762
|
126,097
|
245,426
|
359,708
|
|||||||||
EXPENSES
|
|||||||||||||
Fuel
and Other Consumables for Electric Generation
|
14,016
|
13,433
|
33,175
|
37,772
|
|||||||||
Purchased
Electricity for Resale
|
14,606
|
34,425
|
60,343
|
88,367
|
|||||||||
Purchased
Electricity from AEP Affiliates
|
2,436
|
1
|
3,978
|
23
|
|||||||||
Other
Operation
|
19,003
|
18,878
|
59,192
|
97,135
|
|||||||||
Maintenance
|
5,088
|
5,954
|
15,505
|
15,093
|
|||||||||
Depreciation
and Amortization
|
10,767
|
10,435
|
31,172
|
30,952
|
|||||||||
Taxes
Other Than Income Taxes
|
5,478
|
6,047
|
16,874
|
17,465
|
|||||||||
TOTAL
|
71,394
|
89,173
|
220,239
|
286,807
|
|||||||||
OPERATING
INCOME
|
16,368
|
36,924
|
25,187
|
72,901
|
|||||||||
Other
Income (Expense):
|
|||||||||||||
Interest
Income
|
203
|
890
|
542
|
1,688
|
|||||||||
Allowance
for Equity Funds Used During Construction
|
146
|
137
|
636
|
366
|
|||||||||
Interest
Expense
|
(4,472
|
)
|
(4,931
|
)
|
(13,351
|
)
|
(14,784
|
)
|
|||||
INCOME
BEFORE INCOME TAXES
|
12,245
|
33,020
|
13,014
|
60,171
|
|||||||||
Income
Tax Expense
|
3,799
|
10,716
|
1,326
|
18,469
|
|||||||||
NET
INCOME
|
8,446
|
22,304
|
11,688
|
41,702
|
|||||||||
Preferred
Stock Dividend Requirements
|
26
|
26
|
78
|
78
|
|||||||||
Gain
on Reacquired Preferred Stock
|
-
|
-
|
2
|
-
|
|||||||||
EARNINGS
APPLICABLE TO COMMON STOCK
|
$
|
8,420
|
$
|
22,278
|
$
|
11,612
|
$
|
41,624
|
Common
Stock
|
Paid-in
Capital
|
Retained
Earnings
|
Accumulated
Other Comprehensive Income (Loss)
|
Total
|
||||||||||||
DECEMBER
31, 2004
|
$
|
137,214
|
$
|
2,351
|
$
|
170,984
|
$
|
(128
|
)
|
$
|
310,421
|
|||||
Common
Stock Dividends
|
(20,827
|
)
|
(20,827
|
)
|
||||||||||||
Preferred
Stock Dividends
|
(78
|
)
|
(78
|
)
|
||||||||||||
TOTAL
|
289,516
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $698
|
(1,296
|
)
|
(1,296
|
)
|
||||||||||||
NET
INCOME
|
41,702
|
41,702
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
40,406
|
|||||||||||||||
SEPTEMBER
30, 2005
|
$
|
137,214
|
$
|
2,351
|
$
|
191,781
|
$
|
(1,424
|
)
|
$
|
329,922
|
|||||
DECEMBER
31, 2005
|
$
|
137,214
|
$
|
2,351
|
$
|
174,858
|
$
|
(504
|
)
|
$
|
313,919
|
|||||
Common
Stock Dividends
|
(12,750
|
)
|
(12,750
|
)
|
||||||||||||
Preferred
Stock Dividends
|
(78
|
)
|
(78
|
)
|
||||||||||||
Gain
on Reacquired Preferred Stock
|
2
|
2
|
||||||||||||||
TOTAL
|
301,093
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $660
|
(1,226
|
)
|
(1,226
|
)
|
||||||||||||
NET
INCOME
|
11,688
|
11,688
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
10,462
|
|||||||||||||||
SEPTEMBER
30, 2006
|
$
|
137,214
|
$
|
2,351
|
$
|
173,720
|
$
|
(1,730
|
)
|
$
|
311,555
|
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Cash
and Cash Equivalents
|
$
|
-
|
$
|
-
|
|||
Other
Cash Deposits
|
9,087
|
1,432
|
|||||
Advances
to Affiliates
|
4,383
|
34,286
|
|||||
Accounts
Receivable:
|
|||||||
Customers
|
23,367
|
77,678
|
|||||
Affiliated
Companies
|
11,910
|
26,149
|
|||||
Accrued
Unbilled Revenues
|
2,567
|
5,016
|
|||||
Allowance
for Uncollectible Accounts
|
(24
|
)
|
(18
|
)
|
|||
Total
Accounts Receivable
|
37,820
|
108,825
|
|||||
Fuel
|
5,528
|
2,636
|
|||||
Materials
and Supplies
|
8,459
|
6,858
|
|||||
Risk
Management Assets
|
-
|
7,114
|
|||||
Prepayments
and Other
|
1,537
|
3,772
|
|||||
TOTAL
|
66,814
|
164,923
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric:
|
|||||||
Production
|
290,391
|
288,934
|
|||||
Transmission
|
324,724
|
289,029
|
|||||
Distribution
|
507,307
|
492,878
|
|||||
Other
|
165,403
|
167,849
|
|||||
Construction
Work in Progress
|
31,991
|
46,424
|
|||||
Total
|
1,319,816
|
1,285,114
|
|||||
Accumulated
Depreciation and Amortization
|
486,131
|
478,519
|
|||||
TOTAL
- NET
|
833,685
|
806,595
|
|||||
OTHER
NONCURRENT ASSETS
|
|||||||
Regulatory
Assets
|
8,920
|
9,787
|
|||||
Long-term
Risk Management Assets
|
-
|
5,772
|
|||||
Employee
Benefits and Pension Assets
|
45,409
|
46,289
|
|||||
Deferred
Charges and Other
|
7,153
|
10,468
|
|||||
TOTAL
|
61,482
|
72,316
|
|||||
TOTAL
ASSETS
|
$
|
961,981
|
$
|
1,043,834
|
2006
|
2005
|
||||||
CURRENT
LIABILITIES
|
(in
thousands)
|
||||||
Accounts
Payable:
|
|||||||
General
|
$
|
9,151
|
$
|
19,739
|
|||
Affiliated
Companies
|
27,854
|
84,923
|
|||||
Long-term
Debt Due Within One Year - Nonaffiliated
|
8,151
|
-
|
|||||
Risk
Management Liabilities
|
2,138
|
6,475
|
|||||
Accrued
Taxes
|
29,458
|
21,212
|
|||||
Other
|
11,203
|
21,050
|
|||||
TOTAL
|
87,955
|
153,399
|
|||||
NONCURRENT
LIABILITIES
|
|||||||
Long-term
Debt - Nonaffiliated
|
268,762
|
276,845
|
|||||
Long-term
Risk Management Liabilities
|
2,057
|
3,906
|
|||||
Deferred
Income Taxes
|
123,991
|
132,335
|
|||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
143,506
|
139,732
|
|||||
Deferred
Credits and Other
|
21,806
|
21,341
|
|||||
TOTAL
|
560,122
|
574,159
|
|||||
TOTAL
LIABILITIES
|
648,077
|
727,558
|
|||||
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
2,349
|
2,357
|
|||||
Commitments
and Contingencies (Note 5)
|
|||||||
COMMON
SHAREHOLDER’S EQUITY
|
|||||||
Common
Stock - $25 Par Value Per Share:
|
|||||||
Authorized
- 7,800,000 Shares
|
|||||||
Outstanding
- 5,488,560 Shares
|
137,214
|
137,214
|
|||||
Paid-in
Capital
|
2,351
|
2,351
|
|||||
Retained
Earnings
|
173,720
|
174,858
|
|||||
Accumulated
Other Comprehensive Income (Loss)
|
(1,730
|
)
|
(504
|
)
|
|||
TOTAL
|
311,555
|
313,919
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
961,981
|
$
|
1,043,834
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
11,688
|
$
|
41,702
|
|||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
31,172
|
30,952
|
|||||
Deferred
Income Taxes
|
(4,667
|
)
|
(313
|
)
|
|||
Mark-to-Market
of Risk Management Contracts
|
4,836
|
(452
|
)
|
||||
Deferred
Property Taxes
|
(4,359
|
)
|
(4,072
|
)
|
|||
Change
in Other Noncurrent Assets
|
(5,173
|
)
|
(1,109
|
)
|
|||
Change
in Other Noncurrent Liabilities
|
(630
|
)
|
(71
|
)
|
|||
Changes
in Components of Working Capital:
|
|||||||
Accounts
Receivable, Net
|
71,005
|
9,366
|
|||||
Fuel,
Materials and Supplies
|
(4,493
|
)
|
922
|
||||
Accounts
Payable
|
(66,653
|
)
|
16,834
|
||||
Customer
Deposits
|
(3,571
|
)
|
5,471
|
||||
Accrued
Taxes, Net
|
7,984
|
(10,097
|
)
|
||||
Other
Current Assets
|
2,496
|
11,189
|
|||||
Other
Current Liabilities
|
(5,304
|
)
|
(551
|
)
|
|||
Net
Cash Flows From Operating Activities
|
34,331
|
99,771
|
|||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(52,366
|
)
|
(44,865
|
)
|
|||
Change
in Other Cash Deposits, Net
|
979
|
1,508
|
|||||
Change
In Advances to Affiliates, Net
|
29,903
|
(36,147
|
)
|
||||
Proceeds
from Sale of Assets
|
250
|
1,033
|
|||||
Net
Cash Flows Used For Investing Activities
|
(21,234
|
)
|
(78,471
|
)
|
|||
FINANCING
ACTIVITIES
|
|||||||
Retirement
of Preferred Stock
|
(6
|
)
|
-
|
||||
Principal
Payments for Capital Lease Obligations
|
(263
|
)
|
(180
|
)
|
|||
Dividends
Paid on Common Stock
|
(12,750
|
)
|
(20,827
|
)
|
|||
Dividends
Paid on Cumulative Preferred Stock
|
(78
|
)
|
(78
|
)
|
|||
Net
Cash Flows Used For Financing Activities
|
(13,097
|
)
|
(21,085
|
)
|
|||
Net
Increase in Cash and Cash Equivalents
|
-
|
215
|
|||||
Cash
and Cash Equivalents at Beginning of Period
|
-
|
-
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
-
|
$
|
215
|
|||
SUPPLEMENTAL
DISCLOSURE
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
13,988
|
$
|
15,192
|
|||
Net
Cash Paid (Received) for Income Taxes
|
(252
|
)
|
30,486
|
||||
Noncash
Acquisitions Under Capital Leases
|
1,178
|
193
|
|||||
Construction
Expenditures Included in Accounts Payable at September 30,
|
2,155
|
2,289
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
Footnote
Reference
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Customer
Choice and Industry Restructuring
|
Note
4
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Income
Taxes
|
Note
10
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
Third
Quarter of 2005
|
$
|
37
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
(23
|
)
|
|||||
Off-system
Sales
|
33
|
||||||
Transmission
Revenues
|
(10
|
)
|
|||||
Other
|
16
|
||||||
Total
Change in Gross Margin
|
16
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
6
|
||||||
Depreciation
and Amortization
|
(11
|
)
|
|||||
Carrying
Costs Income (Expense)
|
(29
|
)
|
|||||
Other
Income
|
7
|
||||||
Interest
Expense
|
(2
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(29
|
)
|
|||||
Income
Tax Expense
|
7
|
||||||
Third
Quarter of 2006
|
$
|
31
|
·
|
Retail
Margins decreased $23 million in comparison to 2005 primarily due
to:
|
|
·
|
a
$28 million decrease related to an increase in sharing of off-system
sales
margins with retail customers due to higher off-system sales. This
sharing
mechanism was reinstated in West Virginia effective July 1, 2006
in
conjunction with our West Virginia rate case. Retail Margins further
decreased due to;
|
|
·
|
a
$13 million decrease in revenues related to financial transmission
rights,
net of congestion, primarily due to fewer transmission constraints
in the
PJM market partially offset by;
|
|
·
|
a
$19 million increase in fuel recovery caused by the activation of
the West
Virginia fuel clause in July 2006.
|
|
·
|
Off-system
Sales increased $33 million primarily due to $19 million increase
in
physical sales margins and an $18 million increase from lower sharing
of
off-system sales margins under the SIA slightly offset by a $3 million
decrease in margins from optimization activities. See the “Allocation
Agreement between AEP East companies and AEP West companies and CSW
Operating Agreement” section of Note 3.
|
|
·
|
Transmission
Revenues decreased $10 million primarily due to the elimination of
SECA
revenues as of April 1, 2006. At this time, we have a pending proposal
with the FERC to replace SECA revenues. See the “Transmission Rate
Proceedings at the FERC” section of Note 3.
|
|
·
|
Other
revenue increased $16 million primarily due to a write off of previously
deferred gains on sales of allowances associated with the Virginia
Environmental and Reliability Costs (E&R) case. See “APCo Virginia
Environmental and Reliability Costs” section of Note
3.
|
·
|
Other
Operation and Maintenance expenses decreased $6 million mainly due
to a
decrease in expenses associated with the Transmission Equalization
Agreement with the addition of the Wyoming-Jacksons Ferry 765 kV
line,
which was energized and placed in service in June 2006. This decrease
was
partially offset by a write off of deferred maintenance expenses
associated with the E&R case. See “APCo Virginia Environmental and
Reliability Costs” section of Note 3.
|
·
|
Depreciation
and Amortization expenses increased $11 million primarily due to
a write
off of previously deferred depreciation expenses associated with
the
E&R case. See “APCo Virginia Environmental and Reliability Costs”
section of Note 3.
|
·
|
Carrying
Costs Income (Expense) decreased $29 million primarily due to a write
off
of previously recorded carrying costs income associated with the
E&R
case. See “APCo Virginia Environmental and Reliability Costs” section of
Note 3.
|
·
|
Other
Income increased $7 million primarily due to interest income related
to an
increase in Advances to Affiliates and an increase in allowance for
funds
during construction (AFUDC).
|
Nine
Months Ended September 30, 2005
|
$
|
108
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
12
|
||||||
Off-system
Sales
|
34
|
||||||
Transmission
Revenues
|
(27
|
)
|
|||||
Other
|
15
|
||||||
Total
Change in Gross Margin
|
34
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
9
|
||||||
Depreciation
and Amortization
|
(11
|
)
|
|||||
Taxes
Other Than Income Taxes
|
1
|
||||||
Carrying
Costs Income (Expense)
|
(19
|
)
|
|||||
Other
Income
|
12
|
||||||
Interest
Expense
|
(13
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(21
|
)
|
|||||
Income
Tax Expense
|
(7
|
)
|
|||||
Nine
Months Ended September 30, 2006
|
$
|
114
|
·
|
Retail
Margins increased $12 million in comparison to 2005 primarily
due
to:
|
|
·
|
a
$16 million increase in retail revenues primarily related to
two new
industrial customers;
|
|
·
|
a
$14 million reduction in capacity settlement payments under the
Interconnection Agreement due to our lower member load ratio
(MLR) share
and our increased generation capacity and;
|
|
·
|
an
$11 million increase in revenues related to financial transmission
rights,
net of congestion. The increase in financial transmission rights
revenue
is due to improved management of price risk related to serving
retail load
under current transmission constraints. Retail Margin increases
were
partially offset by;
|
|
·
|
a $28 million decrease related to an increase in sharing of off-system sales margins with retail customers due to higher off-system sales. This sharing mechanism was reinstated in West Virginia effective July 1, 2006 in conjunction with our West Virginia rate case. | |
·
|
Off-system
Sales increased $34 million primarily due to $42 million increase
in
physical sales margins and a $22 million increase from lower
sharing of
off-system sales margins under the SIA offset by a $30 million
decrease in
margins from optimization activities. See the “Allocation Agreement
between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
|
|
·
|
Transmission
Revenues decreased $27 million primarily due to the elimination
of SECA
revenues as of April 1, 2006 and a provision of $5 million for
potential
SECA refunds pending settlement negotiations with various intervenors.
At
this time, we have a pending proposal with the FERC to replace
SECA
revenues. See the “Transmission Rate Proceedings at the FERC” section of
Note 3.
|
|
·
|
Other
revenue increased $15 million primarily due to a write off of
previously
deferred gains on sales of allowances associated with the E&R case and
higher gains on sales of allowances. See “APCo Virginia Environmental and
Reliability Costs” section of Note
3.
|
·
|
Other
Operation and Maintenance expenses decreased $9 million mainly due
to a
decrease in expenses associated with the Transmission Equalization
Agreement with the addition of the Wyoming-Jacksons Ferry 765 kV
line,
which was energized and placed in service in June 2006, partially
offset
by a write off of previously deferred maintenance expenses associated
with
the E&R case. See “APCo Virginia Environmental and Reliability Costs”
section of Note 3.
|
·
|
Depreciation
and Amortization expenses increased $11 million primarily due to
a write
off of previously deferred depreciation expenses associated with
the
E&R case. See “APCo Virginia Environmental and Reliability Costs”
section of Note 3.
|
·
|
Carrying
Costs Income (Expense) decreased $19 million primarily due to write
off of
previously recorded carrying costs income associated with the E&R
case. See “APCo Virginia Environmental and Reliability Costs” section of
Note 3.
|
·
|
Other
Income increased $12 million primarily due to interest income related
to
an increase in Advances to Affiliates and an increase in
AFUDC.
|
·
|
Interest
Expense increased $13 million primarily due to long-term debt issuances
in
2006, partially offset by an increase in allowance for borrowed funds
used
during construction and a write off of previously deferred AFUDC
associated with the E&R case. See “APCo Virginia Environmental and
Reliability Costs” section of Note
3.
|
Moody’s
|
S&P
|
Fitch
|
|||
Senior
Unsecured Debt
|
Baa2
|
BBB
|
BBB+
|
2006
|
2005
|
||||||
(in
thousands)
|
|||||||
Cash
and Cash Equivalents at Beginning of Period
|
$
|
1,741
|
$
|
1,543
|
|||
Net
Cash Flows From (Used For):
|
|||||||
Operating
Activities
|
436,795
|
180,504
|
|||||
Investing
Activities
|
(725,650
|
)
|
(479,420
|
)
|
|||
Financing
Activities
|
288,363
|
298,938
|
|||||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
(492
|
)
|
22
|
||||
Cash
and Cash Equivalents at End of Period
|
$
|
1,249
|
$
|
1,565
|
Principal
Amount
|
Interest
|
Due
|
|||||
Type
of Debt
|
Rate
|
Date
|
|||||
(in
thousands)
|
(%)
|
||||||
Senior
Unsecured Notes
|
$
|
250,000
|
5.55
|
2011
|
|||
Senior
Unsecured Notes
|
250,000
|
6.375
|
2036
|
||||
Pollution
Control Bonds
|
50,275
|
Variable
|
2036
|
Principal
Amount
|
Interest
|
Due
|
|||||
Type
of Debt
|
Rate
|
Date
|
|||||
(in
thousands)
|
(%)
|
||||||
First
Mortgage Bonds
|
$
|
100,000
|
6.80
|
2006
|
|||
Other
Debt
|
8
|
13.718
|
2026
|
MTM
Risk Management Contracts
|
Cash
Flow &
Fair
Value Hedges
|
DETM
Assignment (a)
|
Total
|
||||||||||
Current
Assets
|
$
|
85,654
|
$
|
7,481
|
$
|
-
|
$
|
93,135
|
|||||
Noncurrent
Assets
|
107,705
|
510
|
-
|
108,215
|
|||||||||
Total
MTM Derivative Contract Assets
|
193,359
|
7,991
|
-
|
201,350
|
|||||||||
Current
Liabilities
|
(64,432
|
)
|
(1,979
|
)
|
(1,881
|
)
|
(68,292
|
)
|
|||||
Noncurrent
Liabilities
|
(70,002
|
)
|
(699
|
)
|
(9,138
|
)
|
(79,839
|
)
|
|||||
Total
MTM Derivative Contract Liabilities
|
(134,434
|
)
|
(2,678
|
)
|
(11,019
|
)
|
(148,131
|
)
|
|||||
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
$
|
58,925
|
$
|
5,313
|
$
|
(11,019
|
)
|
$
|
53,219
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
$
|
56,407
|
||
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
(6,079
|
)
|
||
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
121
|
|||
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
(315
|
)
|
||
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
316
|
|||
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
6,107
|
|||
Changes
due to SIA Agreement (c)
|
(6,533
|
)
|
||
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
8,901
|
|||
Total
MTM Risk Management Contract Net Assets
|
58,925
|
|||
Net
Cash Flow & Fair Value Hedge Contracts
|
5,313
|
|||
DETM
Assignment (e)
|
(11,019
|
)
|
||
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
$
|
53,219
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(d)
|
“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.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving an indication
of
when these MTM amounts will settle and generate
cash.
|
Remainder
2006
|
2007
|
2008
|
2009
|
2010
|
After
2010
|
Total
|
||||||||||||||||
Prices
Actively Quoted - Exchange Traded
Contracts
|
$
|
1,794
|
$
|
12,885
|
$
|
4,663
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
19,342
|
||||||||
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
4,076
|
11,246
|
4,922
|
7,304
|
-
|
-
|
27,548
|
|||||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
(43
|
)
|
(4,690
|
)
|
1,149
|
4,648
|
8,331
|
2,640
|
12,035
|
|||||||||||||
Total
|
$
|
5,827
|
$
|
19,441
|
$
|
10,734
|
$
|
11,952
|
$
|
8,331
|
$
|
2,640
|
$
|
58,925
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Power
|
Foreign
Currency
|
Interest
Rate
|
Total
|
||||||||||
Beginning
Balance in AOCI December 31, 2005
|
$
|
(1,480
|
)
|
$
|
(171
|
)
|
$
|
(14,770
|
)
|
$
|
(16,421
|
)
|
|
Changes
in Fair Value
|
4,482
|
-
|
4,951
|
9,433
|
|||||||||
Impact
due to Changes in SIA (a)
|
(442
|
)
|
-
|
-
|
(442
|
)
|
|||||||
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
2,261
|
5
|
1,757
|
4,023
|
|||||||||
Ending
Balance in AOCI September 30, 2006
|
$
|
4,821
|
$
|
(166
|
)
|
$
|
(8,062
|
)
|
$
|
(3,407
|
)
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
Nine
Months Ended
September
30, 2006
|
Twelve
Months Ended
December
31, 2005
|
||||||||||||||||
(in
thousands)
|
(in
thousands)
|
||||||||||||||||
End
|
High
|
Average
|
Low
|
End
|
High
|
Average
|
Low
|
||||||||||
$655
|
$1,915
|
$683
|
$365
|
$732
|
$1,216
|
$579
|
$209
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
REVENUES
|
|||||||||||||
Electric
Generation, Transmission and Distribution
|
$
|
588,684
|
$
|
468,558
|
$
|
1,612,735
|
$
|
1,380,928
|
|||||
Sales
to AEP Affiliates
|
57,177
|
99,551
|
177,557
|
237,648
|
|||||||||
Other
|
2,740
|
2,013
|
7,338
|
6,343
|
|||||||||
TOTAL
|
648,601
|
570,122
|
1,797,630
|
1,624,919
|
|||||||||
EXPENSES
|
|||||||||||||
Fuel
and Other Consumables for Electric Generation
|
184,275
|
161,154
|
506,368
|
402,057
|
|||||||||
Purchased
Electricity for Resale
|
41,027
|
24,217
|
98,622
|
79,182
|
|||||||||
Purchased
Electricity from AEP Affiliates
|
130,826
|
108,008
|
356,682
|
341,994
|
|||||||||
Other
Operation
|
63,259
|
78,421
|
210,914
|
228,916
|
|||||||||
Maintenance
|
53,874
|
44,865
|
138,381
|
129,321
|
|||||||||
Depreciation
and Amortization
|
61,160
|
50,284
|
157,518
|
146,734
|
|||||||||
Taxes
Other Than Income Taxes
|
24,464
|
23,696
|
70,355
|
71,127
|
|||||||||
TOTAL
|
558,885
|
490,645
|
1,538,840
|
1,399,331
|
|||||||||
OPERATING
INCOME
|
89,716
|
79,477
|
258,790
|
225,588
|
|||||||||
Other
Income (Expense):
|
|||||||||||||
Interest
Income
|
2,463
|
662
|
6,228
|
1,667
|
|||||||||
Carrying
Costs Income (Expense)
|
(27,316
|
)
|
1,255
|
(13,532
|
)
|
5,320
|
|||||||
Allowance
for Equity Funds Used During Construction
|
6,748
|
1,791
|
13,307
|
6,559
|
|||||||||
Interest
Expense
|
(27,103
|
)
|
(24,976
|
)
|
(89,024
|
)
|
(76,320
|
)
|
|||||
INCOME
BEFORE INCOME TAXES
|
44,508
|
58,209
|
175,769
|
162,814
|
|||||||||
Income
Tax Expense
|
13,972
|
20,837
|
61,992
|
54,557
|
|||||||||
NET
INCOME
|
30,536
|
37,372
|
113,777
|
108,257
|
|||||||||
Preferred
Stock Dividend Requirements Including Capital Stock Expense
and Other
|
238
|
238
|
714
|
1,940
|
|||||||||
EARNINGS
APPLICABLE TO COMMON STOCK
|
$
|
30,298
|
$
|
37,134
|
$
|
113,063
|
$
|
106,317
|
Common
Stock
|
Paid-in
Capital
|
Retained
Earnings
|
Accumulated
Other Comprehensive Income (Loss)
|
Total
|
||||||||||||
DECEMBER
31, 2004
|
$
|
260,458
|
$
|
722,314
|
$
|
508,618
|
$
|
(81,672
|
)
|
$
|
1,409,718
|
|||||
Capital
Contribution From Parent
|
150,000
|
150,000
|
||||||||||||||
Preferred
Stock Dividends
|
(600
|
)
|
(600
|
)
|
||||||||||||
Capital
Stock Expense and Other
|
2,485
|
(1,340
|
)
|
1,145
|
||||||||||||
TOTAL
|
1,560,263
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $8,340
|
(15,490
|
)
|
(15,490
|
)
|
||||||||||||
NET
INCOME
|
108,257
|
108,257
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
92,767
|
|||||||||||||||
SEPTEMBER
30, 2005
|
$
|
260,458
|
$
|
874,799
|
$
|
614,935
|
$
|
(97,162
|
)
|
$
|
1,653,030
|
|||||
DECEMBER
31, 2005
|
$
|
260,458
|
$
|
924,837
|
$
|
635,016
|
$
|
(16,610
|
)
|
$
|
1,803,701
|
|||||
Common
Stock Dividends
|
(7,500
|
)
|
(7,500
|
)
|
||||||||||||
Preferred
Stock Dividends
|
(600
|
)
|
(600
|
)
|
||||||||||||
Capital
Stock Expense and Other
|
118
|
(114
|
)
|
4
|
||||||||||||
TOTAL
|
1,795,605
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Income, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of
$7,007
|
13,014
|
13,014
|
||||||||||||||
NET
INCOME
|
113,777
|
113,777
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
126,791
|
|||||||||||||||
SEPTEMBER
30, 2006
|
$
|
260,458
|
$
|
924,955
|
$
|
740,579
|
$
|
(3,596
|
)
|
$
|
1,922,396
|
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Cash
and Cash Equivalents
|
$
|
1,249
|
$
|
1,741
|
|||
Advances
to Affiliates
|
93,764
|
-
|
|||||
Accounts
Receivable:
|
|||||||
Customers
|
165,193
|
141,810
|
|||||
Affiliated
Companies
|
126,586
|
153,453
|
|||||
Accrued
Unbilled Revenues
|
29,073
|
51,201
|
|||||
Miscellaneous
|
4,326
|
527
|
|||||
Allowance
for Uncollectible Accounts
|
(4,415
|
)
|
(1,805
|
)
|
|||
Total Accounts Receivable
|
320,763
|
345,186
|
|||||
Fuel
|
61,892
|
64,657
|
|||||
Materials
and Supplies
|
54,286
|
54,967
|
|||||
Risk
Management Assets
|
93,135
|
132,247
|
|||||
Accrued
Tax Benefits
|
3,470
|
32,979
|
|||||
Regulatory
Asset for Under-Recovered Fuel Costs
|
34,028
|
30,697
|
|||||
Prepayments
and Other
|
13,230
|
44,432
|
|||||
TOTAL
|
675,817
|
706,906
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric:
|
|||||||
Production
|
2,836,442
|
2,798,157
|
|||||
Transmission
|
1,595,963
|
1,266,855
|
|||||
Distribution
|
2,218,402
|
2,141,153
|
|||||
Other
|
336,999
|
323,158
|
|||||
Construction
Work in Progress
|
784,644
|
647,638
|
|||||
Total
|
7,772,450
|
7,176,961
|
|||||
Accumulated
Depreciation and Amortization
|
2,458,665
|
2,524,855
|
|||||
TOTAL
- NET
|
5,313,785
|
4,652,106
|
|||||
OTHER
NONCURRENT ASSETS
|
|||||||
Regulatory
Assets
|
419,891
|
457,294
|
|||||
Long-term
Risk Management Assets
|
108,215
|
176,231
|
|||||
Deferred
Charges and Other
|
237,113
|
261,556
|
|||||
TOTAL
|
765,219
|
895,081
|
|||||
TOTAL
ASSETS
|
$
|
6,754,821
|
$
|
6,254,093
|
2006
|
2005
|
||||||
CURRENT
LIABILITIES
|
(in
thousands)
|
||||||
Advances
from Affiliates
|
$
|
-
|
$
|
194,133
|
|||
Accounts
Payable:
|
|||||||
General
|
274,165
|
230,570
|
|||||
Affiliated
Companies
|
113,461
|
85,941
|
|||||
Long-term
Debt Due Within One Year - Nonaffiliated
|
141,696
|
146,999
|
|||||
Risk
Management Liabilities
|
68,292
|
121,165
|
|||||
Customer
Deposits
|
56,263
|
79,854
|
|||||
Accrued
Taxes
|
63,395
|
49,833
|
|||||
Accrued
Interest
|
59,394
|
28,614
|
|||||
Other
|
86,917
|
80,132
|
|||||
TOTAL
|
863,583
|
1,017,241
|
|||||
NONCURRENT
LIABILITIES
|
|||||||
Long-term
Debt - Nonaffiliated
|
2,356,175
|
1,904,379
|
|||||
Long-term
Debt - Affiliated
|
100,000
|
100,000
|
|||||
Long-term
Risk Management Liabilities
|
79,839
|
147,117
|
|||||
Deferred
Income Taxes
|
937,835
|
952,497
|
|||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
315,346
|
201,230
|
|||||
Deferred
Credits and Other
|
161,884
|
110,144
|
|||||
TOTAL
|
3,951,079
|
3,415,367
|
|||||
TOTAL
LIABILITIES
|
4,814,662
|
4,432,608
|
|||||
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
17,763
|
17,784
|
|||||
Commitments
and Contingencies (Note 5)
|
|||||||
COMMON
SHAREHOLDER’S EQUITY
|
|||||||
Common
Stock - No Par Value:
|
|||||||
Authorized
- 30,000,000 Shares
|
|||||||
Outstanding
- 13,499,500 Shares
|
260,458
|
260,458
|
|||||
Paid-in
Capital
|
924,955
|
924,837
|
|||||
Retained
Earnings
|
740,579
|
635,016
|
|||||
Accumulated
Other Comprehensive Income (Loss)
|
(3,596
|
)
|
(16,610
|
)
|
|||
TOTAL
|
1,922,396
|
1,803,701
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
6,754,821
|
$
|
6,254,093
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
113,777
|
$
|
108,257
|
|||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
157,518
|
146,734
|
|||||
Deferred
Income Taxes
|
(7,753
|
)
|
25,103
|
||||
Carrying
Costs (Income) Expense
|
13,532
|
(5,320
|
)
|
||||
Mark-to-Market
of Risk Management Contracts
|
(3,817
|
)
|
(21,412
|
)
|
|||
Pension
Contributions to Qualified Plan Trusts
|
-
|
(59,812
|
)
|
||||
Over/Under
Fuel Recovery, Net
|
830
|
(21,001
|
)
|
||||
Change
in Other Noncurrent Assets
|
8,466
|
361
|
|||||
Change
in Other Noncurrent Liabilities
|
20,187
|
(10,306
|
)
|
||||
Changes
in Components of Working Capital:
|
|||||||
Accounts
Receivable, Net
|
24,423
|
2,899
|
|||||
Fuel,
Materials and Supplies
|
3,446
|
(7,467
|
)
|
||||
Margin
Deposits
|
27,103
|
(38,634
|
)
|
||||
Accounts
Payable
|
22,063
|
54,994
|
|||||
Customer
Deposits
|
(23,591
|
)
|
52,302
|
||||
Accrued
Taxes, Net
|
43,071
|
(39,022
|
)
|
||||
Accrued
Interest
|
30,780
|
15,467
|
|||||
Other
Current Assets
|
4,972
|
(20,482
|
)
|
||||
Other
Current Liabilities
|
1,788
|
(2,157
|
)
|
||||
Net
Cash Flows From Operating Activities
|
436,795
|
180,504
|
|||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(633,164
|
)
|
(421,544
|
)
|
|||
Change
in Other Cash Deposits, Net
|
(873
|
)
|
(24
|
)
|
|||
Change
in Advances to Affiliates, Net
|
(93,764
|
)
|
(67,532
|
)
|
|||
Proceeds
from Sales of Assets
|
2,151
|
9,680
|
|||||
Net
Cash Flows Used For Investing Activities
|
(725,650
|
)
|
(479,420
|
)
|
|||
FINANCING
ACTIVITIES
|
|||||||
Capital
Contributions from Parent
|
-
|
150,000
|
|||||
Issuance
of Long-term Debt - Nonaffiliated
|
544,364
|
840,469
|
|||||
Issuance
of Long-term Debt - Affiliated
|
-
|
100,000
|
|||||
Change
in Advances from Affiliates, Net
|
(194,133
|
)
|
(211,060
|
)
|
|||
Retirement
of Long-term Debt - Nonaffiliated
|
(100,008
|
)
|
(575,007
|
)
|
|||
Retirement
of Preferred Stock
|
(16
|
)
|
-
|
||||
Principal
Payments for Capital Lease Obligations
|
(4,008
|
)
|
(4,864
|
)
|
|||
Funds
From Amended Coal Contract, Net
|
50,264
|
-
|
|||||
Dividends
Paid on Common Stock
|
(7,500
|
)
|
-
|
||||
Dividends
Paid on Cumulative Preferred Stock
|
(600
|
)
|
(600
|
)
|
|||
Net
Cash Flows From Financing Activities
|
288,363
|
298,938
|
|||||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
(492
|
)
|
22
|
||||
Cash
and Cash Equivalents at Beginning of Period
|
1,741
|
1,543
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
1,249
|
$
|
1,565
|
|||
SUPPLEMENTAL
DISCLOSURE
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
51,537
|
$
|
56,253
|
|||
Net
Cash Paid for Income Taxes
|
12,047
|
61,514
|
|||||
Noncash
Acquisitions Under Capital Leases
|
2,598
|
1,087
|
|||||
Construction
Expenditures Included in Accounts Payable at September 30,
|
131,692
|
54,380
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
Footnote
Reference
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
Third
Quarter of 2005
|
$
|
34
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
36
|
||||||
Off-system
Sales
|
20
|
||||||
Transmission
Revenues
|
(6
|
)
|
|||||
Other
|
(2
|
)
|
|||||
Total
Change in Gross Margin
|
48
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(2
|
)
|
|||||
Depreciation
and Amortization
|
(14
|
)
|
|||||
Asset
Impairments and Other Related Charges
|
39
|
||||||
Taxes
Other Than Income Taxes
|
5
|
||||||
Carrying
Costs Income
|
(1
|
)
|
|||||
Interest
Expense
|
(2
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
25
|
||||||
Income
Tax Expense
|
(23
|
)
|
|||||
Third
Quarter of 2006
|
$
|
84
|
·
|
Retail
Margins were $36 million higher than the prior period primarily due
to
Rate Stabilization Plan (RSP) and Transition Regulatory Asset rate
increases effective January 1, 2006 as well as the addition of Monongahela
Power’s Ohio customers on December 31, 2005, partially offset by an
increase in delivered fuel costs.
|
·
|
Off-system
Sales increased $20 million primarily due to $13 million increase
in
physical sales margins and a $10 million increase from lower sharing
of
off-system sales margins under the SIA. See the “Allocation Agreement
between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
|
·
|
Transmission
Revenues decreased $6 million primarily due to the elimination of
SECA
revenues as of April 1, 2006. At this time, we have a pending proposal
with the FERC to replace SECA revenues. See the “Transmission Rate
Proceedings at the FERC” section of Note
3.
|
·
|
Depreciation
and Amortization expense increased $14 million due to the increase
in the
amortization of regulatory assets and a greater depreciable base
resulting
primarily from the acquisitions of the Waterford Plant and Monongahela
Power’s Ohio assets in late 2005.
|
·
|
Asset
Impairments and Other Related Charges of $39 million were recorded
last
year due to the 2005 retirement of units 1 and 2 at our Conesville
Plant.
|
·
|
Taxes
Other Than Income Taxes decreased $5 million due to favorable accrual
adjustments to property taxes in 2006 and unfavorable accrual adjustments
in 2005 partially offset by the increase in property taxes associated
with
the Waterford and Monongahela asset
additions.
|
Nine
Months Ended September 30, 2005
|
$
|
116
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
93
|
||||||
Off-system
Sales
|
29
|
||||||
Transmission
Revenues
|
(13
|
)
|
|||||
Other
|
6
|
||||||
Total
Change in Gross Margin
|
115
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(19
|
)
|
|||||
Depreciation
and Amortization
|
(41
|
)
|
|||||
Asset
Impairments and Other Related Charges
|
39
|
||||||
Taxes
Other Than Income Taxes
|
(7
|
)
|
|||||
Carrying
Costs Income
|
(6
|
)
|
|||||
Interest
Expense
|
(8
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(42
|
)
|
|||||
Income
Tax Expense
|
(21
|
)
|
|||||
Nine
Months Ended September 30, 2006
|
$
|
168
|
·
|
Retail
Margins increased $93 million primarily due to the RSP and Transition
Regulatory Asset rate increases effective January 1, 2006, lower
capacity
settlement costs, and the addition of Monongahela Power’s Ohio customers
on December 31, 2005, partially offset by an increase in delivered
fuel
costs.
|
·
|
Off-system
Sales increased $29 million due to $30 million increase in physical
sales
margins and a $12 million increase from lower sharing of off-system
sales
margins under the SIA offset by a decrease in margins from optimization
activities. See the “Allocation Agreement between AEP East companies and
AEP West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Transmission
Revenues decreased $13 million primarily due to the elimination of
SECA
revenues as of April 1, 2006 and a provision of $3 million recorded
in
2006 related to potential SECA refunds pending settlement negotiations
with various intervenors. At this time, we have a pending proposal
with
the FERC to replace SECA revenues. See the “Transmission Rate Proceedings
at the FERC” section of Note 3.
|
·
|
Other
revenues increased $6 million primarily due to higher gains on sales
of
emission allowances.
|
·
|
Other
Operation and Maintenance increased $19 million due to an increase
in PJM
administrative fees, an increase in transmission expenses related
to the
AEP Transmission Equalization Agreement, favorable adjustments in
the
prior year related to the corporate owned life insurance policy and
increased expenses related to factored receivables and uncollectible
accounts. The increases were partially offset by the recognition
of
a regulatory asset related to recent PUCO orders regarding
distribution service reliability and restoration
costs.
|
·
|
Depreciation
and Amortization expense increased $41 million primarily due to the
increase in the amortization of regulatory assets and a greater
depreciable base resulting primarily from the acquisitions of the
Waterford Plant and Monongahela Power’s Ohio assets. In addition, the 2005
RSP order resulted in a reversal of unused shopping credits of $18
million
offset by the establishment of a $7 million regulatory liability
to
benefit low-income customers and for economic
development.
|
·
|
Asset
Impairments and Other Related Charges in the amount of $39 million
were
recorded last year due to the 2005 retirement of units 1 and 2 at
our
Conesville Plant.
|
·
|
Taxes
Other Than Income Taxes increased $7 million due to the increase
in
property taxes associated with the Waterford and Monongahela asset
additions partially offset by accrual adjustments to property taxes
that
were favorable in 2006 and unfavorable in 2005.
|
·
|
Carrying
Costs Income decreased $6 million primarily due to the completion
of
deferrals of carrying costs on environmental capital expenditures
from
2004 and 2005 that are now recovered during 2006 through 2008 according
to
the RSP.
|
·
|
Interest
Expense increased $8 million primarily due to a new long-term debt
issuance during the fourth quarter of
2005.
|
Moody’s
|
S&P
|
Fitch
|
|||
Senior
Unsecured Debt
|
A3
|
BBB
|
A-
|
MTM
Risk Management Contracts
|
Cash
Flow Hedges
|
DETM
Assignment (a)
|
Total
|
||||||||||
Current
Assets
|
$
|
53,028
|
$
|
4,782
|
$
|
-
|
$
|
57,810
|
|||||
Noncurrent
Assets
|
68,304
|
326
|
-
|
68,630
|
|||||||||
Total
MTM Derivative Contract Assets
|
121,332
|
5,108
|
-
|
126,440
|
|||||||||
Current
Liabilities
|
(39,606
|
)
|
(743
|
)
|
(1,202
|
)
|
(41,551
|
)
|
|||||
Noncurrent
Liabilities
|
(44,001
|
)
|
(8
|
)
|
(5,841
|
)
|
(49,850
|
)
|
|||||
Total
MTM Derivative Contract Liabilities
|
(83,607
|
)
|
(751
|
)
|
(7,043
|
)
|
(91,401
|
)
|
|||||
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
$
|
37,725
|
$
|
4,357
|
$
|
(7,043
|
)
|
$
|
35,039
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
$
|
33,322
|
||
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
(5,405
|
)
|
||
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
146
|
|||
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
(138
|
)
|
||
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
381
|
|||
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
12,996
|
|||
Changes
Due to SIA (c)
|
(3,864
|
)
|
||
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
287
|
|||
Total
MTM Risk Management Contract Net Assets
|
37,725
|
|||
Net
Cash Flow Hedge Contracts
|
4,357
|
|||
DETM
Assignment (e)
|
(7,043
|
)
|
||
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
$
|
35,039
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(d)
|
“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.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving an indication
of
when these MTM amounts will settle and generate
cash.
|
Remainder
2006
|
2007
|
2008
|
2009
|
2010
|
After
2010
|
Total
|
|||||||||||||||
Prices
Actively Quoted - Exchange Traded
Contracts
|
$
|
1,146
|
$
|
8,236
|
$
|
2,981
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
12,363
|
|||||||
Prices
Provided by Other External Sources
- OTC Broker
Quotes
(a)
|
2,425
|
6,394
|
3,095
|
4,669
|
-
|
-
|
16,583
|
||||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
4
|
(2,247
|
)
|
1,039
|
2,971
|
5,324
|
1,688
|
8,779
|
|||||||||||||
Total
|
$
|
3,575
|
$
|
12,383
|
$
|
7,115
|
$
|
7,640
|
$
|
5,324
|
$
|
1,688
|
$
|
37,725
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Power
|
||||
Beginning
Balance in AOCI December 31, 2005
|
$
|
(859
|
)
|
|
Changes
in Fair Value
|
2,853
|
|||
Impact
due to Changes in SIA (a)
|
(261
|
)
|
||
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
1,348
|
|||
Ending
Balance in AOCI September 30, 2006
|
$
|
3,081
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
Nine
Months Ended
September
30, 2006
|
Twelve
Months Ended
December
31, 2005
|
||||||||||||||||
(in
thousands)
|
(in
thousands)
|
||||||||||||||||
End
|
High
|
Average
|
Low
|
End
|
High
|
Average
|
Low
|
||||||||||
$418
|
$1,224
|
$414
|
$233
|
$424
|
$705
|
$335
|
$121
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
REVENUES
|
|||||||||||||
Electric
Generation, Transmission and Distribution
|
$
|
513,643
|
$
|
406,525
|
$
|
1,321,422
|
$
|
1,074,099
|
|||||
Sales
to AEP Affiliates
|
24,806
|
46,698
|
60,337
|
103,939
|
|||||||||
Other
|
1,449
|
1,345
|
4,016
|
3,653
|
|||||||||
TOTAL
|
539,898
|
454,568
|
1,385,775
|
1,181,691
|
|||||||||
EXPENSES
|
|||||||||||||
Fuel
and Other Consumables for Electric Generation
|
90,510
|
72,550
|
231,543
|
191,188
|
|||||||||
Purchased
Electricity for Resale
|
35,449
|
9,016
|
87,902
|
26,922
|
|||||||||
Purchased
Electricity from AEP Affiliates
|
102,669
|
109,274
|
272,334
|
284,221
|
|||||||||
Other
Operation
|
66,195
|
56,276
|
180,022
|
152,833
|
|||||||||
Maintenance
|
14,704
|
21,863
|
56,140
|
63,947
|
|||||||||
Asset
Impairments and Other Related Charges
|
-
|
39,109
|
-
|
39,109
|
|||||||||
Depreciation
and Amortization
|
51,149
|
37,454
|
143,495
|
102,985
|
|||||||||
Taxes
Other Than Income Taxes
|
38,586
|
43,422
|
119,875
|
112,657
|
|||||||||
TOTAL
|
399,262
|
388,964
|
1,091,311
|
973,862
|
|||||||||
OPERATING
INCOME
|
140,636
|
65,604
|
294,464
|
207,829
|
|||||||||
Other
Income (Expense):
|
|||||||||||||
Interest
Income
|
989
|
1,038
|
1,919
|
2,666
|
|||||||||
Carrying
Costs Income
|
1,046
|
1,800
|
3,082
|
8,716
|
|||||||||
Allowance
for Equity Funds Used During Construction
|
659
|
229
|
1,466
|
1,036
|
|||||||||
Interest
Expense
|
(15,813
|
)
|
(13,508
|
)
|
(50,247
|
)
|
(42,089
|
)
|
|||||
INCOME
BEFORE INCOME TAXES
|
127,517
|
55,163
|
250,684
|
178,158
|
|||||||||
Income
Tax Expense
|
43,496
|
20,938
|
83,064
|
61,814
|
|||||||||
NET INCOME | 84,021 | 34,225 | 167,620 | 116,344 | |||||||||
Capital
Stock Expense
|
39
|
254
|
118
|
2,366
|
|||||||||
EARNINGS APPLICABLE TO COMMON STOCK | $ | 83,982 | $ | 33,971 | $ | 167,502 | $ | 113,978 |
The
common stock of CSPCo is wholly-owned by AEP.
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
Common
Stock
|
Paid-in
Capital
|
Retained
Earnings
|
Accumulated
Other Comprehensive Income (Loss)
|
Total
|
||||||||||||
DECEMBER
31, 2004
|
$
|
41,026
|
$
|
577,415
|
$
|
341,025
|
$
|
(60,816
|
)
|
$
|
898,650
|
|||||
Common
Stock Dividends
|
(85,500
|
)
|
(85,500
|
)
|
||||||||||||
Capital
Stock Expense and Other
|
2,366
|
(2,366
|
)
|
-
|
||||||||||||
TOTAL
|
813,150
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $3,655
|
(6,789
|
)
|
(6,789
|
)
|
||||||||||||
NET
INCOME
|
116,344
|
116,344
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
109,555
|
|||||||||||||||
SEPTEMBER
30, 2005
|
$
|
41,026
|
$
|
579,781
|
$
|
369,503
|
$
|
(67,605
|
)
|
$
|
922,705
|
|||||
DECEMBER
31, 2005
|
$
|
41,026
|
$
|
580,035
|
$
|
361,365
|
$
|
(880
|
)
|
$
|
981,546
|
|||||
Common
Stock Dividends
|
(67,500
|
)
|
(67,500
|
)
|
||||||||||||
Capital
Stock Expense
|
118
|
(118
|
)
|
-
|
||||||||||||
TOTAL
|
914,046
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Income, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $2,121
|
3,940
|
3,940
|
||||||||||||||
NET
INCOME
|
167,620
|
167,620
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
171,560
|
|||||||||||||||
SEPTEMBER
30, 2006
|
$
|
41,026
|
$
|
580,153
|
$
|
461,367
|
$
|
3,060
|
$
|
1,085,606
|
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Cash
and Cash Equivalents
|
$
|
1,251
|
$
|
940
|
|||
Advances
to Affiliates
|
60,417
|
-
|
|||||
Accounts
Receivable:
|
|||||||
Customers
|
54,517
|
43,143
|
|||||
Affiliated
Companies
|
51,218
|
67,694
|
|||||
Accrued
Unbilled Revenues
|
15,687
|
10,086
|
|||||
Miscellaneous
|
5,185
|
2,012
|
|||||
Allowance
for Uncollectible Accounts
|
(1,380
|
)
|
(1,082
|
)
|
|||
Total Accounts Receivable
|
125,227
|
121,853
|
|||||
Fuel
|
33,556
|
28,579
|
|||||
Materials
and Supplies
|
30,742
|
27,519
|
|||||
Emission
Allowances
|
7,070
|
20,181
|
|||||
Risk
Management Assets
|
57,810
|
76,507
|
|||||
Accrued
Tax Benefits
|
-
|
36,838
|
|||||
Prepayments
and Other
|
11,284
|
23,546
|
|||||
TOTAL
|
327,357
|
335,963
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric:
|
|||||||
Production
|
1,889,414
|
1,874,652
|
|||||
Transmission
|
478,513
|
457,937
|
|||||
Distribution
|
1,451,842
|
1,380,722
|
|||||
Other
|
191,599
|
184,096
|
|||||
Construction
Work in Progress
|
224,854
|
129,246
|
|||||
Total
|
4,236,222
|
4,026,653
|
|||||
Accumulated
Depreciation and Amortization
|
1,589,465
|
1,500,858
|
|||||
TOTAL
- NET
|
2,646,757
|
2,525,795
|
|||||
OTHER
NONCURRENT ASSETS
|
|||||||
Regulatory
Assets
|
216,339
|
231,599
|
|||||
Long-term
Risk Management Assets
|
68,630
|
101,512
|
|||||
Deferred
Charges and Other
|
187,915
|
237,925
|
|||||
TOTAL
|
472,884
|
571,036
|
|||||
TOTAL
ASSETS
|
$
|
3,446,998
|
$
|
3,432,794
|
2006
|
2005
|
||||||
CURRENT
LIABILITIES
|
(in
thousands)
|
||||||
Advances
from Affiliates
|
$
|
-
|
$
|
17,609
|
|||
Accounts
Payable:
|
|||||||
General
|
104,090
|
59,134
|
|||||
Affiliated
Companies
|
57,910
|
59,399
|
|||||
Risk
Management Liabilities
|
41,551
|
69,036
|
|||||
Customer
Deposits
|
32,448
|
47,013
|
|||||
Accrued
Taxes
|
111,910
|
157,729
|
|||||
Other
|
47,351
|
50,229
|
|||||
TOTAL
|
395,260
|
460,149
|
|||||
NONCURRENT
LIABILITIES
|
|||||||
Long-term
Debt - Nonaffiliated
|
1,097,222
|
1,096,920
|
|||||
Long-term
Debt - Affiliated
|
100,000
|
100,000
|
|||||
Long-term
Risk Management Liabilities
|
49,850
|
84,291
|
|||||
Deferred
Income Taxes
|
494,805
|
498,232
|
|||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
177,801
|
165,344
|
|||||
Deferred
Credits and Other
|
46,454
|
46,312
|
|||||
TOTAL
|
1,966,132
|
1,991,099
|
|||||
TOTAL
LIABILITIES
|
2,361,392
|
2,451,248
|
|||||
Commitments
and Contingencies (Note 5)
|
|||||||
COMMON
SHAREHOLDER’S EQUITY
|
|||||||
Common
Stock - No Par Value Per Share:
|
|||||||
Authorized
- 24,000,000 Shares
|
|||||||
Outstanding
- 16,410,426 Shares
|
41,026
|
41,026
|
|||||
Paid-in
Capital
|
580,153
|
580,035
|
|||||
Retained
Earnings
|
461,367
|
361,365
|
|||||
Accumulated
Other Comprehensive Income (Loss)
|
3,060
|
(880
|
)
|
||||
TOTAL
|
1,085,606
|
981,546
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
$
|
3,446,998
|
$
|
3,432,794
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
167,620
|
$
|
116,344
|
|||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
143,495
|
102,985
|
|||||
Deferred
Income Taxes
|
(5,097
|
)
|
(9,441
|
)
|
|||
Asset
Impairments and Other Related Charges
|
-
|
39,109
|
|||||
Carrying
Costs Income
|
(3,082
|
)
|
(8,716
|
)
|
|||
Mark-to-Market
of Risk Management Contracts
|
(4,502
|
)
|
(12,767
|
)
|
|||
Pension
Contributions to Qualified Plan Trusts
|
-
|
(37,832
|
)
|
||||
Deferred
Property Taxes
|
49,518
|
47,640
|
|||||
Change
in Other Noncurrent Assets
|
(24,297
|
)
|
(24,839
|
)
|
|||
Change
in Other Noncurrent Liabilities
|
11,752
|
14,747
|
|||||
Changes
in Components of Working Capital:
|
|||||||
Accounts
Receivable, Net
|
(3,374
|
)
|
(7,748
|
)
|
|||
Fuel,
Materials and Supplies
|
(8,200
|
)
|
8,611
|
||||
Accounts
Payable
|
31,765
|
2,215
|
|||||
Customer
Deposits
|
(14,565
|
)
|
30,760
|
||||
Accrued
Taxes, Net
|
(8,981
|
)
|
(94,788
|
)
|
|||
Other
Current Assets
|
26,838
|
(14,809
|
)
|
||||
Other
Current Liabilities
|
(2,878
|
)
|
(10,471
|
)
|
|||
Net
Cash Flows From Operating Activities
|
356,012
|
141,000
|
|||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(207,875
|
)
|
(118,222
|
)
|
|||
Change
in Advances to Affiliates, Net
|
(60,417
|
)
|
141,550
|
||||
Purchase
of Waterford Plant
|
-
|
(218,356
|
)
|
||||
Other
|
8
|
4,639
|
|||||
Net
Cash Flows Used For Investing Activities
|
(268,284
|
)
|
(190,389
|
)
|
|||
FINANCING
ACTIVITIES
|
|||||||
Change
in Advances from Affiliates, Net
|
(17,609
|
)
|
138,541
|
||||
Principal
Payments for Capital Lease Obligations
|
(2,308
|
)
|
(2,642
|
)
|
|||
Dividends
Paid on Common Stock
|
(67,500
|
)
|
(85,500
|
)
|
|||
Net
Cash Flows From (Used For) Financing Activities
|
(87,417
|
)
|
50,399
|
||||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
311
|
1,010
|
|||||
Cash
and Cash Equivalents at Beginning of Period
|
940
|
58
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
1,251
|
$
|
1,068
|
|||
SUPPLEMENTARY
INFORMATION
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
52,958
|
$
|
50,095
|
|||
Net
Cash Paid for Income Taxes
|
35,561
|
109,382
|
|||||
Noncash
Acquisitions Under Capital Leases
|
2,130
|
520
|
|||||
Construction
Expenditures Included in Accounts Payable at September 30,
|
22,955
|
4,974
|
|||||
Assumption
of Liabilities in Connection with Waterford Plant Acquisition
|
-
|
2,295
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
Footnote
Reference
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Customer
Choice and Industry Restructuring
|
Note
4
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Acquisitions,
Assets Held for Sale and Asset Impairments
|
Note
8
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
Third
Quarter of 2005
|
$
|
53
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
(44
|
)
|
|||||
Off-system
Sales (a)
|
34
|
||||||
Transmission
Revenues
|
(4
|
)
|
|||||
Other
|
2
|
||||||
Total
Change in Gross Margin
|
(12
|
)
|
|||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(17
|
)
|
|||||
Depreciation
and Amortization
|
(5
|
)
|
|||||
Other
Income (Expense)
|
3
|
||||||
Interest
Expense
|
(1
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(20
|
)
|
|||||
Income
Tax Expense
|
14
|
||||||
Third
Quarter of 2006
|
$
|
35
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
·
|
Retail
Margins decreased $44 million primarily due to lower fuel recovery
as fuel
cost increases could not be recovered due to the Indiana fuel cap
and a
reduction in capacity revenues of $22 million under the Interconnection
Agreement. Capacity revenues declined due to our new peak demand
in July
2006 and our affiliates’ addition of generating capacity in
2005.
|
·
|
Off-system
Sales increased $34 million primarily due to the addition of new
municipal
contracts including new rates and increased demand beginning January
2006,
a $13 million increase in physical sales margins and a $10 million
increase from lower sharing of off-system sales margins under the
SIA. See
the “Allocation Agreement between AEP East companies and AEP West
companies and CSW Operating Agreement” section of Note
3.
|
·
|
Transmission
Revenues decreased $4 million primarily due to the elimination of
SECA
revenues as of April 1, 2006. At this time, we have a pending proposal
with the FERC to replace SECA revenues. See the “Transmission
Rate Proceedings at the FERC” section of Note
3.
|
·
|
Other Operation
and Maintenance expenses increased $17 million primarily due to the
abandonment of digital turbine control equipment at the Cook
Plant.
|
·
|
Depreciation
and Amortization increased $5 million primarily due to higher expense
related to capital additions.
|
Nine
Months Ended September 30, 2005
|
$
|
128
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
(55
|
)
|
|||||
Off-system
Sales (a)
|
63
|
||||||
Transmission
Revenues
|
(11
|
)
|
|||||
Other
|
11
|
||||||
Total
Change in Gross Margin
|
8
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(12
|
)
|
|||||
Depreciation
and Amortization
|
(9
|
)
|
|||||
Taxes
Other Than Income Taxes
|
(3
|
)
|
|||||
Other
Income (Expense)
|
4
|
||||||
Interest
Expense
|
(4
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(24
|
)
|
|||||
Income
Tax Expense
|
9
|
||||||
Nine
Months Ended September 30, 2006
|
$
|
121
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
·
|
Retail
Margins decreased $55 million primarily due to lower fuel recovery
as fuel
cost increases could not be recovered due to the Indiana fuel cap
and a
reduction in capacity settlement revenues of $27 million under the
Interconnection Agreement. Capacity revenues declined due to our
new peak
demand in July 2006 and our affiliates’ addition of generating capacity in
2005.
|
·
|
Off-system
Sales increased $63 million primarily due to the addition of new
municipal
contracts including new rates and increased demand beginning January
2006,
a $33 million increase in physical sales margins and a $12 million
increase from lower sharing of off-system sales margins under the
SIA,
offset by a $12 million decrease in margins from reduced optimization
activities. See the “Allocation Agreement between AEP East companies and
AEP West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Transmission
Revenues decreased $11 million primarily due to the elimination of
SECA
revenues as of April 1, 2006 and a $3 million provision for potential
SECA
refunds pending settlement negotiations with various intervenors.
At this
time, we have a pending proposal with the FERC to replace SECA
revenues. See the “Transmission Rate Proceedings at the FERC” section of
Note 3.
|
·
|
Other
revenues increased
$11 million primarily due to increased River Transportation Division
(RTD)
revenues for barging coal and gains on sales of emission allowances.
Related expenses which offset the RTD revenue increase are included
in
Other Operation on the Condensed Consolidated Statements of Income
resulting in our earning only a return approved under regulatory
order.
|
·
|
Other Operation
and Maintenance expenses increased $12 million primarily due to the
abandonment of digital turbine control equipment at the Cook Plant
and an
increase in RTD expenses.
|
·
|
Depreciation
and Amortization increased $9 million primarily due to higher expense
related to capital additions.
|
Moody’s
|
S&P
|
Fitch
|
|||
Senior
Unsecured Debt
|
Baa2
|
BBB
|
BBB
|
2006
|
2005
|
||||||
(in
thousands)
|
|||||||
Cash
and Cash Equivalents at Beginning of Period
|
$
|
854
|
$
|
511
|
|||
Net
Cash Flows From (Used For):
|
|||||||
Operating
Activities
|
456,313
|
276,523
|
|||||
Investing
Activities
|
(355,252
|
)
|
(238,875
|
)
|
|||
Financing
Activities
|
(101,209
|
)
|
(37,428
|
)
|
|||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
(148
|
)
|
220
|
||||
Cash
and Cash Equivalents at End of Period
|
$
|
706
|
$
|
731
|
Principal
Amount
|
Interest
|
Due
|
|||||
Type
of Debt
|
Rate
|
Date
|
|||||
(in
thousands)
|
(%)
|
||||||
Pollution
Control Bonds
|
$
|
50,000
|
Variable
|
2025
|
Principal
Amount
Paid
|
Interest
|
Due
|
|||||
Type
of Debt
|
Rate
|
Date
|
|||||
(in
thousands)
|
(%)
|
||||||
Pollution
Control Bonds
|
$
|
50,000
|
6.55
|
2025
|
MTM
Risk Management Contracts
|
Cash
Flow &
Fair
Value Hedges
|
DETM
Assignment (a)
|
Total
|
||||||||||
Current
Assets
|
$
|
55,747
|
$
|
5,010
|
$
|
-
|
$
|
60,757
|
|||||
Noncurrent
Assets
|
71,650
|
342
|
-
|
71,992
|
|||||||||
Total
MTM Derivative Contract Assets
|
127,397
|
5,352
|
-
|
132,749
|
|||||||||
Current
Liabilities
|
(42,116
|
)
|
(15,586
|
)
|
(1,259
|
)
|
(58,961
|
)
|
|||||
Noncurrent
Liabilities
|
(46,349
|
)
|
(8
|
)
|
(6,120
|
)
|
(52,477
|
)
|
|||||
Total
MTM Derivative Contract Liabilities
|
(88,465
|
)
|
(15,594
|
)
|
(7,379
|
)
|
(111,438
|
)
|
|||||
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
$
|
38,932
|
$
|
(10,242
|
)
|
$
|
(7,379
|
)
|
$
|
21,311
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
$
|
33,932
|
||
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
(538
|
)
|
||
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
|
(137
|
)
|
||
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
-
|
|||
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
(310
|
)
|
||
Changes
Due to SIA (c)
|
(3,940
|
)
|
||
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
9,925
|
|||
Total
MTM Risk Management Contract Net Assets
|
38,932
|
|||
Net
Cash Flow & Fair Value Hedge Contracts
|
(10,242
|
)
|
||
DETM
Assignment (e)
|
(7,379
|
)
|
||
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
$
|
21,311
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(d)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected in our Condensed
Consolidated Statements of Income. These net gains (losses) are recorded
as regulatory liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving an indication
of
when these MTM amounts will settle and generate
cash.
|
Remainder
2006
|
2007
|
2008
|
2009
|
2010
|
After
2010
|
Total
|
||||||||||||||||
Prices
Actively Quoted - Exchange Traded
Contracts
|
$
|
1,202
|
$
|
8,629
|
$
|
3,123
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
12,954
|
||||||||
Prices
Provided by Other External Sources
- OTC Broker
Quotes
(a)
|
2,395
|
6,585
|
3,260
|
4,892
|
-
|
-
|
17,132
|
|||||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
-
|
(2,602
|
)
|
988
|
3,113
|
5,579
|
1,768
|
8,846
|
||||||||||||||
Total
|
$
|
3,597
|
$
|
12,612
|
$
|
7,371
|
$
|
8,005
|
$
|
5,579
|
$
|
1,768
|
$
|
38,932
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Power
|
Interest
Rate
|
Total
|
||||||||
Beginning
Balance in AOCI December 31, 2005
|
$
|
(877
|
)
|
$
|
(2,590
|
)
|
$
|
(3,467
|
)
|
|
Changes
in Fair Value
|
2,978
|
(9,382
|
)
|
(6,404
|
)
|
|||||
Impact
due to Changes in SIA (a)
|
(267
|
)
|
-
|
(267
|
)
|
|||||
Reclassifications
from AOCI to Net Income for Cash Flow
Hedges Settled
|
1,394
|
241
|
1,635
|
|||||||
Ending
Balance in AOCI September 30, 2006
|
$
|
3,228
|
$
|
(11,731
|
)
|
$
|
(8,503
|
)
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
Nine
Months Ended
September
30, 2006
|
Twelve
Months Ended
December
31, 2005
|
||||||||||||||||
(in
thousands)
|
(in
thousands)
|
||||||||||||||||
End
|
High
|
Average
|
Low
|
End
|
High
|
Average
|
Low
|
||||||||||
$438
|
$1,283
|
$427
|
$242
|
$433
|
$720
|
$343
|
$124
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
REVENUES
|
|||||||||||||
Electric
Generation, Transmission and Distribution
|
$
|
449,259
|
$
|
391,361
|
$
|
1,224,609
|
$
|
1,095,621
|
|||||
Sales
to AEP Affiliates
|
54,793
|
103,141
|
223,728
|
277,223
|
|||||||||
Other
- Affiliated
|
12,903
|
11,745
|
37,838
|
34,215
|
|||||||||
Other
- Nonaffiliated
|
8,580
|
8,832
|
24,593
|
23,139
|
|||||||||
TOTAL
|
525,535
|
515,079
|
1,510,768
|
1,430,198
|
|||||||||
EXPENSES
|
|||||||||||||
Fuel
and Other Consumables for Electric Generation
|
98,135
|
93,557
|
283,734
|
253,255
|
|||||||||
Purchased
Electricity for Resale
|
20,450
|
11,784
|
46,993
|
35,786
|
|||||||||
Purchased
Electricity from AEP Affiliates
|
92,052
|
82,763
|
259,304
|
228,756
|
|||||||||
Other
Operation
|
125,170
|
122,927
|
357,882
|
343,239
|
|||||||||
Maintenance
|
56,960
|
42,300
|
142,531
|
144,988
|
|||||||||
Depreciation
and Amortization
|
47,895
|
42,726
|
136,681
|
127,695
|
|||||||||
Taxes
Other Than Income Taxes
|
18,472
|
18,268
|
56,343
|
53,246
|
|||||||||
TOTAL
|
459,134
|
414,325
|
1,283,468
|
1,186,965
|
|||||||||
OPERATING
INCOME
|
66,401
|
100,754
|
227,300
|
243,233
|
|||||||||
Other
Income (Expense):
|
|||||||||||||
Interest
Income
|
1,102
|
586
|
2,459
|
1,437
|
|||||||||
Allowance
for Equity Funds Used During Construction
|
2,517
|
563
|
5,881
|
3,252
|
|||||||||
Interest
Expense
|
(17,228
|
)
|
(16,343
|
)
|
(52,663
|
)
|
(48,427
|
)
|
|||||
INCOME
BEFORE INCOME TAXES
|
52,792
|
85,560
|
182,977
|
199,495
|
|||||||||
Income
Tax Expense
|
18,231
|
32,548
|
62,013
|
71,221
|
|||||||||
NET
INCOME
|
34,561
|
53,012
|
120,964
|
128,274
|
|||||||||
Preferred
Stock Dividend Requirements including Capital Stock Expense
|
85
|
86
|
255
|
311
|
|||||||||
EARNINGS
APPLICABLE TO COMMON STOCK
|
$
|
34,476
|
$
|
52,926
|
$
|
120,709
|
$
|
127,963
|
Common
Stock
|
Paid-in
Capital
|
Retained
Earnings
|
Accumulated
Other Comprehensive Income (Loss)
|
Total
|
||||||||||||
DECEMBER
31, 2004
|
$
|
56,584
|
$
|
858,835
|
$
|
221,330
|
$
|
(45,251
|
)
|
$
|
1,091,498
|
|||||
Common
Stock Dividends
|
(52,000
|
)
|
(52,000
|
)
|
||||||||||||
Preferred
Stock Dividends
|
(255
|
)
|
(255
|
)
|
||||||||||||
Capital
Stock Expense and Other
|
2,455
|
(56
|
)
|
2,399
|
||||||||||||
TOTAL
|
1,041,642
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $2,900
|
(5,385
|
)
|
(5,385
|
)
|
||||||||||||
NET
INCOME
|
128,274
|
128,274
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
122,889
|
|||||||||||||||
SEPTEMBER
30, 2005
|
$
|
56,584
|
$
|
861,290
|
$
|
297,293
|
$
|
(50,636
|
)
|
$
|
1,164,531
|
|||||
DECEMBER
31, 2005
|
$
|
56,584
|
$
|
861,290
|
$
|
305,787
|
$
|
(3,569
|
)
|
$
|
1,220,092
|
|||||
Common
Stock Dividends
|
(30,000
|
)
|
(30,000
|
)
|
||||||||||||
Preferred
Stock Dividends
|
(255
|
)
|
(255
|
)
|
||||||||||||
TOTAL
|
1,189,837
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net
of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $2,712
|
(5,036
|
)
|
(5,036
|
)
|
||||||||||||
NET
INCOME
|
120,964
|
120,964
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
115,928
|
|||||||||||||||
SEPTEMBER
30, 2006
|
$
|
56,584
|
$
|
861,290
|
$
|
396,496
|
$
|
(8,605
|
)
|
$
|
1,305,765
|
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Cash
and Cash Equivalents
|
$
|
706
|
$
|
854
|
|||
Accounts
Receivable:
|
|||||||
Customers
|
72,718
|
62,614
|
|||||
Affiliated
Companies
|
80,334
|
127,981
|
|||||
Miscellaneous
|
2,463
|
1,982
|
|||||
Allowance
for Uncollectible Accounts
|
(1,204
|
)
|
(898
|
)
|
|||
Total
Accounts Receivable
|
154,311
|
191,679
|
|||||
Fuel
|
38,531
|
25,894
|
|||||
Materials
and Supplies
|
126,067
|
118,039
|
|||||
Risk
Management Assets
|
60,757
|
78,134
|
|||||
Accrued
Tax Benefits
|
16,951
|
51,846
|
|||||
Margin
Deposits
|
1,258
|
17,115
|
|||||
Prepayments
and Other
|
9,072
|
14,188
|
|||||
TOTAL
|
407,653
|
497,749
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric:
|
|||||||
Production
|
3,217,437
|
3,128,078
|
|||||
Transmission
|
1,041,725
|
1,028,496
|
|||||
Distribution
|
1,084,530
|
1,029,498
|
|||||
Other
(including nuclear fuel and coal mining)
|
523,502
|
465,130
|
|||||
Construction
Work in Progress
|
283,714
|
311,080
|
|||||
Total
|
6,150,908
|
5,962,282
|
|||||
Accumulated
Depreciation, Depletion and Amortization
|
2,909,705
|
2,822,558
|
|||||
TOTAL
- NET
|
3,241,203
|
3,139,724
|
|||||
OTHER
NONCURRENT ASSETS
|
|||||||
Regulatory
Assets
|
217,070
|
222,686
|
|||||
Nuclear
Decommissioning and Spent Nuclear Fuel Disposal Trust
Funds
|
1,191,142
|
1,133,567
|
|||||
Long-term
Risk Management Assets
|
71,992
|
103,645
|
|||||
Deferred
Charges and Other
|
144,890
|
164,938
|
|||||
TOTAL
|
1,625,094
|
1,624,836
|
|||||
TOTAL
ASSETS
|
$
|
5,273,950
|
$
|
5,262,309
|
2006
|
2005
|
||||||
CURRENT
LIABILITIES
|
(in
thousands)
|
||||||
Advances
from Affiliates
|
$
|
27,616
|
$
|
93,702
|
|||
Accounts
Payable:
|
|||||||
General
|
137,157
|
139,334
|
|||||
Affiliated
Companies
|
59,163
|
60,324
|
|||||
Long-term
Debt Due Within One Year
|
349,627
|
364,469
|
|||||
Risk
Management Liabilities
|
58,961
|
71,032
|
|||||
Customer
Deposits
|
34,943
|
49,258
|
|||||
Accrued
Taxes
|
49,964
|
56,567
|
|||||
Other
|
138,352
|
112,839
|
|||||
TOTAL
|
855,783
|
947,525
|
|||||
NONCURRENT
LIABILITIES
|
|||||||
Long-term
Debt
|
1,104,274
|
1,080,471
|
|||||
Long-term
Risk Management Liabilities
|
52,477
|
86,159
|
|||||
Deferred
Income Taxes
|
336,194
|
335,264
|
|||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
714,663
|
710,015
|
|||||
Asset
Retirement Obligations
|
774,061
|
737,959
|
|||||
Deferred
Credits and Other
|
122,651
|
136,740
|
|||||
TOTAL
|
3,104,320
|
3,086,608
|
|||||
TOTAL
LIABILITIES
|
3,960,103
|
4,034,133
|
|||||
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
8,082
|
8,084
|
|||||
Commitments
and Contingencies (Note 5)
|
|||||||
COMMON
SHAREHOLDER’S EQUITY
|
|||||||
Common
Stock - No Par Value:
|
|||||||
Authorized
- 2,500,000 Shares
|
|||||||
Outstanding
- 1,400,000 Shares
|
56,584
|
56,584
|
|||||
Paid-in
Capital
|
861,290
|
861,290
|
|||||
Retained
Earnings
|
396,496
|
305,787
|
|||||
Accumulated
Other Comprehensive Income (Loss)
|
(8,605
|
)
|
(3,569
|
)
|
|||
TOTAL
|
1,305,765
|
1,220,092
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
5,273,950
|
$
|
5,262,309
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
120,964
|
$
|
128,274
|
|||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
136,681
|
127,695
|
|||||
Accretion
of Asset Retirement Obligations
|
36,309
|
35,742
|
|||||
Deferred
Income Taxes
|
7,734
|
2,269
|
|||||
Deferred
Investment Tax Credits
|
(5,460
|
)
|
(5,496
|
)
|
|||
Amortization
(Deferral) of Incremental Nuclear Refueling Outage Expenses,
Net
|
(20,673
|
)
|
10,506
|
||||
Amortization
of Nuclear Fuel
|
37,839
|
41,613
|
|||||
Mark-to-Market
of Risk Management Contracts
|
(4,915
|
)
|
(11,275
|
)
|
|||
Pension
Contributions to Qualified Plan Trusts
|
-
|
(46,051
|
)
|
||||
Deferred
Property Taxes
|
10,854
|
9,814
|
|||||
Change
in Other Noncurrent Assets
|
25,260
|
11,650
|
|||||
Change
in Other Noncurrent Liabilities
|
5,071
|
13,961
|
|||||
Changes
in Components of Working Capital:
|
|||||||
Accounts
Receivable, Net
|
37,368
|
14,441
|
|||||
Fuel,
Materials and Supplies
|
(20,665
|
)
|
4,303
|
||||
Accounts
Payable
|
29,483
|
4,065
|
|||||
Accrued
Taxes, Net
|
28,292
|
(85,750
|
)
|
||||
Customer
Deposits
|
(14,315
|
)
|
28,233
|
||||
Accrued
Interest
|
11,534
|
10,358
|
|||||
Rent
Accrued - Rockport Plant Unit 2
|
18,464
|
18,464
|
|||||
Other
Current Assets
|
20,997
|
(36,068
|
)
|
||||
Other
Current Liabilities
|
(4,509
|
)
|
(225
|
)
|
|||
Net
Cash Flows From Operating Activities
|
456,313
|
276,523
|
|||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(240,806
|
)
|
(190,171
|
)
|
|||
Change
in Advances to Affiliates, Net
|
-
|
5,093
|
|||||
Purchases
of Investment Securities
|
(559,803
|
)
|
(473,802
|
)
|
|||
Sales
of Investment Securities
|
517,017
|
434,639
|
|||||
Acquisitions
of Nuclear Fuel
|
(72,614
|
)
|
(28,188
|
)
|
|||
Proceeds
from Sales of Assets
|
954
|
13,554
|
|||||
Net
Cash Flows Used For Investing Activities
|
(355,252
|
)
|
(238,875
|
)
|
|||
FINANCING
ACTIVITIES
|
|||||||
Issuance
of Long-term Debt
|
49,745
|
-
|
|||||
Change
in Advances from Affiliates, Net
|
(66,086
|
)
|
81,101
|
||||
Retirement
of Long-term Debt
|
(50,000
|
)
|
-
|
||||
Retirement
of Cumulative Preferred Stock
|
(1
|
)
|
(61,445
|
)
|
|||
Principal
Payments for Capital Lease Obligations
|
(4,612
|
)
|
(4,829
|
)
|
|||
Dividends
Paid on Common Stock
|
(30,000
|
)
|
(52,000
|
)
|
|||
Dividends
Paid on Cumulative Preferred Stock
|
(255
|
)
|
(255
|
)
|
|||
Net
Cash Flows Used For Financing Activities
|
(101,209
|
)
|
(37,428
|
)
|
|||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
(148
|
)
|
220
|
||||
Cash
and Cash Equivalents at Beginning of Period
|
854
|
511
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
706
|
$
|
731
|
|||
SUPPLEMENTAL
DISCLOSURE
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
37,708
|
$
|
34,999
|
|||
Net
Cash Paid for Income Taxes
|
20,180
|
149,058
|
|||||
Noncash
Acquisitions Under Capital Leases
|
4,359
|
1,465
|
|||||
Construction
Expenditures Included in Accounts Payable at September 30,
|
29,755
|
25,008
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
Footnote
Reference
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
Third
Quarter of 2005
|
$
|
8
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
1
|
||||||
Off-system
Sales
|
8
|
||||||
Transmission
Revenues
|
(3
|
)
|
|||||
Total
Change in Gross Margin
|
6
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(3
|
)
|
|||||
Taxes
Other Than Income Taxes
|
1
|
||||||
Total
Change in Operating Expenses and Other
|
(2
|
)
|
|||||
Income
Tax Expense
|
(2
|
)
|
|||||
Third
Quarter of 2006
|
$
|
10
|
·
|
Retail
Margins increased $1 million primarily due to $12 million of
rate relief
from the March 2006 approval of the settlement agreement in our
base rate
case. The rate increase was partially offset by the effect
of:
|
|
|
·
|
a
23% decrease in cooling degree days as a result of mild weather
on
residential and commercial sales,
|
|
·
|
a
decrease in financial transmission rights revenue, net of congestion,
primarily due to fewer transmission constraints in the PJM market
and
|
|
·
|
increased
capacity charges due to changes in the relative peak demands
and
generating capacity of the AEP Power Pool
members.
|
·
|
Off-system
Sales increased $8 million due to $4 million increase in physical
sales
margins and a $4 million increase from lower sharing of off-system
sales
margins under the SIA. See the “Allocation Agreement between AEP East
companies and AEP West companies and CSW Operating Agreement” section of
Note 3.
|
|
·
|
Transmission
Revenues decreased $3 million primarily due to the elimination
of SECA
revenues as of April 1, 2006. At this time, we have a pending
proposal
with the FERC to replace SECA revenues. See the “Transmission Rate
Proceedings at the FERC” section of Note
3.
|
·
|
Other
Operation and Maintenance expenses increased $3 million primarily
due to
maintenance of overhead lines.
|
Nine
Months Ended September 30, 2005
|
$
|
20
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
8
|
||||||
Off-system
Sales
|
9
|
||||||
Transmission
Revenues
|
(6
|
)
|
|||||
Other
|
3
|
||||||
Total
Change in Gross Margin
|
14
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(4
|
)
|
|||||
Depreciation
and Amortization
|
(1
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(5
|
)
|
|||||
Income
Tax Expense
|
(4
|
)
|
|||||
Nine
Months Ended September 30, 2006
|
$
|
25
|
|||||
·
|
Retail
Margins increased $8 million primarily due to rate relief from the
March
2006 approval of the settlement agreement in our base rate case as
well as
favorable financial transmission rights revenue, net of congestion.
The
above was partially offset by increased capacity charges due to changes
in
the relative peak demands and generating capacity of the AEP Power
Pool
members.
|
·
|
Off-system
Sales increased $9 million primarily due to $10 million increase
in
physical sales margins and a $5 million increase from lower sharing
of
off-system sales margins under the SIA offset by a $5 million decrease
in
margins from optimization activities. See the “Allocation Agreement
between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
|
·
|
Transmission
Revenues decreased $6 million primarily due to the elimination of
SECA
revenues as of April 1, 2006 and a provision of $1 million recorded
in
2006 related to potential SECA refunds pending settlement negotiations
with various intervenors. At this time, we have a pending proposal
with
the FERC to replace SECA revenues. See the “Transmission Rate Proceedings
at the FERC” section of Note 3.
|
·
|
Other
revenues increased
$3 million primarily due to a $3 million unfavorable adjustment of
the
Demand Side Management Program regulatory asset in March
2005.
|
·
|
Other
Operation and Maintenance expenses increased $4 million primarily
due to
maintenance of overhead lines.
|
Moody’s
|
S&P
|
Fitch
|
|||
Senior
Unsecured Debt
|
Baa2
|
BBB
|
BBB
|
Principal
|
Interest
|
Due
|
|||||
Type
of Debt
|
Amount
|
Rate
|
Date
|
||||
(in
thousands)
|
(%)
|
||||||
Notes
Payable-Affiliated
|
$
|
40,000
|
6.501
|
2006
|
MTM
Risk Management Contracts
|
Cash
Flow &
Fair
Value Hedges
|
DETM
Assignment (a)
|
Total
|
||||||||||
Current
Assets
|
$
|
19,926
|
$
|
1,916
|
$
|
-
|
$
|
21,842
|
|||||
Noncurrent
Assets
|
25,640
|
122
|
-
|
25,762
|
|||||||||
Total
MTM Derivative Contract Assets
|
45,566
|
2,038
|
-
|
47,604
|
|||||||||
Current
Liabilities
|
(14,945
|
)
|
(1,156
|
)
|
(451
|
)
|
(16,552
|
)
|
|||||
Noncurrent
Liabilities
|
(16,550
|
)
|
(2
|
)
|
(2,192
|
)
|
(18,744
|
)
|
|||||
Total
MTM Derivative Contract Liabilities
|
(31,495
|
)
|
(1,158
|
)
|
(2,643
|
)
|
(35,296
|
)
|
|||||
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
$
|
14,071
|
$
|
880
|
$
|
(2,643
|
)
|
$
|
12,308
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
$
|
13,518
|
||
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
32
|
|||
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
|
(70
|
)
|
||
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
-
|
|||
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
(462
|
)
|
||
Changes
Due to SIA (c)
|
(1,565
|
)
|
||
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
2,618
|
|||
Total
MTM Risk Management Contract Net Assets
|
14,071
|
|||
Net
Cash Flow & Fair Value Hedge Contracts
|
880
|
|||
DETM
Assignment (e)
|
(2,643
|
)
|
||
Total
MTM Risk Management Contract Net Assets at September 30, 2006
|
$
|
12,308
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(d)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected in the Condensed
Statements of Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving an indication
of
when these MTM amounts will settle and generate
cash.
|
Remainder
2006
|
2007
|
2008
|
2009
|
2010
|
After
2010
|
Total
|
||||||||||||||||
Prices
Actively Quoted - Exchange Traded
Contracts
|
$
|
430
|
$
|
3,090
|
$
|
1,118
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
4,638
|
||||||||
Prices
Provided by Other External Sources
- OTC Broker Quotes
(a)
|
905
|
2,379
|
1,164
|
1,752
|
-
|
-
|
6,200
|
|||||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
1
|
(885
|
)
|
372
|
1,114
|
1,998
|
633
|
3,233
|
||||||||||||||
Total
|
$
|
1,336
|
$
|
4,584
|
$
|
2,654
|
$
|
2,866
|
$
|
1,998
|
$
|
633
|
$
|
14,071
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Power
|
Interest
Rate
|
Total
|
||||||||
Beginning
Balance in AOCI December 31, 2005
|
$
|
(352
|
)
|
$
|
158
|
$
|
(194
|
)
|
||
Changes
in Fair Value
|
1,072
|
-
|
1,072
|
|||||||
Impact
Due to Changes in SIA (a)
|
(106
|
)
|
-
|
(106
|
)
|
|||||
Reclassifications
from AOCI to Net Income for Cash Flow Hedges Settled
|
543
|
(66
|
)
|
477
|
||||||
Ending
Balance in AOCI September 30, 2006
|
$
|
1,157
|
$
|
92
|
$
|
1,249
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
Nine
Months Ended
September
30, 2006
|
Twelve
Months Ended
December
31, 2005
|
||||||||||||||||
(in
thousands)
|
(in
thousands)
|
||||||||||||||||
End
|
High
|
Average
|
Low
|
End
|
High
|
Average
|
Low
|
||||||||||
$157
|
$459
|
$164
|
$87
|
$174
|
$289
|
$138
|
$50
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
REVENUES
|
|||||||||||||
Electric
Generation, Transmission and Distribution
|
$
|
138,554
|
$
|
120,321
|
$
|
397,248
|
$
|
337,912
|
|||||
Sales
to AEP Affiliates
|
13,466
|
23,341
|
41,543
|
55,598
|
|||||||||
Other
|
299
|
334
|
678
|
1,255
|
|||||||||
TOTAL
|
152,319
|
143,996
|
439,469
|
394,765
|
|||||||||
EXPENSES
|
|||||||||||||
Fuel
and Other Consumables for Electric Generation
|
39,580
|
43,603
|
115,336
|
104,271
|
|||||||||
Purchased
Electricity for Resale
|
3,974
|
1,563
|
6,938
|
5,473
|
|||||||||
Purchased
Electricity from AEP Affiliates
|
48,755
|
45,300
|
149,204
|
131,049
|
|||||||||
Other
Operation
|
15,176
|
14,352
|
42,662
|
42,549
|
|||||||||
Maintenance
|
9,607
|
7,180
|
26,041
|
21,578
|
|||||||||
Depreciation
and Amortization
|
11,574
|
11,318
|
34,603
|
33,695
|
|||||||||
Taxes
Other Than Income Taxes
|
1,807
|
2,457
|
6,761
|
7,101
|
|||||||||
TOTAL
|
130,473
|
125,773
|
381,545
|
345,716
|
|||||||||
OPERATING
INCOME
|
21,846
|
18,223
|
57,924
|
49,049
|
|||||||||
Other
Income (Expense):
|
|||||||||||||
Interest
Income
|
159
|
189
|
518
|
456
|
|||||||||
Allowance
for Equity Funds Used During Construction
|
236
|
37
|
249
|
209
|
|||||||||
Interest
Expense
|
(6,581
|
)
|
(7,227
|
)
|
(21,317
|
)
|
(21,665
|
)
|
|||||
INCOME
BEFORE INCOME TAXES
|
15,660
|
11,222
|
37,374
|
28,049
|
|||||||||
Income
Tax Expense
|
5,791
|
3,495
|
12,624
|
7,991
|
|||||||||
NET
INCOME
|
$
|
9,869
|
$
|
7,727
|
$
|
24,750
|
$
|
20,058
|
Common
Stock
|
Paid-in
Capital
|
Retained
Earnings
|
Accumulated
Other
Comprehensive
Income (Loss)
|
Total
|
||||||||||||
DECEMBER
31, 2004
|
$
|
50,450
|
$
|
208,750
|
$
|
70,555
|
$
|
(8,775
|
)
|
$
|
320,980
|
|||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $1,534
|
(2,848
|
)
|
(2,848
|
)
|
||||||||||||
NET
INCOME
|
20,058
|
20,058
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
17,210
|
|||||||||||||||
SEPTEMBER
30, 2005
|
$
|
50,450
|
$
|
208,750
|
$
|
90,613
|
$
|
(11,623
|
)
|
$
|
338,190
|
|||||
DECEMBER
31, 2005
|
$
|
50,450
|
$
|
208,750
|
$
|
88,864
|
$
|
(223
|
)
|
$
|
347,841
|
|||||
Common
Stock Dividends
|
(10,000
|
)
|
(10,000
|
)
|
||||||||||||
TOTAL
|
337,841
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Income, Net
of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $777
|
1,443
|
1,443
|
||||||||||||||
NET
INCOME
|
24,750
|
24,750
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
26,193
|
|||||||||||||||
SEPTEMBER
30, 2006
|
$
|
50,450
|
$
|
208,750
|
$
|
103,614
|
$
|
1,220
|
$
|
364,034
|
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Cash
and Cash Equivalents
|
$
|
479
|
$
|
526
|
|||
Accounts
Receivable:
|
|||||||
Customers
|
23,776
|
26,533
|
|||||
Affiliated
Companies
|
14,337
|
23,525
|
|||||
Accrued
Unbilled Revenues
|
1,004
|
6,311
|
|||||
Miscellaneous
|
554
|
35
|
|||||
Allowance
for Uncollectible Accounts
|
(253
|
)
|
(147
|
)
|
|||
Total
Accounts Receivable
|
39,418
|
56,257
|
|||||
Fuel
|
10,780
|
8,490
|
|||||
Materials
and Supplies
|
8,854
|
10,181
|
|||||
Risk
Management Assets
|
21,842
|
31,437
|
|||||
Accrued
Tax Benefits
|
2,535
|
6,598
|
|||||
Margin
Deposits
|
453
|
6,895
|
|||||
Prepayments
and Other
|
1,955
|
6,324
|
|||||
TOTAL
|
86,316
|
126,708
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric:
|
|||||||
Production
|
477,777
|
472,575
|
|||||
Transmission
|
391,671
|
386,945
|
|||||
Distribution
|
470,606
|
456,063
|
|||||
Other
|
60,607
|
63,382
|
|||||
Construction
Work in Progress
|
30,436
|
35,461
|
|||||
Total
|
1,431,097
|
1,414,426
|
|||||
Accumulated
Depreciation and Amortization
|
438,023
|
425,817
|
|||||
TOTAL
- NET
|
993,074
|
988,609
|
|||||
OTHER
NONCURRENT ASSETS
|
|||||||
Regulatory
Assets
|
111,089
|
117,432
|
|||||
Long-term
Risk Management Assets
|
25,762
|
41,810
|
|||||
Deferred
Charges and Other
|
54,607
|
45,467
|
|||||
TOTAL
|
191,458
|
204,709
|
|||||
TOTAL
ASSETS
|
$
|
1,270,848
|
$
|
1,320,026
|
2006
|
2005
|
||||||
CURRENT
LIABILITIES
|
(in
thousands)
|
||||||
Advances
from Affiliates
|
$
|
24,507
|
$
|
6,040
|
|||
Accounts
Payable:
|
|||||||
General
|
31,118
|
32,454
|
|||||
Affiliated
Companies
|
18,045
|
29,326
|
|||||
Long-term
Debt Due Within One Year - Nonaffiliated
|
124,123
|
-
|
|||||
Long-term
Debt Due Within One Year - Affiliated
|
-
|
39,771
|
|||||
Risk
Management Liabilities
|
16,552
|
28,770
|
|||||
Customer
Deposits
|
15,849
|
21,643
|
|||||
Accrued
Taxes
|
9,322
|
8,805
|
|||||
Accrued
Interest
|
9,897
|
7,428
|
|||||
Other
|
15,967
|
14,096
|
|||||
TOTAL
|
265,380
|
188,333
|
|||||
NONCURRENT
LIABILITIES
|
|||||||
Long-term
Debt - Nonaffiliated
|
302,861
|
427,219
|
|||||
Long-term
Debt - Affiliated
|
20,000
|
20,000
|
|||||
Long-term
Risk Management Liabilities
|
18,744
|
35,302
|
|||||
Deferred
Income Taxes
|
240,423
|
234,719
|
|||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
50,500
|
56,794
|
|||||
Deferred
Credits and Other
|
8,906
|
9,818
|
|||||
TOTAL
|
641,434
|
783,852
|
|||||
TOTAL
LIABILITIES
|
906,814
|
972,185
|
|||||
Commitments
and Contingencies (Note 5)
|
|||||||
COMMON
SHAREHOLDER’S EQUITY
|
|||||||
Common
Stock - $50 Par Value Per Share:
|
|||||||
Authorized
- 2,000,000 Shares
|
|||||||
Outstanding
- 1,009,000 Shares
|
50,450
|
50,450
|
|||||
Paid-in
Capital
|
208,750
|
208,750
|
|||||
Retained
Earnings
|
103,614
|
88,864
|
|||||
Accumulated
Other Comprehensive Income (Loss)
|
1,220
|
(223
|
)
|
||||
TOTAL
|
364,034
|
347,841
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDER’S EQUITY
|
$
|
1,270,848
|
$
|
1,320,026
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
24,750
|
$
|
20,058
|
|||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
34,603
|
33,695
|
|||||
Deferred
Income Taxes
|
2,742
|
1,836
|
|||||
Mark-to-Market
of Risk Management Contracts
|
(842
|
)
|
(5,204
|
)
|
|||
Pension
Contributions to Qualified Plan Trusts
|
-
|
(9,137
|
)
|
||||
Over/Under
Fuel Recovery
|
3,608
|
(4,453
|
)
|
||||
Change
in Other Noncurrent Assets
|
5,666
|
(4
|
)
|
||||
Change
in Other Noncurrent Liabilities
|
2,629
|
10,333
|
|||||
Changes
in Components of Working Capital:
|
|||||||
Accounts
Receivable, Net
|
16,839
|
(2,592
|
)
|
||||
Fuel,
Materials and Supplies
|
(963
|
)
|
(4,200
|
)
|
|||
Accounts
Payable
|
(8,149
|
)
|
12,876
|
||||
Customer
Deposits
|
(5,794
|
)
|
12,776
|
||||
Accrued
Taxes, Net
|
4,580
|
(553
|
)
|
||||
Other
Current Assets
|
7,726
|
(14,231
|
)
|
||||
Other
Current Liabilities
|
3,819
|
2,297
|
|||||
Net
Cash Flows From Operating Activities
|
91,214
|
53,497
|
|||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(59,264
|
)
|
(38,837
|
)
|
|||
Change
in Advances to Affiliates, Net
|
-
|
6,486
|
|||||
Other
|
465
|
191
|
|||||
Net
Cash Flows Used For Investing Activities
|
(58,799
|
)
|
(32,160
|
)
|
|||
FINANCING
ACTIVITIES
|
|||||||
Change
in Advances from Affiliates, Net
|
18,467
|
-
|
|||||
Retirement
of Long-term Debt - Affiliated
|
(40,000
|
)
|
(20,000
|
)
|
|||
Principal
Payments for Capital Lease Obligations
|
(929
|
)
|
(1,122
|
)
|
|||
Dividends
Paid on Common Stock
|
(10,000
|
)
|
-
|
||||
Net
Cash Flows Used For Financing Activities
|
(32,462
|
)
|
(21,122
|
)
|
|||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
(47
|
)
|
215
|
||||
Cash
and Cash Equivalents at Beginning of Period
|
526
|
132
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
479
|
$
|
347
|
|||
SUPPLEMENTARY
INFORMATION
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
18,242
|
$
|
17,250
|
|||
Net
Cash Paid for Income Taxes
|
4,573
|
7,466
|
|||||
Noncash
Acquisitions Under Capital Leases
|
551
|
273
|
|||||
Construction
Expenditures Included in Accounts Payable at September 30,
|
2,085
|
1,386
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
Footnote
Reference
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
Third
Quarter of 2005
|
$
|
56
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
47
|
||||||
Off-system
Sales
|
23
|
||||||
Transmission
Revenues
|
(9
|
)
|
|||||
Other
|
(7
|
)
|
|||||
Total
Change in Gross Margin
|
54
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(5
|
)
|
|||||
Depreciation
and Amortization
|
(9
|
)
|
|||||
Taxes
Other Than Income Taxes
|
6
|
||||||
Other
Income
|
(1
|
)
|
|||||
Carrying
Costs Income
|
(6
|
)
|
|||||
Interest
Expense
|
4
|
||||||
Total
Change in Operating Expenses and Other
|
(11
|
)
|
|||||
Income
Tax Expense
|
(16
|
)
|
|||||
Third
Quarter of 2006
|
$
|
83
|
·
|
Retail
Margins were $47 million higher than the prior period primarily due
to the
Rate Stabilization Plan (RSP) rate increase effective January 1,
2006,
favorable capacity settlements, and lower consumable expenses. These
increases were partially offset by lower residential revenue due
to mild
weather and lower industrial revenue due to the transfer of a significant
customer to an affiliate.
|
·
|
Off-system
Sales increased $23 million primarily due to $19 million increase
in
physical sales margins and a $14 million increase from lower sharing
of
off-system sales margins under the SIA offset by a $10 million decrease
in
margins from optimization activities. See the “Allocation Agreement
between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
|
·
|
Transmission
Revenues decreased $9 million primarily due to the elimination of
SECA
revenues as of April 1, 2006. At this time, we have a pending proposal
with the FERC to replace SECA revenues. See the “Transmission Rate
Proceedings at the FERC” section of Note 3.
|
·
|
Other
revenue decreased $7 million primarily due to the expiration of a
contract
to sell supplemental demand to Buckeye Power and a decrease in rental
revenue.
|
·
|
Other
Operation and Maintenance expense increased $5 million partially
due to an
increase in maintenance from planned and forced outages at the Muskingum
and Sporn plants related to major turbine overhaul and boiler tube
inspections and repairs. The increase was partially offset by the
recognition of a regulatory asset related to recent PUCO orders
regarding distribution service reliability and restoration costs.
|
·
|
Depreciation
and Amortization increased $9 million due to increased amortization
of
regulatory assets and a greater depreciable base in electric utility
plant.
|
·
|
Taxes
Other Than Income Taxes decreased $6 million primarily due an adjustment
in 2005 to true-up 2004 and 2005 property taxes.
|
·
|
Carrying
Costs Income decreased $6 million primarily due to the completion
of
deferrals of the environmental carrying costs from 2004 and 2005
that are
now being recovered during 2006 through 2008 according to the
RSP.
|
Nine
Months Ended September 30, 2005
|
$
|
227
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
Margins
|
42
|
||||||
Off-system
Sales
|
29
|
||||||
Transmission
Revenues
|
(19
|
)
|
|||||
Other
|
4
|
||||||
Total
Change in Gross Margin
|
56
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(65
|
)
|
|||||
Depreciation
and Amortization
|
(12
|
)
|
|||||
Taxes
Other than Income Taxes
|
1
|
||||||
Carrying
Costs Income
|
(28
|
)
|
|||||
Interest
Expense
|
8
|
||||||
Total
Change in Operating Expenses and Other
|
(96
|
)
|
|||||
Income
Tax Expense
|
15
|
||||||
Nine
Months Ended September 30, 2006
|
$
|
202
|
·
|
Retail
Margins increased $42 million primarily due to the RSP rate increase
effective January 1, 2006, favorable capacity settlements, and lower
consumable expenses. The increase is partially offset by lower fuel
margins, a decrease in residential revenue due to mild weather and
lower
industrial revenue due to the transfer of a significant customer
to an
affiliate.
|
·
|
Off-System
Sales increased $29 million primarily due to $48 million increase
in
physical sales margins and a $17 million increase from lower sharing
of
off-system sales margins under the SIA offset by a $35 million decrease
in
margins related to optimization activities. See the “Allocation Agreement
between AEP East companies and AEP West companies and CSW Operating
Agreement” section of Note 3.
|
·
|
Transmission
Revenues decreased $19 million primarily due to the elimination of
SECA
revenues as of April 1, 2006 and a provision of $4 million recorded
in
2006 related to potential SECA refunds pending settlement negotiations
with various intervenors. At this time, we have a pending proposal
with
the FERC to replace SECA revenues. See the “Transmission Rate Proceedings
at the FERC” section of Note 3.
|
·
|
Other
revenue increased $4 million partially due to an increase in gains
on
sales of emission allowances.
|
·
|
Other
Operation and Maintenance expense increased $65 million primarily
due to
an increase in maintenance from planned and forced outages at the
Gavin,
Muskingum River, Kammer, and Sporn plants related to major boiler
and
turbine overhauls and boiler tube inspections and related removal
costs
and PJM administrative fees. The increase was partially offset by
the
recognition of a regulatory asset related to recent PUCO orders
regarding distribution service reliabiltiy and restoration costs
and major
ice storm expenses in the prior year.
|
·
|
Depreciation
and Amortization increased $12 million primarily due to increased
amortization of regulatory assets and a greater depreciable base
in
electric utility plant.
|
·
|
Carrying
Costs Income decreased $28 million primarily due to the completion
of
deferrals of the environmental carrying costs from 2004 and 2005
that are
now being recovered during 2006 through 2008 according to the
RSP.
|
·
|
Interest
Expense decreased $8 million primarily due to an increase in allowance
for
borrowed funds used during construction partially offset by interest
on
long-term debt issuances subsequent to September
2005.
|
Moody’s
|
S&P
|
Fitch
|
|||
Senior
Unsecured Debt
|
A3
|
BBB
|
BBB+
|
2006
|
2005
|
||||||
(in
thousands)
|
|||||||
Cash
and Cash Equivalents at Beginning of Period
|
$
|
1,240
|
$
|
9,337
|
|||
Net
Cash Flows From (Used For):
|
|||||||
Operating
Activities
|
476,382
|
319,579
|
|||||
Investing
Activities
|
(709,752
|
)
|
(325,415
|
)
|
|||
Financing
Activities
|
233,455
|
(2,121
|
)
|
||||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
85
|
(7,957
|
)
|
||||
Cash
and Cash Equivalents at End of Period
|
$
|
1,325
|
$
|
1,380
|
Principal
|
Interest
|
Due
|
|||||
Type
of Debt
|
Amount
|
Rate
|
Date
|
||||
(in
thousands)
|
(%)
|
||||||
Pollution
Control Bonds
|
$
|
65,000
|
Variable
|
2036
|
|||
Senior
Unsecured Notes
|
350,000
|
6.00
|
2016
|
Principal
|
Interest
|
Due
|
|||||
Type
of Debt
|
Amount
|
Rate
|
Date
|
||||
(in
thousands)
|
(%)
|
||||||
Notes
Payable - Nonaffiliated
|
$
|
4,390
|
6.81
|
2008
|
|||
Notes
Payable - Nonaffiliated
|
6,500
|
6.27
|
2009
|
||||
Notes
Payable - Affiliated
|
200,000
|
3.32
|
2006
|
MTM
Risk Management Contracts
|
Cash
Flow Hedges
|
DETM
Assignment (a)
|
Total
|
||||||||||
Current
Assets
|
$
|
66,808
|
$
|
5,639
|
$
|
-
|
$
|
72,447
|
|||||
Noncurrent
Assets
|
82,034
|
386
|
-
|
82,420
|
|||||||||
Total
MTM Derivative Contract Assets
|
148,842
|
6,025
|
-
|
154,867
|
|||||||||
Current
Liabilities
|
(55,074
|
)
|
(881
|
)
|
(1,425
|
)
|
(57,380
|
)
|
|||||
Noncurrent
Liabilities
|
(55,004
|
)
|
(9
|
)
|
(6,923
|
)
|
(61,936
|
)
|
|||||
Total
MTM Derivative Contract Liabilities
|
(110,078
|
)
|
(890
|
)
|
(8,348
|
)
|
(119,316
|
)
|
|||||
Total
MTM Derivative Contract Net Assets
(Liabilities)
|
$
|
38,764
|
$
|
5,135
|
$
|
(8,348
|
)
|
$
|
35,551
|
(a)
|
See
“Natural Gas Contracts with DETM” section of Note 17 in the 2005 Annual
Report.
|
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
$
|
40,894
|
||
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
(2,331
|
)
|
||
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
173
|
|||
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
(427
|
)
|
||
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
451
|
|||
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
4,664
|
|||
Changes
Due to SIA (c)
|
(4,984
|
)
|
||
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
324
|
|||
Total
MTM Risk Management Contract Net Assets
|
38,764
|
|||
Net
Cash Flow Hedge Contracts
|
5,135
|
|||
DETM
Assignment (e)
|
(8,348
|
)
|
||
Total
MTM Risk Management Contract Net Assets at September 30, 2006
|
$
|
35,551
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(d)
|
“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.
|
(e)
|
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving an indication
of
when these MTM amounts will settle and generate
cash.
|
Remainder
2006
|
2007
|
2008
|
2009
|
2010
|
After
2010
|
Total
|
||||||||||||||||
Prices
Actively Quoted - Exchange Traded
Contracts
|
$
|
1,359
|
$
|
9,761
|
$
|
3,533
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
14,653
|
||||||||
Prices
Provided by Other External Sources
- OTC Broker Quotes
(a)
|
1,850
|
6,345
|
3,856
|
5,534
|
-
|
-
|
17,585
|
|||||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
(38
|
)
|
(5,390
|
)
|
119
|
3,521
|
6,314
|
2,000
|
6,526
|
|||||||||||||
Total
|
$
|
3,171
|
$
|
10,716
|
$
|
7,508
|
$
|
9,055
|
$
|
6,314
|
$
|
2,000
|
$
|
38,764
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Power
|
Foreign
Currency
|
Interest
Rate
|
Total
|
||||||||||
Beginning
Balance in AOCI December 31, 2005
|
$
|
(392
|
)
|
$
|
(344
|
)
|
$
|
1,491
|
$
|
755
|
|||
Changes
in Fair Value
|
3,413
|
-
|
2,761
|
6,174
|
|||||||||
Impact
due to Change in SIA (a)
|
(337
|
)
|
-
|
-
|
(337
|
)
|
|||||||
Reclassifications
from AOCI to Net Income for Cash Flow Hedges
Settled
|
950
|
10
|
(497
|
)
|
463
|
||||||||
Ending
Balance in AOCI September 30, 2006
|
$
|
3,634
|
$
|
(334
|
)
|
$
|
3,755
|
$
|
7,055
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
Nine
Months Ended
September
30, 2006
|
Twelve
Months Ended
December
31, 2005
|
||||||||||||||||
(in
thousands)
|
(in
thousands)
|
||||||||||||||||
End
|
High
|
Average
|
Low
|
End
|
High
|
Average
|
Low
|
||||||||||
$496
|
$1,451
|
$519
|
$276
|
$583
|
$968
|
$461
|
$166
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
REVENUES
|
|||||||||||||
Electric
Generation, Transmission and Distribution
|
$
|
558,490
|
$
|
468,795
|
$
|
1,556,193
|
$
|
1,413,796
|
|||||
Sales
to AEP Affiliates
|
198,640
|
204,063
|
502,547
|
544,016
|
|||||||||
Other
- Affiliated
|
4,400
|
5,333
|
11,975
|
12,534
|
|||||||||
Other
- Nonaffiliated
|
3,378
|
8,949
|
12,806
|
22,947
|
|||||||||
TOTAL
|
764,908
|
687,140
|
2,083,521
|
1,993,293
|
|||||||||
EXPENSES
|
|||||||||||||
Fuel
and Other Consumables for Electric Generation
|
280,593
|
272,468
|
727,261
|
721,559
|
|||||||||
Purchased
Electricity for Resale
|
28,324
|
12,345
|
76,351
|
53,530
|
|||||||||
Purchased
Electricity from AEP Affiliates
|
35,423
|
36,012
|
92,086
|
86,723
|
|||||||||
Other
Operation
|
100,274
|
93,067
|
286,107
|
238,916
|
|||||||||
Maintenance
|
44,503
|
46,481
|
163,443
|
145,435
|
|||||||||
Depreciation
and Amortization
|
82,746
|
73,799
|
239,407
|
227,687
|
|||||||||
Taxes
Other Than Income Taxes
|
47,945
|
53,531
|
143,634
|
144,671
|
|||||||||
TOTAL
|
619,808
|
587,703
|
1,728,289
|
1,618,521
|
|||||||||
OPERATING
INCOME
|
145,100
|
99,437
|
355,232
|
374,772
|
|||||||||
Other
Income (Expense):
|
|||||||||||||
Interest
Income
|
840
|
930
|
2,072
|
2,402
|
|||||||||
Carrying
Costs Income
|
3,502
|
8,882
|
10,336
|
38,431
|
|||||||||
Allowance
for Equity Funds Used During Construction
|
755
|
1,952
|
1,891
|
2,684
|
|||||||||
Interest
Expense
|
(24,610
|
)
|
(28,416
|
)
|
(72,461
|
)
|
(80,418
|
)
|
|||||
INCOME
BEFORE INCOME TAXES
|
125,587
|
82,785
|
297,070
|
337,871
|
|||||||||
Income
Tax Expense
|
42,245
|
26,377
|
95,297
|
110,499
|
|||||||||
NET
INCOME
|
83,342
|
56,408
|
201,773
|
227,372
|
|||||||||
Preferred
Stock Dividend Requirements including Capital Stock
Expense and Other Expense
|
183
|
183
|
549
|
723
|
|||||||||
EARNINGS
APPLICABLE TO COMMON STOCK
|
$
|
83,159
|
$
|
56,225
|
$
|
201,224
|
$
|
226,649
|
Common
Stock
|
Paid-in
Capital
|
Retained
Earnings
|
Accumulated
Other Comprehensive Income (Loss)
|
Total
|
||||||||||||
DECEMBER
31, 2004
|
$
|
321,201
|
$
|
462,485
|
$
|
764,416
|
$
|
(74,264
|
)
|
$
|
1,473,838
|
|||||
Common
Stock Dividends
|
(22,499
|
)
|
(22,499
|
)
|
||||||||||||
Preferred
Stock Dividends
|
(549
|
)
|
(549
|
)
|
||||||||||||
Other
|
4,151
|
(174
|
)
|
3,977
|
||||||||||||
TOTAL
|
1,454,767
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $4,739
|
(8,802
|
)
|
(8,802
|
)
|
||||||||||||
NET
INCOME
|
227,372
|
227,372
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
218,570
|
|||||||||||||||
SEPTEMBER
30, 2005
|
$
|
321,201
|
$
|
466,636
|
$
|
968,566
|
$
|
(83,066
|
)
|
$
|
1,673,337
|
|||||
DECEMBER
31, 2005
|
$
|
321,201
|
$
|
466,637
|
$
|
979,354
|
$
|
755
|
$
|
1,767,947
|
||||||
Capital
Contribution From Parent
|
70,000
|
70,000
|
||||||||||||||
Preferred
Stock Dividends
|
(549
|
)
|
(549
|
)
|
||||||||||||
Gain
on Reacquired Preferred Stock
|
2
|
2
|
||||||||||||||
TOTAL
|
1,837,400
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Income, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $3,393
|
6,300
|
6,300
|
||||||||||||||
NET
INCOME
|
201,773
|
201,773
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
208,073
|
|||||||||||||||
SEPTEMBER
30, 2006
|
$
|
321,201
|
$
|
536,639
|
$
|
1,180,578
|
$
|
7,055
|
$
|
2,045,473
|
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Cash
and Cash Equivalents
|
$
|
1,325
|
$
|
1,240
|
|||
Accounts
Receivable:
|
|||||||
Customers
|
107,329
|
125,404
|
|||||
Affiliated
Companies
|
122,993
|
167,579
|
|||||
Accrued
Unbilled Revenues
|
13,771
|
14,817
|
|||||
Miscellaneous
|
2,313
|
15,644
|
|||||
Allowance
for Uncollectible Accounts
|
(2,786
|
)
|
(1,517
|
)
|
|||
Total Accounts Receivable
|
243,620
|
321,927
|
|||||
Fuel
|
115,992
|
97,600
|
|||||
Materials
and Supplies
|
67,920
|
60,937
|
|||||
Emission
Allowances
|
12,738
|
39,251
|
|||||
Risk
Management Assets
|
72,447
|
115,020
|
|||||
Accrued
Tax Benefits
|
1,463
|
39,965
|
|||||
Prepayments
and Other
|
19,271
|
27,439
|
|||||
TOTAL
|
534,776
|
703,379
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric:
|
|||||||
Production
|
4,388,325
|
4,278,553
|
|||||
Transmission
|
1,016,000
|
1,002,255
|
|||||
Distribution
|
1,308,532
|
1,258,518
|
|||||
Other
|
296,005
|
293,794
|
|||||
Construction
Work in Progress
|
1,121,259
|
690,168
|
|||||
Total
|
8,130,121
|
7,523,288
|
|||||
Accumulated
Depreciation and Amortization
|
2,805,417
|
2,738,899
|
|||||
TOTAL
- NET
|
5,324,704
|
4,784,389
|
|||||
OTHER
NONCURRENT ASSETS
|
|||||||
Regulatory
Assets
|
347,457
|
398,007
|
|||||
Long-term
Risk Management Assets
|
82,420
|
144,015
|
|||||
Deferred
Charges and Other
|
276,752
|
300,880
|
|||||
TOTAL
|
706,629
|
842,902
|
|||||
TOTAL
ASSETS
|
$
|
6,566,109
|
$
|
6,330,670
|
2006
|
2005
|
||||||
CURRENT
LIABILITIES
|
(in
thousands)
|
||||||
Advances
from Affiliates
|
$
|
48,163
|
$
|
70,071
|
|||
Accounts
Payable:
|
|||||||
General
|
250,280
|
210,752
|
|||||
Affiliated
Companies
|
105,916
|
147,470
|
|||||
Short-term
Debt - Nonaffiliated
|
7,103
|
10,366
|
|||||
Long-term
Debt Due Within One Year - Nonaffiliated
|
12,354
|
12,354
|
|||||
Long-term
Debt Due Within One Year - Affiliated
|
-
|
200,000
|
|||||
Risk
Management Liabilities
|
57,380
|
108,797
|
|||||
Customer
Deposits
|
28,811
|
51,209
|
|||||
Accrued
Taxes
|
92,539
|
158,774
|
|||||
Other
|
138,777
|
147,778
|
|||||
TOTAL
|
741,323
|
1,117,571
|
|||||
NONCURRENT
LIABILITIES
|
|||||||
Long-term
Debt - Nonaffiliated
|
2,186,023
|
1,787,316
|
|||||
Long-term
Debt - Affiliated
|
200,000
|
200,000
|
|||||
Long-term
Risk Management Liabilities
|
61,936
|
119,247
|
|||||
Deferred
Income Taxes
|
972,867
|
987,386
|
|||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
182,647
|
168,492
|
|||||
Deferred
Credits and Other
|
142,616
|
154,770
|
|||||
TOTAL
|
3,746,089
|
3,417,211
|
|||||
TOTAL
LIABILITIES
|
4,487,412
|
4,534,782
|
|||||
Minority
Interest
|
16,593
|
11,302
|
|||||
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
16,631
|
16,639
|
|||||
Commitments
and Contingencies (Note 5)
|
|||||||
COMMON
SHAREHOLDER’S EQUITY
|
|||||||
Common
Stock - No Par Value Per Share:
|
|||||||
Authorized
- 40,000,000 Shares
|
|||||||
Outstanding
- 27,952,473 Shares
|
321,201
|
321,201
|
|||||
Paid-in
Capital
|
536,639
|
466,637
|
|||||
Retained
Earnings
|
1,180,578
|
979,354
|
|||||
Accumulated
Other Comprehensive Income
|
7,055
|
755
|
|||||
TOTAL
|
2,045,473
|
1,767,947
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
6,566,109
|
$
|
6,330,670
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
201,773
|
$
|
227,372
|
|||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
239,407
|
227,687
|
|||||
Deferred
Income Taxes
|
(18,399
|
)
|
11,492
|
||||
Carrying
Costs Income
|
(10,336
|
)
|
(38,431
|
)
|
|||
Mark-to-Market
of Risk Management Contracts
|
668
|
(10,841
|
)
|
||||
Pension
Contributions to Qualified Plan Trusts
|
-
|
(60,020
|
)
|
||||
Deferred
Property Taxes
|
54,073
|
47,803
|
|||||
Change
in Other Noncurrent Assets
|
7,958
|
(12,979
|
)
|
||||
Change
in Other Noncurrent Liabilities
|
15,923
|
6,746
|
|||||
Changes
in Components of Working Capital:
|
|||||||
Accounts
Receivable, Net
|
78,307
|
(54,418
|
)
|
||||
Fuel,
Materials and Supplies
|
(25,375
|
)
|
(25,840
|
)
|
|||
Accounts
Payable
|
(44,817
|
)
|
57,644
|
||||
Accrued
Taxes, Net
|
(27,733
|
)
|
(114,998
|
)
|
|||
Other
Current Assets
|
36,333
|
28,559
|
|||||
Other
Current Liabilities
|
(31,400
|
)
|
29,803
|
||||
Net
Cash Flows From Operating Activities
|
476,382
|
319,579
|
|||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(715,200
|
)
|
(460,282
|
)
|
|||
Change
in Advances to Affiliates, Net
|
-
|
125,971
|
|||||
Other
|
5,448
|
8,896
|
|||||
Net
Cash Flows Used For Investing Activities
|
(709,752
|
)
|
(325,415
|
)
|
|||
FINANCING
ACTIVITIES
|
|||||||
Capital
Contributions from Parent Company
|
70,000
|
-
|
|||||
Issuance
of Long-term Debt - Nonaffiliated
|
405,841
|
348,237
|
|||||
Change
in Short-term Debt, Net - Nonaffiliated
|
(3,264
|
)
|
(8,133
|
)
|
|||
Change
in Advances from Affiliates, Net
|
(21,908
|
)
|
55,508
|
||||
Retirement
of Long-term Debt - Nonaffiliated
|
(10,890
|
)
|
(363,890
|
)
|
|||
Retirement
of Long-term Debt - Affiliated
|
(200,000
|
)
|
-
|
||||
Retirement
of Preferred Stock
|
(7
|
)
|
(5,000
|
)
|
|||
Principal
Payments for Capital Lease Obligations
|
(5,768
|
)
|
(5,795
|
)
|
|||
Dividends
Paid on Common Stock
|
-
|
(22,499
|
)
|
||||
Dividends
Paid on Cumulative Preferred Stock
|
(549
|
)
|
(549
|
)
|
|||
Net
Cash Flows From (Used For) Financing Activities
|
233,455
|
(2,121
|
)
|
||||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
85
|
(7,957
|
)
|
||||
Cash
and Cash Equivalents at Beginning of Period
|
1,240
|
9,337
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
1,325
|
$
|
1,380
|
|||
SUPPLEMENTARY
INFORMATION
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
71,666
|
$
|
92,073
|
|||
Net
Cash Paid for Income Taxes
|
72,175
|
158,627
|
|||||
Noncash
Acquisitions Under Capital Leases
|
2,529
|
7,591
|
|||||
Construction
Expenditures Included in Accounts Payable at September 30,
|
117,638
|
73,895
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries .
|
Footnote
Reference
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Customer
Choice and Industry Restructuring
|
Note
4
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
Third
Quarter of 2005
|
$
|
49
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
and Off-system Sales Margins
|
(2
|
)
|
|||||
Transmission
Revenues
|
(3
|
)
|
|||||
Total
Change in Gross Margin
|
(5
|
)
|
|||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(8
|
)
|
|||||
Depreciation
and Amortization
|
(1
|
)
|
|||||
Taxes
Other Than Income Taxes
|
6
|
||||||
Interest
Expense
|
(2
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(5
|
)
|
|||||
Income
Tax Expense
|
3
|
||||||
Third
Quarter of 2006
|
$
|
42
|
·
|
Retail
and Off-system Sales Margins decreased $2 million primarily due to
a $4
million decrease in retail margins resulting from lower sales to
industrial customers due to the price mix and an increase in
non-recoverable fuel items including an accrual for an unfavorable
FERC
ruling on an SPP Reactive Power dispute with Calpine, partially offset
by
an increase in Distribution Vegetation Management (DVM) recovery.
The
decrease in retail margins was partially offset by a $2 million increase
in off-system sales margins, comprised of a $16 million increase
in
margins from optimization activities partially offset by a $14 million
decrease primarily related to lower sharing of off-system sales margins
under the SIA. See the “Allocation Agreement between AEP East companies
and AEP West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Transmission
Revenues decreased $3 million due to lower point-to-point transmission
services within SPP.
|
·
|
Other
Operation and Maintenance expenses increased $8 million due to a
$6
million increase in distribution maintenance primarily related to
increased DVM expenses.
|
·
|
Taxes
Other Than Income Taxes decreased $6 million due to an adjustment
to the
provision for state sales and use
tax.
|
Nine
Months Ended September 30, 2005
|
$
|
68
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
and Off-system Sales Margins
|
12
|
||||||
Transmission
Revenues
|
(1
|
)
|
|||||
Other
|
3
|
||||||
Total
Change in Gross Margin
|
14
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(35
|
)
|
|||||
Depreciation
and Amortization
|
1
|
||||||
Taxes
Other Than Income Taxes
|
2
|
||||||
Interest
Expense
|
(5
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(37
|
)
|
|||||
Income
Tax Expense
|
6
|
||||||
Nine
Months Ended September 30, 2006
|
$
|
51
|
·
|
Retail
and Off-system Sales Margins increased $12 million primarily due
to a $20
million increase in retail margins resulting from a 29% increase
in
cooling degree days and an increase in DVM recovery, partially offset
by
an increase in non-recoverable fuel items including an accrual for
an
unfavorable FERC ruling on an SPP Reactive Power dispute with Calpine.
The
increase in retail margins was partially offset by an $8 million
decrease
in off-system sales margins comprised of a $17 million decrease primarily
related to lower sharing of off-system sales margins under the SIA,
partially offset by a $9 million increase in margins from optimization
activities. See the “Allocation Agreement between AEP East companies and
AEP West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Other
revenue increased $3 million partially due to a 2006 settlement received
from an electric cooperative.
|
·
|
Other
Operation and Maintenance expenses increased $35 million due to a
$15
million increase in distribution maintenance primarily related to
increased DVM expenses, a $7 million increase in forced and scheduled
power plant maintenance, a $6 million increase in administration
and
general expenses, mostly related to increased pension and other
postemployment benefits expense, a $5 million increase in expenses
related
to the factoring of accounts receivable and a $4 million increase
in
expenses related to power plant operations.
|
·
|
Interest
Expense increased $5 million primarily due to increased affiliated
short-term borrowings during the period and the issuance of long-term
debt
in 2006.
|
Moody’s
|
S&P
|
Fitch
|
|||
Senior
Unsecured Debt
|
Baa1
|
BBB
|
A-
|
Principal
Amount
|
Interest
|
Due
|
|||||
Type
of Debt
|
Rate
|
Date
|
|||||
(in
thousands)
|
(%)
|
||||||
Senior
Unsecured Notes
|
$
|
150,000
|
6.15
|
2016
|
Principal
Amount
|
Interest
|
Due
|
|||||
Type
of Debt
|
Rate
|
Date
|
|||||
(in
thousands)
|
(%)
|
||||||
Notes
Payable - Affiliated
|
$
|
50,000
|
3.35
|
2006
|
MTM
Risk Management Contracts
|
Cash
Flow Hedges
|
DETM
Assignment
(a)
|
Total
|
||||||||||
Current
Assets
|
$
|
71,635
|
$
|
-
|
$
|
-
|
$
|
71,635
|
|||||
Noncurrent
Assets
|
32,354
|
-
|
-
|
32,354
|
|||||||||
Total
MTM Derivative Contract Assets
|
103,989
|
-
|
-
|
103,989
|
|||||||||
Current
Liabilities
|
(75,244
|
)
|
-
|
(96
|
)
|
(75,340
|
)
|
||||||
Noncurrent
Liabilities
|
(22,869
|
)
|
-
|
(467
|
)
|
(23,336
|
)
|
||||||
Total
MTM Derivative Contract Liabilities
|
(98,113
|
)
|
-
|
(563
|
)
|
(98,676
|
)
|
||||||
Total
MTM Derivative Contract Net Assets
|
$
|
5,876
|
$
|
-
|
$
|
(563
|
)
|
$
|
5,313
|
(a)
|
Starting
in the third quarter of 2006, we were allocated a portion of the
DETM
assignment based on the FERC- approved methodology of AEP recording
trading and marketing margins shared between the AEP East and AEP
West
companies. See “Natural Gas Contracts with DETM” section of Note 17 of the
2005 Annual Report.
|
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
$
|
14,214
|
||
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
817
|
|||
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
|
(386
|
)
|
||
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
-
|
|||
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
148
|
|||
Changes
Due to SIA and CSW Operating Agreement (c)
|
10,185
|
|||
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
(19,102
|
)
|
||
Total
MTM Risk Management Contract Net Assets
|
5,876
|
|||
Net
Cash Flow Hedge Contracts
|
-
|
|||
DETM
Assignment (e)
|
(563
|
)
|
||
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
$
|
5,313
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(d)
|
“Changes
in Fair Value Allocated to Regulated Jurisdictions” relates to the net
gains (losses) of those contracts that are not reflected in the Condensed
Statements of Operations. These net gains (losses) are recorded as
regulatory liabilities/assets for those subsidiaries that operate
in
regulated jurisdictions.
|
(e)
|
Starting
in the third quarter of 2006, we were allocated a portion of the
DETM
assignment based on the FERC- approved methodology of AEP recording
trading margins shared between the AEP East and AEP West companies.
See
“Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual
Report.
|
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving an indication
of
when these MTM amounts will settle and generate
cash.
|
Remainder
2006
|
2007
|
2008
|
2009
|
2010
|
After
2010
|
Total
|
||||||||||||||||
Prices
Actively Quoted - Exchange Traded
Contracts
|
$
|
(3,194
|
)
|
$
|
(21,390
|
)
|
$
|
3,101
|
$
|
(383
|
)
|
$
|
-
|
$
|
-
|
$
|
(21,866
|
)
|
||||
Prices
Provided by Other External Sources
- OTC Broker
Quotes (a)
|
(6,056
|
)
|
27,924
|
5,533
|
(490
|
)
|
-
|
-
|
26,911
|
|||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
(143
|
)
|
(216
|
)
|
(131
|
)
|
1,313
|
42
|
(34
|
)
|
831
|
|||||||||||
Total
|
$
|
(9,393
|
)
|
$
|
6,318
|
$
|
8,503
|
$
|
440
|
$
|
42
|
$
|
(34
|
)
|
$
|
5,876
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Power
|
Interest
Rate
|
Total
|
||||||||
Beginning
Balance in AOCI December 31, 2005
|
$
|
(629
|
)
|
$
|
(483
|
)
|
$
|
(1,112
|
)
|
|
Changes
in Fair Value
|
-
|
-
|
-
|
|||||||
Impact
Due to Change in SIA (a)
|
506
|
-
|
506
|
|||||||
Reclassifications
from AOCI to Net Income for Cash
Flow Hedges Settled
|
123
|
(633
|
)
|
(510
|
)
|
|||||
Ending
Balance in AOCI September 30, 2006
|
$
|
-
|
$
|
(1,116
|
)
|
$
|
(1,116
|
)
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
Nine
Months Ended
September
30, 2006
|
Twelve
Months Ended
December
31, 2005
|
||||||||||||||||
(in
thousands)
|
(in
thousands)
|
||||||||||||||||
End
|
High
|
Average
|
Low
|
End
|
High
|
Average
|
Low
|
||||||||||
$1,175
|
$1,786
|
$647
|
$58
|
$311
|
$517
|
$246
|
$89
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
REVENUES
|
|||||||||||||
Electric
Generation, Transmission and Distribution
|
$
|
443,593
|
$
|
415,558
|
$
|
1,116,507
|
$
|
937,985
|
|||||
Sales
to AEP Affiliates
|
14,034
|
16,032
|
40,647
|
32,314
|
|||||||||
Other
|
814
|
1,043
|
3,062
|
2,018
|
|||||||||
TOTAL
|
458,441
|
432,633
|
1,160,216
|
972,317
|
|||||||||
EXPENSES
|
|||||||||||||
Fuel
and Other Consumables for Electric Generation
|
202,836
|
192,968
|
566,985
|
456,690
|
|||||||||
Purchased
Electricity for Resale
|
68,547
|
39,186
|
158,122
|
84,111
|
|||||||||
Purchased
Electricity from AEP Affiliates
|
17,706
|
26,643
|
54,817
|
64,877
|
|||||||||
Other
Operation
|
40,756
|
40,029
|
117,721
|
107,168
|
|||||||||
Maintenance
|
25,072
|
17,809
|
67,412
|
43,321
|
|||||||||
Depreciation
and Amortization
|
22,103
|
20,842
|
64,724
|
65,708
|
|||||||||
Taxes
Other Than Income Taxes
|
3,844
|
9,769
|
23,997
|
25,507
|
|||||||||
TOTAL
|
380,864
|
347,246
|
1,053,778
|
847,382
|
|||||||||
OPERATING
INCOME
|
77,577
|
85,387
|
106,438
|
124,935
|
|||||||||
Other
Income (Expense):
|
|||||||||||||
Interest
Income
|
828
|
658
|
1,734
|
729
|
|||||||||
Allowance
for Equity Funds Used During Construction
|
222
|
206
|
96
|
542
|
|||||||||
Interest
Expense
|
(10,954
|
)
|
(8,677
|
)
|
(29,723
|
)
|
(25,173
|
)
|
|||||
INCOME
BEFORE INCOME TAXES
|
67,673
|
77,574
|
78,545
|
101,033
|
|||||||||
Income
Tax Expense
|
25,650
|
28,920
|
27,241
|
33,304
|
|||||||||
NET
INCOME
|
42,023
|
48,654
|
51,304
|
67,729
|
|||||||||
Preferred
Stock Dividend Requirements
|
53
|
53
|
159
|
159
|
|||||||||
EARNINGS
APPLICABLE TO COMMON STOCK
|
$
|
41,970
|
$
|
48,601
|
$
|
51,145
|
$
|
67,570
|
Common
Stock
|
Paid-in
Capital
|
Retained
Earnings
|
Accumulated
Other Comprehensive Income (Loss)
|
Total
|
||||||||||||
DECEMBER
31, 2004
|
$
|
157,230
|
$
|
230,016
|
$
|
141,935
|
$
|
75
|
$
|
529,256
|
||||||
Common
Stock Dividends
|
(27,000
|
)
|
(27,000
|
)
|
||||||||||||
Preferred
Stock Dividends
|
(159
|
)
|
(159
|
)
|
||||||||||||
TOTAL
|
502,097
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $2,581
|
(4,794
|
)
|
(4,794
|
)
|
||||||||||||
NET
INCOME
|
67,729
|
67,729
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
62,935
|
|||||||||||||||
SEPTEMBER
30, 2005
|
$
|
157,230
|
$
|
230,016
|
$
|
182,505
|
$
|
(4,719
|
)
|
$
|
565,032
|
|||||
DECEMBER
31, 2005
|
$
|
157,230
|
$
|
230,016
|
$
|
162,615
|
$
|
(1,264
|
)
|
$
|
548,597
|
|||||
Preferred
Stock Dividends
|
(159
|
)
|
(159
|
)
|
||||||||||||
TOTAL
|
548,438
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net
of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $2
|
(4
|
)
|
(4
|
)
|
||||||||||||
NET
INCOME
|
51,304
|
51,304
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
51,300
|
|||||||||||||||
SEPTEMBER
30, 2006
|
$
|
157,230
|
$
|
230,016
|
$
|
213,760
|
$
|
(1,268
|
)
|
$
|
599,738
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Cash
and Cash Equivalents
|
$
|
2,277
|
$
|
1,520
|
|||
Advances
to Affiliates
|
43,538
|
-
|
|||||
Accounts
Receivable:
|
|||||||
Customers
|
59,153
|
37,740
|
|||||
Affiliated
Companies
|
54,535
|
73,321
|
|||||
Miscellaneous
|
10,105
|
10,501
|
|||||
Allowance
for Uncollectible Accounts
|
(82
|
)
|
(240
|
)
|
|||
Total Accounts Receivable
|
123,711
|
121,322
|
|||||
Fuel
|
15,301
|
16,431
|
|||||
Materials
and Supplies
|
46,665
|
38,545
|
|||||
Risk
Management Assets
|
71,635
|
40,383
|
|||||
Accrued
Tax Benefits
|
61
|
11,972
|
|||||
Regulatory
Asset for Under-Recovered Fuel Costs
|
31,794
|
108,732
|
|||||
Margin
Deposits
|
35,862
|
10,051
|
|||||
Prepayments
and Other
|
8,058
|
4,236
|
|||||
TOTAL
|
378,902
|
353,192
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric:
|
|||||||
Production
|
1,083,390
|
1,072,928
|
|||||
Transmission
|
499,175
|
479,272
|
|||||
Distribution
|
1,196,071
|
1,140,535
|
|||||
Other
|
239,625
|
211,805
|
|||||
Construction
Work in Progress
|
82,724
|
90,455
|
|||||
Total
|
3,100,985
|
2,994,995
|
|||||
Accumulated
Depreciation and Amortization
|
1,192,825
|
1,175,858
|
|||||
TOTAL
- NET
|
1,908,160
|
1,819,137
|
|||||
OTHER
NONCURRENT ASSETS
|
|||||||
Regulatory
Assets
|
76,543
|
50,723
|
|||||
Long-term
Risk Management Assets
|
32,354
|
33,566
|
|||||
Employee
Benefits and Pension Assets
|
79,701
|
82,559
|
|||||
Deferred
Charges and Other
|
22,372
|
16,287
|
|||||
TOTAL
|
210,970
|
183,135
|
|||||
TOTAL
ASSETS
|
$
|
2,498,032
|
$
|
2,355,464
|
2006
|
2005
|
||||||
CURRENT
LIABILITIES
|
(in
thousands)
|
||||||
Advances
from Affiliates
|
$
|
-
|
$
|
75,883
|
|||
Accounts
Payable:
|
|||||||
General
|
130,260
|
130,627
|
|||||
Affiliated
Companies
|
89,834
|
89,786
|
|||||
Long-term
Debt Due Within One Year - Affiliated
|
-
|
50,000
|
|||||
Risk
Management Liabilities
|
75,340
|
38,243
|
|||||
Customer
Deposits
|
51,107
|
53,844
|
|||||
Accrued
Taxes
|
59,354
|
22,420
|
|||||
Other
|
37,793
|
51,548
|
|||||
TOTAL
|
443,688
|
512,351
|
|||||
NONCURRENT
LIABILITIES
|
|||||||
Long-term
Debt - Nonaffiliated
|
669,953
|
521,071
|
|||||
Long-term
Risk Management Liabilities
|
23,336
|
22,582
|
|||||
Deferred
Income Taxes
|
418,846
|
436,382
|
|||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
309,818
|
284,640
|
|||||
Deferred
Credits and Other
|
27,391
|
24,579
|
|||||
TOTAL
|
1,449,344
|
1,289,254
|
|||||
TOTAL
LIABILITIES
|
1,893,032
|
1,801,605
|
|||||
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
5,262
|
5,262
|
|||||
Commitments
and Contingencies (Note 5)
|
|||||||
COMMON
SHAREHOLDER’S EQUITY
|
|||||||
Common
Stock - $15 Par Value Per Share:
|
|||||||
Authorized
- 11,000,000 Shares
|
|||||||
Issued
- 10,482,000 Shares
|
|||||||
Outstanding
- 9,013,000 Shares
|
157,230
|
157,230
|
|||||
Paid-in
Capital
|
230,016
|
230,016
|
|||||
Retained
Earnings
|
213,760
|
162,615
|
|||||
Accumulated
Other Comprehensive Income (Loss)
|
(1,268
|
)
|
(1,264
|
)
|
|||
TOTAL
|
599,738
|
548,597
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
2,498,032
|
$
|
2,355,464
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
51,304
|
$
|
67,729
|
|||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
64,724
|
65,708
|
|||||
Deferred
Income Taxes
|
(18,661
|
)
|
32,661
|
||||
Mark-to-Market
of Risk Management Contracts
|
8,901
|
(2,954
|
)
|
||||
Deferred
Property Taxes
|
(8,098
|
)
|
(8,123
|
)
|
|||
Change
in Other Noncurrent Assets
|
18,186
|
(34,576
|
)
|
||||
Change
in Other Noncurrent Liabilities
|
(24,838
|
)
|
26,798
|
||||
Changes
in Components of Working Capital:
|
|||||||
Accounts
Receivable, Net
|
(2,389
|
)
|
(1,687
|
)
|
|||
Fuel,
Materials and Supplies
|
(6,990
|
)
|
(3,873
|
)
|
|||
Margin
Deposits
|
(25,811
|
)
|
(16,121
|
)
|
|||
Accounts
Payable
|
1,585
|
69,794
|
|||||
Customer
Deposits
|
(2,737
|
)
|
24,404
|
||||
Accrued
Taxes, Net
|
48,845
|
480
|
|||||
Over/Under
Fuel Recovery
|
76,938
|
(81,808
|
)
|
||||
Other
Current Assets
|
(3,828
|
)
|
(7,253
|
)
|
|||
Other
Current Liabilities
|
(13,755
|
)
|
(6,099
|
)
|
|||
Net
Cash Flows From Operating Activities
|
163,376
|
125,080
|
|||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(140,998
|
)
|
(87,804
|
)
|
|||
Change
in Other Cash Deposits, Net
|
6
|
(6
|
)
|
||||
Change
in Advances to Affiliates, Net
|
(43,538
|
)
|
-
|
||||
Net
Cash Flows Used For Investing Activities
|
(184,530
|
)
|
(87,810
|
)
|
|||
FINANCING
ACTIVITIES
|
|||||||
Issuance
of Long-term Debt - Nonaffiliated
|
148,747
|
74,405
|
|||||
Change
in Advances from Affiliates, Net
|
(75,883
|
)
|
(32,401
|
)
|
|||
Retirement
of Long-term Debt - Nonaffiliated
|
-
|
(50,000
|
)
|
||||
Retirement
of Long-term Debt - Affiliated
|
(50,000
|
)
|
-
|
||||
Principal
Payments for Capital Lease Obligations
|
(794
|
)
|
(483
|
)
|
|||
Dividends
Paid on Common Stock
|
-
|
(27,000
|
)
|
||||
Dividends
Paid on Cumulative Preferred Stock
|
(159
|
)
|
(159
|
)
|
|||
Net
Cash Flows From (Used For) Financing Activities
|
21,911
|
(35,638
|
)
|
||||
Net
Increase in Cash and Cash Equivalents
|
757
|
1,632
|
|||||
Cash
and Cash Equivalents at Beginning of Period
|
1,520
|
279
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
2,277
|
$
|
1,911
|
|||
SUPPLEMENTARY
INFORMATION
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
25,491
|
$
|
21,954
|
|||
Net
Cash Paid for Income Taxes
|
7,471
|
14,241
|
|||||
Noncash
Acquisitions Under Capital Leases
|
2,639
|
798
|
|||||
Construction
Expenditures Included in Accounts Payable at September 30,
|
6,591
|
3,482
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
Footnote
Reference
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Income
Taxes
|
Note
10
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
Third
Quarter of 2005
|
$
|
50
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
and Off-system Sales Margins (a)
|
(9
|
)
|
|||||
Transmission
Revenues
|
(1
|
)
|
|||||
Other
|
6
|
||||||
Total
Change in Gross Margin
|
(4
|
)
|
|||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
6
|
||||||
Taxes
Other Than Income Taxes
|
1
|
||||||
Interest
Expense
|
(1
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
6
|
||||||
Income
Tax Expense
|
(2
|
)
|
|||||
Third
Quarter of 2006
|
$
|
50
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
·
|
Retail
and Off-system Sales Margins decreased $9 million primarily due to
a $4
million non-recoverable accrual for an unfavorable FERC ruling on
an SPP
Reactive Power Contract with Calpine as well as an $8 million decrease
in
off-system sales margins primarily due to lower sharing of off-system
sales margins under the SIA. Partially offsetting these decreases
was a $3
million increase in wholesale revenues due to higher usage and favorable
prices. See the “Allocation Agreement between AEP East companies and AEP
West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Other
revenues increased $6 million primarily due to gains on sales of
emission
allowances.
|
·
|
Other
Operation and Maintenance decreased $6 million primarily due to a
$3
million decrease in transmission operation expense resulting from
favorable changes to the SPP fee structure as well as a $3 million
decrease in overhead line maintenance expense primarily related to
the
absence of 2005 hurricane-related
expenses.
|
Nine
Months Ended September 30, 2005
|
$
|
81
|
|||||
Changes
in Gross Margin:
|
|||||||
Retail
and Off-system Sales Margins (a)
|
15
|
||||||
Transmission
Revenues
|
1
|
||||||
Other
|
22
|
||||||
Total
Change in Gross Margin
|
38
|
||||||
Changes
in Operating Expenses and Other:
|
|||||||
Other
Operation and Maintenance
|
(8
|
)
|
|||||
Interest
Expense
|
(2
|
)
|
|||||
Total
Change in Operating Expenses and Other
|
(10
|
)
|
|||||
Income
Tax Expense
|
(13
|
)
|
|||||
Nine
Months Ended September 30, 2006
|
$
|
96
|
(a)
|
Includes
firm wholesale sales to municipals and
cooperatives.
|
·
|
Retail
and Off-system Sales Margins increased $15 million primarily due
to a $17
million increase in wholesale margins resulting from higher prices,
increased usage and new wholesale contracts, as well as a $15 million
increase primarily due to increased wholesale fuel recovery. These
increases were partially offset by a $17 million decrease in off-system
sales margins primarily due to lower sharing of off-system sales
margins
under the SIA. See the “Allocation Agreement between AEP East companies
and AEP West companies and CSW Operating Agreement” section of Note
3.
|
·
|
Other
revenues increased $22 million primarily due to gains on sales of
emission
allowances.
|
·
|
Other
Operation and Maintenance expenses increased $8 million primarily
due to a
$5 million increase in employee-related expenses, a $3 million increase
in
mining operations expense resulting from increased production and
a $2
million increase in expenses related to the factoring of customer
accounts
receivable, offset by the absence of $4 million of 2005 hurricane-related
expenses.
|
Moody’s
|
S&P
|
Fitch
|
|||
First
Mortgage Bonds
|
A3
|
A-
|
A
|
||
Senior
Unsecured Debt
|
Baa1
|
BBB
|
A-
|
2006
|
2005
|
||||||
(in
thousands)
|
|||||||
Cash
and Cash Equivalents at Beginning of Period
|
$
|
3,049
|
$
|
3,715
|
|||
Net
Cash Flows From (Used For):
|
|||||||
Operating
Activities
|
242,721
|
163,705
|
|||||
Investing
Activities
|
(186,631
|
)
|
(67,857
|
)
|
|||
Financing
Activities
|
(56,343
|
)
|
(95,759
|
)
|
|||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
(253
|
)
|
89
|
||||
Cash
and Cash Equivalents at End of Period
|
$
|
2,796
|
$
|
3,804
|
Principal
Amount
|
Interest
|
Due
|
|||||
Type
of Debt
|
Rate
|
Date
|
|||||
(in
thousands)
|
(%)
|
||||||
Pollution
Control Bonds
|
$
|
81,700
|
Variable
|
2018
|
Principal
Amount
|
Interest
|
Due
|
|||||
Type
of Debt
|
Rate
|
Date
|
|||||
(in
thousands)
|
(%)
|
||||||
Notes
Payable
|
$
|
5,039
|
4.47
|
2011
|
|||
Notes
Payable
|
2,250
|
Variable
|
2008
|
||||
Pollution
Control Bonds
|
81,700
|
6.10
|
2018
|
MTM
Risk Management Contracts
|
Cash
Flow Hedges
|
DETM
Assignment
(a)
|
Total
|
||||||||||
Current
Assets
|
$
|
84,685
|
$
|
-
|
$
|
-
|
$
|
84,685
|
|||||
Noncurrent
Assets
|
38,252
|
-
|
-
|
38,252
|
|||||||||
Total
MTM Derivative Contract Assets
|
122,937
|
-
|
-
|
122,937
|
|||||||||
Current
Liabilities
|
(89,430
|
)
|
(4,097
|
)
|
(114
|
)
|
(93,641
|
)
|
|||||
Noncurrent
Liabilities
|
(27,326
|
)
|
(28
|
)
|
(550
|
)
|
(27,904
|
)
|
|||||
Total
MTM Derivative Contract Liabilities
|
(116,756
|
)
|
(4,125
|
)
|
(664
|
)
|
(121,545
|
)
|
|||||
Total
MTM Derivative Contract Net Assets (Liabilities)
|
$
|
6,181
|
$
|
(4,125
|
)
|
$
|
(664
|
)
|
$
|
1,392
|
(a)
|
Starting
in the third quarter of 2006, we were allocated a portion of the
DETM
assignment based on the FERC- approved methodology of AEP recording
trading and marketing margins shared between the AEP East and AEP
West
companies. See “Natural Gas Contracts with DETM” section of Note 17 of the
2005 Annual Report.
|
Total
MTM Risk Management Contract Net Assets at December 31,
2005
|
$
|
16,387
|
||
(Gain)
Loss from Contracts Realized/Settled During the Period and Entered
in a
Prior Period
|
655
|
|||
Fair
Value of New Contracts at Inception When Entered During the Period
(a)
|
52
|
|||
Net
Option Premiums Paid/(Received) for Unexercised or Unexpired Option
Contracts Entered During the Period
|
(452
|
)
|
||
Change
in Fair Value Due to Valuation Methodology Changes on Forward
Contracts
|
139
|
|||
Changes
in Fair Value Due to Market Fluctuations During the Period
(b)
|
(7,302
|
)
|
||
Changes
Due to SIA and CSW Operating Agreement (c)
|
11,900
|
|||
Changes
in Fair Value Allocated to Regulated Jurisdictions (d)
|
(15,198
|
)
|
||
Total
MTM Risk Management Contract Net Assets
|
6,181
|
|||
Net
Cash Flow Hedge Contracts
|
(4,125
|
)
|
||
DETM
Assignment (e)
|
(664
|
)
|
||
Total
MTM Risk Management Contract Net Assets at September 30,
2006
|
$
|
1,392
|
(a)
|
Most
of the fair value comes from longer term fixed price contracts with
customers that seek to limit their risk against fluctuating energy
prices.
Inception value is only recorded if observable market data can be
obtained
for valuation inputs for the entire contract term. The contract prices
are
valued against market curves associated with the delivery location
and
delivery term.
|
(b)
|
Market
fluctuations are attributable to various factors such as supply/demand,
weather, etc.
|
(c)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note 3.
|
(d)
|
“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.
|
(e)
|
Starting
in the third quarter of 2006, we were allocated a portion of the
DETM
assignment based on the FERC- approved methodology of AEP recording
trading and marketing margins shared between the AEP East and AEP
West
companies. See “Natural Gas Contracts with DETM” section of Note 17 of the
2005 Annual Report.
|
·
|
The
method of measuring fair value used in determining the carrying amount
of
our total MTM asset or liability (external sources or modeled
internally).
|
·
|
The
maturity, by year, of our net assets/liabilities giving an indication
of
when these MTM amounts will settle and generate
cash.
|
Remainder
2006
|
2007
|
2008
|
2009
|
2010
|
After
2010
|
Total
|
||||||||||||||||
Prices
Actively Quoted - Exchange Traded
Contracts
|
$
|
(3,762
|
)
|
$
|
(25,203
|
)
|
$
|
3,654
|
$
|
(451
|
)
|
$
|
-
|
$
|
-
|
$
|
(25,762
|
)
|
||||
Prices
Provided by Other External Sources
- OTC Broker Quotes
(a)
|
(7,187
|
)
|
32,724
|
6,546
|
(577
|
)
|
-
|
-
|
31,506
|
|||||||||||||
Prices
Based on Models and Other Valuation
Methods (b)
|
(173
|
)
|
(636
|
)
|
(310
|
)
|
1,546
|
50
|
(40
|
)
|
437
|
|||||||||||
Total
|
$
|
(11,122
|
)
|
$
|
6,885
|
$
|
9,890
|
$
|
518
|
$
|
50
|
$
|
(40
|
)
|
$
|
6,181
|
(a)
|
“Prices
Provided by Other External Sources - OTC Broker Quotes” reflects
information obtained from over-the-counter brokers, industry services,
or
multiple-party on-line platforms.
|
(b)
|
“Prices
Based on Models and Other Valuation Methods” is used in absence of pricing
information from external sources. Modeled information is derived
using
valuation models developed by the reporting entity, reflecting when
appropriate, option pricing theory, discounted cash flow concepts,
valuation adjustments, etc. and may require projection of prices
for
underlying commodities beyond the period that prices are available
from
third-party sources. In addition, where external pricing information
or
market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid
for
placing it in the modeled category varies by
market.
|
Power
|
Interest
Rate
|
Total
|
||||||||
Beginning
Balance in AOCI December 31, 2005
|
$
|
(736
|
)
|
$
|
(5,116
|
)
|
$
|
(5,852
|
)
|
|
Changes
in Fair Value
|
-
|
(2,655
|
)
|
(2,655
|
)
|
|||||
Impact
due to Change in SIA (a)
|
591
|
-
|
591
|
|||||||
Reclassifications
from AOCI to Net Income for Cash
Flow Hedges Settled
|
145
|
403
|
548
|
|||||||
Ending
Balance in AOCI September 30, 2006
|
$
|
-
|
$
|
(7,368
|
)
|
$
|
(7,368
|
)
|
(a)
|
See
“Allocation Agreement between AEP East companies and AEP West companies
and CSW Operating Agreement” section of Note
3.
|
Nine
Months Ended
September
30, 2006
|
Twelve
Months Ended
December
31, 2005
|
||||||||||||||||
(in
thousands)
|
(in
thousands)
|
||||||||||||||||
End
|
High
|
Average
|
Low
|
End
|
High
|
Average
|
Low
|
||||||||||
$1,385
|
$2,104
|
$758
|
$68
|
$363
|
$604
|
$287
|
$104
|
Three
Months Ended
|
Nine
Months Ended
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
REVENUES
|
|||||||||||||
Electric
Generation, Transmission and Distribution
|
$
|
440,542
|
$
|
459,220
|
$
|
1,084,185
|
$
|
1,015,074
|
|||||
Sales
to AEP Affiliates
|
14,692
|
14,614
|
34,871
|
38,573
|
|||||||||
Other
|
1,466
|
449
|
2,260
|
698
|
|||||||||
TOTAL
|
456,700
|
474,283
|
1,121,316
|
1,054,345
|
|||||||||
EXPENSES
|
|||||||||||||
Fuel
and Other Consumables for Electric Generation
|
158,992
|
179,904
|
367,924
|
386,719
|
|||||||||
Purchased
Electricity for Resale
|
61,816
|
45,194
|
135,918
|
91,377
|
|||||||||
Purchased
Electricity from AEP Affiliates
|
18,140
|
27,363
|
58,303
|
55,230
|
|||||||||
Other
Operation
|
55,256
|
60,229
|
158,338
|
152,340
|
|||||||||
Maintenance
|
21,120
|
22,353
|
68,008
|
65,713
|
|||||||||
Depreciation
and Amortization
|
32,996
|
32,930
|
98,406
|
98,580
|
|||||||||
Taxes
Other Than Income Taxes
|
17,107
|
18,175
|
49,254
|
49,725
|
|||||||||
TOTAL
|
365,427
|
386,148
|
936,151
|
899,684
|
|||||||||
OPERATING
INCOME
|
91,273
|
88,135
|
185,165
|
154,661
|
|||||||||
Other
Income (Expense):
|
|||||||||||||
Interest
Income
|
822
|
250
|
2,277
|
1,167
|
|||||||||
Allowance
for Equity Funds Used During Construction
|
287
|
516
|
400
|
1,849
|
|||||||||
Interest
Expense
|
(13,844
|
)
|
(12,346
|
)
|
(40,688
|
)
|
(38,027
|
)
|
|||||
INCOME
BEFORE INCOME TAXES AND MINORITY
INTEREST
EXPENSE
|
78,538
|
76,555
|
147,154
|
119,650
|
|||||||||
Income
Tax Expense
|
27,873
|
25,789
|
49,187
|
35,675
|
|||||||||
Minority
Interest Expense
|
959
|
1,035
|
2,077
|
2,735
|
|||||||||
NET
INCOME
|
49,706
|
49,731
|
95,890
|
81,240
|
|||||||||
Preferred
Stock Dividend Requirements
|
57
|
57
|
172
|
172
|
|||||||||
EARNINGS
APPLICABLE TO COMMON STOCK
|
$
|
49,649
|
$
|
49,674
|
$
|
95,718
|
$
|
81,068
|
The
common stock of SWEPCo is owned by a wholly-owned subsidiary of
AEP.
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
Common
Stock
|
Paid-in
Capital
|
Retained
Earnings
|
Accumulated
Other Comprehensive Income (Loss)
|
Total
|
||||||||||||
DECEMBER
31, 2004
|
$
|
135,660
|
$
|
245,003
|
$
|
389,135
|
$
|
(1,180
|
)
|
$
|
768,618
|
|||||
Common
Stock Dividends
|
(40,000
|
)
|
(40,000
|
)
|
||||||||||||
Preferred
Stock Dividends
|
(172
|
)
|
(172
|
)
|
||||||||||||
TOTAL
|
728,446
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $4,827
|
(8,965
|
)
|
(8,965
|
)
|
||||||||||||
NET
INCOME
|
81,240
|
81,240
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
72,275
|
|||||||||||||||
SEPTEMBER
30, 2005
|
$
|
135,660
|
$
|
245,003
|
$
|
430,203
|
$
|
(10,145
|
)
|
$
|
800,721
|
|||||
DECEMBER
31, 2005
|
$
|
135,660
|
$
|
245,003
|
$
|
407,844
|
$
|
(6,129
|
)
|
$
|
782,378
|
|||||
Common
Stock Dividends
|
(30,000
|
)
|
(30,000
|
)
|
||||||||||||
Preferred
Stock Dividends
|
(172
|
)
|
(172
|
)
|
||||||||||||
TOTAL
|
752,206
|
|||||||||||||||
COMPREHENSIVE
INCOME
|
||||||||||||||||
Other
Comprehensive Loss, Net
of Taxes:
|
||||||||||||||||
Cash
Flow Hedges, Net of Tax of $817
|
(1,516
|
)
|
(1,516
|
)
|
||||||||||||
NET
INCOME
|
95,890
|
95,890
|
||||||||||||||
TOTAL
COMPREHENSIVE INCOME
|
94,374
|
|||||||||||||||
SEPTEMBER
30, 2006
|
$
|
135,660
|
$
|
245,003
|
$
|
473,562
|
$
|
(7,645
|
)
|
$
|
846,580
|
2006
|
2005
|
||||||
CURRENT
ASSETS
|
|||||||
Cash
and Cash Equivalents
|
$
|
2,796
|
$
|
3,049
|
|||
Advances
to Affiliates
|
7,018
|
-
|
|||||
Accounts
Receivable:
|
|||||||
Customers
|
65,274
|
47,515
|
|||||
Affiliated
Companies
|
40,779
|
49,226
|
|||||
Miscellaneous
|
8,260
|
7,984
|
|||||
Allowance
for Uncollectible Accounts
|
(264
|
)
|
(548
|
)
|
|||
Total Accounts Receivable
|
114,049
|
104,177
|
|||||
Fuel
|
58,785
|
40,333
|
|||||
Materials
and Supplies
|
43,108
|
34,821
|
|||||
Risk
Management Assets
|
84,685
|
47,319
|
|||||
Regulatory
Asset for Under-Recovered Fuel Costs
|
-
|
51,387
|
|||||
Margin
Deposits
|
42,232
|
13,740
|
|||||
Prepayments
and Other
|
19,129
|
20,270
|
|||||
TOTAL
|
371,802
|
315,096
|
|||||
PROPERTY,
PLANT AND EQUIPMENT
|
|||||||
Electric:
|
|||||||
Production
|
1,697,764
|
1,660,392
|
|||||
Transmission
|
662,009
|
645,297
|
|||||
Distribution
|
1,200,577
|
1,153,026
|
|||||
Other
|
458,905
|
443,749
|
|||||
Construction
Work in Progress
|
137,128
|
104,175
|
|||||
Total
|
4,156,383
|
4,006,639
|
|||||
Accumulated
Depreciation and Amortization
|
1,825,110
|
1,776,216
|
|||||
TOTAL
- NET
|
2,331,273
|
2,230,423
|
|||||
OTHER
NONCURRENT ASSETS
|
|||||||
Regulatory
Assets
|
101,273
|
81,776
|
|||||
Long-term
Risk Management Assets
|
38,252
|
39,796
|
|||||
Employee
Benefits and Pension Assets
|
79,770
|
83,330
|
|||||
Deferred
Charges and Other
|
54,333
|
46,926
|
|||||
TOTAL
|
273,628
|
251,828
|
|||||
TOTAL
ASSETS
|
$
|
2,976,703
|
$
|
2,797,347
|
2006
|
2005
|
||||||
CURRENT
LIABILITIES
|
(in
thousands)
|
||||||
Advances
from Affiliates
|
$
|
-
|
$
|
28,210
|
|||
Accounts
Payable:
|
|||||||
General
|
94,188
|
71,138
|
|||||
Affiliated
Companies
|
82,937
|
53,019
|
|||||
Short-term
Debt - Nonaffiliated
|
15,676
|
1,394
|
|||||
Long-term
Debt Due Within One Year - Nonaffiliated
|
108,926
|
15,755
|
|||||
Risk
Management Liabilities
|
93,641
|
45,098
|
|||||
Customer
Deposits
|
48,931
|
50,848
|
|||||
Accrued
Taxes
|
89,311
|
42,799
|
|||||
Other
|
79,223
|
82,699
|
|||||
TOTAL
|
612,833
|
390,960
|
|||||
NONCURRENT
LIABILITIES
|
|||||||
Long-term
Debt - Nonaffiliated
|
578,575
|
678,886
|
|||||
Long-term
Debt - Affiliated
|
50,000
|
50,000
|
|||||
Long-term
Risk Management Liabilities
|
27,904
|
27,083
|
|||||
Deferred
Income Taxes
|
379,470
|
409,513
|
|||||
Regulatory
Liabilities and Deferred Investment Tax Credits
|
343,954
|
320,066
|
|||||
Deferred
Credits and Other
|
131,017
|
131,477
|
|||||
TOTAL
|
1,510,920
|
1,617,025
|
|||||
TOTAL
LIABILITIES
|
2,123,753
|
2,007,985
|
|||||
Minority
Interest
|
1,672
|
2,284
|
|||||
Cumulative
Preferred Stock Not Subject to Mandatory Redemption
|
4,698
|
4,700
|
|||||
Commitments
and Contingencies (Note 5)
|
|||||||
COMMON
SHAREHOLDER’S EQUITY
|
|||||||
Common
Stock - $18 Par Value Per Share:
|
|||||||
Authorized
- 7,600,000 Shares
|
|||||||
Outstanding
- 7,536,640 Shares
|
135,660
|
135,660
|
|||||
Paid-in
Capital
|
245,003
|
245,003
|
|||||
Retained
Earnings
|
473,562
|
407,844
|
|||||
Accumulated
Other Comprehensive Income (Loss)
|
(7,645
|
)
|
(6,129
|
)
|
|||
TOTAL
|
846,580
|
782,378
|
|||||
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$
|
2,976,703
|
$
|
2,797,347
|
2006
|
2005
|
||||||
OPERATING
ACTIVITIES
|
|||||||
Net
Income
|
$
|
95,890
|
$
|
81,240
|
|||
Adjustments
for Noncash Items:
|
|||||||
Depreciation
and Amortization
|
98,406
|
98,580
|
|||||
Deferred
Income Taxes
|
(24,642
|
)
|
11,552
|
||||
Mark-to-Market
of Risk Management Contracts
|
10,870
|
(3,141
|
)
|
||||
Deferred
Property Taxes
|
(9,438
|
)
|
(9,579
|
)
|
|||
Change
in Other Noncurrent Assets
|
20,982
|
(16,262
|
)
|
||||
Change
in Other Noncurrent Liabilities
|
(33,256
|
)
|
10,149
|
||||
Changes
in Components of Working Capital:
|
|||||||
Accounts
Receivable, Net
|
(9,872
|
)
|
(3,337
|
)
|
|||
Fuel,
Materials and Supplies
|
(26,739
|
)
|
6,254
|
||||
Margin
Deposits
|
(28,492
|
)
|
(18,766
|
)
|
|||
Accounts
Payable
|
54,264
|
41,775
|
|||||
Customer Deposits | (1,917 | ) | 26,571 | ||||
Accrued
Taxes, Net
|
45,514
|
4,655
|
|||||
Over/Under Fuel Recovery, Net | 63,862 | (66,173 | ) | ||||
Other
Current Assets
|
2,635
|
(3,859
|
)
|
||||
Other
Current Liabilities
|
(15,346
|
)
|
4,046
|
||||
Net
Cash Flows From Operating Activities
|
242,721
|
163,705
|
|||||
INVESTING
ACTIVITIES
|
|||||||
Construction
Expenditures
|
(179,117
|
)
|
(110,209
|
)
|
|||
Change
in Advances to Affiliates, Net
|
(7,018
|
)
|
39,106
|
||||
Other
|
(496
|
)
|
3,246
|
||||
Net
Cash Flows Used For Investing Activities
|
(186,631
|
)
|
(67,857
|
)
|
|||
FINANCING
ACTIVITIES
|
|||||||
Issuance
of Long-term Debt - Nonaffiliated
|
80,593
|
154,642
|
|||||
Change
in Short-term Debt, Net - Nonaffiliated
|
14,282
|
-
|
|||||
Change
in Advances from Affiliates, Net
|
(28,210
|
)
|
605
|
||||
Retirement
of Long-term Debt - Nonaffiliated
|
(88,989
|
)
|
(208,122
|
)
|
|||
Retirement
of Preferred Stock
|
(2
|
)
|
-
|
||||
Principal
Payments for Capital Lease Obligations
|
(3,845
|
)
|
(2,712
|
)
|
|||
Dividends
Paid on Common Stock
|
(30,000
|
)
|
(40,000
|
)
|
|||
Dividends
Paid on Cumulative Preferred Stock
|
(172
|
)
|
(172
|
)
|
|||
Net
Cash Flows Used For Financing Activities
|
(56,343
|
)
|
(95,759
|
)
|
|||
Net
Increase (Decrease) in Cash and Cash Equivalents
|
(253
|
)
|
89
|
||||
Cash
and Cash Equivalents at Beginning of Period
|
3,049
|
3,715
|
|||||
Cash
and Cash Equivalents at End of Period
|
$
|
2,796
|
$
|
3,804
|
|||
SUPPLEMENTARY
INFORMATION
|
|||||||
Cash
Paid for Interest, Net of Capitalized Amounts
|
$
|
37,372
|
$
|
33,748
|
|||
Net
Cash Paid for Income Taxes
|
53,509
|
49,176
|
|||||
Noncash
Acquisitions Under Capital Leases
|
17,110
|
4,414
|
|||||
Construction
Expenditures Included in Accounts Payable at September 30,
|
8,924
|
5,075
|
See
Condensed Notes to Condensed Financial Statements of Registrant
Subsidiaries.
|
Footnote
Reference
|
|
Significant
Accounting Matters
|
Note
1
|
New
Accounting Pronouncements
|
Note
2
|
Rate
Matters
|
Note
3
|
Customer
Choice and Industry Restructuring
|
Note
4
|
Commitments
and Contingencies
|
Note
5
|
Guarantees
|
Note
6
|
Company-wide
Staffing and Budget Review
|
Note
7
|
Benefit
Plans
|
Note
9
|
Income
Taxes
|
Note
10
|
Business
Segments
|
Note
11
|
Financing
Activities
|
Note
12
|
The
condensed notes to condensed financial statements that follow are
a
combined presentation for the Registrant Subsidiaries. The following
list
indicates the registrants to which the footnotes apply:
|
||
1.
|
Significant
Accounting Matters
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
2.
|
New
Accounting Pronouncements
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
3.
|
Rate
Matters
|
APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
4.
|
Customer
Choice and Industry
Restructuring
|
CSPCo,
OPCo, SWEPCo, TCC, TNC
|
5.
|
Commitments
and Contingencies
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
6.
|
Guarantees
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
7.
|
Company-wide
Staffing and Budget Review
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
8.
|
Acquisitions,
Assets Held for Sale and Asset Impairments
|
CSPCo,
TCC
|
9.
|
Benefit
Plans
|
APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
10.
|
Income
Taxes
|
PSO,
SWEPCo, TCC, TNC
|
11.
|
Business
Segments
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
|
12.
|
Financing
Activities
|
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC,
TNC
|
September
30,
|
December
31,
|
||||||
2006
|
2005
|
||||||
(in
thousands)
|
|||||||
Components
|
|||||||
Cash
Flow Hedges:
|
|||||||
APCo
|
$
|
(3,407
|
)
|
$
|
(16,421
|
)
|
|
CSPCo
|
3,081
|
(859
|
)
|
||||
I&M
|
(8,503
|
)
|
(3,467
|
)
|
|||
KPCo
|
1,249
|
(194
|
)
|
||||
OPCo
|
7,055
|
755
|
|||||
PSO
|
(1,116
|
)
|
(1,112
|
)
|
|||
SWEPCo
|
(7,368
|
)
|
(5,852
|
)
|
|||
TCC
|
-
|
(224
|
)
|
||||
TNC
|
(1,337
|
)
|
(111
|
)
|
|||
Minimum
Pension Liability:
|
|||||||
APCo
|
$
|
(189
|
)
|
$
|
(189
|
)
|
|
CSPCo
|
(21
|
)
|
(21
|
)
|
|||
I&M
|
(102
|
)
|
(102
|
)
|
|||
KPCo
|
(29
|
)
|
(29
|
)
|
|||
PSO
|
(152
|
)
|
(152
|
)
|
|||
SWEPCo
|
(277
|
)
|
(277
|
)
|
|||
TCC
|
(928
|
)
|
(928
|
)
|
|||
TNC
|
(393
|
)
|
(393
|
)
|
|
ARO
at
December
31,
2005
|
Accretion
Expense
|
Liabilities
Incurred
|
Liabilities
Settled
|
Revisions
in Cash Flow
Estimates
|
ARO
at September 30, 2006
|
|||||||||||||
(in
thousands)
|
|||||||||||||||||||
SWEPCo
|
$
|
43,077
|
$
|
1,781
|
$
|
4,200
|
$
|
(4,967
|
)
|
$
|
(763
|
)
|
$
|
43,328
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
||||||||||||
Company
|
2006
|
2005
|
2006
|
2005
|
|||||||||
(in
thousands)
|
|||||||||||||
APCo
|
$
|
19,555
|
$
|
19,501
|
$
|
62,209
|
$
|
54,763
|
|||||
CSPCo
|
5,536
|
5,103
|
17,100
|
14,752
|
|||||||||
I&M
|
9,784
|
7,920
|
28,848
|
22,704
|
|||||||||
OPCo
|
19,303
|
16,703
|
58,626
|
47,757
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
||||||||||||
Company
|
2006
|
2005
|
2006
|
2005
|
|||||||||
(in
thousands)
|
|||||||||||||
PSO
|
$
|
13,750
|
$
|
11,051
|
$
|
39,886
|
$
|
31,160
|
|||||
SWEPCo
|
16,170
|
13,189
|
46,925
|
27,570
|
|||||||||
TCC
|
-
|
5,548
|
703
|
20,120
|
|||||||||
TNC
|
-
|
8,559
|
4,229
|
19,638
|
·
|
A
$50 million increase in Expanded Net Energy Cost (ENEC) for fuel,
purchased power expenses, off-system sales credits and other
energy-related costs;
|
·
|
A
$21 million special construction surcharge providing recovery of
the costs
of scrubbers and the Wyoming-Jacksons Ferry 765 kV line to
date;
|
·
|
A
$16 million general base rate reduction resulting predominantly from
a
reduction in the return on equity to 10.5% and a $9 million reduction
in
depreciation expense which affects cash flows but not earnings;
and
|
·
|
A
$15 million credit to refund a portion of deferred prior over-recoveries
of ENEC recorded in regulatory liabilities on APCo’s Condensed
Consolidated Balance Sheets, which will impact cash flows but not
earnings.
|
September
30, 2006
|
December
31, 2005
|
||||||||||||
PJM-Billed
Integration Costs
|
Non-PJM
Billed Formation/ Integration Costs
|
PJM-Billed
Integration Costs
|
Non-PJM
Billed Formation/ Integration Costs
|
||||||||||
(in
millions)
|
|||||||||||||
APCo
|
$
|
3.7
|
$
|
4.8
|
$
|
4.1
|
$
|
4.9
|
|||||
CSPCo
|
1.5
|
1.9
|
1.7
|
1.9
|
|||||||||
I&M
|
3.0
|
3.4
|
3.2
|
3.7
|
|||||||||
KPCo
|
0.9
|
1.1
|
1.0
|
1.1
|
|||||||||
OPCo
|
4.3
|
5.0
|
4.7
|
5.1
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
||||||||||||
2006
|
2005
|
2006
(a)
|
2005
|
||||||||||
(in
millions)
|
|||||||||||||
APCo
|
$
|
-
|
$
|
13.6
|
$
|
13.4
|
$
|
39.1
|
|||||
CSPCo
|
-
|
7.7
|
7.9
|
20.8
|
|||||||||
I&M
|
-
|
8.0
|
8.1
|
22.5
|
|||||||||
KPCo
|
-
|
3.2
|
3.2
|
9.3
|
|||||||||
OPCo
|
-
|
10.6
|
10.4
|
28.8
|
(a)
|
Represents
revenues through March 31, 2006, when SECA rates expired, and excludes
the
provision for refund recorded in the second quarter of 2006 discussed
below.
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(in
thousands)
|
|||||||||||||
APCo
|
$
|
-
|
$
|
0.3
|
$
|
6.1
|
$
|
0.7
|
|||||
CSPCo
|
-
|
0.2
|
3.4
|
0.4
|
|||||||||
I&M
|
-
|
0.2
|
3.6
|
0.4
|
|||||||||
KPCo
|
-
|
0.1
|
1.4
|
0.2
|
|||||||||
OPCo
|
-
|
0.3
|
4.6
|
0.5
|
·
|
AEP/AP
proposed a Highway/Byway rate design in which:
|
|
·
|
The
cost of all transmission facilities in the PJM region operated at
345 kV
or higher would be included in a “Highway” rate that all load serving
entities (LSEs) would pay based on peak demand. The AEP/AP proposal
would
produce about $125 million in additional revenues per year for AEP
from
users in other zones of PJM.
|
|
·
|
The
cost of transmission facilities operating at lower voltages would
be
collected in the zones where those costs are presently charged under
PJM’s
existing rate design.
|
|
·
|
Two
other utilities, Baltimore Gas & Electric Company (BG&E) and Old
Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate
that
includes transmission facilities above 200 kV, which would produce
lower
revenues than the AEP/AP proposal.
|
|
·
|
In
a competing Highway/Byway proposal, a group of LSEs proposed rates
that
would include existing 500 kV and higher voltage facilities and new
facilities above 200 kV in the Highway rate, which would produce
considerably lower revenues than the AEP/AP proposal.
|
|
·
|
In
January 2006, the FERC staff issued testimony and exhibits supporting
a
PJM-wide flat rate or “Postage Stamp” type of rate design that would
include all transmission facilities, which would produce higher
transmission revenues than the AEP/AP
proposal.
|
·
|
In
Kentucky, KPCo settled a rate case, which provided for the recovery
of its
share of the transmission revenue reduction in new rates effective
March
30, 2006.
|
·
|
In
Ohio, CSPCo and OPCo recover the FERC-approved OATT which reflects
their
share of the full transmission revenue requirement retroactive to
April 1,
2006 under a May 2006 PUCO order.
|
·
|
In
West Virginia, APCo settled a rate case, which provided for the recovery
of its share of the T&O/SECA transmission revenue reduction beginning
July 28, 2006.
|
·
|
In
Virginia, APCo filed a request for revised rates, which includes
recovery
of its share of the T&O/SECA transmission revenue reduction starting
October 2, 2006, subject to refund.
|
·
|
In
Indiana, I&M is precluded by a rate cap from raising its rates until
July 1, 2007.
|
·
|
In
Michigan, I&M has not yet filed to seek recovery of the lost
transmission revenues.
|
(in
millions)
|
||||
Stranded
Generation Plant Costs
|
$
|
974
|
||
Net
Generation-related Regulatory Asset
|
249
|
|||
Excess
Earnings
|
(49
|
)
|
||
Recorded
Net Stranded Generation Plant Costs
|
1,174
|
|||
Recorded
Debt Carrying Costs on Net Stranded Generation Plant Costs
|
400
|
|||
Recorded
Securitizable True-up Regulatory Asset
|
1,574
|
|||
Unrecorded
But Recoverable Equity Carrying Costs
|
224
|
|||
Unrecorded
Estimated October 2006 Debt Carrying Costs
|
3
|
|||
Unrecorded
Excess Earnings, Related Carrying Costs and Other
|
53
|
|||
Unrecorded
Settlement Reduction
|
(77
|
)
|
||
Reduction
for the Present Value of ADITC and EDFIT Benefits
|
(61
|
)
|
||
Approved
Securitizable Amount as of October 11, 2006
|
1,716
|
|||
Unrecorded
Securitization Bond Issuance Costs
|
24
|
|||
Amount
Securitized on October 11, 2006
|
$
|
1,740
|
(in
millions)
|
||||
Wholesale
Capacity Auction True-up
|
$
|
61
|
||
Carrying
Costs on Wholesale Capacity Auction True-up
|
31
|
|||
Retail
Clawback including Carrying Costs
|
(65
|
)
|
||
Deferred
Over-recovered Fuel Balance
|
(184
|
)
|
||
Retrospective
ADFIT Benefit
|
(77
|
)
|
||
Other
|
(4
|
)
|
||
Recorded
Net Regulatory Liabilities - Other True-up Items
|
(238
|
)
|
||
Unrecorded
Prospective ADFIT Benefit
|
(240
|
)
|
||
Gross
CTC Refund Proposed
|
(478
|
)
|
||
FERC
Jurisdictional Fuel Refund Deferral
|
16
|
|||
ADITC
and EDFIT Benefit Refund Deferral
|
98
|
|||
Net
CTC Refund Proposed, After Deferrals
|
(364
|
)
|
||
True-up
Proceeding Expense Surcharge
|
7
|
|||
Net
CTC Refund Proposed, After Deferrals and Expenses
|
$
|
(357
|
)
|
(in
millions)
|
||||
AEGCo
|
$
|
12
|
||
APCo
|
928
|
|||
CSPCo
|
319
|
|||
I&M
|
330
|
|||
KPCo
|
54
|
|||
OPCo
|
1,065
|
|||
PSO
|
262
|
|||
SWEPCo
|
315
|
|||
TCC
|
286
|
|||
TNC
|
72
|
Maximum
Potential Loss
|
||||
Subsidiary
|
(in
millions)
|
|||
APCo
|
$
|
7
|
||
CSPCo
|
4
|
|||
I&M
|
5
|
|||
KPCo
|
2
|
|||
OPCo
|
7
|
|||
PSO
|
5
|
|||
SWEPCo
|
5
|
|||
TCC
|
6
|
|||
TNC
|
3
|
Three
Months Ended Sept. 30, 2005
|
Nine
Months Ended Sept. 30, 2005
|
||||||
Company
|
(in
millions)
|
||||||
AEGCo
|
$
|
0.1
|
$
|
0.3
|
|||
APCo
|
0.6
|
4.5
|
|||||
CSPCo
|
0.3
|
2.6
|
|||||
I&M
|
0.7
|
4.7
|
|||||
KPCo
|
0.4
|
1.1
|
|||||
OPCo
|
0.5
|
3.9
|
|||||
PSO
|
0.2
|
1.4
|
|||||
SWEPCo
|
0.2
|
1.8
|
|||||
TCC
|
0.5
|
4.3
|
|||||
TNC
|
0.2
|
1.3
|
Texas
Plants (TCC)
|
September
30, 2006
|
December
31, 2005
|
|||||
Assets:
|
(in
millions)
|
||||||
Other
Current Assets
|
$
|
2
|
$
|
1
|
|||
Property,
Plant and Equipment, Net
|
44
|
43
|
|||||
Total
Assets Held for Sale - Texas Generation Plants
|
$
|
46
|
$
|
44
|
Three
Months Ended September 30, 2006 and 2005:
|
Pension
Plans
|
Other
Postretirement
Benefit
Plans
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(in
millions)
|
|||||||||||||
Service
Cost
|
$
|
23
|
$
|
23
|
$
|
10
|
$
|
10
|
|||||
Interest
Cost
|
57
|
57
|
26
|
26
|
|||||||||
Expected
Return on Plan Assets
|
(82
|
)
|
(77
|
)
|
(24
|
)
|
(23
|
)
|
|||||
Amortization
of Transition (Asset) Obligation
|
-
|
(1
|
)
|
7
|
6
|
||||||||
Amortization
of Net Actuarial Loss
|
20
|
13
|
5
|
5
|
|||||||||
Net
Periodic Benefit Cost
|
$
|
18
|
$
|
15
|
$
|
24
|
$
|
24
|
Nine
Months Ended September 30, 2006 and 2005:
|
Pension
Plans
|
Other
Postretirement
Benefit
Plans
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(in
millions)
|
|||||||||||||
Service
Cost
|
$
|
71
|
$
|
69
|
$
|
30
|
$
|
31
|
|||||
Interest
Cost
|
171
|
169
|
76
|
79
|
|||||||||
Expected
Return on Plan Assets
|
(248
|
)
|
(232
|
)
|
(70
|
)
|
(68
|
)
|
|||||
Amortization
of Transition (Asset) Obligation
|
-
|
(1
|
)
|
21
|
20
|
||||||||
Amortization
of Net Actuarial Loss
|
59
|
40
|
15
|
19
|
|||||||||
Net
Periodic Benefit Cost
|
$
|
53
|
$
|
45
|
$
|
72
|
$
|
81
|
Three
Months Ended September 30, 2006 and 2005:
|
Pension
Plans
|
Other
Postretirement
Benefit
Plans
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(in
thousands)
|
|||||||||||||
APCo
|
$
|
1,469
|
$
|
1,848
|
$
|
4,487
|
$
|
4,756
|
|||||
CSPCo
|
205
|
534
|
1,807
|
1,928
|
|||||||||
I&M
|
2,331
|
2,365
|
2,949
|
3,134
|
|||||||||
KPCo
|
360
|
376
|
512
|
515
|
|||||||||
OPCo
|
823
|
1,206
|
3,395
|
3,353
|
|||||||||
PSO
|
979
|
72
|
1,588
|
1,661
|
|||||||||
SWEPCo
|
1,222
|
364
|
1,578
|
1,642
|
|||||||||
TCC
|
772
|
(219
|
)
|
1,699
|
1,789
|
||||||||
TNC
|
326
|
41
|
715
|
784
|
Nine
Months Ended September 30, 2006 and 2005:
|
Pension
Plans
|
Other
Postretirement
Benefit
Plans
|
|||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(in
thousands)
|
|||||||||||||
APCo
|
$
|
4,406
|
$
|
5,544
|
$
|
13,465
|
$
|
15,248
|
|||||
CSPCo
|
615
|
1,602
|
5,417
|
6,273
|
|||||||||
I&M
|
6,992
|
7,095
|
8,855
|
10,229
|
|||||||||
KPCo
|
1,076
|
1,128
|
1,538
|
1,689
|
|||||||||
OPCo
|
2,478
|
3,618
|
10,187
|
10,812
|
|||||||||
PSO
|
2,935
|
216
|
4,764
|
5,329
|
|||||||||
SWEPCo
|
3,672
|
1,092
|
4,734
|
5,244
|
|||||||||
TCC
|
2,317
|
(657
|
)
|
5,091
|
5,732
|
||||||||
TNC
|
978
|
123
|
2,145
|
2,507
|
Company
|
Decrease
in SFAS 109 Regulatory Asset, Net
|
Decrease
in State Income Tax Expense
|
Decrease
in Deferred State Income Tax Liabilities
|
|||||||
TCC
|
$
|
36,315
|
$
|
-
|
$
|
36,315
|
||||
TNC
|
4,801
|
1,265
|
6,066
|
|||||||
PSO
|
-
|
3,273
|
3,273
|
|||||||
SWEPCo
|
4,438
|
501
|
4,939
|
Company
|
Type
of Debt
|
Principal
Amount
|
Interest
Rate
|
Due
Date
|
|||||
(in
thousands)
|
(%)
|
||||||||
Issuances:
|
|||||||||
APCo
|
Pollution
Control Bonds
|
$
|
50,275
|
Variable
|
2036
|
||||
APCo
|
Senior
Unsecured Notes
|
250,000
|
5.55
|
2011
|
|||||
APCo
|
Senior
Unsecured Notes
|
250,000
|
6.375
|
2036
|
|||||
I&M
|
Pollution
Control Bonds
|
50,000
|
Variable
|
2025
|
|||||
OPCo
|
Pollution
Control Bonds
|
65,000
|
Variable
|
2036
|
|||||
OPCo
|
Senior
Unsecured Notes
|
350,000
|
6.00
|
2016
|
|||||
PSO
|
Senior
Unsecured Notes
|
150,000
|
6.15
|
2016
|
|||||
SWEPCo
|
Pollution
Control Bonds
|
81,700
|
Variable
|
2018
|
Company
|
Type
of Debt
|
Principal
Amount
|
Interest
Rate
|
Due
Date
|
|||||
(in
thousands)
|
(%)
|
||||||||
Retirements
and Principal Payments:
|
|||||||||
APCo
|
First
Mortgage Bonds
|
$
|
100,000
|
6.80
|
2006
|
||||
APCo
|
Other
|
8
|
13.718
|
2026
|
|||||
I&M
|
Pollution
Control Bonds
|
50,000
|
6.55
|
2025
|
|||||
OPCo
|
Notes
Payable
|
4,390
|
6.81
|
2008
|
|||||
OPCo
|
Notes
Payable
|
6,500
|
6.27
|
2009
|
|||||
SWEPCo
|
Notes
Payable
|
5,039
|
4.47
|
2011
|
|||||
SWEPCo
|
Notes
Payable
|
2,250
|
Variable
|
2008
|
|||||
SWEPCo
|
Pollution
Control Bonds
|
81,700
|
6.10
|
2018
|
|||||
TCC
|
Securitization
Bonds
|
52,265
|
5.01
|
2010
|
Company
|
Type
of Debt
|
Principal
Amount
|
Interest
Rate
|
Due
Date
|
|||||
(in
thousands)
|
(%)
|
||||||||
Issuances:
|
|||||||||
TCC
|
Notes
Payable
|
$
|
125,000
|
5.14
|
2007
|
||||
TCC
|
Notes
Payable
|
70,000
|
5.86
|
2007
|
|||||
Retirements:
|
|||||||||
KPCo
|
Notes
Payable
|
40,000
|
6.501
|
2006
|
|||||
OPCo
|
Notes
Payable
|
200,000
|
3.32
|
2006
|
|||||
PSO
|
Notes
Payable
|
50,000
|
3.35
|
2006
|
Principal
Amount
|
Interest
|
Scheduled
Final Payment
|
|||
Rate
|
Date
|
||||
(in
thousands)
|
(%)
|
||||
$
|
217,000
|
4.98
|
2010
|
||
341,000
|
4.98
|
2013
|
|||
250,000
|
5.09
|
2015
|
|||
437,000
|
5.17
|
2018
|
|||
494,700
|
5.3063
|
2020
|
Principal
Amount
|
Interest
|
Due
|
|||
Rate
|
Date
|
||||
(in
thousands)
|
(%)
|
||||
$
|
150,000
|
4.58
|
2007
|
||
125,000
|
5.14
|
2007
|
|||
70,000
|
5.86
|
2007
|
Company
|
Maximum
Borrowings from Utility Money Pool
|
Maximum
Loans to Utility Money Pool
|
Average
Borrowings from Utility Money Pool
|
Average
Loans to Utility Money Pool
|
Loans
(Borrowings) to/from Utility Money Pool as of September 30,
2006
|
Authorized
Short-Term Borrowing Limit
|
|||||||||||||
(in
thousands)
|
|||||||||||||||||||
AEGCo
|
$
|
58,209
|
$
|
2,247
|
$
|
21,005
|
$
|
2,247
|
$
|
(14,938
|
)
|
$
|
125,000
|
||||||
APCo
|
283,872
|
314,064
|
200,248
|
194,781
|
93,764
|
600,000
|
|||||||||||||
CSPCo
|
48,337
|
95,977
|
15,133
|
35,929
|
60,417
|
350,000
|
|||||||||||||
I&M
|
128,071
|
-
|
64,123
|
-
|
(27,616
|
)
|
500,000
|
||||||||||||
KPCo
|
46,156
|
11,993
|
24,285
|
4,384
|
(24,507
|
)
|
200,000
|
||||||||||||
OPCo
|
351,302
|
40,382
|
100,212
|
15,845
|
(48,163
|
)
|
600,000
|
||||||||||||
PSO
|
167,456
|
146,657
|
97,332
|
94,937
|
43,538
|
300,000
|
|||||||||||||
SWEPCo
|
127,291
|
24,209
|
56,984
|
10,722
|
7,018
|
350,000
|
|||||||||||||
TCC
|
117,429
|
49,193
|
44,416
|
23,779
|
25,304
|
600,000
|
|||||||||||||
TNC
|
22,218
|
34,574
|
6,269
|
8,381
|
(9,492
|
)
|
250,000
|
||||||||||||
TNC
(a)
|
10
|
13,947
|
8
|
13,834
|
13,875
|
-
|
Company
|
Average
Interest Rate
for Funds Borrowed from the Utility Money Pool for Nine Months
Ended
September
30, 2006
|
Average
Interest Rate
for Funds Borrowed
from the Utility
Money Pool for
Nine Months Ended
September
30, 2005
|
Average
Interest Rate
for Funds Loaned to the Utility
Money Pool
for Nine Months Ended
September
30, 2006
|
Average
Interest Rate
for Funds Loaned to the
Utility
Money Pool
for
Nine Months Ended September 30, 2005
|
|||||||||
(in
percentage)
|
|||||||||||||
AEGCo
|
4.85
|
2.91
|
5.11
|
3.14
|
|||||||||
APCo
|
4.62
|
3.30
|
4.98
|
2.72
|
|||||||||
CSPCo
|
4.73
|
3.92
|
4.63
|
2.76
|
|||||||||
I&M
|
4.81
|
3.25
|
-
|
2.12
|
|||||||||
KPCo
|
4.92
|
3.52
|
4.97
|
2.54
|
|||||||||
OPCo
|
4.83
|
3.67
|
5.12
|
2.40
|
|||||||||
PSO
|
5.02
|
2.62
|
4.36
|
3.52
|
|||||||||
SWEPCo
|
5.01
|
3.64
|
4.36
|
2.60
|
|||||||||
TCC
|
4.79
|
3.07
|
4.71
|
2.43
|
|||||||||
TNC
|
4.81
|
-
|
4.56
|
3.13
|
|||||||||
TNC
(a)
|
5.36
|
-
|
5.33
|
-
|
(a)
|
In
the third quarter of 2006, TNC created a new wholly-owned subsidiary,
AEP
Texas North Generation Company, LLC. Following the creation of this
subsidiary, TNC transferred all of its mothballed generation assets
and
related liabilities to this new subsidiary, effectively completing
the
business separation requirement of the Texas Restructuring Legislation.
Subsequently, AEP Texas North Generation Company, LLC became a participant
in the Nonutility Money Pool. For the nine months ended September
30,
2006, the maximum and minimum interest rates for funds either borrowed
from or loaned to the Nonutility Money Pool were 5.39% and 5.28%
respectively.
|
(in
millions)
|
||||
AEGCo
|
$
|
12
|
||
APCo
|
928
|
|||
CSPCo
|
319
|
|||
I&M
|
330
|
|||
KPCo
|
54
|
|||
OPCo
|
1,065
|
|||
PSO
|
262
|
|||
SWEPCo
|
315
|
|||
TCC
|
286
|
|||
TNC
|
72
|
·
|
Requirements
under the CAA to reduce emissions of SO2,
NOx,
particulate matter, and mercury from fossil fuel-fired power
plants;
|
·
|
Requirements
under the Clean Water Act to reduce the impacts of water intake structures
on aquatic species at certain power plants; and
|
·
|
Possible
future requirements to reduce carbon dioxide emissions to address
concerns
about global climate change.
|
Period
|
Total
Number
of
Shares
Purchased
|
Average
Price
Paid
per Share
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
|
Maximum
Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased
Under the Plans or Programs
|
||||||||||||
07/01/06
- 07/31/06
|
-
|
$
|
-
|
-
|
$
|
-
|
||||||||||
08/01/06
- 08/31/06
|
12
|
(a
|
)
|
73.00
|
-
|
-
|
||||||||||
09/01/06
- 09/30/06
|
30
|
(b
|
)
|
79.75
|
-
|
-
|
(a)
|
I&M
repurchased 12 shares of its 4-1/8% cumulative preferred stock, in
a
privately-negotiated transaction outside of an announced
program.
|
(b)
|
APCo
repurchased 30 shares of its 4-1/2% cumulative preferred stock, in
a
privately-negotiated transaction outside of an announced
program.
|