2013 Fact Book 48th EEI Financial Conference

Transcription

2013 Fact Book
48th EEI Financial Conference
Orlando, Florida
“Safe Harbor” Statement under the Private Securities
Litigation Reform Act of 1995
This presentation contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its
Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause
actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the
forward-looking statements are: the economic climate and growth or contraction within and changes in market demand and demographic patterns in our service
territory, inflationary or deflationary interest rate trends, volatility in the financial markets, particularly developments affecting the availability of capital on reasonable
terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates, the availability and cost of funds to finance
working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material, electric load,
customer growth and the impact of retail competition, particularly in Ohio, weather conditions, including storms and drought conditions, and our ability to recover
significant storm restoration costs through applicable rate mechanisms, available sources and costs of, and transportation for, fuels and the creditworthiness and
performance of fuel suppliers and transporters, availability of necessary generating capacity and the performance of our generating plants, 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, and transmission line
facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs
(including the costs of projects that are cancelled) through applicable rate cases or competitive rates, new legislation, litigation and government regulation including
oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or
particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost
recovery of our plants and related assets, evolving public perception of the risks associated with fuels used before, during and after the generation of electricity,
including nuclear fuel, a reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers, timing and
resolution of pending and future rate cases, negotiations and other regulatory decisions including rate or other recovery of new investments in generation, distribution
and transmission service and environmental compliance, resolution of litigation, our ability to constrain operation and maintenance costs, our ability to develop and
execute a strategy based on a view regarding prices of electricity and other energy-related commodities, prices and demand for power that we generate and sell at
wholesale, changes in technology, particularly with respect to new, developing or alternative sources of generation, our ability to recover through rates or market
prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives, volatility and changes in
markets for capacity and electricity, coal, and other energy-related commodities, particularly changes in the price of natural gas, changes in utility regulation and the
allocation of costs within regional transmission organizations, including PJM and SPP, the transition to market and the legal separation of generation in Ohio,
including the implementation of ESPs and the successful approval, where applicable, and transfer of such Ohio generation assets and liabilities to regulated and nonregulated entities at book value, our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate the Interconnection
Agreement, changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market,
actions of rating agencies, including changes in the ratings of our debt, the impact of volatility in the capital markets on the value of the investments held by our
pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact on future funding requirements, accounting
pronouncements periodically issued by accounting standard-setting bodies and other risks and unforeseen events, including wars, the effects of terrorism (including
increased security costs), embargoes, cyber security threats and other catastrophic events.
Investor Relations Contacts
2
Bette Jo Rozsa
Managing Director
Investor Relations
614-716-2840
[email protected]
Julie Sherwood
Director
Investor Relations
614-716-2663
[email protected]
Sara Macioch
Analyst
Investor Relations
614-716-2835
[email protected]
AEP Overview (NYSE:AEP)
OUR CORE BUSINESS OPERATIONS ARE
REGULATED UTILITIES
Provide generation, transmission and distribution services to approximately 5.3 million customers in eleven states
with headquarters in Columbus, Ohio
Our electric assets include:
Approximately 37,600 megawatts of generating capacity in 3 RTOs (one of the largest
US generation portfolios with a significant cost advantage in many of our market areas)
Approximately 39,000 circuit miles of transmission lines, including 2,116 miles of
765kV lines, the backbone of the electric interconnection grid in the Eastern U.S.
Approximately 222,000 miles of overhead and underground distribution lines
With our coal and transportation assets we:
control over 7,600 railcars
own and/or operate approximately 3,100 hopper barges, 60 towboats and 25 harbor boats
operate one active coal-handling terminal with 18 millions tons of capacity
AEP consumes approximately 56 million tons of coal and 220,000,000 cubic feet of natural gas annually.
3
AEP Corporate Leadership
Nicholas K. Akins - President and
Chief Executive Officer
Robert P. Powers - Executive Vice President and
Chief Operating Officer
Brian X. Tierney - Executive Vice President and
Chief Financial Officer
Lisa M. Barton - Executive Vice President Transmission
David M. Feinberg - Senior Vice President,
General Counsel and Secretary
4
Mark C. McCullough - Executive Vice President Generation
Dennis E. Welch- Executive Vice President
and Chief External Officer
Charles E. Zebula- Executive Vice President,
Energy Supply
Lana L. Hillebrand- Senior Vice President
and Chief Administrative Officer
AEP Operational Structure*
5
* Does not represent legal structure
AEP Service Territory
VERTICALLY INTEGRATED UTILITIES
Appalachian Power Company (APCo)
Public Service Company of Oklahoma (PSO)
Indiana Michigan Power Company (I&M)
Southwestern Electric Power Company (SWEPCO)
Kingsport Power Company (KGPCo)
Kentucky Power Company (KPCo)
Wheeling Power Company (WPCo)
6
AEP Service Territory
TRANSMISSION AND DISTRIBUTION UTILITIES
Ohio Power Company* (OPCo)
Texas Central Company (TCC)
Texas North Company (TNC)
7
* Wires only effective 01/01/2014
2012 Retail Revenue
CUSTOMER PROFILE
AEP’S SERVICE TERRITORY ENCOMPASSES
APPROXIMATELY 5.3 MILLION CUSTOMERS IN 11 STATES
Percentage of AEP System Retail Revenues
Ohio
Texas
West Virginia
Virginia
Oklahoma
Indiana
Louisiana
Kentucky
Arkansas
Michigan
Tennessee
8
29%
13%
12%
12%
10%
9%
5%
4%
3%
2%
1%
Source: 2012 10-K.
*Note: Figures do not include Other Revenues
Revenue Composition by Customer Class*
Residential
Commercial
Industrial
Wholesale
Top 10 Industrial Sectors Across the AEP System By
NAICS Code
331 Primary Metal Manufacturing
325 Chemical Manufacturing
324 Petroleum and Coal Products Manufacturing
212 Mining (except Oil and Gas)
322 Paper Manufacturing
326 Plastics and Rubber Products Manufacturing
311 Food Manufacturing
336 Transportation Equipment Manufacturing
211 Oil and Gas Extraction
486 Pipeline Transportation
% of Total
Industrial
Sales
20.8%
13.1%
11.2%
7.6%
6.3%
5.5%
4.4%
4.4%
4.2%
3.8%
Generation Fleet
2013 Generation Capacity
by Fuel Type (Including PPAs)
Based on 42,535 MW
Note: Includes 1,590MW Demand Response/Energy Efficiency
9
2012 Generation Production
by Fuel Type (Owned Assets)
Based on 159,921,676 MWh
Transmission Line Circuit Miles Detail
Operating Company Level (Circuit Miles)
Operating Company
APCo
OPCo
I&M
KGPCo
KPCo
PSO
SWEPCO
TCC
TNC
WPCo
Transco - Ohio
Transco - OK
Total
765kV
734
509
615
0
258
0
0
0
0
0
0
0
2,116
500kV
97
0
0
0
0
0
0
0
0
16
0
0
113
345kV
383
1,798
1,615
0
8
579
672
626
223
9
0
0
5,913
230kV
106
0
0
0
0
34
0
0
0
0
0
0
140
161kV
0
0
0
0
46
8
235
0
0
0
0
0
289
138kV
3,400
3,354
1,673
0
335
2,132
1,386
2,316
1,466
204
7
44
16,317
115kV
0
0
0
0
0
10
57
0
0
0
0
0
67
88kV
23
0
0
0
0
0
0
0
0
0
0
0
23
69kV
1,105
2,672
714
3
546
763
1,609
1,400
2,493
90
43
49
11,487
46kV
789
0
0
0
55
0
0
0
0
0
0
0
844
40kV
0
59
0
0
0
0
0
0
0
0
0
0
59
34.5kV
230
365
746
27
3
0
0
0
0
0
0
0
1,371
23kV
0
214
0
0
0
0
0
0
0
0
11
0
225
Total
6,867
8,971
5,363
30
1,251
3,526
3,959
4,342
4,182
319
61
93
38,964
State Level (Circuit Miles)
State
Arkansas
Indiana
Kentucky
Louisiana
Michigan
Ohio
Oklahoma
Tennessee
Texas
W. Virginia
Virginia
Total
765kV
0
599
258
0
16
509
0
0
0
385
349
2,116
500kV
0
0
0
0
0
0
0
0
0
17
96
113
345kV
40
1,381
8
105
234
1,798
625
0
1,330
323
69
5,913
230kV
0
0
0
0
0
0
34
91
0
0
15
140
161kV
235
0
46
0
0
0
8
0
0
0
0
289
138kV
216
1,431
335
276
242
3,361
2,201
154
4,650
1,679
1,772
16,317
Note: Transmission line circuit miles are current as of 12/31/12
10
115kV
42
0
0
1
0
0
10
0
14
0
0
67
88kV
0
0
0
0
0
0
0
0
0
23
0
23
69kV
461
418
547
337
296
2,715
812
3
4,704
463
731
11,487
46kV
0
0
55
0
0
0
0
0
0
741
48
844
40kV
34.5kV
0
0
0
0
0
59
0
0
0
0
0
59
0
590
3
0
156
365
0
27
0
89
141
1,371
23kV
0
0
0
0
0
225
0
0
0
0
0
225
Total
994
4,419
1,252
719
944
9,032
3,690
275
10,698
3,720
3,221
38,964
Distribution Line Detail
By State
Tennessee
Virginia
W. Virginia
Kentucky
Ohio
Michigan
Indiana
Texas
Oklahoma
Arkansas
Louisiana
Total
Line Miles*
1,558
30,724
21,679
10,029
45,580
5,315
14,997
52,348
22,080
4,494
13,121
221,925
|
|
|
|
|
|
|
|
|
|
|
Company
Line Miles*
KGPCo
KPCo
APCo
OPCo
I&M
WPCo
TCC
TNC
PSO
SWEPCO
1,558
10,029
50,890
45,583
20,312
1,510
29,783
13,868
22,080
26,312
Total
* Includes approximately 32,000 miles of underground circuit line
Note: Distribution line miles are current as of 12/31/12
11
221,925
Rate Bases & ROEs
Vertically Integrated Utilities
APCo-Virginia
APCo-West Virginia
APCo - FERC
APCo Total3
$
Proforma 2 Earned
Approved Approved Effective Date of last
ROE as of
ROE
Debt/Equity approved rate case
09/30/2013
10.90%
57/43
1/29/2012
10.00%
57/43
3/31/2011
10.23%
55/45
6/1/2013
7,813
8.8%
KPCo-Kentucky 4
$
1,752
Jurisdiction
Rate Base 1
($ millions)
8.5%
I&M-Indiana
I&M-Michigan
I&M - FERC
I&M Total
$
3,474
8.4%
PSO-Oklahoma
$
2,552
11.1%
SWEPCO-Louisiana
SWEPCO-Arkansas
SWEPCO-Texas
SWEPCO - FERC
SWEPCO Total
$
4,522
Transmission and Distribution Companies
Jurisdiction
AEP Ohio - Distribution
AEP Ohio - Transmission
AEP Ohio total
TCC-Texas
TNC-Texas
AEP Texas Total
Transcos
Company
12
AEP Ohio Transco
AEP Indiana Michigan Transco
AEP Oklahoma Transco
10.50%
57/435
6/29/2010
10.20%
10.20%
9.98%
48/52
49/51
47/53
2/28/2013
3/29/2012
6/1/2013
10.15%
54/46
1/31/2011
10.00% 6
10.25%
9.65%
11.10%
49/51
54/46
51/49
50/50
2/28/2013
11/25/2009
1/29/2013
1/1/2013
7.5%
$
Proforma 2 Earned
Approved Approved Effective Date of last 1
ROE as of
Rate base represents Net Plant less
ROE
Debt/Equity approved rate case
Accumulated Deferred Income taxes
09/30/2013
10.20%
47/53
1/1/2012 from Ferc Form 1
11.49%
45/55
7/1/2013 2
Proforma adjusts GAAP results by
4,403
12.3%
eliminating any material nonrecurring
$
$
$
2,439
901
3,340
Rate Base 1
($ millions)
9.96%
9.96%
60/40
60/40
8/28/2013
1/25/2013
items and is not weather normalized
3
4
2
Includes Amos Unit 3
Includes 50% of Mitchell Plant
5
Proforma Earned
Represents a negotiated settlement
Approved Approved Effective Date of last
ROE as of
ROE
Debt/Equity approved rate case 6
Represents the midpoint of the ROE
09/30/2013
462
9.0% 11.49%
50/50
7/1/2013 range approved in the formula rate case
104
11.9% 11.49%
50/50
7/1/2013 settled in February 2013
164
10.0% 11.20%
50/50
7/1/2013
Rate Base 1
($ millions)
$
$
$
14.4%
9.3%
Summary of Rate Case Filing Requirements
Texas
Virginia
West
Virginia
FERC
No
No
No
No
Yes
No
No
No
No
Yes
Annually
Annually
TriAnnually
Annually
Annually
--
Yes
30
Yes
45
Yes
30
No
Note 5
Yes
60
Yes
30
No
No
Forecast
Optional
Partially
Projected
Historical
Historical
Historical
Historical
Historical
Forecast
Optional
Yes
Yes
Yes
Yes
Yes
Yes
No
No
Yes
4
Note 3
9
6
6
6
Note 6
Note 7
2 or 7
Arkansas
Indiana
GENERAL
Time Limitations Between Cases
Pancaking Permitted (Note 1)
No
No
Yes
No
No
No
No
No
No
No
Note 4
Limited
No
No
Fuel Clause Renewal Frequency
Annually
SemiAnnually
Monthly
Monthly
Annually
Quarterly
Yes
60
Yes
Varies
Yes
28
No
n/a
Optional
45
Partially
Projected
Forecast
Optional
Other
Rates Effective Subject to Refund
Yes
Yes
Yes
Approx. # of months after filing to
implement rates subject to refund
10
Note 2
6
Notice of Intent
Prior PSC Notice Required?
Notice Period (days)
Kentucky Louisiana Michigan
Ohio
Oklahoma Tennessee
CASE COMPONENTS
Base Case Test Year
Historical Historical
Note 1: Pancaking refers to paying multiple charges to more than one utility to transmit electric power across bulk-power systems. It impacts wholesale customers who
are
obligated to pay each transmission owner a separate rate to pass through.
Note 2: If the Commission doesn't issue an order within 300 days (10 months) or doesn't extend the 300 days by an additional 60 days, I&M can implement
50% of the proposed rate increase, subject to refund.
Note 3: If no order is received within 180 days of the filing, utility can implement interim rates, however they can not be implemented before the start of the test
year.
Note 4: In 2011 Ohio Distribution case settlement, AEP Ohio agreed not to file another distribution case until 2014 for rates to be effective no
sooner than June 1 ,2015.
Note 5: Notice is required for each municipality having original jurisdiction 30-days prior to filing.
Note 6: Rates are put into effect approximately 10 months after filing, but are not subject to refund.
Note 7: Rates are put into effect approximately 9 months after filing, but are not subject to refund.
13
Recovery Mechanisms Across Jurisdictions
* Previously, for certain jurisdictions confirmation with the applicable Commission concerning replacement of CAIR with CSAPR may have been necessary. CSAPR was vacated; CAIR remains in effect
** SSO has component for environmental recovery through the transition period ending 05/31/2015. FAC goes through 5/31/2015
*** Also applicable for AEP-Texas
AER - Alternative Energy Rider
BR - Base Rates
CCTR - Clean Coal Technology Rider
CO2 - Carbon Dioxide
DSM - Demand Side Management
EAC - Environmental Adjustment Clause
ECCR - Environmental Compliance Cost Rider
ECR - Energy Cost Recovery Rider
EE - Energy Efficiency
EE/PDR - EE Peak Demand Reduction
EECR - EE Cost Rate
EECRF - Energy Efficiency Cost Recovery Factor Rider
14
ENEC - Expanded Net Energy Cost
ERAC - Environmental Rate Adjustment Clause
ESRR - Enhanced Service Reliability Rider
FAC - Fuel Adjustment Clause
FRP - Formula Rate Plan
GHG - Green House Gas
N/A - not applicable in this jurisdiction
NOx - Nitrogen Oxide
OATT - Open Access Transmission Tariff
PPAR - Purchased Power Adjustment Rider
PPC - Purchased Power Capacity Rider
PSCR - Power Supply Cost Recovery Rider
RAC - Rate Adjustment Clause
REP - Renewable Energy Plan
RPS-RAC - Renewable Portfolio Standard RAC
RVU - Reliability Vegetation / Underground Rider
SO2 - Sulfur Dioxide
SSO - Standard Service Offer
TCRF - Transmission Cost Recovery Factor
TCRR - Transmission Cost Recovery Rider
TRAC - Transmission Rate Adjustment Clause
Storm Recovery Mechanisms by Jurisdiction
STATE
15
Deferral
Detail
Arkansas
Yes
Storm expense is normally recorded as incurred without deferral although if it is a significant storm expense the
commission has granted authority to defer and recover.
Indiana
Yes
Recovery of storm costs is requested in base rate cases.
Kentucky
Yes
Louisiana
No
Storm costs are expensed and included in developing future formula rates. Amounts are not deferred.
Michigan
No
Ohio
Yes
2012 Electric Security Plan and 2011 Distribution Base Case orders established a major storm $5M reserve and an
over/under recovery mechanism.
Oklahoma
Yes
Recovery of storm costs is requested in base rate cases. Significant storms are addressed in separate proceedings.
Tennessee
Yes
May recover costs through base rate case or a separate mechanism.
Texas (SPP)
Yes
Storm expense is normally recorded as incurred without deferral although if a test period includes a significant storm
expense and authority is granted to defer costs it may be deferred for recovery.
Texas (TNC)
No
Storm expense is normally recorded as incurred without deferral and is included in base rates during the test year.
Texas (TCC)
Yes
Approved catastrophe reserve in base rates that allows deferral of all major storm O&M above $500K.
Virginia
Yes
Deferral of major storm damages dependent on APCo’s VA Retail earned return on equity. Recovery of deferrals, if
any, would be requested in a base case.
West Virginia
Yes
Renewable Portfolio/Energy Efficiency Standards
Energy Efficiency Standards:
Ohio: 22% reduction of retail electricity sales by
2025 phased in beginning in 2009
Indiana: 2% electricity sales reduction by 2019
phased in starting in 2010
Michigan – M: phase in
starting at 2% in 2012
increasing to 10% by 2015
Michigan: 1% annual reduction of previous year
retail sales by 2012
Texas: 25% reduction in annual growth in
demand 2012; 30% reduction in annual growth
in demand 2013
Virginia: 10% electricity savings by 2022 relative
to 2006 base sales (voluntary)
Ohio – M: phase in starting
at 0.5% in 2009 increasing
to 25% by 2024
Indiana – V: phase in
Oklahoma – V: goal of
15% by 2015
West Virginia – M: phase in
Virginia – V: phase in
Louisiana – pilot program to
determine whether a
standard is suitable
Texas – M: starting at
2,280MW in 2007 increasing
to 10,000MW statewide by
2025
There are no renewable
portfolio standards in
Tennessee , Kentucky or
Arkansas currently
16
M: Mandatory
V: Voluntary
Jurisdictional Off-System Sales Sharing Summary
STATE
Detail
Arkansas
Yes, above and Up to $758,600 annual margin, ratepayers receive 100%. From $758,601 to $1,167,078,
below base levels ratepayers receive 85%. Above $1,167,078, ratepayers receive 50%.
Indiana
Yes, above and Sharing occurs above and below levels included in base rates of $26.9M, ratepayers
below base levels receive 50%.
Kentucky*
Yes, below base Below levels included in base rates of $15,290,363, ratepayers receive 100%. Above
levels
ratepayers receive zero.
Louisiana
Yes, above base Up to $874,000 annual margin, ratepayers receive 100%. From $874,001 to $1,314,000,
levels
ratepayers receive 85%. Above $1,314,000, ratepayers receive 50%.
Michigan
Ohio
17
OSS Sharing?
Yes
No
Oklahoma
Yes
Tennessee
No
80% of profits are shared with ratepayers.
n/a
n/a
Texas (SPP)
Yes
Virginia
Yes
West Virginia
Yes
100% of profits passed back to ratepayers through the Expanded Net Energy Cost
(ENEC) clause.
* Effective 01/01/2014
Commission Overview
Federal Energy Regulatory Commission
Commissioners
Number: 5
Appointed/Elected: Appointed
Term: 5 Years
Political Makeup: R: 2 D: 3
Qualifications for Commissioners
The Federal Energy Regulatory Commission (FERC) is composed of up to five commissioners who are appointed by the President of the United States with
the advice and consent of the Senate. Commissioners serve five-year terms, and have an equal vote on regulatory matters. To avoid any undue political
influence or pressure, no more than three commissioners may belong to the same political party.
Commissioners
Jon Wellinghoff, Chairman (Dem.), since 2006; term expired June 2013. Chairman Wellinghoff is an energy law specialist with more than 30 years
experience in the field. Before joining FERC, he was in private practice and focused exclusively on client matters related to renewable energy, energy
efficiency and distributed generation. While in the private sector, Chairman Wellinghoff represented an array of clients from federal agencies, renewable
developers, and large consumers of power to energy efficient product manufacturers and clean energy advocacy organizations.
Phillip D. Moeller, Commissioner (Rep.), since 2006; term expires June 2015. From 1997 through 2000, Mr. Moeller served as an energy policy advisor to
U.S. Senator Slade Gorton (R-Washington) where he worked on electricity policy, electric system reliability, hydropower, energy efficiency, nuclear waste,
energy and water appropriations and other energy legislation. Before becoming a Commissioner, Mr. Moeller headed the Washington, D.C., office of Alliant
Energy Corporation. Prior to Alliant Energy, Mr. Moeller worked in the Washington office of Calpine Corporation.
Sheryl A. LaFleur, Commissioner (Dem.) since 2010; term expires June 2014. Retired in 2007 as executive vice president and acting CEO of National Grid
USA, responsible for the delivery of electricity to 3.4 million customers in the Northeast. Her previous positions at National Grid and its predecessor New
England Electric System included COO, president of New England distribution and general counsel. She practiced law in Boston earlier in her career, and has
been a community and nonprofit leader.
John R. Norris, Commissioner (Dem.) since 2010: term expires June 2017. Most recently served as Chief of Staff to Secretary Tom Vilsack of the U.S.
Department of Agriculture. Prior to joining the USDA, he served as Chairman of the Iowa Utilities Board (IUB) from 2005 to 2009. During his tenure as IUB
Chairman, Commissioner Norris served on the National Association of Regulatory Utility Commissioners (NARUC) Electricity Committee and was Co-Chair of
the 2009 National Electricity Delivery Forum.
Tony Clark, Commissioner (Rep.) since 2012: term expires June 2016. Most recently served as Chairman of the North Dakota Public Service Commission.
In November 2010, Commissioner Clark was elected to serve a one-year term as President of the National Association of Regulatory Utility Commissioners
(NARUC). He is a graduate of North Dakota State University and holds an MPA from the University of North Dakota.
18
Overview
President and Chief Operating Officer:
Charles Patton
Since July 2010
18 years with AEP
Appalachian Power Company (APCo)
( organized in Virginia in 1926) is engaged in the generation,
transmission and distribution of electric power to approximately
960,000 retail customers in the southwestern portion of Virginia and
southern West Virginia, and in supplying and marketing electric power
at wholesale to other electric utility companies, municipalities and
other market participants. At December 31, 2012, APCo and its wholly
owned subsidiaries had 2,128 employees. APCo is a member of PJM.
Total Customers at 12/31/12:
Residential
816,000
Commercial
133,000
Industrial
4,000
Other
7,000
Total
PRINCIPAL INDUSTRIES SERVED:
Coal Mining
Primary Metals
Chemical Manufacturing
Paper Manufacturing
Pipeline Transportation
Owned Generating Capacity 7,018 MW
Generating Capacity by Fuel Mix:
• Coal:
72.6%
• Hydro/Pump:
11.4%
• Natural Gas:
16.0%
Transmission Miles
Distribution Miles
19
960,000
6,867
50,890
Financial & Operational Data
CAPITAL STRUCTURE (in thousands)
CAPITAL STRUCTURE
Credit Ratings/Outlook
2012
Equity
Debt
Capitalization Per Balance Sheet
% of Capitalization Per Balance Sheet
3,876,407
55.9%
3,052,562
44.1%
FFO Interest Coverage
FFO Total Debt
Total
Debt
6,928,969 3,704,693
100.0%
54.5%
4.34
17.0%
9/30/2013
Equity
Total
3,088,041
45.5%
6,792,734
100.0%
Moody's
S&P
Fitch
Baa2/S
BBB/S
BBB/S
4.79^
19.3%
^ - calculated on rolling 12-month avg.
Capital Expenditures (in millions)
2013 Asset Data * (in thousands)
Excludes AFUDC
As of 9/30/13
2012A
2013E
2014E
2015E
2016E
$ 462 $ 361 $ 527 $ 548
$ 561
Total Assets
$
10,321,166
Net Plant Assets $
8,159,605
Cash
Operating Information**
2012 retail electric sales in megawatt-hours
2012 firm wholesale sales in megawatt-hours
2012 average cost per kilowatt-hour (residential)
2012 System Peak – January 4
$
4,130
29,785,880
3,386,617
10.18 cents
6,881MW
Sources: * 3Q13 Form 10-Q (unaudited)
** 2012 FERC Form 1
20
Customer Statistics
APPALACHIAN AREA
TYPICAL BILL COMPARISON **
INVESTOR OWNED UTILITIES *
West Virginia
West Virginia
Customers
APCo
439,206
Monongahela Power
386,819
Potomac Edison
136,045
AEP – Wheeling
41,099
Virginia
APCo
Customers
Virginia
$/month
Potomac Edison
95.13
Kentucky Utilities
93.35
Monongahela Power
95.13
Dominion Virginia
105.32
APCo
96.76
APCo
112.69
AEP – Wheeling
96.76
Tennessee
AEP – Kingsport
$/Month
86.27
521,923
Dominion Virginia
2,319,501
Kentucky Utilities
29,250
Tennessee
AEP - Kingsport
** Typical bills are displayed in $/month, based on 1,000 kWh of residential usage.
Billing amounts sourced from the EEI Typical Bills and Average Rates Report as
of January 1, 2013.
Customers
47,436
* Customer counts are as of December 31, 2011 and were sourced from table 10
at http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html
Top 10 Customers = 27% of industrial sales
Metropolitan areas account for 52% of ultimate sales
117 persons per square mile (U.S. = 87)
(Data for 12 months ended December 2012)
21
$/month
MAJOR CUSTOMERS:
Roanoke Cement Co. LLC (VA)
Greif Brothers Corporation (VA)
Steel of WV, Inc. (WV)
WVA Manufacturing (WV)
Roanoke Electric Steel Corporation (VA)
Georgia-Pacific Corporation (VA)
Bayer Crop Science LP (WV)
Felman Production (WV)
Constellium Rolled Products (WV)
The Goodyear Tire and Rubber Co. (VA)
(Data for year ended December 2012)
Generation
Plant Name
Appalachian Power Company
Buck
Byllesby
Claytor
Leesville
London
Marmet
Niagara
Reusens
Winfield
Smith Mountain
Amos (Units 1&2)
Clinch River^*
Glen Lyn^*
Kanawha River^
Mountaineer
Sporn (Units 1&3)^*
Dresden
Ceredo
Units
3
4
4
2
3
3
2
5
3
5
2
3
2
2
1
2
1
6
VA
VA
VA
VA
WV
WV
VA
VA
WV
VA
WV
VA
VA
WV
WV
WV
OH
WV
State
Fuel Type
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Pumped Storage
Steam - Coal
Steam - Coal
Steam - Coal
Steam - Coal
Steam - Coal
Steam - Coal
Natural Gas
Natural Gas
* Plants on extended start-up: Clinch River Unit 3, Glen Lyn Units 5&6, Sporn Unit 3
Net
Maximum
Capacity
Year Plant
(MW)
Commissioned
9
22
76
50
14
14
2
13
15
586
2,033
705
335
400
1,320
300
608
516
7,018
1912
1912
1939
1964
1935
1935
1906
1904
1938
1965
1971
1958
1918
1953
1980
1950
2012
2001
^ To be retired: all units at Glen Lyn, Kanawha River, and Sporn, Clinch River Unit 3 (235MW),
Project Name
State
Renewable
Type
Long-Term Renewable Purchase Power Agreements
Camp Grove
IL
Beech Ridge
WV
Fowler Ridge III
IN
Grand Ridge II and III
IL
22
Wind
Wind
Wind
Wind
Net
Maximum
Capacity
(MW)
75
100
100
100
375
Contract
Initiated
2008
2009
2009
2009
Commission Overview
Virginia State Corporation Commission
Commissioners
Number: 3
Appointed/Elected: Elected
Term: 6 Years
The Virginia State Corporation Commission (VSCC) is composed of three members elected by the General Assembly. Commissioners are elected to serve sixyear terms, staggered in two year increments. The chair rotates annually among the three commissioners on February 1.
Commissioners
Mark C. Christie, (Rep.), since 2004; current term expires 2016. Prior counsel to the Speaker of the House of delegates of the Virginia General Assembly.
Lawyer, private practice. Law degree from Georgetown.
Judith Williams Jagdmann, (Rep.), since 2006; current term expires 2018. Law degree from T.C. Williams School of Law at the University of Richmond.
Served as Deputy Attorney General for Civil Litigation Division from 1998 to 2005. Attorney General for Commonwealth of Virginia from 2005 to 2006.
James C. Dimitri, Chairman, (Dem.), since 2008; current term expires 2014. Prior to being named Commissioner, Dimitri was in private practice in
Richmond. From 1994 to 2000 he served as Senior Counsel, then General Counsel at the SCC. He was an assistant Attorney General from 1983 to 1987.
Dimitri received his undergraduate degree in economics from the University of Virginia and his J.D. from the Boston University School of Law.
AEP Regulatory Status
APCo-VA provides retail electric service in Virginia at unbundled rates. In 2007, the General Assembly passed legislation re-establishing retail rate regulation
in the Commonwealth. The legislation provides for biennial rate reviews beginning in 2009, sharing of off-system sales margins at a rate of a minimum of
25% retained by the company effective July 1, 2007 and a post-2008 rider for DSM, renewable programs and new generation. APCo-VA is entitled to
adjustments to fuel rates to recover its actual fuel costs, the fuel component of its purchased power costs and certain capacity charges. Virginia currently has
a voluntary renewable energy standard which is phased in starting at 4% and increasing to 10% from 2010 - 2025 . The next biennial filing is due March 31,
2014.
23
Commission Overview
Public Service Commission of West Virginia
Commissioners
Number: 3
Term: 6 Years
The West Virginia Public Service Commission (WVPSC) consists of three members, appointed by the Governor, with the advice and consent of the senate.
No more than two members of the commission may belong to the same political party. The Commissioners serve six year staggered terms, with one term
expiring as of July 1 of each odd numbered year. One Commissioner is designated as Chairman of the Commission by the Governor. The Chairman serves
as the chief fiscal officer of the Commission.
Commissioners
Michael A. Albert, Chairman (Rep.), since 2007; term expires June 2019. Served as a member in the Business Law Department of Jackson Kelly. President
and Chairman of the board of directors of the Kanawha County Public Library. Bachelor’s degree and Doctorate of Jurisprudence, West Virginia University.
Jon W. McKinney, Commissioner (Dem.), since 2005; term expired June 2011. Currently on the board of directors of the NARUC and second VP of the MidAtlantic Conference of Regulated Utilities Commissioners. Formerly served as plant manager of Flexsys’ Nitro, W .V. operations, chairman of Chemical
Industry Committee for W.V., board member of W.V. Chamber of Commerce, W.V. Manufacturer’s Association, Chemical Alliance Zone, W.V. Roundtable,
Advantage Valle, St. Francis Hospital & Thomas Memorial Hospital.
Ryan B. Palmer, Commissioner (Dem.), since 2010; term expires June 2015. Served as Deputy General Counsel to West Virginia Governor Joe Manchin,
III; as Attorney/Advisor to Commissioner Charlotte R. Lane of the United States International Trade Commission and Law Clerk to the Honorable W. Craig
Broadwater of the United States District Court, Northern District of West Virginia. Bachelor’s degree and Doctorate of Jurisprudence, West Virginia University.
APCo and Wheeling Power in WV provide retail electric service at bundled rates approved by the WV PSC. West Virginia has an active annual ENEC
(Expanded Net Energy Cost) mechanism, which provides for a rate adjustment for fuel costs, among other items. West Virginia also has a special
construction surcharge permitted, primarily related to environmental-related construction. West Virginia currently has a renewable energy standard which is
phased in starting at 10% and increasing to 25% from 2015-2025.
24
Commission Overview
Tennessee Regulatory Authority
Commissioners
Number: 5
Term: 6 Years
The Tennessee Regulatory Authority (TRA) directors are appointed, one each, by the Governor, Lieutenant Governor (as Speaker of the Senate), Speaker of
the House and two joint appointments by the three together, and are confirmed by the Tennessee General Assembly. The directors are appointed for six and
three-year staggered terms. The chairmanship rotates every year in an agreed upon decision by the directors.
Commissioners
James M. Allison, Chairman, since 2012; current term expires June 2018. Allison is an accomplished utility executive with over 35 years industry
management experience. His career has spanned all sectors of the utility industry with service at the officer/CEO level. He has served on numerous corporate
boards and governing bodies including experience working with Public Service Commissions in six states.
Herbert H Hilliard, Vice-Chairman, since 2012; current term expires June 2017. Former Executive Vice President and Chief Government Relations Officer for
Frist Horizon National Corporation. Serves as Chairman of the Board of Directors of The National Civil Rights Museum, Board member of Blue Cross Blue
Shield of Tennessee and Commissioner for the Memphis Shelby County Airport Authority. BBA in Personnel Administration and Industrial Relations from
University of Memphis.
David Jones, Director, since 2012; current term expires June 2018. President of Complete Holding Group. Certified facilitator/executive coach with the
Alternative Board. BS in Business from University of Tennessee, Knoxville and an MBA from the University of Houston.
Kenneth C. Hill, Director (Rep.), since 2009; current term expires June 2014. At the time of his appointment to the TRA, Hill was Chief Executive Officer of
Appalachian Educational Communication Corporation and served as General Manager of five radio stations reaching portions of East Tennessee and four
surrounding states. Doctor of Religious Education, Andersonville Baptist Seminary.
Robin Bennett, Director (), since 2013; current term expires June 2014. Vice President and financial center manager for First Tennessee bank. Member
Chattanooga Bar Association Auxiliary. Bachelor’s degree in Business Administration-Finance from the University of Tennessee-Chattanooga.
No deregulation legislation and no base rate freeze or cap. Tennessee has an active fuel clause.
25
Debt Schedules
26
Interest
Maturity CUSIP / PPN*
Amount
Pollution Control Bond
3.250%
05/01/2019
95648NAB3
$30,000,000
3.250%
05/01/2019
95648NAC1
$40,000,000
4.625%
11/01/2021
782470AR9
$17,500,000
2.000%
1
10/1/2022
575200BA7
$100,000,000
Floating
2/1/20362
95648VAL3
$50,275,000
Floating
2/1/20362
95648VAK5
$75,000,000
5.375%
12/01/2038
95648VAS8
$50,000,000
2.250%
1/1/20413
95648VAT6
$65,350,000
Floating
12/1/20424
95648VAP4
$54,375,000
Floating
4
12/1/2042
95648VAQ2
$50,000,000
Senior Notes
4.950%
02/01/2015
037735CB1
$200,000,000
Senior Notes
3.400%
05/24/2015
037735CQ8
$300,000,000
Senior Notes
5.000%
06/01/2017
037735CD7
$250,000,000
Senior Notes
7.950%
01/15/2020
037735CP0
$350,000,000
Senior Notes
4.600%
03/30/2021
037735CR6
$350,000,000
Senior Notes
5.950%
05/15/2033
037735BZ9
$200,000,000
Senior Notes
5.800%
10/01/2035
037735CE5
$250,000,000
Senior Notes
6.375%
04/01/2036
037735CG0
$250,000,000
Senior Notes
6.700%
08/15/2037
037735CK1
$250,000,000
Senior Notes
7.000%
04/01/2038
037735CM7
$500,000,000
Weighted Average or Total
5.62%
1
Put date 10/01/2014
2
Put date 03/17/2015
3
Put date 09/01/2016
4
Put date 03/24/2014
$3,432,500,000
Note: Debt schedules current as of 9/30/13. The weighted average coupon excludes all floating rate debt.
* PPN – Private Placement Number
Overview
Paul Chodak
Since July 2010
12 years with AEP
Indiana Michigan Power Company
(I&M) (organized in Indiana in 1907) is engaged in the
generation, transmission and distribution of electric power to
approximately 584,000 retail customers in northern and
eastern Indiana and southwestern Michigan, and in supplying
and marketing electric power at wholesale to other electric
utility companies, rural electric cooperatives, municipalities
and other market participants. At December 31, 2012, I&M
had 2,649 employees. I&M is a member of PJM.
Residential
508,000
Commercial
69,000
Industrial
5,000
Other
2,000
Total
584,000
Owned Generating Capacity
4,518MW
Primary Metals
Transportation Equipment
Plastics and Rubber Products
Fabricated Metal Products
27
• Coal:
51.0%
• Nuclear:
48.5%
• Hydro:
Transmission Miles
Distribution Miles
0.5%
5,363
20,312
CAPITAL STRUCTURE
2012
Equity
Debt
2,057,666
53.3%
1,803,775
46.7%
FFO Total Debt
Total
Debt
3,861,441 2,271,613
100.0%
54.4%
4.53
21.4%
9/30/2013
Equity
1,902,579
45.6%
Total
4,174,192
100.0%
Moody's
S&P
Fitch
Baa2/S
BBB/S
BBB/S
4.79^
20.6%
Excludes AFUDC
As of 9/30/13
Total Assets
2012A
2013E
2014E
2015E
2016E
$ 383 $ 456 $ 444 $ 454
$ 488
$
8,187,792
Net Plant Assets $
4,900,559
`
Cash
2012 System Peak – July 6
$
18,403,788
5,036,929
8.74 cents
4,726MW
** 2012 FERC Form 1
28
1,798
Customer Statistics
INDIANA & MICHIGAN INVESTOR
OWNED UTILITIES *
Indiana
Customers
Indiana
Michigan
$/month
I&M
454,952
I&M
86.24
I&M
101.89
IP & L
468,195
IP & L
98.18
Consumers Energy
129.43
NIPSCO
456,953
Duke Energy Indiana
112.16
Detroit Edison
149.81
Duke Energy Indiana
782,879
NIPSCO
132.15
SIGECo
146,136
SIGECo
152.88
Michigan
I&M
Customers
127,844
Consumers Energy
1,779,1841,788,799
Detroit Edison
2,156,2142,122,473
** Typical bills are displayed in $/month, based on 1,000 kWh of residential usage.
Billing amounts sourced from the EEI Typical Bills and Average Rates Report as
of January 1, 2013.
Top 10 Customers = 45% of industrial sales
29
$/month
MAJOR CUSTOMERS:
Steel Dynamics Inc. (IN)
Metal Technologies Inc. (MI)
American Axle and Mfg. Co, Inc. (MI)
IN TEK (IN)
Rettenmaier USA LP (MI)
Saint Gobain Containers Inc. (IN)
White Pigeon Paper Company (MI)
Air Products & Chemicals. Inc. (IN)
The Minute Maid Company (MI)
BOC Gases (IN)
Generation
Plant Name
Units
Berrien Springs
12
Buchanan
10
Constantine
4
Elkhart
3
Mottville
4
Twin Branch
6
Rockport
2
Tanners Creek^*
4
Cook
2
State
MI
MI
MI
IN
MI
IN
IN
IN
MI
Fuel Type
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Steam - Coal
Steam - Coal
Steam - Nuclear
Net
Maximum
Capacity
Year Plant
(MW)
Commissioned
7
4
1
3
2
5
1,310
995
2,191
4,518
1908
1919
1921
1913
1923
1904
1984
1951
1975
* Plants on extended start-up: Tanners Creek Units 1&2
^ Plants to be retired
Project Name
State
Renewable
Type
Net
Maximum
Capacity
(MW)
Contract
Initiated
Fowler Ridge I
Fowler Ridge II
Wildcat
Headwaters
IN
IN
IN
IN
# Under contract but not yet on-line, expected 2015
30
Wind
Wind
Wind
Wind
100
50
100
200
450
2009
2009
2012
#
Commission Overview
Indiana Utility Regulatory Commission
Commissioners
Number: 5
Term: 4 Years
Five members, appointed by the Governor from among persons nominated by a legislatively mandated utility commission nominating committee; four-year,
staggered terms, full-time positions. Not more than three of the members of the IURC shall be members of the same political party. At least one of the
commissioners must be an attorney qualified to practice law before the Indiana Supreme Court. The Governor appoints one of the five as chairperson.
Commissioners
James D. Atterholt, Chairman (Rep.), since 2009; current term ends April 2017. Prior to joining the Commission, he was the State Insurance Commissioner
for more than four years where he also served as a member of the Governor’s Cabinet. Atterholt worked as Director of Government Affairs for AT&T--Indiana
from 2003 – 2004. Holds a Bachelors degree from the University of Wisconsin.
David E. Ziegner, Commissioner (Dem.), since 1990; current term ends April 2015. Lawyer, staff attorney for Legislative Services Agency, General Counsel
for IURC. Treasurer of NARUC, vice-chair NARUC Committee on Electricity and former chairman of the NARUC clean coal and carbon sequestration
subcommittee. Law degree from the Indiana University School of Law in Indianapolis.
Larry S. Landis, Commissioner (Rep.), since 2002; current term ends December 2015. Former president of a marketing and communications agency, VP
Corporate Advertising, American Fletcher National Bank. Bachelor’s degrees in political science and economics.
Carolene R. Mays, Commissioner (Dem.), since 2010; current term ends December 2013. Former publisher and president of the Indianapolis Recorder
Newspaper and the Indiana Minority Business Magazine. From 2002 to 2008, served in the Indiana House of Representatives and sat on the committees for
Small Business and Economic Development, Ways and Means and Public Health.
Kari A. E. Bennett, Commissioner (Rep.), since 2011;current term ends March 2014. Prior to joining the Commission, she was chief legal counsel of the
Indiana Department of Natural Resources. From 2005 to 2007 she was Policy Director for Environments and Natural Resources for Indiana Governor Daniels.
She graduated from Miami University of Ohio with a degree in environmental science and received her Juris Doctorate from the University of Minnesota.
I&M–Indiana provides retail electric service at bundled rates approved by the IURC. Rates are set on a cost-of-service basis with a fuel recovery mechanism.
I&M–Indiana has trackers in place for PJM expenses, OSS sharing, clean coal technology, environmental, nuclear life cycle management and DSM. Indiana
currently has a voluntary renewable standard which phases in starting at 4% and ending at 10% from 2013-2025.
31
Commission Overview
Michigan Public Service Commission
Commissioners
Number: 3
Term: 6 Years
Political Makeup: I: 2 R: 1
The Michigan Public Service Commission (MPSC) is composed of three members appointed by the Governor with the advice and consent of the Senate.
Commissioners are appointed to serve staggered six-year terms. No more than two commissioners may represent the same political party. One
commissioner is designated as chairman by the Governor.
Commissioners
John D. Quackenbush, Chairman (Rep), since 2011; current term expires July 2017. Former managing director and senior investment analyst at UBS
Global Asset Management responsible for equity research of transportation, utilities and coal industries in the US and Canada. Undergraduate degree in
business economics from Calvin College and master’s degree in finance from Michigan State University.
Sally Talberg, Commissioner (Ind), since 2013; current term expires July 2019. Former senior consultant at Public Sector Consultants. Previously served
as an analyst at the MPSC, managed enforcement and contested cases at the Michigan Department of Environmental Quality and advised commissioners at
the Public Utility Commission of Texas. Holds a bachelor of science from Michigan State University and a master’s of Public Administration from the University
of Texas – Austin..
Greg R. White, Commissioner, (Ind.) , since 2009; current term expires July 2015. Former legislative liaison for the MPSC and liaison for the MPSC to the
Michigan Department of Energy, Labor and Economic Growth. Holds a bachelor of science from Michigan State University and master’s of public
administration from Grand Valley State University.
Customer choice began January 2002. Generation was not deregulated. Retail rates were unbundled (though they continue to be regulated) to allow
customers to evaluate generation costs. In 2008, legislation was enacted to limit customer choice load to no more than 10% of the annual retail load for the
preceding calendar year but there is currently active legislation attempting to increase this cap. I&M-Michigan has an active fuel clause and return on CWIP
can be included in base rates. Michigan currently has a mandatory renewable energy standard which phases in starting at 2% and ending at 10% from 20122015 .
32
Debt Schedules
Interest
Amount
Floating
10/01/20191
520453AL5
$25,000,000
Floating
2
11/01/2021
520453AK7
$52,000,000
4.625%
06/01/2025
773835AV5
$50,000,000
6.250%
06/01/20253
773835BF9
$50,000,000
6.250%
06/01/20253
773835BE2
$50,000,000
Nuclear Fuel Lease
5.440%
10/01/2013
N/A
$7,865,587
Nuclear Fuel Lease
4.000%
10/13/2014
N/A
$13,298,845
Nuclear Fuel Lease
Floating
06/07/2015
N/A
$14,279,766
Nuclear Fuel Lease
2.120%
05/01/2016
N/A
$18,113,241
Nuclear Fuel Lease
Floating
05/01/2016
N/A
$26,153,507
Nuclear Fuel Lease
Floating
10/27/2016
N/A
$60,116,617
Nuclear Fuel Lease
Floating
10/27/2016
N/A
$93,149,930
Term Loan
Floating
05/15/2015
45488QAA6
$105,913,672
Senior Notes
5.050%
11/15/2014
454889AK2
$175,000,000
Senior Notes
5.650%
12/01/2015
454889AL0
$125,000,000
Senior Notes
7.000%
03/15/2019
454889AN6
$475,000,000
Senior Notes
6.050%
03/15/2037
454889AM8
$400,000,000
Senior Notes
3.200%
03/15/2023
454889 AP1
$250,000,000
5.653%
1
Put date is 03/22/2015
2
3
$1,990,891,165
* Private Placement Number
33
Overview
Greg Pauley
Since August 2010
39 years with AEP
Kentucky Power Company (KPCo)
(organized in Kentucky in 1919) is engaged in the generation,
transmission and distribution of electric power to
approximately 173,000 retail customers in an area in eastern
Kentucky, and in supplying and marketing electric power at
wholesale to other electric utility companies, municipalities
and other market participants. At December 31, 2012, KPCo
had 392 employees. KPCo is a member of PJM.
Residential
141,000
Commercial
30,000
Industrial
1,500
Other
500
Total
173,000
Owned Generating Capacity* 1,078 MW
Big Sandy Plant – Louisa, KY
Petroleum and Coal Products Manufacturing
Coal Mining
Primary Metals
Mining Support Activities
• Coal:
100%
PPA: ecoPower Biomass **
Transmission Miles
Distribution Miles
59MW
1,251
10,029
* As of 1/1/2014 also includes 50% of Mitchell Units 1&2 – 780MW
** Pending regulatory approval
34
CAPITAL STRUCTURE
Debt
562,581
54.0%
2012
Equity
Total
479,610
46.0%
1,042,191
100.0%
FFO Total Debt
3.79
18.1%
Debt
9/30/2013
Equity
549,347
54.0%
468,417
46.0%
Total
1,017,764
100.0%
Moody's
S&P
Fitch
Baa2/S
BBB/S
BBB/N
4.01^
19.7%
Excludes AFUDC
As of 9/30/13
Total Assets
2012A
2013E
$ 102 $
2014E
2015E
$
1,550,269
Net Plant Assets $
1,219,054
2016E
74 $ 117 $ 120 $
77
Cash
2012 System Peak – January 4
$
845
6,660,656
94,158
9.18 cents
1,378MW
Sources: * 3Q13 Financial Statements (unaudited)
** 2012 FERC Form 1
35
Customer Statistics
KENTUCKY INVESTOR OWNED UTILITIES *
Kentucky
Customers
Kentucky
$/month
KPCo
173,642
Kentucky Utilities
87.07
Duke Energy Kentucky
135,574
KPCo
87.91
Kentucky Utilities
511,585
Duke Energy Kentucky
90.86
LG & E
394,062
LG&E
94.29
** Typical bills are displayed in $/month, based on 1,000 kWh of
residential usage. Billing amounts sourced from the EEI Typical
Bills and Average Rates Report as of January 1, 2013.
MAJOR CUSTOMERS:
Catlettsburg Refining LLC
AK Steel Holding Corporation
Sidney Coal Company, Inc.
KES Acquisition Company LLC
Air Products & Chemicals, Inc.
Air Liquide
Calgon Carbon Corp
Markwest Energy Appalachia LLC
Huntington Alloys
Czar Coal Corporation
36
Top 10 customers = 68% of industrial sales
Commission Overview
Kentucky Public Service Commission
AEP Regulated Electric Utilities
Kentucky Power Co.
Commissioners
Number: 3
Term: 4 Years
Typically three members, appointed by the governor and confirmed by the state senate for four years, staggered terms, full-time positions. The governor
appoints one of the three as chairman and another of the three as vice chairman to serve in the chairman’s absence. Not more than two members of the
KPSC shall be of the same profession or occupation.
Commissioners
David L. Armstrong, Chairman (Dem.), since 2008; current term expires June 2015. Former practicing attorney in private practice. Board member of NARUC
and serves on its Electricity Committee and the Subcommittee on Clean Coal Technology. J.D. from University of Louisville Brandeis School of Law. Mr.
Armstrong is also the former Mayor for the city of Louisville, KY (1999-2003).
James W. Gardner, Vice Chairman (Rep.), since 2008; current term expires June 2016. Prior to joining the PSC Mr. Gardner was a partner at the law firm
Henry Watz Gardner & Sellars PLLC where he specialized in bankruptcy law. JD degree from the University of Kentucky College of Law.
Linda Breathitt, Commissioner (Dem.), since 2012; current term expires June 2017. Before joining the PSC, Commissioner Breathitt served as the federal
representative to the Southern States Energy Board. She has previously served on the PSC from 1993 to 1997 and also served a five year term as a member
of the Federal Energy Regulatory Commission. BA from the University of Kentucky.
KPCo provides service at regulated bundled rates in Kentucky. Kentucky has an environmental surcharge to recover approved environmental costs and it has
an active fuel clause. Kentucky also has an OSS sharing mechanism and a monthly adjustment clause in place for DSM.
37
Debt Schedules
Kentucky Power
Interest
Amount
Senior Notes
6.000%
09/15/2017
491386AM0
$325,000,000
Senior Notes
7.250%
06/18/2021
491386 C*7
$40,000,000
Senior Notes
8.030%
06/18/2029
491386 C@5
$30,000,000
Senior Notes
5.625%
12/01/2032
491386AL2
$75,000,000
Senior Notes
8.130%
06/18/2039
491386 C#3
$60,000,000
6.397%
$530,000,000
38
Overview
Pablo Vegas
Since May 2012
8 years with AEP
AEP Ohio- Ohio Power Company (OPCo)
(organized in Ohio in 1907 and re-incorporated in 1924) is engaged in
the generation, transmission and distribution of electric power to
approximately 1,459,000 retail customers in the northwestern, east
central, eastern and southern sections of Ohio, and in supplying and
marketing electric power at wholesale to other electric utility
companies, municipalities and other market participants. At December
31, 2012, OPCo had 3,131 employees. Ohio is transitioning to
competitive electricity markets for generation service. OPCo expects
corporate separation to be completed at the end of 2013 wherein all
the generation assets currently owned by OPCo will be transferred to
AEP Generation Resources and legacy OPCo will become a wires
only company. As of June 1, 2015 AEP Generation Resources will be
fully competitive. OPCo is a member of PJM.
Residential
1,273,000
Commercial
173,000
Industrial
10,000
Other
3,000
Total
1,459,000
Primary Metals
Petroleum and Coal Products Manufacturing
Rubber & Plastic Products
Fabricated Metal Products
39
• Coal:
88.0%
• Natural Gas:
11.6%
• Hydro:
Transmission Miles
Distribution Miles
0.4%
8,971
45,583
CAPITAL STRUCTURE
Debt
3,860,440
46.0%
2012
Equity
4,525,709
54.0%
FFO Total Debt
Total
Debt
9/30/2013
Equity
8,386,149 3,699,299
100.0%
44.6%
5.23
24.0%
Total
4,587,574
55.4%
8,286,873
100.0%
Moody's
S&P
Fitch
Baa1/S
BBB/S
A-/N
4.90^
22.9%
Excludes AFUDC
As of 9/30/13
2012A
2013E
2014E
2015E
2016E
$ 524 $ 616 $ 356 $ 315
$ 307
Total Assets
$
12,556,214
Net Plant Assets $
10,028,455
`
As of 01/01/2014 AEP Ohio is a wires only company –
post 2013 capex is more indicative of run rate
2012 System Peak – June 29
Cash
$
30,897,005
2,596,133
13.19 cents
9,670MW
** 2012 FERC Form 1
40
4,341
Customer Statistics
OHIO INVESTOR OWNED UTILITIES *
Ohio
TYPICAL BILL COMPARISON ***
Ohio
Customers
AEP Ohio
1,435,614
Duke Energy Ohio
112.26
FirstEnergy **
664,111
FE (Toledo Edison)
113.89
Duke Energy Ohio
474,243
FE (CEI)
113.95
DP&L
484,278
FE (Ohio Edison)
116.03
AEP (OPCo)
129.38
DP&L
131.66
AEP (CSPCo)
132.68
** FirstEnergy -Toledo Edison = 106,547
CEI = 188,592
Ohio Edison = 368,972
MAJOR CUSTOMERS:
Lima Refining Co
Republic Engineered Products, LLC
The Timken Company
E.I. Du Pont de Nemour
Eramet Marietta, Inc.
Kraton Polymers US, LLC
Glatfelter Company
Amsted Rail Company, Inc.
Globe Metallurgical, Inc.
41
$/month
*** Typical bills are displayed in $/month, based on 1,000
kWh of residential usage. Billing amounts sourced
from the EEI Typical Bills and Average Rates Report
as of January 1, 2013. Ohio rates represent provider
of last resort bundled residential rates.
Top 10 OPCo customers = 47% of industrial sales
Generation
Plant Name
Units
State
Fuel Type
Net
Maximum
Capacity
Year Plant
(MW)
Commissioned
Ohio Power Company (to AEP Generation Resources effective 01/01/2014)
Racine
2
OH
Hydro
Darby
6
OH
Natural Gas
Waterford
4
OH
Natural Gas
Cardinal
1
OH
Steam - Coal
Gavin
2
OH
Steam - Coal
Muskingum River^*
5
OH
Steam - Coal
Picway^*
1
OH
Steam - Coal
Beckjord (CCD)^**
1
OH
Steam - Coal
Conesville (Unit 4) (CCD)**
1
OH
Steam - Coal
Stuart (CCD)**
4
OH
Steam - Coal
Stuart (CCD)**
4
OH
Oil
Zimmer (CCD)**
1
OH
Steam - Coal
Amos (Unit 3)***
1
WV
Steam - Coal
Conesville (Units 5&6)
2
OH
Steam - Coal
Kammer^
3
WV
Steam - Coal
Mitchell***
2
WV
Steam - Coal
Sporn (Units 2&4)^*
2
WV
Steam - Coal
* Plants on extended start-up: MR Unit 4, Picway Unit 5, Sporn Unit 4
** CCD Plants jointly owned by AEP Ohio, Duke, and DP&L
*** To be transferred to APCo (Amos 3) and KPCo (50% Mitchell)
Project Name
Fowler Ridge II
Wyandot Solar
Timber Road
42
State
IN
OH
OH
Renewable
Type
Wind
Solar
Wind
48
507
840
595
2,640
1,440
100
53
339
600
3
330
867
800
630
1,560
300
11,652
Net
Maximum
Capacity
(MW)
100
10
99
209
1982
2001
2003
1967
1974
1953
1926
1969
1957
1971
1970
1991
1973
1957
1958
1971
1950
Contract
Initiated
2009
2010
2013
Commission Overview
Ohio Public Utilities Commission
Commissioners
Number: 5
Term: 5 Years
Political Makeup: R: 2 D: 1 I: 2
Five members, appointed by the governor and confirmed by the state senate; five year, staggered terms, full-time positions, commissioners shall be selected
from the lists of qualified persons submitted to the governor by the PUC nominating council. Not more than three of the members of the PUCO shall be
members of the same political party. The governor appoints one of the five as chairman, who serves at the pleasure of the governor until a successor has
been designated.
Commissioners
Todd A. Snitchler, Chairman, (Rep.) , since 2011; term expires April 2014. Before joining the commission was elected to two terms in the Ohio House of
Representatives. Past chairman and secretary of the Lake Township Chamber of Commerce. Received his B.S. from Grove City College in history and
secondary education/social science and his law degree from the University of Akron School of Law.
M. Beth Trombold, Commissioner, (Ind.) since 2013; term expires April 2018. Prior to joining the commission, was the assistant director of the Ohio
Development Services Agency. Prior to that was on PUC staff for 16 years. Bachelor’s degree in international business and marketing from Ohio University
and master’s in public policy from Ohio State University.
Steven D. Lesser, Commissioner, (Dem.) since 2010; term expires April 2015. Juris Doctorate from Capital University; previously served as PUCO chief of
staff, assistant director of the legal department, deputy director of the transportation department and administrative law judge/attorney examiner in the legal
department.
Asim Haque, Commissioner, (Ind.) since 2013; term expires April 2016. Prior to joining the commission was assistant counsel at Honda of America. Prior to
that was an attorney with Ice Miller LLP. Bachelor’s degrees in chemistry and political science from Case Western Reserve University and Juris Doctorate from
Ohio State University.
Lynn Slaby, Commissioner, (Rep.) since 2012; term expires April 2017. Juris Doctorate and Bachelor of Science from University of Akron; previously served
in Ohio House of Representatives representing 41st District. For 14 years Commissioner Slaby served as Summit County Prosecuting Attorney.
The currently approved electric security plan expires in May 2015. Corporate Separation expected as of January 1, 2014 at which time OPCo will be a wires
only company. Transmission rates are currently regulated by FERC as reflected in the OATT. SB221 allows that OPCo has an active fuel clause effective
January 1, 2009. Ohio currently has a mandatory renewable energy standard of 25% by 2025, phased in beginning in 2009.
43
Debt Schedules
Ohio Power Company
Amount
Floating
07/01/2014
572287AT7
$50,000,000
Floating
05/1/20261
677525MQ7
$50,000,000
2.875%
12/01/20272
677525TX5
$39,130,000
Floating
06/1/20373
95648VAD1
$65,000,000
3.875%
12/01/20384
677525TL1
$60,000,000
5.800%
12/01/2038
677525TM9
$32,245,000
3.250%
06/01/20415
677525TV9
$79,450,000
3.125%
6
03/01/2043
95648VAR0
$86,000,000
Term Loan
Floating
05/13/2015
N/A
$200,000,000
Term Loan
Floating
05/13/2015
N/A
$400,000,000
Senior Notes
4.850%
01/15/2014
677415CG4
$225,000,000
Senior Notes
6.000%
06/01/2016
677415CL3
$350,000,000
Senior Notes
6.050%
05/01/2018
199575AW1
$350,000,000
Senior Notes
5.375%
10/01/2021
677415CP4
$500,000,000
Senior Notes
6.600%
02/15/2033
677415CF6
$250,000,000
Senior Notes
6.600%
03/01/2033
199575AT8
$250,000,000
Senior Notes
5.850%
10/01/2035
199575AV3
$250,000,000
5.590%
Securitization Bond
0.958%
07/01/2017
67741Y AA6
$164,900,000
Securitization Bond
2.049%
07/01/2019
67741Y AB4
$102,508,000
1.376%
1
Put date 11/21/2014
2
Put date 08/01/2014
3
Put date 07/01/2014
4
Put date 06/01/2014
5
Put date 06/02/2014
6
Put date 04/01/2015
$3,236,825,000
$267,408,000
44
Interest
Overview
Stuart Solomon
Since June 2004
24 years with AEP
Public Service Company of Oklahoma (PSO)
(organized in Oklahoma in 1913) is engaged in the generation, transmission
and distribution of electric power to approximately 535,000 retail customers
in eastern and southwestern Oklahoma, and in supplying and marketing
electric power at wholesale to other electric utility companies, municipalities,
rural electric cooperatives and other market participants. At December 31,
2012, PSO had 1,127 employees. PSO benefits from the largest percentage
of natural gas fired plants in the AEP fleet. PSO is a member of SPP.
Residential
460,500
Commercial
61,000
Industrial
6,000
Other
7,500
Total
Paper Manufacturing
Oil & Gas Extraction
Transportation Equipment
Plastics and Rubber Products
Petroleum & Coal Products Manufacturing
• Coal:
23.3%
• Natural Gas:
76.4%
• Oil:
Transmission Miles
Distribution Miles
45
535,000
0.4%
3,526
22,080
CAPITAL STRUCTURE
Debt
2012
Equity
949,871
50.9%
Total
916,278
49.1%
1,866,149
100.0%
Debt
9/30/2013
Equity
949,826
49.5%
967,656
50.5%
Total
1,917,482
100.0%
Moody's
Baa1/S
FFO Total Debt
5.84
28.3%
S&P
BBB/S BBB+/S
4.32^
19.0%
Excludes AFUDC
As of 9/30/13
Total Assets
2012A
2013E
2014E
Fitch
2015E
2016E
$ 221 $ 302 $ 343 $ 353
$ 308
$
3,432,965
Net Plant Assets $
3,059,120
`
Cash
2012 System Peak – August 1
$
17,963,562
7,728
8.01 cents
4,419MW
** 2012 FERC Form 1
46
2,000
Customer Statistics
OKLAHOMA INVESTOR OWNED UTILITIES *
Oklahoma
Customers
Oklahoma
$/month
PSO
532,395
PSO
72.84
OG&E
721,269
OG&E
83.53
Empire District
99.98
Empire District
4,727
* Customer counts are as of December 31, 2011 and were
sourced from table 10 at
http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html
** Typical bills are displayed in $/month, based
on 1,000 kWh of residential usage. Billing
amounts sourced from the EEI Typical Bills
and Average Rates Report as of January 1,
2013.
MAJOR CUSTOMERS:
Weyerhaeuser Valliant Company
Transok, Inc.
Kimberly Clark Corp.
Goodyear Tire & Rubber Company
American Airlines
Sinclair Tulsa Refining Company
Sun Refining & Marketing
Terra Nitrogen
Kelco
47
Generation
Plant Name
Units
Public Service Company of Oklahoma
Tulsa
2
Riverside (1&2)
2
Riverside (3&4)
2
Riverside
1
Northeastern (1&2)
4
Northeastern
1
Southwestern (1-3)
3
Southwestern (4&5)
2
Southwestern
1
Comanche
3
Comanche
2
Weleetka
3
Weleetka
2
Northeastern (3&4)^
2
Northeastern
1
Oklaunion
1
State
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
TX
Fuel Type
Steam
Steam
Steam
Oil
Steam
Oil
Steam
Steam
Oil
Steam
Oil
Steam
Oil
Steam
Oil
Steam
- Natural Gas
- Natural Gas
- Natural Gas
- Natural Gas
- Natural Gas
- Natural Gas
- Natural Gas
- Natural Gas
- Coal
- Coal
^ Plants to be retired: Northeastern Unit 4 (470MW)
Project Name
Weatherford
Blue Canyon II*
Sleeping Bear
Blue Canyon V
Minco
Elk City
Balko**
Seling**
Goodwell**
48
* Expires 2015
** Pending regulatory approval
State
Renewable
Type
OK
OK
OK
OK
OK
OK
OK
OK
OK
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Net
Maximum
Capacity
Year Plant
(MW)
Commissioned
309
909
157
3
920
3
466
170
2
260
4
196
4
930
1
102
4,436
Net
Maximum
Capacity
(MW)
1923
1974
2008
1976
1961
1961
1952
2008
1962
1973
1962
1975
1963
1979
1980
1986
Contract
Initiated
147
2005
151
2005
95
2008
99
2009
99
2010
99
2010
199
***
200
***
199
***
1,288
*** Under contract but not yet on-line, expected 2016
Commission Overview
Oklahoma Corporation Commission
AEP Regulated Electric Utilities
Commissioners
Number: 3
Term: 6 Years
The Oklahoma Corporation Commission (OCC) is composed of three commissioners who are elected by state-wide vote. Commissioners serve staggered sixyear terms. The election pattern was established when the Commission was created by the state constitution.
Commissioners
Bob Anthony, Vice Chairman, (Rep.), since 1989; current term expires January 2019. Member, NARUC. Served on the boards of the Oklahoma State,
Oklahoma City, and South Oklahoma City chambers of commerce. Earned an M.Sc. from the London School of Economics, an M.A. from Yale University and
an M.P.A. from the Kennedy School of Government at Harvard University.
Patrice Douglas, Chairperson, (Rep.), since 2011; current term ends January 2015. Served as president of SpiritBank and executive vice president of First
Fidelity Bank. Received her undergraduate degree from Oklahoma Christian and her juris doctorate from the University of Oklahoma.
Dana Murphy, Commissioner, (Rep.), since 2008; current term expires January 2017. Member, NARUC. Murphy’s prior experience includes working as an
administrative law judge at the Commission. She has more than 20 years experience in the petroleum industry including owning and operating her own
private law practice and working as a geologist in the Oklahoma petroleum industry. Juris Doctorate Oklahoma City University.
PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC. PSO’s rates are set on a cost-of-service basis. Fuel and purchased
energy costs above the amount included in base rates are recovered by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is generally
adjusted annually and is based upon forecasted fuel and purchased energy costs. Over or under collections of fuel costs for prior periods are returned to or
recovered from customers when new annual factors are established. PSO has an OSS margin sharing mechanism. Oklahoma currently has a voluntary
renewable energy standard of 15% by 2015.
49
Debt Schedules
Interest
Amount
Notes Payable
3.000%
12/01/2025
N/A
$6,846,018
5.250%
06/01/2014
67884LAB9
$33,700,000
4.450%
06/01/2020
756864BT0
$12,660,000
Senior Notes
6.150%
08/01/2016
744533BH2
$150,000,000
Senior Notes
5.150%
12/01/2019
744533BK5
$250,000,000
Senior Notes
4.400%
02/01/2021
744533BL3
$250,000,000
Senior Notes
6.625%
11/15/2037
744533BJ8
$250,000,000
5.455%
$953,206,018
50
Overview
Venita McCellon-Allen
Since July 2010
30 years with AEP
Southwestern Electric Power Company (SWEPCO)
(organized in Delaware in 1912) is engaged in the generation, transmission and distribution of
electric power to approximately 524,000 retail customers in northeastern Texas, northwestern
Louisiana and western Arkansas, and in supplying and marketing electric power at wholesale
to other electric utility companies, municipalities, rural electric cooperatives and other market
participants. At December 31, 2012, SWEPCO had 1,472 employees. The territory served by
SWEPCO also includes several military installations, colleges, and universities. SWEPCO
also owns and operates a lignite coal mining operation. SWEPCO is a member of SPP.
Residential
444,500
Commercial
72,000
Industrial
7,000
Other
Food Manufacturing
Paper Manufacturing
Oil and Gas Extraction
Primary Metals
Total
524,000
• Coal:
39.9%
• Natural Gas:
45.5%
• Lignite:
14.6%
Transmission Miles
51
500
Distribution Miles
3,959
26,312
CAPITAL STRUCTURE
Debt
2,048,831
50.3%
2012
Equity
2,021,212
49.7%
FFO Total Debt
Total
Debt
4,070,043 2,043,244
100.0%
50.8%
5.26
26.7%
9/30/2013
Equity
1,975,437
49.2%
Total
4,018,681
100.0%
Moody's
Baa3/P
Excludes AFUDC
As of 9/30/13
Total Assets
2013E
2014E
2015E
2016E
$ 412 $ 392 $ 488 $ 573
$ 439
$
6,250,394
Net Plant Assets $
5,308,648
`
Cash
2012 System Peak – July 30
$
17,651
18,146,517
6,117,257
8.09 cents
5,205MW
** 2012 FERC Form 1
52
Fitch
BBB/S BBB/S
3.84^
18.0%
2012A
S&P
Customer Statistics
SOUTHWESTERN INVESTOR
OWNED UTILITIES *
Arkansas
Arkansas
Customers
SWEPCO
113,656
Entergy AR
695,385
OG&E
65,253
Empire District
Louisiana
$/month
SWEPCO
227,287
CLECO
276,973
Entergy
1,212,995
$/month
Texas
62.86
Entergy Gulf St.
88.33
SWEPCO
67.78
SWEPCO
82.39
SWEPCO
88.70
Entergy TX
84.84
97.63
Entergy NO
97.55
SPSCo
87.97
101.32
Entergy LA
102.27
El Paso
104.98
CLECO
115.32
Empire District
Entergy AR
** Typical bills are displayed in $/month, based on 1,000 kWh of residential usage. Billing amounts sourced from
the EEI Typical Bills and Average Rates Report as of January 1, 2013.
MAJOR CUSTOMERS:
Texas
Customers
SWEPCO
180,658
El Paso
287,516
SPSCo
261,904
Entergy TX
411,690
Lone Star Steel Company (TX)
International Paper Company (TX)
Calumet Lubricants (LA)
Pratt Paper (LA)
Domtar, Inc. (AR)
Exxon Mobil Corp (TX)
Cooper Tire & Rubber Company (AR)
Libbey Glass, Inc. (LA)
Big Three Industrial Gas (TX)
Superior Industries (AR)
Glad Manufacturing (AR)
53
$/month
OG&E
4,333
Customers
Louisiana
Generation
Plant Name
Units
State
Southwestern Electric Power Company
Arsenal Hill
1
Lieberman
4
Knox Lee
4
Wilkes
3
Lone Star
1
Stall
1
Mattison
4
Welsh^
3
Flint Creek
1
Turk
1
Pirkey
1
Dolet Hills
1
LA
LA
TX
TX
TX
LA
AR
TX
AR
AR
TX
LA
Net
Maximum
Capacity
Year Plant
(MW)
Commissioned
Fuel Type
Steam - Natural
Steam - Natural
Steam - Natural
Steam - Natural
Steam - Natural
Natural Gas
Natural Gas
Steam - Coal
Steam - Coal
Steam - Coal
Steam - Lignite
Steam - Lignite
Gas
Gas
Gas
Gas
Gas
110
268
475
845
49
543
316
1,584
264
440
580
256
5,730
1960
1947
1950
1964
1954
2010
2007
1977
1978
2012
1985
1986
^ Plants to be retired: Welsh Unit 2 (528MW)
Project Name
Majestic
Majestic II
Flat Ridge
Canadian Hills
54
State
TX
TX
OK
OK
Renewable
Type
Wind
Wind
Wind
Wind
Net
Maximum
Capacity
(MW)
80
80
109
201
470
Contract
Initiated
2009
2012
2013
2012
Commission Overview
Arkansas Public Service Commission
Commissioners
Number: 3
Term: 6 Years
The Arkansas Public Service Commission (APSC) is composed of 3 members. The Governor appoints the Commissioners as well as the Chairman.
Governor Beebe has appointed all of the current commissioners.
Commissioners
Collette D. Honorable, Chairperson (Dem.), since 2007; current term expires in Jan 2017. Commissioner Honorable is a member of NARUC and serves on
the Consumer Affairs and Investment Committees. She previously served on the Smart Grid Collaborative, a joint effort of NARUC and the FERC. Honorable
received her Juris Doctorate from the University of Arkansas at Little Rock School of Law.
Olan W. Reeves, Commissioner (Rep.), since 2009; current term expires in Jan 2015. Chairman of the Workers’ Compensation Commission from January,
2003 until January, 2009. Prior to these appointments, Commissioner Reeves was Chief Legal Counsel to the Governor from 1998-2003 and served as the
State Drug Director from 1996 to 1998. Reeves received his Juris Doctorate from the University of Arkansas School of Law in Fayetteville.
Elana C. Wills, Commissioner (Dem.), since 2011; current term expired Jan 2013. Served as an Associate Justice on the Arkansas Supreme Court by
gubernatorial appointment from October 2008 – December 2010. Received her Juris Doctorate from the University of Arkansas School of Law in Fayetteville.
SWEPCO-AR provides service at regulated bundled rates in Arkansas. Arkansas has an active fuel pass-through clause. Arkansas has an OSS margin
sharing mechanism and allows CWIP in rate base for a plant that is placed in service within six months after the end of the test year.
55
Commission Overview
Louisiana Public Service Commission
Commissioners
Number: 5
Term: 6 Years
The Louisiana Public Service Commission (LPSC) is composed of five elected members. The commissioners serve overlapping terms of six years.
Commissioners
Scott Angelle, (Rep.), since 2013; current term ends December 2018. Appointed in 2004 as Secretary of the Department of Natural Resources and
Chairman of State’s Mineral Board. Left the DNR to seek office on PSC. Bachelor’s degree in petroleum land management from University of LouisianaLafayette.
Foster L. Campbell, (Dem.), since 2003; current term ends December 2014. Member, Louisiana State Senate (1976-2002). Independent insurance
businessman and farmer, former school teacher and agricultural products salesman. Bachelor’s degree from Northwestern State University.
Lambert C. Bossiere, III (Dem.), since 2005; current term ends December 2016. B.S. Business Administration from Southern University. American
University of Paris – International Trade Law – Paralegal Certificate. Former First City Court Constable for the City of New Orleans. Member of NARUC.
Eric Skrmetta, (Chairman) (Rep.), since 2009; current term ends December 2014. Practicing Attorney since 1985. Practicing Mediator since 1989.
Republican State Central Committee District 81. Juris Doctorate Southern University Law School.
Clyde Holloway, (Vice-Chairman) (Rep.), since 2009; current term ends December 2016. Elected to Congress in 1987 and served in the United States
House of Representatives until 1993. In October 2006 he received an appointment by President Bush as the USDA State Director of Rural Development
where he served until 2009.
SWEPCO-LA provides service at regulated bundled rates in Louisiana. Louisiana has an active fuel pass-through clause and an OSS margin sharing
mechanism. Formula rate plans are permitted in Louisiana including a potential for a partial CWIP return on new generation projects. A formula rate plan was
implemented August 1, 2008 with annual true-ups required. A new FRP was implemented in January 2013.
56
Commission Overview
Public Utility Commission of Texas
Commissioners
Number: 3
Term: 6 Years
To be eligible for appointment, a commissioner must be: a qualified voter and a citizen of the U.S.; a competent and experienced administrator; well informed
and qualified in the field of public utilities and public utility regulation; and, have at least five years of experience in the administration of business or
government or as a practicing attorney or certified public accountant. Chairman appointed by the Governor.
Commissioners
Donna L. Nelson, Chairman (Rep.), since August 2008; current term expires August 2015. Nelson served as a special assistant and advisor to Governor
Perry on energy, telecommunications and cable budget and policy issues. She previously served as director of the PUC telecommunication's section and legal
advisor to the PUC chairman. Nelson holds a law degree from Texas Tech University.
Kenneth W. Anderson Jr., (Rep.) since September 2008; current term expires August 2017. Past Director of Governmental Appointments under Governor
Perry. Prior to that Anderson served in private practice as a corporate attorney in the area of securities law and regulatory matters. He also served as a
member of the Texas Securities Board from 1999-2006. Anderson holds a law degree from Southern Methodist University.
Brandy Marty (Rep.), since 2013; current term expires August 2019. Formerly Governor Perry’s chief of staff. Has also held positions as: governor’s Deputy
Chief of Staff, Director of the Budget, Planning and Policy Division and deputy legislative director/liaison to the Texas House of Representatives. Bachelor’s
degree in government from University of Texas and juris doctorate from St Mary’s University.
Retail competition has been delayed by the PUCT in the SPP area of Texas (including SWEPCO). SWEPCO-TX has an active fuel pass-through clause as
well as OSS margin sharing. In some circumstances, CWIP is allowed in rate base. Texas currently has a mandatory renewable energy standard of 5% by
2015.
57
Debt Schedules
Interest
Amount
Notes Payable
6.370%
10/31/2024
78532* AC7
$25,000,000
Notes Payable
4.580%
02/21/2032
78532* AD5
$60,125,000
4.950%
03/01/2018
785652CJ5
$81,700,000
3.250%
1
01/01/2019
241627AV0
$53,500,000
Senior Notes
5.375%
04/15/2015
845437BE1
$100,000,000
Senior Notes
4.900%
07/01/2015
845437BG6
$150,000,000
Senior Notes
5.550%
01/15/2017
845437BH4
$250,000,000
Senior Notes
5.875%
03/01/2018
845437BJ0
$300,000,000
Senior Notes
6.450%
01/15/2019
845437BK7
$400,000,000
Senior Notes
3.550%
02/15/2022
845437BM3
$275,000,000
Senior Notes
6.200%
03/15/2040
845437BL5
$350,000,000
5.457%
1
$2,045,325,000
Put date 01/02/2015
58
Overview
Wade Smith
Since July 2010
24 years with AEP
AEP Texas Central Company (TCC)
(organized in Texas in 1945) is engaged in the transmission and
distribution of electric power to approximately 799,000 retail
customers through REPs in southern Texas. At December 31, 2012,
TCC had 996 employees. TCC is a member of ERCOT.
MAJOR CUSTOMERS:
Valero Energy Corporation
Javelina Refinery
Equistar
Koch Refinery West
Air Liquide America Ingles
Food Manufacturing
(Based on electric meters)
Residential
681,000
Commercial
111,000
Industrial
5,000
Other
2,000
Total
799,000
Metropolitan areas account for 78% ultimate sales
(data for 12 months ended December 2012)
59
Transmission Miles
Distribution Miles
4,342
29,783
CAPITAL STRUCTURE
2012
Equity
Debt^
3,027,901
82.1%
658,015
17.9%
Total
Debt^
3,685,916 2,941,927
100.0%
80.1%
9/30/2013
Equity
732,531
19.9%
Total
3,674,458
100.0%
Moody's S&P
Baa2/P BBB/S
FFO Total Debt
4.77
23.0%
Fitch
A-/S
4.70^^
21.0%
^^ - calculated on rolling 12-month avg.
^ includes securitization debt of $2,281M and $2,071 at December 31, 2012 and Sept. 30, 2013 respectively
Excludes AFUDC
As of 9/30/13
2012A
2013E
2014E
2015E
2016E
$ 276 $ 386 $ 359 $ 351
$ 311
Total Assets
$
5,699,800
Net Plant Assets $
3,090,864
`
Cash
$
100
60
Overview
Wade Smith
Since July 2010
24 years with AEP
AEP Texas North Company (TNC)
(organized in Texas in 1927) is engaged in the transmission
and distribution of electric power to approximately 187,000
retail customers through REPs in west and central Texas.
TNC’s remaining generating capacity that is not deactivated
has been transferred to an affiliate at TNC’s cost pursuant
to an agreement effective through 2027. At December 31,
2012, TNC had 319 employees. The territory served by
TNC also includes several military installations and
correctional facilities. TNC is a member of ERCOT.
MAJOR CUSTOMERS:
Equilon Haskell
Sheridan Production Co.
Plains All American
Kinder Morgan Energy
TXN
Support Activities for Mining
Pipeline Transportation
Food Manufacturing
Nonmetallic Mineral Products
(Based on electric meters)
Residential
147,000
Commercial
30,000
Industrial
5,000
Other
5,000
Total
Top 10 customers = 70% industrial sales
Owned Generating Capacity
Oklaunion Plant – Vernon, TX
Metropolitan areas account for 55% ultimate sales
61
187,000
• Coal:
Transmission Miles
Distribution Miles
355 MW
100%
4,182
13,868
CAPITAL STRUCTURE
Debt
2012
Equity
420,660
55.6%
336,242
44.4%
Total
Debt
756,902
100.0%
439,493
55.1%
FFO Total Debt
4.82
20.1%
9/30/2013
Equity
358,518
44.9%
Total
798,011
100.0%
Moody's
S&P
Fitch
Baa2/P
BBB/S
A-/S
4.82^
18.9%
Excludes AFUDC
As of 9/30/13
Total Assets
2012A
$
2013E
2014E
2015E
2016E
88 $ 103 $ 114 $ 131
$ 127
$
1,244,836
Net Plant Assets $
1,111,276
`
Cash
$
-
62
Commission Overview
Public Utility Commission of Texas
Commissioners
Number: 3
Term: 6 Years
To be eligible for appointment, a commissioner must be: a qualified voter and a citizen of the U.S.; a competent and experienced administrator; well informed
and qualified in the field of public utilities and public utility regulation; and, have at least five years of experience in the administration of business or
government or as a practicing attorney or certified public accountant. Chairman appointed by the Governor.
Commissioners
Donna L. Nelson, Chairman (Rep.), since August 2008; current term expires August 2015. Nelson served as a special assistant and advisor to Governor
Perry on energy, telecommunications and cable budget and policy issues. She previously served as director of the PUC telecommunication's section and legal
advisor to the PUC chairman. Nelson holds a law degree from Texas Tech University.
Kenneth W. Anderson Jr., (Rep.) since September 2008; current term expires August 2017. Past Director of Governmental Appointments under Governor
Perry. Prior to that Anderson served in private practice as a corporate attorney in the area of securities law and regulatory matters. He also served as a
member of the Texas Securities Board from 1999-2006. Anderson holds a law degree from Southern Methodist University.
Brandy Marty (Rep.), since 2013; current term expires August 2019. Formerly Governor Perry’s chief of staff. Has also held positions as: governor’s Deputy
Chief of Staff, Director of the Budget, Planning and Policy Division and deputy legislative director/liaison to the Texas House of Representatives. Bachelor’s
degree in government from University of Texas and juris doctorate from St Mary’s University.
TCC and TNC provide retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission
service under tariffs approved by the FERC consistent with PUCT rules. Transmission riders provide annual recovery dependent on the level of transmission
investment and ERCOT load growth rates. AFUDC is permitted in limited circumstances.
63
Debt Schedules
AEP Texas North
Interest
4.450%
06/01/2020
Senior Notes
5.890%
Senior Notes
6.760%
Senior Notes
Amount
756864BT0
$44,310,000
04/01/2018
0010EQ A*7
$30,000,000
04/01/2038
0010EQ A@5
$70,000,000
3.090%
02/28/2023
0010EQ A#3
$125,000,000
Senior Notes
4.480%
02/28/2043
0010EQ B*6
$75,000,000
Term Loan
Floating
07/31/2016
N/A
$75,000,000
4.558%
AEP Texas Central
Interest
$419,310,000
Amount
5.625%
10/01/2017
40053QAQ4
4.450%
06/01/2020
756864BT0
$40,890,000
$6,330,000
6.300%
11/01/2029
576528DM2
$100,635,000
5.200%
05/01/2030
576528DE0
$60,000,000
4.400%
05/01/2030
576528CY7
$111,700,000
4.550%
05/01/2030
576528CZ4
$50,000,000
Senior Notes
6.650%
02/15/2033
0010EPAF5
$275,000,000
Term Loan
Floating
07/31/2016
N/A
$75,000,000
5.821%
Securitization Bond
6.250%
6.250%
Securitization Bond
5.090%
07/01/2015
00110AAC8
$208,096,401
Securitization Bond
5.170%
01/01/2018
00110AAD6
$437,000,000
Securitization Bond
5.306%
07/01/2020
00110AAE4
$494,700,000
5.215%
Securitization Bond
0.880%
12/01/2017
00104UAA6
$246,906,438
Securitization Bond
1.976%
06/01/2020
00104UAB4
$180,200,000
Securitization Bond
2.845%
12/01/2024
00104UAC2
$311,900,000
1.977%
$719,555,000
01/15/2016
12617AAE7
$191,856,858
$191,856,858
$1,139,796,401
$739,006,438
64
Generation & Environmental
•
•
•
•
65
Units
Generation and Fuel Statistics
Regulated Coal Procurement and Delivery
Regulated Environmental and Announced Unit Retirements
Generation
Generation Capacity*
Company
AEP Generating Co
Appalachian Power Co
Indiana Michigan Power Co
Kentucky Power Co
Ohio Power Co (To be AEP Generation Resources at 01/01/2014)**
Southwestern Electric Power Co
Texas North Co
OVEC Capacity ***
Domestic IPPs
Long Term Renewable Purchase Power Agreements****
MW Capacity
2,496
7,018
4,518
1,078
11,652
4,436
5,730
355
980
311
2,371
40,945
* Capacity amounts represent the maximum capacity
** After transfer of Amos 3 to APCo and 50% of Mitchell plant to KPCo, 10,005MW w ill transfer to AEP Generation Resources
*** Represents AEP's 43.5% interest in Ohio Valley Electric Corporation (OVEC)
**** Excludes agreements pending regulatory approval
AEP Total System
Coal/Lignite
25,531
Natural Gas/Oil
9,670
Nuclear
2,191
Wind/Hydro/Pumped Storage
3,553
Total Generating Capacity
40,945
#
#
Includes AEP's 43.5% ow nership of OVEC
Vertically Integrated Utilities - PJM
Coal/Lignite #
12,413
71%
Natural Gas/Oil
1,124
6%
Nuclear
2,191
12%
1,857
11%
17,585
100%
#
Includes 43.5% ow nership of OVEC
66
63%
24%
5%
9%
100%
Vertically Integrated Utilities - SPP
Coal/Lignite
4,156
37%
Natural Gas/Oil
6,010
53%
1,160
7%
11,326
100%
AEP Generation Resources^ as of 01/01/2014
Coal
8,962
74%
Natural Gas/Oil
2,536
21%
Wind/Hydro/Solar
536
4%
12,034
100%
^ Includes all PJM, and ERCOT capacity including
Lawrenceburg PPA, Renewable PPAs and plants
slated for retirement.
Generation
Plant Name
AEP Generating Company
Rockport
Lawrenceburg*
67
Units
State
2
6
IN
IN
Buck
Byllesby
Claytor
Leesville
London
Marmet
Niagara
Reusens
Winfield
Smith Mountain
Amos (Units 1&2)
Clinch River^**
Glen Lyn^**
Kanawha River^
Mountaineer
Sporn (Units 1&3)^**
Dresden
Ceredo
3
4
4
2
3
3
2
5
3
5
2
3
2
2
1
2
1
6
Kentucky Power Company
Big Sandy^
2
Fuel Type
Net
Maximum
Capacity
Year Plant
(MW)
Commissioned
Steam - Coal
Natural Gas
1,310
1,186
2,496
1984
2004
VA
VA
VA
VA
WV
WV
VA
VA
WV
VA
WV
VA
VA
WV
WV
WV
OH
WV
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Pumped Storage
Steam - Coal
Steam - Coal
Steam - Coal
Steam - Coal
Steam - Coal
Steam - Coal
Natural Gas
Natural Gas
9
22
76
50
14
14
2
13
15
586
2,033
705
335
400
1,320
300
608
516
7,018
1912
1912
1939
1964
1935
1935
1906
1904
1938
1965
1971
1958
1918
1953
1980
1950
2012
2001
KY
Steam - Coal
1,078
1963
* Capacity and energy entitlements considered part of AEP Generation Resources as of January 1, 2014
** Plants on extended start-up: Clinch River Unit 3, Glen Lyn Units 5&6, Sporn Unit 3
^ To be retired: All units at Glen Lyn, Kanawha River and Sporn, Clinch River Unit 3 (235MW), Big Sandy Unit 2 (800MW)
Generation
Plant Name
Berrien Springs
Buchanan
Constantine
Elkhart
Mottville
Twin Branch
Rockport
Tanners Creek^*
Cook
Units
State
12
10
4
3
4
6
2
4
2
MI
MI
MI
IN
MI
IN
IN
IN
MI
Fuel Type
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Steam - Coal
Steam - Coal
Steam - Nuclear
Ohio Power Company (to AEP Generation Resources effective 01/01/2014)
Racine
2
OH
Hydro
Darby
6
OH
Natural Gas
Waterford
4
OH
Natural Gas
Cardinal
1
OH
Steam - Coal
Gavin
2
OH
Steam - Coal
Muskingum River^*
5
OH
Steam - Coal
Picway^*
1
OH
Steam - Coal
Beckjord (CCD)^**
1
OH
Steam - Coal
Conesville (Unit 4) (CCD)**
1
OH
Steam - Coal
Stuart (CCD)**
4
OH
Steam - Coal
Stuart (CCD)**
4
OH
Oil
Zimmer (CCD)**
1
OH
Steam - Coal
Amos (Unit 3)***
1
WV
Steam - Coal
Conesville (Units 5&6)
2
OH
Steam - Coal
Kammer^
3
WV
Steam - Coal
Mitchell***
2
WV
Steam - Coal
Sporn (Units 2&4)^*
2
WV
Steam - Coal
68
Net
Maximum
Capacity
Year Plant
(MW)
Commissioned
7
4
1
3
2
5
1,310
995
2,191
4,518
1908
1919
1921
1913
1923
1904
1984
1951
1975
48
507
840
595
2,640
1,440
100
53
339
600
3
330
867
800
630
1,560
300
11,652
1982
2001
2003
1967
1974
1953
1926
1969
1957
1971
1970
1991
1973
1957
1958
1971
1950
* Plants on extended start-up: Tanners Creek Units 1&2, MR Unit 4, Picway, Sporn Unit 4
** CCD Plants jointly owned by AEP Ohio, Duke, and DP&L
*** To be transferred to APCo (Amos 3) and KPCo (50% Mitchell)
Generation
Plant Name
Units
Tulsa
2
Riverside (1&2)
2
Riverside (3&4)
2
Riverside
1
Northeastern (1&2)
4
Northeastern
1
Southwestern (1-3)
3
Southwestern (4&5)
2
Southwestern
1
Comanche
3
Comanche
2
Weleetka
3
Weleetka
2
Northeastern (3&4)^
2
Northeastern
1
Oklaunion
1
69
State
Fuel Type
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
OK
TX
Steam
Steam
Steam
Oil
Steam
Oil
Steam
Steam
Oil
Steam
Oil
Steam
Oil
Steam
Oil
Steam
- Natural Gas
- Natural Gas
- Natural Gas
- Natural Gas
- Natural Gas
- Natural Gas
- Natural Gas
- Natural Gas
- Coal
- Coal
Arsenal Hill
Lieberman
Knox Lee
Wilkes
Lone Star
Stall
Mattison
Welsh^
Flint Creek
Turk
Pirkey
Dolet Hills
1
4
4
3
1
1
4
3
1
1
1
1
LA
LA
TX
TX
TX
LA
AR
TX
AR
AR
TX
LA
Steam - Natural
Steam - Natural
Steam - Natural
Steam - Natural
Steam - Natural
Natural Gas
Natural Gas
Steam - Coal
Steam - Coal
Steam - Coal
Steam - Lignite
Steam - Lignite
Texas North Company
Oklaunion
1
TX
Steam - Coal
^
Net
Maximum
Capacity
Year Plant
(MW)
Commissioned
Gas
Gas
Gas
Gas
Gas
Plants to be retired: Northeastern Unit 4 (470MW) and Welsh Unit 2 (528MW)
309
909
157
3
920
3
466
170
2
260
4
196
4
930
1
102
4,436
1923
1974
2008
1976
1961
1961
1952
2008
1962
1973
1962
1975
1963
1979
1980
1986
110
268
475
845
49
543
316
1,584
264
440
580
256
5,730
1960
1947
1950
1964
1954
2010
2007
1977
1978
2012
1985
1986
355
1986
Generation
Operating
Company
Project Name
Domestic Independent Power Projects*
Trent Mesa
AEPEP^
Desert Sky
AEPEP^
70
PSO
PSO
PSO
PSO
PSO
PSO
PSO
I&M
I&M
I&M
I&M
SWEPCO
SWEPCO
SWEPCO
SWEPCO
Contract
Initiated
State
Renewable Type
TX
TX
Wind
Wind
150
161
311
2001
2001
Wind
Wind
Wind
Wind
Wind
Wind
Biomass
Wind
Solar
Wind
Wind
Wind
75
102
75
100
100
100
59
100
10
99
147
151
2005
2008
2008
2009
2009
2009
2009
2009
2010
2013
2005
2005
95
99
99
99
199
200
199
100
50
100
200
80
80
109
201
3,028
2008
2009
2010
2010
***
***
***
2009
2009
2012
****
2009
2012
2013
2012
Southwest Mesa
AEPEP^
TX
South Trent
AEPEP^
TX
Camp Grove
APCo
IL
Beech Ridge
APCo
WV
Fowler Ridge III
APCo
IN
Grand Ridge II and III
APCo
IL
ecoPower**
KPCo
IN
Fowler Ridge II
OPCo
IN
Wyandot Solar
OPCo
OH
Timber Road
OPCo
OH
Weatherford
PSO
OK
Blue Canyon II#
PSO
OK
Sleeping Bear
Blue Canyon V
Minco
Elk City
Balko**
Seling**
Goodwell**
Fowler Ridge I
Fowler Ridge II
Wildcat
Headwaters
Majestic
Majestic II
Flat Ridge II
Canadian Hills
Net
Maximum
Capacity
(MW)
OK
OK
OK
OK
OK
OK
OK
IN
IN
IN
IN
TX
TX
OK
OK
* Owned capacity, energy sold through wholesale energy supply contracts
** Pending Regulatory Approval
# Expires 2015
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
*** Under contract but not yet on-line, expected 2016
**** Under contract but not yet on-line, expected 2015
^ AEP Energy Partners
Generation Statistics
Equivalent
Availability
Factors
2011
2012
AEP East
72.65%
74.89%
73.23%
69.57%
71.08%
70.36%
Equivalent
Forced Outage
Rate (EFOR)
2011
2012
AEP East
13.33%
12.93%
12.77%
14.48%
14.56%
14.20%
Net Capacity
Factors
2011
2012
AEP East
53.96%
49.89%
47.67%
57.46%
49.15%
49.14%
S upe r Critic a l*
64.31%
58.09%
57.83%
S upe r Critic a l*
72.26%
72.66%
70.72%
S upe r Critic a l*
12.40%
11.83%
11.20%
S ub- Critic a l*
36.55%
22.57%
22.31%
S ub- Critic a l*
61.36%
66.38%
69.24%
S ub- Critic a l*
22.27%
25.89%
26.77%
20.98%
39.81%
25.79%
Gas
78.04%
84.40%
79.59%
Gas - See Below
Hydro**
9.80%
9.77%
14.73%
Hydro**
84.74%
82.54%
78.49%
Hydro**
23.20%
7.07%
17.50%
Nuclear
90.44%
92.07%
88.25%
Nuclear
89.84%
91.30%
86.76%
Nuclear
2.50%
1.26%
0.80%
43.85%
41.76%
41.78%
83.54%
80.39%
83.69%
4.65%
7.11%
6.96%
81.40%
74.06%
73.26%
87.51%
83.58%
86.30%
1.47%
3.87%
4.35%
S upe r Critic a l*
87.09%
72.93%
76.85%
S upe r Critic a l*
89.82%
81.24%
86.44%
S upe r Critic a l*
1.87%
3.84%
4.82%
S ub- Critic a l*
79.45%
75.14%
70.32%
S ub- Critic a l*
86.54%
84.57%
83.68%
S ub- Critic a l*
1.31%
3.88%
4.12%
23.24%
23.68%
19.63%
81.36%
78.60%
81.85%
7.41%
9.88%
10.27%
3.31%
Coal
Gas
AEP SPP
Coal***
Gas
AEP Texas
YTD
SEPT 13
Coal
AEP SPP
Coal***
Gas
AEP Texas
YTD
SEPT 13
Coal
AEP SPP
Coal***
Gas
AEP Texas
YTD
SEPT 13
62.92%
60.31%
76.50%
78.05%
87.28%
85.93%
8.63%
2.77%
Coal****
62.92%
60.31%
76.50%
Coal****
78.05%
87.28%
85.93%
Coal****
8.63%
2.77%
3.31%
AEP System
51.57%
48.03%
46.40%
AEP System
75.40%
76.38%
76.07%
AEP System
11.09%
11.30%
11.06%
Equivalent
Forced Outage
Rate (EFOR)
2011
2012
Net Capacity
Factors
2011
2012
East Gas CC
37.17%
62.82%
YTD
SEPT 13
40.20%
Equivalent
Availability
Factors
2011
2012
East Gas CC
74.24%
82.86%
YTD
SEPT 13
75.06%
East Gas CC
6.25%
4.45%
YTD
SEPT 13
6.02%
* Super-critical includes coal units with a net maximum capacity of 500MW or greater;
sub-critical includes coal units with a net maximum capacity less than 420MW.
** Includes all AEP owned Hydro and Pumped Storage generation.
*** CF, EAF, and EFOR do not include Dolet Hills.
**** Oklaunion reported as owned.
71
***** East Gas Units evaluated using Equivalent Forced Outage Factor. Since these
units are run less frequently, this factor gauges their performance based on Period
Hours instead of Service Hours. EFOR uses Service Hours in the denominator, and
EFOF uses Period Hours in the denominator.
Equivalent
Forced Outage
Factor (EFOF)
AEP East Gas*****
2011
6.25%
2012
2.60%
YTD
SEPT 13
2.21%
Generation Statistics
MWh Produced
Operating Company
Appalachian Power
Indiana Michigan Power
Kentucky Power
Ohio Power
Southwestern Electric Power
Texas North Company
AEP System Total Net Generation
2010
2011
10,362,410
22,287,975
28,476,693
6,552,258
61,289,647
14,376,653
22,343,172
2,098,311
12,215,480
25,361,448
29,578,992
6,372,925
56,508,205
14,823,903
24,072,538
1,951,343
16,024,054
23,058,020
30,016,071
2,661,344
49,428,700
13,458,301
23,493,468
1,781,718
12,867,315
23,569,148
29,357,252
5,195,509
55,742,184
14,219,619
23,303,059
1,943,791
167,787,119
170,884,834
159,921,676
166,197,876
Note: Figures represent generation produced from AEP-owned assets only.
72
2012 Three Year Average
Coal and Natural Gas Statistics
Coal/Lignite Consumption in Tons
Operating Company
2010
2011
Appalachian Power
Kentucky Power
Ohio Power
Texas North Company
4,850,666
8,932,179
6,857,261
2,573,985
25,247,488
3,917,577
12,910,825
1,258,369
4,556,325
10,045,636
6,584,936
2,558,936
22,629,431
4,544,540
12,905,370
1,221,615
5,138,504
8,265,026
6,638,832
1,139,610
18,631,018
3,960,205
12,213,046
1,122,390
4,848,498
9,080,947
6,693,676
2,090,844
22,169,312
4,140,774
12,676,414
1,200,791
AEP System Total Consumption
66,548,350
65,046,789
57,108,631
62,901,257
Natural Gas Consumption in MCFs*
Operating Company
Appalachian Power**
Ohio Power
AEP System Total Consumption
2010
2011
11,232,441
572,848
9,417,195
76,915,672
43,271,124
28,799,060
336,583
18,007,337
71,481,426
48,205,761
46,573,386
18,054,300
36,660,130
68,769,285
49,712,383
28,868,296
6,321,244
21,361,554
72,388,794
47,063,089
141,409,280
166,830,167
219,769,484
176,002,977
* MCF: thousand cubic feet
** 2012 increase due to Dresden Plant coming on-line in January 2012
73
AEP System Historical Gas Consumption
AEP System
Annual Natural Gas Consumption
(2008 - 2013*)
MMBtu
$/MMBtu
9
250,000,000
8
200,000,000
7
6
150,000,000
5
4
100,000,000
3
2
50,000,000
1
0
0
2008
* YTD August Actual + Estimate for rest of year
74
2009
2010
2011
2012
2013*
Total
System
MMBtu
Actual
$/MMBtu
Regulated Coal Procurement – 2014 Projected
Total AEP System - Regulated
Lignite
12%
Northern
Appalachian
16%
AEP East - Regulated
Powder
River Basin
39%
Northern
Appalachian
33%
Central
Appalachian
14%
Powder River
Basin
58%
Central
Appalachian
28%
AEP West - Regulated
Coal Stats:
 Expected 2014 coal burn: approx. 40M tons
Lignite
24%
 76% contracted for 2014 and 51% contracted for 2015
 Avg. 2013 YTD regulated system delivered price ~ $48/ton*
• East ~ $59/ton* West ~ $37/ton*
 Projected regulated system price in 2014 ~ $45/ton*
• East ~ $54/ton*, West ~ $37/ton
*excludes Ohio units moving to AEP Generation Resources- competitive
75
Powder River
Basin
76%
Coal Delivery
Total AEP System
Truck
Combo
Truck
4%
7%
2012 Actual
Belt 10%
Rail/
Barge*
16%
Railcar Direct
37%
`
Barge Direct
26%
AEP East
Truck
Combo
Belt 3%
6%
Truck
11%
Rail/
Barge*
24%
AEP West
Railcar Direct
18%
Belt 26%
Barge Direct
38%
* Reflects coal delivered to AEP plants transported through a combination of rail and barge
76
Railcar Direct
74%
Jurisdictional Fuel Clause Summary
Jurisdiction
Active Fuel Clause
Frequency
Arkansas
Yes
Annually
Indiana
Yes
Semi-Annually
Kentucky
Yes
Monthly
Louisiana
Yes
Monthly
Michigan
Yes
Annually
Ohio
Yes*
Quarterly
Oklahoma
Yes
Annually
Tennessee
Yes
Monthly
Texas (SPP)
Yes
Tri-Annually
Virginia
Yes
Annually
West Virginia
Yes
Annually
* Through the end of the Electric Security Plan period, May 31, 2015
77
EPA Regulatory Deadlines
Rule Vacated
Aug 21, 2012
CSAPR* (SO2 & NOx)
Final Rule Published
Feb 16, 2012
Rule Vacated pending Supreme Court Appeal
Clean Air Interstate Rule (CAIR) in effect in the meantime
Potential for One Year
Compliance Extension
MATS (mercury & air toxics)
Proposed Rule
Sept 20, 2013
Proposed and/or
Finalized Rules
New Source CO2 NSPS**
Compliance Required from Rule Proposal Date
Coal Combustion Residuals
Assumed Final Rule
2014
Compliance Timeline Contingent
on Permit Renewal Cycle
Effluent Limit Guidelines (water discharge limits)
Assumed Final Rule
May 2014
Compliance
Timeline Will Vary
Assumed Final Rule
November 2013
316(b) Rule (water intake structures)
Compliance Timeline Contingent
on State Implementation Plans
Anticipated
Rules
Anticipated Proposed Rule
June 2014
2012
2013
Existing Source CO2 NSPS**
2014 2015
2016
2017
2018
2019
Time From Rule Finalization to Compliance
78
* Cross-State Air Pollution Rule
** New Source Performance Standard
2020
2021 2022
Emission Limits
In compliance with our 2007 NSR settlement, as amended in 2013
the following limits are applicable to AEP’s eastern generation fleet:
79
Emissions caps do not include any of the gas-fired units, or any new units AEP might build or purchase in the east.
Capacity Mix Shift & Emissions Reductions
AEP Coal and Natural Gas
Capacity
 Existing regulations and market
conditions drive a 64% increase in
gas capacity and a 27% decrease
in coal capacity by 2016
80
AEP Emissions
Reductions
 AEP fleet expected to meet
President’s 17% reduction target
for CO2 five years sooner and
without additional regulation
Regulated Environmental Retrofit Status
Plant Name
MW
Capacity
SCR
Projected
In-Service
FGD
Projected
In-Service
ACI
Projected
In-Service
DSI
Projected
In-Service
Baghouse
Projected
In-Service
Gas
Conversion
Projected
In-Service
APCo
Amos 1
800


Amos 2
800


Amos 3
433


Clinch River 1*
235
x
2015
Clinch River 2*
235
x
2016
x
2015
Mountaineer
1,320


KPCo
Big Sandy 1*
278
Big Sandy 2**
800

Rockport 1*
1,310
x
2017
x
2015
Rockport 2*
1,310
x
2019
x
2014
x
2016
I&M
PSO
Oklaunion
102
Northeastern 3
460

x
2015
x
2016
x
2015
x
2016
x
2015
x
2016
x
2015
SWEPCO
Dolet Hills
256

Flint Creek 1
264
x
Pirkey
580

Welsh 1
528
x
2016
x
2016
Welsh 3
528
x
2015
x
2015
81
2016
* Pending regulatory approval
 In-service
** To be retired
x Projected
Regulated Environmental Investment & Retirements
Operating
Company
Plant
APCO Clinch River 1(1,2)
Clinch River 2(1,2)
I&M Rockport(3)
Potential Type of
MW
retrofit
242 Refuel with Natural Gas
2,620
KPCO Big Sandy 1(4)
PSO Oklaunion
Northeastern 3
SWEPCO Welsh 1
Welsh 3
Pirkey
Dolet Hills
Flint Creek
Operating
Company
APCO
DSI, SCR
102
460
ACI
ACI, DSI, Baghouse
528
528
580
256
264
ACI, Baghouse
ACI, Baghouse
ACI
ACI, Baghouse
FGD, ACI
Existing Coal Plant 235MW
(2)
Case on file, subject to regulatory and other approvals
(3)
Pending approval of settlement on file with IURC
Pending filing for CCN at KPSC
(4)
ACI – Activated Carbon Injection
DSI – Dry Sorbent Injection
FGD – Flue Gas Desulfurization
82
SCR – Selective Catalytic Reduction
Expected
MW
Retirement
95
2015
240
2015
235
2015
150
2015
150
2015
200
2015
200
2015
1,270
I&M
Tanners Creek 1 - 4
Total MW
995
995
2015
KPCo
Big Sandy 2
Total MW
800
800
2015
SWEPCO
Welsh 2
Total MW
528
528
2016
PSO
Northeastern 4
Total MW
470
470
2016
Total Regulated retrofits = 6,100
(1)
Plant
Glen Lyn 5
Glen Lyn 6
Clinch River 3
Sporn 1
Sporn 3
Kanawha River 1
Kanawha River 2
Total MW
Total Regulated Retirements =
4,063
Competitive Operations
•
•
•
•
•
•
•
•
83
Structure
Fleet Footprint
Fleet Characteristics
2012 Fleet Statistics
Coal Procurement
Environmental
River Operations
AEP Retail
Competitive Operations Ownership Structure
AEP
AEP Energy Supply
AEP Generation Resources
Generation
Wind Farms
AEP Resources
CSW Energy
AEP Energy
Retail
AEP Energy Partners
Wholesale, Trading and Marketing
84
AEP River
Operations
AEP Generation Resources Footprint
Fleet Characteristics 01/01/2014
(excludes retiring plants)
(In MWs)
Wholly-owned, AEP operated, 72% of fleet
PJM: 8,668MW
Gavin
Cardinal 1
Mitchell 1,2*
Conesville 5, 6
Waterford
Darby
Racine
2,640
595
780
800
840
507
48
PJM
PJM
PJM
PJM
PJM
PJM
PJM
Coal, controlled
Coal, controlled
Coal, controlled
Coal, FGD only
Gas, CC
Gas, CT
Hydro
Joint Venture, AEP operated, 4% of fleet
Conesville 4
339
PJM
Coal, controlled
Joint Venture, operated by others, 11% of fleet
Zimmer
Stuart
330
603
PJM
PJM
Coal, controlled
Coal, controlled
Capacity / energy entitlements, 13% of fleet
Lawrenceburg
Total
1,186
PJM
Gas, CC
8,668
* Represents 50% ownership of Units 1&2; operated by Kentucky Power
The portfolio also includes non-PJM assets including the Oklaunion Coal
Plant (355 MW), Texas Wind Farms (310 MW) and Renewable PPAs (177
MW)
85
Competitive Fleet Characteristics
Plant/Unit
Capacity
Fuel Type
Coal Type
Fuel Delivery
FGD?
SCR?
Gavin 1, 2
Cardinal 1
Conesville 4*
Conesville 5, 6
Mitchell 1, 2**
Zimmer***
Stuart 1-4***
Oklaunion****
Lawrenceburg
Waterford
Darby
Racine
Trent Mesa/Desert Sky
Renewable PPAs
2,640
595
339
800
780
330
603
355
1,186
840
507
48
311
177
9,511
coal
coal
coal
coal
coal
coal
coal
coal
gas
gas
gas
hydro
wind
wind
NAPP
NAPP
NAPP
NAPP
NAPP 60%/CAPP 40%
NAPP
CAPP 40%/ILB 60%
PRB
n/a
n/a
n/a
n/a
n/a
n/a
barge
barge & truck
rail & truck
rail & truck
rail, barge, belt
barge
barge
rail
TX Gas Transmission (Zone 4)
TX Eastern Transmission (Zone M2)
Columbia Gas Transmission/Dominion Transmission
n/a
n/a
n/a
Y-lime
Y-limestone
Y-limestone
Y-lime
Y-limestone
Y-limestone
Y-limestone
Y
n/a
n/a
n/a
n/a
n/a
n/a
Y
Y
Y
N
Y
Y
Y
N
n/a
n/a
n/a
n/a
n/a
n/a
840
600
100
300
630
53
2,523
coal
coal
coal
coal
coal
coal
NAPP
CAPP
NAPP
CAPP
PRB 40%/NAPP 60%
ILB
rail & truck
rail & truck
truck
barge
barge
barge
N
N
N
N
N
N
N
Y
N
N
N
N
Plants slated for retirement
Muskingum River 1-4
Muskingum River 5
Picway 5
Sporn 2-4
Kammer 1-3
Beckjord
* Jointly owned unit operated by AEP
** Represents 50% ownership of Units 1&2; operated by Kentucky Power
*** Jointly owned unit operated by a third-party utility
**** Jointly owned unit operated by PSO
86
Competitive 2012 Fleet Statistics
Plant/Unit
Capacity
Gavin 1, 2
Cardinal 1
Conesville 4*
Conesville 5, 6
Mitchell 1, 2**
Zimmer***
Stuart 1-4***
Okalunion****
Lawrenceburg
Waterford
Darby
Racine
Plants slated for retirement
Muskingum River 1-5
Picway 5
Sporn 2-4
Kammer 1-3
Beckjord
Fuel Type
2012
FOB Plant
(per ton)
2012
MWh
Produced
2012
Capacity
Factor
2,640
595
339
800
780
330
603
355
1,186
840
507
48
9,023
coal
coal
coal
coal
coal
coal
coal
coal
gas
gas
gas
hydro
$
$
$
$
$
$
$
$
55.11
47.03
78.96
57.76
70.25
57.45
59.60
33.30
n/a
n/a
n/a
n/a
2.31
1.89
3.28
2.50
2.83
2.48
2.57
1.99
3.02
2.89
3.68
n/a
17,220,105
2,969,568
999,774
3,307,999
3,772,169
1,142,482
2,935,173
1,781,718
6,634,276
5,027,420
77,009
138,403
74.29%
54.39%
36.21%
42.06%
55.12%
41.87%
56.75%
54.27%
63.59%
68.14%
1.73%
33.17%
1,440
100
300
630
53
2,523
coal
coal
coal
coal
coal
$
$
$
$
$
84.14
76.92
73.08
69.51
56.23
3.42
3.47
3.07
3.08
2.31
1,789,615
3,957
585,060
1,784,836
226,966
14.15%
0.45%
22.20%
32.25%
51.35%
* Jointly owned unit operated by AEP
** Represents 50% ownership of Units 1&2; operated by Kentucky Power
*** Jointly owned unit operated by a third-party utility
**** Jointly owned unit operated by PSO
87
2012
$/MMBtu
Competitive Coal Procurement – 2014 Projected
Illinois Basin
12%
Powder River Basin
2%
Central Appalachian
12%
Northern Appalachian
74%
Coal Stats:
 Expected 2014 coal burn: approx. 16M tons
 95% contracted for 2014 and 91% contracted for 2015
 YTD 09/30/2013 delivered price ~$59/ton*
 Projected price in 2014 ~ $58/ton*
88
*reflects only Ohio units operated by AEP moving to AEP Generation Resources - competitive
Competitive Environmental Investment & Retirements
Operating Company
Plant
MW
(1)
AEP Generation Resources Conesville 5 & 6
800
TNC Oklaunion
355
Potential Type of
retrofit
Mercury Solution
ACI
Total Competitive Retrofits = 1,155
(1)
Assumes investment is able to clear the market
Operating Company
Plant
AEP Generation Resources Muskingum River 1-5
Picway 5
Sporn 2-4
Kammer 1-3
Beckjord
Total Competitive Retirements =
89
Expected
MW
Retirement
1,440
2015
100
2015
300
2015
630
2015
53
2015
2,523
Competitive Environmental Retrofit Status
Plant Name
MW
Capacity
SCR
FGD
ACI
Projected
In-Service
Mercury
Solution
Projected
In-Service
AEP Generation Resources
Cardinal 1
595


Conesville 4
339


Conesville 5
400

x
2016
Conesville 6
400

x
2016
2,640


Mitchell 1&2*
780


Muskingum River 5**
600

Stuart 1-4
600


Zimmer
330


Gavin 1&2
TNC
Oklaunion
355

x
* Represents 50% ownership of Units 1&2; operated by Kentucky Power
** To be retired
 In-service
x Projected
90
2015
AEP River Operations
 Full-service Inland Waterways carrier
 3,100 hopper barges
 60 towboats and 25 fleet & shuttle boats
 Tonnage & Commodity (2012):
 Captive: (for AEP) 32MM tons of coal/
consumables
 Commercial: 42MM tons of
coal/grain/bulk
 Gulf Operations
 Barge cleaning and repair
 Fleeting and shifting
 Midstream transfers
 Operating Centers in Lakin, WV, Paducah,
KY, Convent and Belle Chase, LA and
Mobile, AL
91
Inland Waterway Routes For AEP River Operations
AEP Energy
Customer Accounts*
Geography of customers*
YTD Sept 2013 Delivered Load
 200,000 retail customer accounts
 YTD served 7.4 TWh of load*
 Seven states, focus on Ohio
 Profitable in first year and through the third
quarter of 2013
92
* As of September 30, 2013
Transmission Initiatives
•
•
•
•
93
Structure
Transcos
Joint Ventures
Competitive Transmission
AEP Transmission Ownership Structure
American Electric
Power Company, Inc.
100%
AEP
Transmission
Company, LLC
(“AEP
Transco”)
AEP Appalachian
Transmission
Company, Inc.
AEP Transmission
Holding Company, LLC
(“AEP Trans Holdco”
or “AEPTHC”)
50%
100%
50%
Pioneer
Transmission,
LLC
AEP Kentucky
Transmission
Holding
Company, Inc.
Electric
Transmission
America, LLC
$20 Equity Investment in PWT
($ in millions)
$221 Net Plant* ($ in millions)
AEP Indiana
Michigan
Transmission
Company, Inc.
AEP Ohio
Transmission
Company, Inc.
AEP Oklahoma
Transmission
Company, Inc.
AEP
Southwestern
Transmission
Company, Inc.
AEP
West Virginia
Transmission
Company, Inc.
Currently Operating
Not Currently Operating
* As of 09/30/2013
94
86.5%
Transource
Energy, LLC
50%
Electric
Transmission
Texas, LLC
$2,153* Net Plant
($ in millions)
AEPTHC Growth Plan Project Summary
Regional Projects
 Generation Retirements
 Over 13 GW of generation retiring in PJM; could reach
18 GW by 2015.
 Many of the retirements are in AEP and FirstEnergy
territories.
 Significant changes in regional power flows, resulting
in reliability issues.
 Major issues identified and projects underway, but
additional retirements are possible.
 Integration of Renewables
 Renewable Portfolio Standards (RPS) and tax credits
continue to promote renewable energy development.
 Renewable resources – primarily wind and to an
extent solar – are typically located far from load
centers, requiring transmission build-out to reliably
connect and delivery these resources.
 Opportunities continue to evolve in PJM, SPP, and
MISO.
 Economic & Market Efficiency driven projects
 FERC Order 1000 increasing focus on projects that
reduce congestion and promote market efficiency.
 Economic-driven projects subject of recent PJM
competitive window and on-going PJM-MISO joint
operating agreement study.
Aging Infrastructure
 65% of AEP’s transmission lines were built 40+ years ago.
 Target assets > 45 years old, ~$400m of transmission assets,
each successive year adding ~$75-$100m
 Potential to invest $9-$11 billion, growing at $1 billion per year
95
Local Reliability Plans
 Local transmission facilities (< 138 kV) account for the majority of AEP
Transmission facilities.
 Local facilities tend to be older and more susceptible to trees, storms,
and other threats to reliability and have a direct impact on customers.
 Recent storms such as the Derecho and Superstorm Sandy have raised
awareness of the vulnerability of these facilities, and the need to
strengthen local transmission facilities against future events.
 AEP recently undertook studies to (1) identify areas where poorperforming transmission facilities are causing customer outages, and (2)
identify areas where new transmission projects could solve
distribution/customer reliability issues.
 These studies identified significant (~$2B) of opportunity to enhance
local transmission reliability.
Customer Driven Projects
 Customer interconnection requests dominated by shale gas activity.
 AEP transmission system encompasses large portions of major shale
plays.
 Marcellus, Utica, Huron (East)
 Barnett, Eagle Ford, Woodford, Fayetteville (West)
 Midstream processing facilities require transmission service (10-100 MW),
and rural locations may require significant, long-term transmission buildout.
 Pumping loads (<5 MW) also adding to localized load growth in
some areas.
 AEP using innovative technology, including skid stations, to provide quick
service in as little as 6 weeks.
AEP Transco Has a Large, Diverse Footprint
The State Transcos exist within the expansive service territories of AEP’s distribution
companies, operating across two RTOs and 10 states
ISO RTO Regions
PJM
SPP
AEP State Transcos
AEP Appalachian Transmission Company, Inc.
AEP Kentucky Transmission Company, Inc.
AEP Indiana Michigan Transmission Company, Inc.
AEP Ohio Transmission Company, Inc.
AEP Oklahoma Transmission Company, Inc.
AEP Southwestern Transmission Company, Inc.
AEP West Virginia Transmission Company, Inc.
Non-Transco Operating Companies
AEP Texas
96
State Transco Regulatory Compacts

AEP Transco and its seven State Transco subsidiaries were formed in 2009 to focus on upgrades to
AEP’s transmission system and thereby provide flexibility to AEP’s integrated utility Operating
Companies to direct their capital resources to the distribution businesses and generation fleets

A summary of regulatory approval status is provided in the table below:
State
Transco
State Operational and Project Approval Status
OH Transco
No state regulatory agency approval was required to operate transmission assets in the state of Ohio. However, in Case No. 10-245EL-UNC, OH Transco did receive approval from the PUCO to transfer certain assets under construction from Ohio Power Company
and Columbus Southern Power Company to OH Transco. OH Transco is fully operational with assets in-service.
IM Transco
Indiana Utility Regulatory Commission approval received November 2011; no Michigan approval required. IM Transco is fully
operational with assets in-service.
OK Transco
No state regulatory approval required for utility status. OK Transco is fully operational with assets in-service.
WV Transco
Based on a previous ruling by the West Virginia Public Service Commission (“WVPSC”), WV Transco is required to obtain a Certificate
of Public Convenience and Necessity (“CPCN”) to build any project that costs more than $500K. In 2013, WV Transco filed various
CPCN applications for approval from the WVPSC. On September 25, 2013, the WVPSC granted a CPCN for WV Transco to build one
of these projects, the Kanawha River Transformer Installation Project (~$19M). Construction will begin immediately. The other CPCN
applications are pending.
AP Transco
In Feb. 2012, the Virginia State Corporation Commission (“VSCC”) approved a service agreement between AP Transco and APCo
limited to studying and evaluating potential transmission projects and for preparation of applications for future submission of project
certificate applications to the VSCC. In May 2013, AP Transco and APCo filed a joint application with the Virginia SCC for the
approval of the Cloverdale Extra High Voltage Transmission Improvements Project. AP Transco’s portion of the project is
approximately $222 million. The CPCN application is pending.
KY Transco
In Feb 2011, KY Transco filed an application with the Kentucky Public Service Commission (“KPSC”) in Case No. 2011-00042 to seek
a CPCN to operate as a transmission-only public utility in Kentucky. In June 2013, the KPSC issued an order stating the KPSC
lacked authority to grant the requested CPCN since KY Transco would not be providing a regulated service under KPSC jurisdiction
and, on that basis, denied KY Transco’s application for a CPCN. As a result of the KPSC order, KY Transco will develop transmission
projects in Kentucky subject to certificate authority by the Kentucky State Board on Electric Generation and Transmission Siting, but
not subject to the regulatory authority of the KPSC. KY Transco has identified 7 projects that do not require siting approval and one
additional project that does require siting approval (filing expected late 2013).
SW Transco
Filed for approval in AR and LA in May 2011 and August 2011, respectively; decisions anticipated in 2014.
97
State Transco Rates are Regulated by FERC
Conservative FERC regulation results in timely recovery of costs

In April 2011, the FERC approved a formula rate mechanism for the State Transcos
 The FERC order dictates how the State Transcos determine their rates, including the recovery of all
authorized expenses and the return on and of invested plant

The approved formula rate mechanism established an annual revenue requirement for
transmission services over the facilities of the State Transcos under the PJM and SPP
OATTs, as applicable, and implemented a transmission cost of service formula rate
 Annual rate settings provide a highly predictable and stable source of revenues and income
98

Each State Transco’s annual transmission revenue requirement (“ATRR”) is reset in July
based on the prior year’s financial activity plus the current year’s projected plant balances,
thus establishing rates for the one-year forward period of July to June (“Rate Year”)

The revenue requirements are derived from the following capital structure limitations and
authorized ROEs:
Company
RTO
Capital Structure % Equity
Cap
Authorized ROE*
Rate Base
AP Transco
PJM
50%
11.49%
-
IM Transco
PJM
50%
11.49%
$136M
KY Transco
PJM
50%
11.49%
$19K
OH Transco
PJM
50%
11.49%
$416M
WV Transco
PJM
50%
11.49%
$129K
OK Transco
SPP
50%
11.20%
$224M
SW Transco
SPP
50%
11.20%
-
(as of 07/01/2013)
* Includes 50bps adder for RTO participation
Project Selection Guidelines
 State Transcos will develop new projects that are attached to AEP’s existing
system
 A Project Selection Guideline (“PSG”) is used to determine which facilities are
developed by the State Transco and which are developed by an AEP Operating
Company
 All projects developed by AEP go through an internal process that requires
approval by AEP management and ensures compliance with all proper strategic
and financial controls
 Projects developed as part of an RTO-driven process are subject to approval by
the RTO Board of Directors, and certain high-voltage projects must meet state
siting requirements
 The following projects are eligible for development by a State Transco:
Type of Project
Greenfield
Facility Additions
Facility
Replacements
Component
Replacements
Spare/Mobile
Equipment
99
Definition
New transmission assets that do not require replacement or
modification of existing facilities or components
New transmission components installed at existing AEP Operating
Company-owned transmission or distribution facilities
Replacement of an entire existing AEP Operating Company-owned
facility with a new AEP Transco-owned facility
An apportioned replacement of an existing AEP Operating
Company-owned transmission facility or replacement of
component(s) within a transmission facility
Purchases of major transmission equipment as capitalized spares or
mobiles used to supply any Transco companies
Active Joint Venture Projects
Location
Projected
Completion
Date
Texas (ERCOT)
Prairie Wind
Pioneer
Project
Name
ETT
Transource
Owners (ownership %)
Base
RTO
Project
Risk
Total
2017
MEHC Texas Transco, LLC (50%), AEP (50%)
$3.1 billion
9.96%
0.00%
0.00%
9.96%
Kansas
2014
Westar Energy (50%), ETA (50%)
$180 million
10.80% 0.50%
1.50%
12.80%
Indiana
2018
Duke Energy (50%), AEP (50%)
$330 million
10.54% 0.50%
1.50%
12.54%
Missouri
2017
AEP (86.5%), Great Plains Energy(13.5%)
$434 million
9.80%
* Only approved for Sibley-Nebraksa City line
Transource - Weighted average of 11.15% based on projected cost of each project.
Non active joint ventures and prospects excluded from the financial forecasts
100
Approved Return on Equity
Total Estimated
Project costs at
completion
0.50% 1.00%* 10.3 - 11.3%
Competitive Transmission
 Transource Energy, a joint venture with Great Plains Energy (GPE), is the exclusive vehicle through which AEP will
pursue new competitive transmission projects
 Transource is owned 86.5% by AEP and 13.5% by GPE
 Transource expects to begin active operations as a transmission owner in SPP in early 2014
 SPP approval received to transfer two projects in Missouri from GPE to Transource, totaling approximately
$445 million in investment
 The Sibley to Nebraska City project is estimated to cost $380M with an in-service date of 2017
 The Iatan to Nashua project is estimated to cost $65 million with an in-service date of 2015
 The Missouri Public Service Commission has approved the transfer of the projects to Transource
 FERC has approved the establishment of a base formula rate and incentives for the projects that will go into
effect starting in 2014, including:
 11.15% weighted average ROE approved for the projects and up to 55% equity in the permanent
capital structure
 Incentives include: 100% CWIP in rate base, cost recovery in the event of abandonment, and
hypothetical capital structure of 60% during construction
 Expect projects to transfer in early 2014
 Transource has submitted multiple proposals to PJM for its ongoing competitive opportunities and to PJM/MISO for
the competitive interregional process
 Submitted four proposals into the PJM “Artificial Island” competitive process
 Submitted two proposals into the PJM 2013 Market Efficiency competitive process
 Submitted twelve proposals into the PJM-MISO joint study competitive process
101
Financial Update
•
•
•
•
•
102
Capitalization and Liquidity Position
AEP Banking Group
Credit Ratings
Long-Term Debt Maturity Profile
Debt Schedules
Capitalization & Liquidity
Total Debt / Total Capitalization
Credit Statistics
FFO To Total Debt
Actual
4.6
19.7%
Target
>3.6x
15%- 20%
Note: Credit statistics represent the trailing 12 months as of 09/30/2013
Liquidity Summary (09/30/2013)
Liquidity Summary
(unaudited)
($ in millions)
Revolving Credit Facility
Revolving Credit Facility
Term Credit Facility
Total Credit Facilities
Actual
Amount
$
1,750
1,750
1,000
4,500
Plus
Cash & Cash Equivalents
147
Less
Commercial Paper Outstanding
Amount drawn on bank loans
Letters of credit issued
Net available Liquidity
103
(518)
(600)
(185)
$
3,344
Maturity
Jul-17
Jun-16
May-15
AEP Banking Group
$3.5B Core Credit Facilities
Lender Composition
Bank of Tokyo-Mitsubishi Japanese Bank
Lender mix gives AEP
geopolitical
diversification
S&P Rating
LT (ST)
%Share
Aa3 (P-1)
A+ (A-1)
5.0%
Barclays Bank
British Bank
A2 (P-1)
A (A-1)
5.0%
Citibank
Major US Bank
A3 (P-2)
A (A-1)
5.0%
Credit Suisse
Investment Bank
A1 (P-1)
A (A-1)
5.0%
JP Morgan
Major US Bank
Aa3 (P-1)
A+ (A-1)
5.0%
Key Bank
US Regional Bank
A3 (P-2)
A- (A-2)
5.0%
Royal Bank of Scotland
British Bank
Baa1 (P-2)
A- (A-2)
5.0%
Wells Fargo
Major US Bank
Aa3 (P-1)
AA- (A-1+)
5.0%
Bank of America
Major US Bank
Baa2 (P-2)
A- (A-2)
3.9%
Bank of New York
US Regional Bank
Aa3 (P-1)
A+ (A-1)
3.9%
BNP Paribas
European Bank
A2 (P-1)
A+ (A-1)
3.9%
Credit Agricole
European Bank
A2 (P-1)
A (A-1)
3.9%
Goldman Sachs
Investment Bank
A2 (P-1)
A (A-1)
3.9%
Mizuho
Japanese Bank
A1 (P-1)
A+ (A-1)
3.9%
Morgan Stanley
Investment Bank
Baa1 (P-2)
A- (A-2)
3.9%
Royal Bank of Canada
Canadian Bank
Aa3 (P-1)
AA- (A-1+)
3.9%
Scotia Capital
Canadian Bank
Aa2 (P-1)
A+ (A-1)
3.9%
SunTrust Bank
US Regional Bank
Baa1 (P-2)
BBB (A-2)
3.9%
UBS
Investment Bank
A2 (P-1)
A (A-1)
3.9%
US Bank
US Regional Bank
A1 (P-1)
A+ (A-1)
3.9%
BBVA
European Bank
Baa2 (P-2)
BBB- (A-3)
2.6%
Fifth-Third Bank
US Regional Bank
Baa1 (NR)
BBB+ (A-2)
2.6%
PNC Financial
US Regional Bank
A3 (NR)
A- (A-2)
2.6%
Sumitomo Bank
Japanese Bank
Aa3 (P-1)
A+ (A-1)
2.6%
Huntington National Bank US Regional Bank
A3 (P-2)
BBB+ (NR)
1.4%
The Northern Trust Co.
A1 (P-1)
A+ (A-1)
1.4%
Total
104
Moodys
Rating
LT (ST)
US Regional Bank
100.0%
AEP Credit Ratings
Current Ratings for AEP, Inc. & Subsidiaries
Company
American Electric Power Company Inc.
S&P
Senior
Unsecured Outlook
Fitch
Senior
Unsecured Outlook
Baa2
S
BBB-
S
BBB
N
AEP, Inc. Short Term Rating
P2
S
A2
S
F2
S
AEP Texas Central Company
Baa2
P
BBB
S
A-
S
AEP Texas North Company
Baa2
P
BBB
S
A-
S
Baa2
S
BBB
S
BBB
S
Baa2
S
BBB
S
BBB
S
Kentucky Power Company
Baa2
S
BBB
S
BBB
N
Ohio Power Company
Baa1
S
BBB
S
A-
N
Baa1
S
BBB
S
BBB+
S
Baa3
P
BBB
S
BBB
S
Ratings current as of September 30, 2013
105
Moody's
Senior
Unsecured Outlook
Long-term Debt Maturity Profile
Year
2013
2014
AEP, Inc.
Appalachian Power
Kentucky Power
Ohio Power*
Public Service of Oklahoma
Texas Central Company**
Texas North Company
Total
$8
$8
$45
$204
$288
$569
$34
$1,140
($ in millions)
2015
$625
$322
$686
$304
$208
$2,145
2016
2017
2018
$65
$198
$350
$150
$267
$75
$1,105
$550
$250
$325
$165
$250
$288
$1,828
$350
$382
$437
$30
$1,199
* Includes $165 million of amortizing Ohio Securitization Bonds based upon scheduled final payment date
** Includes $1,084 million of amortizing Texas Securitization Bonds based upon scheduled final payment date
Includes mandatory tenders (put bonds)
Data as of September 30, 2013
106
Debt Schedules
American Electric Power, Inc
Interest
Amount
Senior Notes
1.650%
12/15/2017
025537 AF8
$550,000,000
Senior Notes
2.950%
12/15/2022
025537 AG6
$300,000,000
2.11%
AEP Generating
Interest
$850,000,000
Amount
Floating
07/01/20251
773835BG7
$22,500,000
Floating
07/01/20251
773835BH5
$22,500,000
Senior Notes
6.330%
09/30/2037
00113AA2
$174,545,520
6.330%
1
$219,545,520
Put date 7/15/2014
AEP Transmission
Interest
Amount
Senior Notes
3.300%
10/18/2022
00114* AA1
$104,000,000
Senior Notes
4.000%
10/18/2032
00114* AB9
$85,000,000
Senior Notes
4.730%
10/18/2042
00114* AC7
$61,000,000
Senior Notes
4.780%
12/14/2042
00114* AD5
$75,000,000
Senior Notes
4.830%
03/18/2043
00114* AE3
$25,000,000
4.146%
$350,000,000
107
Debt Schedules
108
Interest
Amount
3.250%
05/01/2019
95648NAB3
$30,000,000
3.250%
05/01/2019
95648NAC1
$40,000,000
4.625%
11/01/2021
782470AR9
$17,500,000
2.000%
10/1/20221
575200BA7
$100,000,000
Floating
2/1/20362
95648VAL3
$50,275,000
Floating
2
2/1/2036
95648VAK5
$75,000,000
5.375%
12/01/2038
95648VAS8
$50,000,000
2.250%
1/1/20413
95648VAT6
$65,350,000
Floating
12/1/20424
95648VAP4
$54,375,000
Floating
12/1/20424
95648VAQ2
$50,000,000
Senior Notes
4.950%
02/01/2015
037735CB1
$200,000,000
Senior Notes
3.400%
05/24/2015
037735CQ8
$300,000,000
Senior Notes
5.000%
06/01/2017
037735CD7
$250,000,000
Senior Notes
7.950%
01/15/2020
037735CP0
$350,000,000
Senior Notes
4.600%
03/30/2021
037735CR6
$350,000,000
Senior Notes
5.950%
05/15/2033
037735BZ9
$200,000,000
Senior Notes
5.800%
10/01/2035
037735CE5
$250,000,000
Senior Notes
6.375%
04/01/2036
037735CG0
$250,000,000
Senior Notes
6.700%
08/15/2037
037735CK1
$250,000,000
Senior Notes
7.000%
04/01/2038
037735CM7
$500,000,000
5.62%
1
Put date 10/01/2014
2
Put date 03/17/2015
3
Put date 09/01/2016
4
Put date 03/24/2014
$3,432,500,000
Debt Schedules
109
Interest
Amount
Floating
10/01/20196
520453AL5
$25,000,000
Floating
11/01/20217
520453AK7
$52,000,000
4.625%
06/01/2025
773835AV5
$50,000,000
6.250%
06/01/20258
773835BF9
$50,000,000
6.250%
8
06/01/2025
773835BE2
$50,000,000
Nuclear Fuel Lease
5.440%
10/01/2013
N/A
$7,865,587
Nuclear Fuel Lease
4.000%
10/13/2014
N/A
$13,298,845
Nuclear Fuel Lease
Floating
06/07/2015
N/A
$14,279,766
Nuclear Fuel Lease
2.120%
05/01/2016
N/A
$18,113,241
Nuclear Fuel Lease
Floating
05/01/2016
N/A
$26,153,507
Nuclear Fuel Lease
Floating
10/27/2016
N/A
$60,116,617
Nuclear Fuel Lease
Floating
10/27/2016
N/A
$93,149,930
Term Loan
Floating
05/15/2015
45488QAA6
$105,913,672
Senior Notes
5.050%
11/15/2014
454889AK2
$175,000,000
Senior Notes
5.650%
12/01/2015
454889AL0
$125,000,000
Senior Notes
7.000%
03/15/2019
454889AN6
$475,000,000
Senior Notes
6.050%
03/15/2037
454889AM8
$400,000,000
Senior Notes
3.200%
03/15/2023
454889 AP1
$250,000,000
5.653%
6
7
8
$1,990,891,165
Debt Schedules
Ohio Power Company
Amount
Floating
07/01/2014
572287AT7
$50,000,000
Floating
05/1/20269
677525MQ7
$50,000,000
2.875%
12/01/202710
677525TX5
$39,130,000
Floating
06/1/203711
95648VAD1
$65,000,000
12
3.875%
677525TL1
$60,000,000
5.800%
12/01/2038
677525TM9
$32,245,000
3.250%
06/01/204113
677525TV9
$79,450,000
3.125%
03/01/204314
95648VAR0
$86,000,000
Term Loan
Floating
05/13/2015
N/A
$200,000,000
Term Loan
Floating
05/13/2015
N/A
$400,000,000
Senior Notes
4.850%
01/15/2014
677415CG4
$225,000,000
Senior Notes
6.000%
06/01/2016
677415CL3
$350,000,000
Senior Notes
6.050%
05/01/2018
199575AW1
$350,000,000
Senior Notes
5.375%
10/01/2021
677415CP4
$500,000,000
Senior Notes
6.600%
02/15/2033
677415CF6
$250,000,000
Senior Notes
6.600%
03/01/2033
199575AT8
$250,000,000
Senior Notes
5.850%
10/01/2035
199575AV3
$250,000,000
5.590%
Securitization Bond
0.958%
07/01/2017
67741Y AA6
$164,900,000
Securitization Bond
2.049%
07/01/2019
67741Y AB4
$102,508,000
1.376%
9
110
Interest
12/01/2038
$3,236,825,000
$267,408,000
Put date 11/21/2014
10
Put date 08/01/2014
11
Put date 07/01/2014
12
Put date 06/01/2014
13
Put date 06/02/2014
14
Put date 04/01/2015
Debt Schedules
Amount
Notes Payable
3.000%
12/01/2025
N/A
$6,846,018
5.250%
06/01/2014
67884LAB9
$33,700,000
4.450%
06/01/2020
756864BT0
$12,660,000
Senior Notes
6.150%
08/01/2016
744533BH2
$150,000,000
Senior Notes
5.150%
12/01/2019
744533BK5
$250,000,000
Senior Notes
4.400%
02/01/2021
744533BL3
$250,000,000
Senior Notes
6.625%
11/15/2037
744533BJ8
$250,000,000
5.455%
Interest
$953,206,018
Amount
Notes Payable
6.370%
10/31/2024
78532* AC7
$25,000,000
Notes Payable
4.580%
02/21/2032
78532* AD5
$60,125,000
4.950%
03/01/2018
785652CJ5
$81,700,000
241627AV0
$53,500,000
15
3.250%
Senior Notes
5.375%
04/15/2015
845437BE1
$100,000,000
Senior Notes
4.900%
07/01/2015
845437BG6
$150,000,000
Senior Notes
5.550%
01/15/2017
845437BH4
$250,000,000
Senior Notes
5.875%
03/01/2018
845437BJ0
$300,000,000
Senior Notes
6.450%
01/15/2019
845437BK7
$400,000,000
Senior Notes
3.550%
02/15/2022
845437BM3
$275,000,000
Senior Notes
6.200%
03/15/2040
845437BL5
$350,000,000
5.457%
15
111
Interest
01/01/2019
$2,045,325,000
Put date 01/02/2015
Debt Schedules
Kentucky Power
Senior Notes
6.000%
09/15/2017
Senior Notes
7.250%
Senior Notes
8.030%
Senior Notes
Amount
491386AM0
$325,000,000
06/18/2021
491386 C*7
$40,000,000
06/18/2029
491386 C@5
$30,000,000
5.625%
12/01/2032
491386AL2
$75,000,000
Senior Notes
8.130%
06/18/2039
491386 C#3
$60,000,000
6.397%
AEP Texas North
112
Interest
Interest
$530,000,000
4.450%
06/01/2020
Senior Notes
5.890%
Senior Notes
6.760%
Senior Notes
Amount
756864BT0
$44,310,000
04/01/2018
0010EQ A*7
$30,000,000
04/01/2038
0010EQ A@5
$70,000,000
3.090%
02/28/2023
0010EQ A#3
$125,000,000
Senior Notes
4.480%
02/28/2043
0010EQ B*6
$75,000,000
Term Loan
Floating
07/31/2016
N/A
$75,000,000
4.558%
$419,310,000
Debt Schedules
AEP Texas Central
113
Interest
Amount
5.625%
10/01/2017
40053QAQ4
4.450%
06/01/2020
756864BT0
$40,890,000
$6,330,000
6.300%
11/01/2029
576528DM2
$100,635,000
5.200%
05/01/2030
576528DE0
$60,000,000
4.400%
05/01/2030
576528CY7
$111,700,000
4.550%
05/01/2030
576528CZ4
$50,000,000
Senior Notes
6.650%
02/15/2033
0010EPAF5
$275,000,000
Term Loan
Floating
07/31/2016
N/A
$75,000,000
5.821%
Securitization Bond
6.250%
6.250%
Securitization Bond
5.090%
07/01/2015
00110AAC8
$208,096,401
Securitization Bond
5.170%
01/01/2018
00110AAD6
$437,000,000
Securitization Bond
5.306%
07/01/2020
00110AAE4
$494,700,000
5.215%
Securitization Bond
0.880%
12/01/2017
00104UAA6
$246,906,438
Securitization Bond
1.976%
06/01/2020
00104UAB4
$180,200,000
Securitization Bond
2.845%
12/01/2024
00104UAC2
$311,900,000
1.977%
$719,555,000
01/15/2016
12617AAE7
$191,856,858
$191,856,858
$1,139,796,401
$739,006,438

2013 Fact Book 48th EEI Financial Conference

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Elkview Operations Environmental Policy

(a) Should we be burning wood, gas or coal? (2014)

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