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Wellington Shields Berenson
Transmission Seminar
January 11, 2011 New York, NY
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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 in, or contraction within, our service territory and changes in market demand and demographic patterns, 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, weather conditions, including storms, 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 I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration costs through warranty, insurance and the regulatory process, our ability to recover regulatory assets and stranded costs in connection with deregulation, our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates, our ability to build or acquire generating capacity, including the Turk Plant, 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 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, 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 (including the dispute with Bank of America), our ability to constrain operation and maintenance costs, our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities, changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market, actions of rating agencies, including changes in the ratings of debt, volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities, changes in utility regulation, including the implementation of ESPs and related regulation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP, accounting pronouncements periodically issued by accounting standard- setting bodies, the impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans and nuclear decommissioning trust and the impact on future funding requirements, 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, other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events and our ability to recover through rates the remaining unrecovered investment, if any, in generating units that may be retired before the end of their previously projected useful lives.
Investor Relations Contacts
“Safe Harbor” Statement under the Private Securities Litigation Reform Act of 1995
Chuck ZebulaTreasurer
SVP Investor Relations614-716-2800
Bette Jo RozsaManaging DirectorInvestor Relations
Julie SherwoodDirector
Investor Relations614-716-2663
Sara MaciochAnalyst
Investor Relations614-716-2835
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Lisa BartonSenior Vice President, AEP Transmission
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Transmission as a Growth Engine
Transmission investments present significant growth opportunities within and outside of AEP's traditional service territories
– Electric Transmission Texas (ETT) – Growing Rate Base– Received CCN approval on first CREZ line; 3 more approvals expected in
2011– AEP Transmission Company (AEP Transco)
– Settlement filed at FERC for wholesale rates. Final order pending.– $50MM spend for 2010; $160MM forecasted for 2011
– Joint Ventures– PATH – Prairie Wind– Pioneer – SMART Transmission study
Two new projects: RITELine and MEC
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AEP Transco was established in 2010
Formula rate settlement filed with FERC in September; awaiting final order – ROE: 11.49% in PJM and 11.2% in SPP
$50 M invested in three states in 2010 (OH, MI & OK)– Ohio application was approved by PUCO on December 29,
2010– Oklahoma and Michigan did not require filings
“Baseline” capital spending targets for OH, MI & OK– $160 M for 2011– $350 M for 2012
Will pursue regulatory approvals for other states in 2011 (AR, LA, WV, VA, IN & KY)– Additional capital spending opportunity in these states for 2012+
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SPPSPP ERCOTERCOT PJMPJM PJM/PJM/MISOMISO
345 kV and below CREZ & ERCOT Expansion
Partner: MidAmerican Energy (50%)
Total Estimated Cost: $1.5 billion
ROE: 9.96%
ETT COD: 2010-2014
765kV development in Oklahoma
Partners: OG&E (50%) & MidAmerican Energy (25%)
Tallgrass
75 - 110 miles of 345 kV*
Partners: Westar (50%) & MidAmerican Energy (25%)
Estimated Cost: $225 million
ROE: 12.8%
Prairie Wind COD: 2013-14
275 miles of 765 kV
Partner: Allegheny Energy (50%)
Estimated Cost: $1.4 billion
ROE: 14.3%
PATH-WV COD: 2015
Up to 240 miles of 765 kV
Partner: Duke Energy (50%)
Estimated Cost: up to $1 billion
ROE: 12.54%
Pioneer COD: ~2015-2017
Regional Expansion of EHV Backbone
SPP EHV Overlay
Interregional EHV & Wind Integration Study
Sponsors: ATC, ETA, Exelon, MidAmerican Energy, Northwestern Energy, Xcel Energy
SMARTransmission Study
Other Projects
Total estimated cost: $1.6 billion (COD 2010-2017)
ETT COD: various
Regional Expansion of EHV systems
PJM Expansion
ACTIVE ACTIVE PROJECTSPROJECTS
FUTURE FUTURE DEVELOPMENTDEVELOPMENT
JV Strategy – Nationwide Grid ExpansionJV Strategy – Nationwide Grid Expansion
* May revert to 765 kV depending on 2010 SPP ITP results
420 miles of 765kV
Partners: Exelon & MidAmerican Energy
Estimated Cost: $1.6 billion
RITELine
180 miles of 765 kV
Partners: MidAmerican Energy
Estimated Cost: $650 million
MEC Project
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Growing Rate Base:
Current rate base is $385 million; expected to grow as follows:
2010: $405 million
2011: $465 million
2012: $765 million
2013: $1,415 million
Interim TCOS filings twice per calendar year
Assigned Competitive Renewable Energy Zone (CREZ) Projects ~$1.1 B:
Seven double-circuit 345kV transmission lines (~$750 M), eight major 345kV stations and several series compensation installations (~$350 M)
PUCT Certificate of Convenience and Necessity (CCN) proceedings underway
ETT: An Operating Utility
CREZ Transmission Line Number of miles
Estimated Cost ($M)
CCN Filing Date
CCN Decision by PUCT
Clear Crossing to Dermott 95 $160 5/3/2010 Unanimously Approved 9/30/2010
Tesla to Riley 65 $110 8/18/2010 2/15/2011
Riley to Edith Clarke to Cottonwood
115 $199 9/8/2010 3/8/2011
Tesla to Edith Clarke to Clear Crossing to West
Shackelford
145 $280 Anticipated 10/20/2010
4/20/2011
Additional Projects in the Pipeline ~$1.6 B:
Approximately 822 miles of lines and 28 substations with in-service dates through 2017
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The ROW routes shown on this diagram are for illustrative purposes only and may not depict the actual route that could eventually be selected. The substation locations may also be modified.
Overview:
The project will provide enhanced electricity transport in Kansas and support expansion of renewable electricity generation in the region.
The project is expected to cost $225 million and be in-service by 2013-2014
AEP’s ownership of the joint venture is 25%.
FERC order received in December 2008:
Cash return on CWIP and 12.8% incentive ROE
Recovery of all costs incurred prior to the time rates go into effect
Recovery of all prudently incurred development and construction costs if the project is abandoned
Project was approved as SPP Priority Project in April 2010
NTC was issued to Westar July 2010. Currently working on a novation of the NTC to Prairie Wind. As a Transmission Owner, Prairie Wind will be entitled to collect revenue upon the novation of the Notice to Construct.
Currently approved at 345 kV.
Key Challenges:
Siting
and Routing
Prairie Wind Transmission, LLCPrairie Wind Transmission, LLC
Prairie Wind 345 kV
Tallgrass 345 kV
Prairie Wind 345 kVPrairie Wind 345 kV
Tallgrass 345 kVTallgrass 345 kV
Project Description: 110 miles of EHV transmission lines extending from Wichita, KS to the KS/OK border
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Update on PATH, LLCUpdate on PATH, LLC
Overview:
FERC order issued on February 29, 2008 approving:―
Cash return on CWIP and 14.3% incentive ROE―
Recovery of all costs incurred prior to the time rates go into effect
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Recovery of all prudently incurred development and construction costs if the project is abandoned as a result of factors beyond the control of PATH or its parents
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Rates went into effect March 1, 2008
FERC order issued on November 19, 2010 set the 14.3% ROE for hearing
Total estimated cost of entire line is $2.1 billion; AEP’s 50/50 JV with Allegheny will develop West Virginia section at a cost of $1.4 billion. AEP share is approximately $700 million
Estimated completion date: June 1, 2015
Key Challenges:
Obtaining a CPCN in West Virginia, Virginia, and Maryland– CPCN applications are filed and accepted in all three
states– PJM released a draft 2011 Load Forecast that could
affect the required in-service date for PATH– PATH filed motions in all three states in December
2010 for a delay in the procedural schedule to allow for the filing of supplemental need testimony to reflect the 2011 PJM Load Forecast
Project Description: 276 miles of 765-kV transmission line from AEP’s John Amos substation near St. Albans, W.Va.,
through a new Welton Spring substation in Hardy County, WV, ending at a new substation near Kemptown, MD.
The ROW routes shown on this diagram are for illustrative purposes only and may not depict the actual route that could eventually be selected. The substation locations may also be modified.
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MISO/PJM Interface: Proposed Projects Under Evaluation
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RITELine ProjectRITELine Project
AEP, ETA and Exelon Corporation executed a Memorandum of Understanding on October 26, 2010 for the development of the Reliability Interregional Transmission Extension Line (“RITELine”) project
The ROW routes shown on this diagram are for illustrative purposes only and may not depict the actual route that could eventually be selected. The substation locations may also be modified.
Estimated Project Cost: $1.6 billion
765 kV transmission line (or a designated lower-voltage solution such as double-circuit 345 kV line)
Extends approximately 420 miles from the Byron Substation in Illinois to the Blue Creek substation at the Ohio/Indiana border and from Kewanee to the Collins Substation in Illinois
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MEC ProjectMEC Project
ETA and MidAmerican Energy Company executed a Memorandum of Understanding on October 28, 2010 for the development of the MEC project
Estimated Project Cost: $650 million
765 kV transmission line (or a designated lower-voltage solution such as double- circuit 345 kV)
Extends approximately 180 miles from the Kewanee Substation in Illinois to the Louisa substation in Iowa and northwest to the Hazelton substation
The ROW routes shown on this diagram are for illustrative purposes only and may not depict the actual route that could eventually be selected. The substation locations may also be modified.
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$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
2010 2011 2012 2013 2014 2015 2016$0
$50
$100
$150
$200
$250
$300
$350
High Case
AEP Transco
PATH + Prairie Wind
ETT
High Case Earnings
Base Case Earnings
Transmission – Capital/Earnings Profile
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1 High Case includes: Pioneer (50% ownership), Prairie Wind at 765kV (25% ownership), Tallgrass at 765kV (25% ownership), ETA-Exelon (25% ownership) and other future opportunities
2 AEP Transco (100% ownership) includes spending in OH, MI & OK only through 2011 and in other jurisdictions for 2012 and beyond3 PATH (50% ownership) assumes an in-service date of 2015 and Prairie Wind (25% ownership) assumed at 345kV4 ETT (50% ownership) includes CREZ and additional projects5 Projection of earnings potential at the transmission holding company level assuming 50/50 debt/equity capitalization and ROE of 12-13% for FERC projects; 60/40
debt/equity capitalization and 10.25% ROE (2011 forward) for ERCOT projects; and 50/50 debt/equity capitalization and ROE of 11.2-11.49% for Transco projects
Cumulative Capital Spending, After Ownership Division ($M)
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Annual Earnings Potential ($M)5
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Evolving Regulatory Policy
2010 saw a number of steps towards resolving the issues related to planning, cost allocation and siting– SPP & FERC approved SPP’s regional cost allocation methodology,
and SPP adopted a new, more strategic planning process called the Integrated Transmission Planning process
– SPP issued notices-to-construct for its “Priority Projects”, including the first segments of an EHV overlay within the region
– The Midwest ISO, through its Regional Generator Outlet Study (RGOS) and Multi-Value Project (MVP) Process, has moved closer to approving a number of significant transmission projects
2011 looks to be a year in which regulatory momentum will support transmission development– FERC’s recently issued Notice of Proposed Rulemaking (NOPR),
which is still in the comment phase, indicates FERC’s desire to break the logjam and resolve the major issues that stand in the way of strategic development of the nation’s transmission grid
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Proposed Reforms in Transmission Planning
On June 16th FERC issued Notice of Proposed Rulemaking (NOPR) suggesting significant reforms in Transmission Planning and Cost allocation
Proposals would require Transmission Owners (TO’s) in RTO’s and ISO’s to:
Participate in a regional transmission planning process that produces a regional transmission plan that considers and evaluates transmission facilities/non-transmission solutions
Amend its OATT such that local and regional transmission planning processes explicitly provide for public policy requirements established by state/federal laws/regulations, (i.e. renewable requirements).
Eliminate from transmission provider’s OATT or FERC-jurisdictional agreements right of first refusal (ROFR) provisions with respect to facilities included in a regional transmission plan
Enter into interregional transmission planning agreement (filed with FERC), to coordinate with transmission providers in neighboring regions
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Proposed Reforms in Cost Allocation
FERC Proposal would also require RTO’s and ISO’s to establish a method for allocating the costs of:
New transmission facilities that are included in the regional transmission planning process in which it participates; and
New interregional transmission facility between the two neighboring transmission planning regions “in which the facility is located or among the beneficiaries of the two regions”.
Inter/cross-regional cost sharing mechanism could significantly improve ability to develop transmission projects across RTO “seams”