2009 AEP-SPP 

(Public Service Company of Oklahoma & Southwestern Electric Power Company) 

INTEGRATED RESOURCE PLAN

2010-2019 

Date Issued: July 2009 

 Business Confidential 

 Copy Control # ______ 

AEP-SPP 2009 Integrated Resource Plan 

 

The Integrated Resource Plan (IRP) is based upon the best available 

information at the time of preparation. However, changes that may impact this 

plan can, and do, occur without notice. Therefore this plan is not a 

commitment to a specific course of action, since the future, now more than 

ever before, is highly uncertain, particularly in light of the current economic 

conditions, access to capital, the movement towards increasing use of 

renewable generation and end-use efficiency, as well as legislative proposals to 

control “greenhouse gases.” 

The implementation action items as described herein are subject to change as 

new information becomes available or as circumstances warrant. It is AEP’s 

intention to revisit and refresh the IRP annually. . 

The contents of this report contain the Company’s forward-looking projections and recommendations 

concerning the capacity resource profile of its affiliated operating companies located in the Southwest 

Power Pool (SPP) Regional Transmission Organization. This report contains information that may be 

viewed by the public. Business sensitive information has been excluded from this document, but will 

be made available in a confidential supplement on an as needed basis to third parties subject to 

execution of a confidentiality agreement. The confidential supplement should be considered strictly 

business sensitive and proprietary and should not be duplicated or transmitted in any manner. Any 

questions or requests for additional copies of this document should be directed to: 

Scott C. Weaver 

Managing Director—Resource Planning and Operational Analysis 

Corporate Planning & Budgeting 

(614) 716-1373 (audinet: 200-1373) 

scweaver@aep.com 
AEP-SPP 2009 Integrated Resource Plan 

 
AEP-SPP 2009 Integrated Resource Plan 

 

Table of Contents 

Executive Summary................................................................................................................. i

1.0 Introduction....................................................................................................................... 1

1.1 IRP Process Overview .................................................................................................................1 

1.2 Introduction to AEP .....................................................................................................................1 

2.0 Current Resource Planning Issues in the Electric Utility Industry ............................. 7

2.1 Regulation/Deregulation ..............................................................................................................7 

2.2 Climate Change and Greenhouse Gases.......................................................................................7

2.3 Role and Impact of Commodity Pricing on Planning ................................................................12 

2.4 Issues Summary .........................................................................................................................18 

3.0 Implications of Industry Issues in this IRP Cycle........................................................ 21

3.1 Demand Response/Energy Efficiency (DR/EE) ........................................................................21 

3.2 Renewables ................................................................................................................................21 

3.3 Carbon Capture & Storage/Sequestration (CCS).......................................................................22 

3.4 Emission Compliance ................................................................................................................22 

4.0 Current Resources .......................................................................................................... 25

4.1 Existing PSO and SWEPCO Generating Resources..................................................................25 

4.2 Capacity Impacts of Environmental Compliance Plan ..............................................................25 

4.3 Existing Unit Disposition...........................................................................................................26 

4.4 AEP-SPP Transmission..............................................................................................................26 

5.0 Demand Projections........................................................................................................ 35

5.1 Load and Demand Forecast - Process Overview .......................................................................35 

5.2 Peak Demand Forecast...............................................................................................................36 

5.3 Current DR/EE Programs...........................................................................................................38 

6.0 Capacity Needs Assessment ........................................................................................... 41

6.1 RTO Requirements ....................................................................................................................42 

6.2 Capacity Positions—Historical Perspective...............................................................................43 

7.0 Planning Objectives ........................................................................................................ 45

7.1 Planning Flexibility—Covering Capacity Deficient Positions with Market Opportunities.......45 

7.2 Planning Horizon .......................................................................................................................45 

7.3 Establishing the Optimal Asset “Mix”.......................................................................................45 

7.4 Other Operational Factors..........................................................................................................45 

7.5 Affordability...............................................................................................................................46 

8.0 Resource Options ............................................................................................................ 47

8.1 Market Options and “Build vs. Buy” Considerations ................................................................47 

8.2 Traditional Capacity-Build Options...........................................................................................49 

8.3 Renewable Alternatives .............................................................................................................54 

8.4 Carbon Capture ..........................................................................................................................61 

8.5 Demand Side Alternatives..........................................................................................................62 

9.0 Evaluating DR/EE Impacts for the 2009 IRP .............................................................. 67

9.1 gridSMARTSM............................................................................................................................67 

9.2 Demand Response/Energy Efficiency Mandates and Goals ......................................................67 

9.3 Assessment of Achievable Potential ..........................................................................................68 

9.4 Determining Programs for the IRP ............................................................................................69 

9.5 Optimizing the Incremental DR/EE Resources..........................................................................71 

9.6 Discussion and Conclusion ........................................................................................................74 

10.0 Fundamental Modeling Parameters............................................................................ 77
AEP-SPP 2009 Integrated Resource Plan 

 

10.1 Modeling and Planning Process—An Overview..................................................................... 77 

10.2 Methodology............................................................................................................................ 77 

10.3 Key Fundamental Modeling Input Parameters ........................................................................ 78 

11.0 Resource Portfolio Modeling ....................................................................................... 81

11.1 The Strategist Model—An Overview...................................................................................... 81 

11.2 Strategist Optimization............................................................................................................ 83 

11.3 AEP–SPP Supply-side Resource “Type” Options/Characteristics.......................................... 83 

11.4 AEP-SPP DR/EE and Renewable Resource Options/Characteristics ..................................... 84 

11.5 PSO Plan Development ........................................................................................................... 85 

11.6 SWEPCO Plan Development .................................................................................................. 97 

12.0 Risk Analysis ............................................................................................................... 107

12.1 The URSA Model.................................................................................................................. 107 

12.2 URSA Modeling Results ....................................................................................................... 108 

12.3 Capital Cost Risk Assessment ............................................................................................... 111 

12.4 Results Including Capital Cost Risk...................................................................................... 111 

12.5 Conclusion From Risk Modeling........................................................................................... 114 

13.0 Conclusions and Recommendations.......................................................................... 115

13.1 Capacity and Energy Plan...................................................................................................... 115 

13.2 Comparison to 2008 IRP ....................................................................................................... 121 

13.3 Plan Impact on Carbon Mitigation (“Prism” Analysis)......................................................... 121 

13.4 Arkansas Stakeholder Process - SWEPCO............................................................................ 124 

13.5 Conclusion............................................................................................................................. 125 

14.0 Implementation ........................................................................................................... 127

14.1 Current Commitments ........................................................................................................... 127 
AEP-SPP 2009 Integrated Resource Plan 

 

Exhibits 

Exhibit 1-1: IRP Process Overview........................................................................................................................2 

Exhibit 1-2: AEP System, East and West Zones ....................................................................................................3 

Exhibit 1-3: PSO Reserve Margin With and Without Exelon PPA........................................................................4 

Exhibit 1-4: SWEPCO Reserve Margin With and Without Turk and Stall Plants .................................................4 

Exhibit 2-1: Fossil Fuel-to-Electricity Emissions, by Fuel Type ...........................................................................7 

Exhibit 2-2: CO2 Price Forecast .............................................................................................................................8 

Exhibit 2-3: Renewable Standards by State ...........................................................................................................9 

Exhibit 2-4: CO2 Capture and Sequestration Process...........................................................................................11

Exhibit 2-5: Power Price Layers...........................................................................................................................12 

Exhibit 2-6: SPP On-Peak Price Index.................................................................................................................13 

Exhibit 2-7: Natural Gas Price Index ...................................................................................................................13 

Exhibit 2-8: PRB Coal Price Index ......................................................................................................................14 

Exhibit 2-9: SO2 Emission Price Index ................................................................................................................17 

Exhibit 2-10: CO2 Emission Price Index..............................................................................................................17 

Exhibit 2-11: 2H08 vs. 1H09 Commodities Comparison.....................................................................................20 

Exhibit 3-1: Renewable Energy Plan Through 2030............................................................................................22 

Exhibit 4-1: Existing PSO and SWEPCO Generating Resources ........................................................................25 

Exhibit 4-2: PSO and SWEPCO Capacity Change After June 2009....................................................................26 

Exhibit 5-1: Load and Demand Forecast Process—Sequential Steps ..................................................................35 

Exhibit 5-2: AEP-SPP Peak Demand and Energy Projection...............................................................................37 

Exhibit 5-3: AEP-SPP Current DR/EE Programs full-year impacts ....................................................................40 

Exhibit 6-1: Capacity vs. SPP Minimum Required Reserves...............................................................................41 

Exhibit 6-2: Summary of Capacity Deficiency Position ......................................................................................42 

Exhibit 6-3: AEP-SPP, Historical Capacity Position ...........................................................................................43 

Exhibit 8-1: Projected SPP Capacity Margin ......................................................................................................47 

Exhibit 8-2: Recent Merchant Generation Purchases ...........................................................................................48 

Exhibit 8-3: United States Wind Power Locations...............................................................................................56 

Exhibit 8-4: United States Solar Resource Locations...........................................................................................57 

Exhibit 8-5: Land Area Required to Support Biomass Facility............................................................................58 

Exhibit 8-6: Biomass Resources in the United States...........................................................................................59 

Exhibit 8-7: Renewable Sources Included in AEP-SPP and East 2009 IRP ........................................................60 

Exhibit 8-8: Typical DR/EE Measure Conservation Load Factor........................................................................65 

Exhibit 9-1: Impact of Legislation on Energy Consumption................................................................................67 

Exhibit 9-2: Achievable Versus Technical Potential (Illustrative) .......................................................................68 

Exhibit 9-3: AEP-SPP Zone Cost Effectiveness of Relative Programs................................................................70 

Exhibit 9-4: AEP-SPP Zone DR/EE Proxy Blocks ..............................................................................................71 

Exhibit 9-5: AEP-SPP Zone DR/EE Modeling Constraints .................................................................................72 

Exhibit 9-6: AEP-SPP Zone DR/EE Blocks Selected in Resource Modeling (AEP-SPP)...................................73 

Exhibit 9-7: AEP-SPP Internal EE Target versus IRP .........................................................................................74 

Exhibit 9-8: AEP-SPP Zone DR/EE Assumption Summary................................................................................75 

Exhibit 10-1: Long-term Forecast Process Flow..................................................................................................78 

Exhibit 10-2: Input Scenarios and Sensitivities....................................................................................................79 

Exhibit 11-1: AEP Sponsored DSM Programs.....................................................................................................85 

Exhibit 11-2: Comparison of PSO Optimal and Suboptimal Plans......................................................................86 

Exhibit 11-3: PSO Optimal Plan Comparison for Power and CO2 Price Scenarios .............................................87 

Exhibit 11-4: PSO Full Study Period Revenue Requirements .............................................................................88 

Exhibit 11-5: PSO Full Study Period Cost over Optimal Plan.............................................................................88 

Exhibit 11-6: PSO Plan Comparisons ..................................................................................................................90 

Exhibit 11-6: PSO Plan Comparisons (Cont’d)....................................................................................................91 

Exhibit 11-7: PSO Load Forecast Trends.............................................................................................................92 

Exhibit 11-8: PSO Load Forecast Comparison ....................................................................................................93 

Exhibit 11-9: PSO Reserve Margin......................................................................................................................94 

Exhibit 11-10: PSO Hybrid Plan ..........................................................................................................................95 
AEP-SPP 2009 Integrated Resource Plan 

 

Exhibit 11-11: Comparison of SWEPCO Optimal and Suboptimal Plans ...........................................................98 

Exhibit 11-12: SWEPCO Optimal Plan Comparison for Power and CO2 Price Scenarios ..................................99 

Exhibit 11-13: SWEPCO Full Study Period Revenue Requirements.................................................................100 

Exhibit 11-14: SWEPCO Full Study Period Cost over Optimal Plan ................................................................100 

Exhibit 11-15: SWEPCO Plan Comparisons......................................................................................................101 

Exhibit 11-15: SWEPCO Plan Comparisons (Cont’d) .......................................................................................102 

Exhibit 11-16: SWEPCO Hybrid Plan ...............................................................................................................103 

Exhibit 11-17: SWEPCO Load Forecast Comparisons ......................................................................................104 

Exhibit 11-18 SWEPCO Reserve Margin With and Without Turk and Stall Plants ..........................................105 

Exhibit 12-1A: Key Risk Factors–Weighted Means for 2009-2035 (PSO)........................................................107 

Exhibit 12-1B: Key Risk Factors–Weighted Means for 2009-2035 (SWEPCO) ...............................................108 

Exhibit 12-2A: Cumulative Probability Distribution of AEP-SPP Revenue Requirement (PSO)......................109 

Exhibit 12-2B: Cumulative Probability Distribution of AEP-SPP Revenue Requirement (SWEPCO).............109 

Exhibit 12-3A: Probability Distribution of AEP-SPP Revenue Requirement (PSO) .........................................110 

Exhibit 12-3B: Probability Distribution of AEP-SPP Revenue Requirement (SWEPCO).................................110 

Exhibit 12-4: Basis of Capital Cost Distributions ..............................................................................................111 

Exhibit 12-5A: Capital Cost Risk-Adjusted CPW 2009-2035 Revenue Requirement ($ Millions) (PSO) ....... 111 

Exhibit 12-5B: Capital Cost Risk-Adjusted CPW 2009-2035 Revenue Requirement ($ Millions) (SWEPCO)111 

Exhibit 12-6A: Distribution Function for All Portfolios (PSO) .........................................................................112 

Exhibit 12-6B: Distribution Function for All Portfolios (SWEPCO).................................................................113 

Exhibit 12-7A: Distribution Function for All Portfolios at > 95% Probability (PSO) .......................................113 

Exhibit 12-7B: Distribution Function for All Portfolios at > 95% Probability (SWEPCO)...............................114 

Exhibit 13-1: AEP-SPP Generation Capacity.....................................................................................................116 

Exhibit 13-2: AEP-SPP Current Capacity Mix ..................................................................................................117 

Exhibit 13-3: AEP-SPP 2019 Capacity Mix.......................................................................................................117 

Exhibit 13-4: 2008 AEP-SPP 2030 Capacity Mix..............................................................................................118 

Exhibit 13-5: Change in Energy Mix With Hybrid Plan - Current vs. 2019 and 2030.......................................119 

Exhibit 13-6: 2009 AEP-SPP IRP ......................................................................................................................121 

Exhibit 13-7: CO2 Emission Profile ...................................................................................................................122 

Exhibit 13-8: CO2 Emission Profile With Caps..................................................................................................123 

Exhibit 13-9: CO2 Emission Profile vs. Estimated Waxman-Markey Allocation ..............................................124 
AEP-SPP 2009 Integrated Resource Plan 

 

Appendices 

Appendix A, Figure 1 Existing Generation Capacity, AEP-SPP Zone ..............................................................131 

Appendix B, Figure 1 Economically Screened Renewable Alternatives ...........................................................132

Appendix C, Figure 1 Key Supply Side Resource Assumptions........................................................................133 

Appendix C, Figure 2 Energy Storage Screening...............................................................................................134 

Appendix D, Figure 1 AEP-SPP Capacity, Demand, Reserve Forecast.............................................................135

Appendix D, Figure 2 AEP-SPP Capacity, Demand, Reserve Forecast (High Demand Scenario)....................136 

Appendix D, Figure 3 PSO Capacity, Demand, Reserve Forecast ....................................................................137 

Appendix D, Figure 4 SWEPCO Capacity, Demand, Reserve Forecast ...........................................................138 

Appendix E, Figure 1 AEP Plan to Meet 10% of Renewable Energy Target by 2020.......................................139 

Appendix F, DSM By Operating Company .......................................................................................................140 

Appendix G, Arkansas Stakeholder Report........................................................................................................141 
AEP-SPP 2009 Integrated Resource Plan 

 

Acknowledgements 

The Resource Planning group appreciates the support and input of the various individuals 

throughout the Service Corporation who provided input into the development of this Integrated 

Resource Plan document. In addition, a number of people provided valuable comments as the report 

was being developed including the operating company regulatory support staffs. 
AEP-SPP 2009 Integrated Resource Plan 

 i 

Executive Summary 

The goal of resource planning is to match a utility’s future suite of resources with projected 

demand for those resources. As such the plan lays out the amount, timing and type of resources that 

achieve this goal at the lowest reasonable cost, considering all the various constraints – reserve 

margins, emission limitations, renewable and energy efficiency requirements – that it is mandated to 

meet. Planning for future resource requirements during volatile periods can be challenging. 

Unprecedented economic contraction and varying levels of proposed regulation regarding greenhouse 

gases and renewable energy are two major drivers of uncertainty that must be addressed during the 

planning process. Over the 10-year, 2010-2019 Integrated Resource Plan (IRP or “Plan”) planning 

period, the AEP’s integrated western zone (AEP-SPP) which includes Public Service Company of 

Oklahoma (PSO) and Southwestern Electric Power Company (SWEPCO) is expected to experience 

load growth at a compound annual rate of 1.5% per year, or roughly 140 MW annually. This growth 

can be considered as occurring in two phases. The impact of the existing recession depresses peak 

demand in 2009 and 2010 with a rapid increase in 2011 from the assumed economic recovery. In 

addition, there is a comparable rate of growth for internal energy sales over the 10-year period, with 

load factors increasing in 2011 due to the recovery of recession impacted industrial load. 

The following Summary Exhibit 1 depicts the “going-in” capacity needs of PSO and SWEPCO 

with committed capacity additions (Stall and Turk for SWEPCO, Exelon-Green Country PPA for 

PSO) but excluding uncommitted planned capacity additions. It amplifies that the recent economic 

downturn has reduced the need for new resources, beyond current commitments, to the end of the 

planning horizon. However, PSO and SWEPCO must still make resource additions to satisfy reserve 

requirements. 

With the supply side additions and demand side measures that provide demand 

reductions/energy efficiency (DR/EE or “DSM”) included in this 2009 IRP, Summary Exhibit 2

shows that PSO and SWEPCO will be able to meet their margin requirements without market 

capacity purchases beginning in 2013. 
AEP-SPP 2009 Integrated Resource Plan 

 ii 

Summary Exhibit 1 

PSO: Capacity Position

NO New Capacity Post-2012 L/T PPA.... NO 'New' Energy Efficiency/Demand Reduction (EE/DR)

2,500

3,000

3,500

4,000

4,500

5,000

5,500

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Year

MW- Summer Capacity

Installed Capacity (MW) Purchased Capacity (MW)

Est. Long-Term PPA Capacity (MW) Demand + SPP Margin (MW) (Nov 2008 Fcst)

Demand + SPP Margin (MW) (April 2009 Fcst)

SWEPCo: Capacity Position

NO New Capacity Post-Turk.... NO 'New' Energy Efficiency/Demand Reduction (EE/DR)

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Year

MW- Summer Capacity

Installed Capacity (MW) Purchased Capacity (MW)

Stall (2011) + Turk (2013) (MW) Demand + SPP Margin (MW) (Nov 2008 Fcst)

Demand + SPP Margin (MW) (April 2009 Fcst)

 

Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan 

 iii 

Summary Exhibit 2 

AEP SPP: (Summer Season)

Reflecting: Current Hybrid Plan

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Year

MW- Summer Capacity

Installed/Purchased Capacity (MW) New Capacity (MW)

Demand + SPP Margin (MW)(W/ DSM) Demand + SPP Margin (MW)(W/O New DSM)

Source: AEP Resource Planning

Both the proposed Turk (SWEPCO) baseload ultra-supercritical pulverized coal (USC-PC) plant 

and a 509 MW Stall Natural Gas Combined Cycle were considered embedded for 2009 AEP-SPP

resource planning purposes, as they were secured during the SWEPCO 2006 Long-term Baseload 

Resource Request For Proposal (RFP) process. These units are currently under construction with Stall 

approximately 60% physically complete—with 95 % of the construction costs committed—and 

scheduled to begin commercial operation prior to the summer peak of 2011 and Turk approximately 

15% physically complete—with 81 % of the construction costs committed—and scheduled to be in 

service prior to the summer peak of 2013. The 2008 PSO RFP process resulted in the selection of a 

purchase power agreement (PPA) with Exelon for 512 MW of the Green Country combined cycle 

facility which is also embedded in this IRP beginning 2012. Each project is fulfilling commissionapproved findings of need/necessity in Arkansas, Louisiana, Texas (Stall and Turk), and Oklahoma 

(450 MW of baseload capacity), and are still required for meeting SPP minimum reserve margin 

requirements. 
AEP-SPP 2009 Integrated Resource Plan 

 iv 

Major Drivers: 

Global Climate Change 

This 2009 IRP for AEP-SPP is consistent with the AEP 2009 Corporate Sustainability Report

with regard to the assumption of potential legislation related to greenhouse gas (GHG)/carbon dioxide 

(CO2

) emissions, renewable portfolio standards (RPS), and energy efficiency. The driving planning 

assumptions include: 

 CO2 mitigation in the form of substantive CO2 reduction legislation effective by 2015 with a 

cap-and-trade regime effective in the same year. 

 Prospect of a future Federal RPS, or a growing critical mass or “patchwork” of AEP statelegislated RPS initiatives—which could be in the range of 10%, or more. 

With that, AEP has positioned itself by assuming an aggressive posture in the adoption of 

renewable alternatives including a 2,000 MW system-wide renewable initiative (by 2011). 

That strategy would be an underpinning of an overall renewable energy target of 10% of 

sales by 2020 and is consistent with the existing state renewable energy targets. 

Demand Side Management and Energy Efficiency (DR/EE) 

Recognizing the prospects of higher (avoided) costs, AEP initiatives to improve grid efficiency 

and install advanced metering, and a national groundswell focused on efficiency, the AEP-SPP IRP 

calls for: 

 Approximately 78 MW of incremental DR/EE by 2010, growing to 389 by 2019. 

 This is “incremental” since it is over-and-above current estimates of existing AEP-SPP 

interruptible-type measures totaling over 48 MW at peak. However, it is inclusive of current 

and pending energy efficiency programs at both PSO and SWEPCO. 

Wind and Other Renewable Resources 

Along with the prospects of CO2 legislation, the possible introduction of a Federal (or “en 

masse” state) RPS, helped justify the planned system-wide purchase of 2,000 MW of renewable 

resources—for planning purposes assumed to be in the form of wind power—by 1/31/2011. The 

largest portion of these purchases is for AEP-East.1

 When added to current and planned PSO and 

SWEPCO long-term wind purchases as well as economically-screened wind and biomass co-firing 

opportunities beyond the 10-year IRP period, these operating companies as well as AEP are 

positioned to achieve 10% of energy sales from renewable sources. 

Emerging Technology 

AEP is committed to pursuing emerging technologies that fit into the capacity resource planning 

process, including Sodium Sulfur (NaS) Batteries, fuel cells, solar panels, and “smart” grid enabling 

meters. These “distributed” technologies, while currently expensive relative to traditional demand 

 

1

 Note: Firm “capacity” attributable to wind would be limited to roughly 8%, of the nameplate amount for 

purposes of capacity planning in SPP. 
AEP-SPP 2009 Integrated Resource Plan 

 v 

and supply options, have the capacity to evolve into common resource options as costs come down 

and the capabilities continue to improve. For each of these options, both the technology and 

associated costs will continue to be monitored for increased inclusion in future planning cycles, if 

warranted. 

AEP-SPP Recommended Plan: 

Complete the 509 MW Stall combined Cycle Facility in SWEPCO by the by the third quarter 

of 2011 so it is ready for the summer peak in 2011

 Begin receipt of 512 MW of baseload/intermediate capacity from Green Country (Exelon 

PPA) in PSO by summer of 2012

 Complete the joint owned (AEP share - 447 MW) Turk Ultra-Supercritical PC plant in 

SWEPCO by the fourth quarter of 2012 so it is ready for the summer peak in 2013 

 Purchase (or construction) of an additional 750 MW (nameplate) of wind generation by 2019 

 Acquire 158 MW of peaking capacity in SWEPCO by 2019 

Implement new DR/EE programs totaling 332 MW over the IRP planning period, or over 860 

GWH annually after 2015. 

The following Summary Exhibit 3 offers a view of the 2009 AEP-SPP IRP: 

Summary Exhibit 3 

RENEWABLE RENEWABLE

Environmental 

Retrofits(G)

E mbedded 

Demand 

Reduction(B) 

(Cumul. 

Contribution)

New 

Demand 

Reduction(C) 

(Cumul. 

Contribution)

Wind (Nameplate) Environmental 

Retrofits(G)

E mbedded 

Demand 

Reduction(B) 

(Cumul. Contribution)

New 

Demand 

Reduction(C) 

(Cumul. 

Contribution)

Wind (Nameplate) 

2009 9 0 10 0

2010 13 31 16 24 79.5(F)

2011 16 62 198 (E) 20 48 100

2012 19 94 24 72 100

2013 21 125 26 96 150

2014 22 157 FC1 (4) 29 120

2015 23 188 67 WSH2 (8) 30 144 33

2016 NE3&4 (15) 24 188 31 144 100

2017 25 188 200 32 144

2018 25 188 32 144

2019 25 188 32 144

Nameplate 

Capacity (15) 25 188 465 (12) 32 144 563

(SPP) Capacity 

Value (Wind 8%; )

60 45

Cumul. 

(Nameplate) 2% 16% 39% 2% 8% 30%

Cumul. 

(Capacity) 

Contribution 3% 24% 8% 2% 11% 42%

(G) Derate associated with the addition of and FGD system

Planned 

Resource 

Reductions

Planned 

Resource 

Reductions

PSO SWEPCO

THERMAL

Duty Cycle Type: 

BL=Baseload 

INT=Intermediate 

PKG=Peaking

(Stall) 509-MW INT

2009 AEP-SPP Integrated Resource Plan (Hybrid Plan) 

 (B) "Embedded" DSM represents 'known & measurable', commission-approved program activity now projected by AEP-Economic Forecasting in the most recent 

load forecast

 157-MW PKG

1,113

Planned Resource Additions (MW) Planned Resource Additions (MW)

DSM

(E) Assumes Elk City and Blue Canyon V wind energy available by 2011, but firm transmission delayed until 2013 

(C) "New" DSM represents incremental activity projected based on estimated contribution & program cost (vs. avoided cost) parameters, from recent Market Potential 

Studies, and were generally limited to an EPRI Jan. '09 study identifying a "Realistically Achievable Potential". This 'New' (increm) DSM-DR activity modeled thru 

2015 only

(D) PPA term for PSO 2012 baseload capacity & energy: 9 years, 7 months (thru 2021)

 (Turk) 447-MW BL

DSM THERMAL

Duty Cycle Type: 

BL=Baseload 

INT=Intermediate 

PKG=Peaking

(F) Assumes Majestic wind energy available by 2010, but firm transmission delayed until 2012 

43%

 (Grn Cntry PPA) 

512-MW BL

60%

 (A) Not shown are relatively small unit uprates and derates embedded in the current plan (e.g. FGD retrofit auxliary load losses)

512

65% 83%

 

Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan 

 vi 

Plan Impact on Carbon Mitigation (“Prism” Analysis) 

Global Climate Change and the prospect for comprehensive CO2 legislation has had a direct 

bearing on the outcome of the 2009 AEP-SPP Plan. To gauge the respective CO2 mitigation impacts 

incorporated into this resource planning, an assessment was performed that emulates an approach 

undertaken by the Electric Power Research Institute (EPRI). This profiling seeks to measure the 

contributions of various “portfolio” components that could, when taken together, effectively achieve 

such carbon mitigation: 

 Energy Efficiency 

 Renewable Generation 

 Fossil Plant Efficiency, including coal-unit retirements 

 Nuclear Generation

 Technology Solutions, including Carbon Capture and Sequestration

The following Summary Exhibit 4 reflects those comparable components within this 2009 IRP–set 

forth as uniquely-colored “prisms”—that are anticipated to contribute to the overall AEP System’s 

(combined East and West regions) initiatives to reduce its carbon footprint:

Summary Exhibit 4 

AEP-SYSTEM (East & West) 

CO2 Emission Profile

Hybrid Plan (2009 IRP) 

Including: 20 MW CCS by 20 1 0... 235 MW by 2013... 1,300 MW by 2020... 1,740 MW by 2025... 5,800 MW by 2030

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

CO2 Emissions, K Tonnes

(Pre-Committed) NSR Caps & Retirements

DR/EE

Renewables

Retirements (post-'R/R/R')

Cook Uprates

CCS Retrofits @ 90%

Hybrid Plan

2009 Hybrid Plan

(Assuming No Carbon Offsets or 

Allowance Purchases)

"Business-As-Usual"

2005 (A)

144.9 M

62.5 M

Tonne 

(35.8%)

Reduction

Source: AEP Resource Planning 

While these results would suggest significant improvement in the AEP System CO2 emission 

profile over time, it could still fall short of prospective legislation that would attempt to further limit 
AEP-SPP 2009 Integrated Resource Plan 

 vii 

CO2. Specifically, using H.R. 2454 (the Waxman-Markey Bill) that passed the U.S. House in June, 

2009 as a proxy, this profile would require reduction in CO2 emissions that would have to consider 

acquisition of carbon “offsets”—financial instruments that represent certified initiative to remove 1 

ton of carbon—to begin to approximate the levels of reduction set forth by such mandates. The 

following Summary Exhibit 5 offers such a comparison for the AEP System: 

Summary Exhibit 5 

AEP-SYSTEM (East & West) 

CO2 Position vs. W-M Emission "Caps"

Hybrid Plan (2009 IRP) 

Including: 20 MW CCS by 2010... 235 MW by 2013... 1,300 MW by 2020... 1,740 MW by 2025... 5,800 MW by 2030

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

CO2 Emissions, K Tonnes

(Pre-Committed) NSR Caps & Retirements

DR/EE

Renewables

Retirements (post-'R/R/R')

Cook Uprates

CCS Retrofits

Offsets (Domestic & Int'l)

Hybrid Plan with Offsets

W-M CO2 Target

62.5 M

Tonne 

(35.8%)

Reduction

Waxman-Markey 

(Physical Compliance) Targets 

(3% by '12... 17% by '20... 42% by '30) 

Assuming

20 M Tonne 

of Carbon Offsets 

Attainable by 2020 

Source: AEP Resource Planning 

Further, under the assumption that a cap-and-trade mechanism could emerge from any set of 

carbon legislation, it is reasonable to assume that such CO2 mitigation efforts, inclusive of offset 

acquisitions, may not provide for an adequate CO2 position within that mechanism. Specifically, if the 

legislation provides for the allocation of an insufficient level of (free) CO2 allowances to the utility, 

any such remaining CO2 position “shortfall” must subsequently be borne by the utilities’ customers 

through additional, potentially more costly, CO2 mitigation efforts, including the purchase of 

additional allowances. The following Summary Exhibit 6 identifies this potential position based on 

the current allowance allocation format set forth by the Waxman-Markey Bill: 
AEP-SPP 2009 Integrated Resource Plan 

 viii 

Summary Exhibit 6 

AEP-SYSTEM (East & West) 

CO2 Position vs. Est. W-M LDC Allocations & Wholesale Recoveries

Hybrid Plan (2009 IRP) 

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

CO2 Emissions, K Tonnes

(Pre-Committed) NSR Caps & Retirements

DR/EE

Renewables

Retirements (post-'R/R/R')

Cook Uprates

CCS Retrofits

Offsets (Domestic & Int'l)

Hybrid Plan with Offsets

W-M CO2 Target

Wholesale Allow. Recovery

W-M LDC Est. Allowance Alloc.

62.5 M

Tonne 

(35.8%)

Reduction

~40 MM 

Allowances 

Required (2012)

~24 MM 

Allowances 

Required (2020)

or...

~4,800 MW "CCS-Equiv."

(@ ~5 MM T per 1GW CCS)

~69 MM 

Allowances 

Required (2030)

or...

~13,800 MW "CCS-Equiv."

(@ ~5 MM T per 1GW CCS)

Est. Utility (Retail) Allow. Allocation @ 

79 MM in 2012 under W-M "50/50" 

distribution basis for Electricty Sector 

allowance alloc

Waxman-Markey 

(Physical Compliance) 

Target 

(17% by '20... 42% by '30)

Est. increm. allowance/cost 

recovery from Wholesale 

Customers

Source: AEP Resource Planning 

In summary, this prism analysis would suggest that the carbon mitigation requirements in the 

AEP System (East and SPP) 2009 IRPs offer a meaningful pathway to the attainment of potential 

Climate Change/CO2 legislation, however, additional contributions–over-and-above the acquisition 

of CO2 allowances—may be required in future planning cycles to protect AEP’s customers from 

significant cost exposures. 

Plan Impact on Capital Requirements 

This Plan includes new capacity additions, as well as unit uprates and environmental retrofits. 

Such generation additions require a significant investment of capital. Some of these projects are still 

conceptual in nature, others do not have site specific information to perform detailed estimates; 

however, it is important to provide an order of magnitude cost estimate for the projects included in 

this plan. As some of the initiatives represented in this plan span both East and West AEP zones, this 

Summary Exhibit 7 includes estimates for projects over the entire AEP system Generation (G) 

functional discipline. 

It is important to reiterate the capital spend level reflected on the Summary Exhibit 7 is 

“incremental” in that it does not include “base”/business-as-usual capital expenditure requirements of 

the “G” sector. Achieving this additional level of expenditure will therefore be a significant challenge 

going-forward and would suggest the Plan itself will remain under constant evaluation and subject to 

change. 
AEP-SPP 2009 Integrated Resource Plan 

 ix 

Summary Exhibit 7 

Reflecting...

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 TOTAL Group %

 By Type... (2010-2019)

IRP (New Generation) 306 362 321 110 175 281 306 302 177 634 2,974 25%

IRP (Response to Carbon / RPS Legislation) - - - 44 147 381 349 548 848 623 2,941 24%

 306 362 321 154 322 662 655 850 1,025 1,257 5,915

 Plus:

Environmental Compliance / Cook License Extension 242 58 519 794 1,039 1,297 866 839 439 33 6,126 51%

 TOTAL INCREMENTAL "G" CAPEX 548 420 840 948 1,361 1,959 1,521 1,689 1,464 1,290 12,041

Annual % 3% 5% 7% 8% 11% 16% 13% 14% 12% 11%

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 TOTAL

 By Operating Company... (2010-2019)

AEG 4 5 90 37 50 135 246 370 220 17 1,172 

APCo 14 15 14 15 98 298 251 546 723 582 2,555 

CSP 0 0 13 30 70 98 9 0 100 125 444 

I&M 30 90 110 152 352 684 642 470 220 93 2,842 

KPCo 2 18 100 150 190 154 102 90 5 0 811 

OPCo 4 3 33 95 164 188 73 69 30 89 748 

PSO 0 5 63 203 258 331 129 23 153 271 1,436 

SWEPCO 366 412 417 267 179 72 70 122 15 114 2,033 

 TOTAL INCREMENTAL "G" CAPEX 420 548 840 948 1,361 1,959 1,521 1,689 1,464 1,290 12,041

Subtotal

AEP System (East & West)

PRELIMINARY (Incremental) "G" Capex Spend

 2009 IRP (E&W) Assuming 1,300 MW CCS (MT only ) by 2020 ... (w/ 1,740 MW by 2025 ... 5,800 MW by 2030 )

2010-2019

($Millions)

Source: AEP Resource Planning

Conclusion: 

The recommended plan provides the “lowest, reasonable cost” solution through a 

combination of traditional supply, renewable and demand side investments. The tempered load 

growth combined with additional renewable resources, increased DR/EE initiatives, completion of 

Stall and Turk plants, and the execution of the Exelon PPA, will allow AEP-SPP to meet its resource 

requirements through 2018 at which point new peaking capacity will be required. No new 

uncommitted baseload capacity is required over the term of the forecast period. 

Keep in mind that the planning process is a continuous activity; assumptions and plans are 

continually reviewed as new information becomes available and are modified as appropriate. Indeed, 

the resource expansion plan reported herein reflects, to a large extent, assumptions that are subject to 

change. It is simply a snapshot of the future at this time. The Plan is not a commitment to a specific 

course of action. The future, now more than ever before, is highly uncertain, particularly in light of 

the current economic conditions, the movement towards increasing use of renewable generation and 

end-use efficiency, as well as legislative proposals to control “greenhouse gases” which could result 

in the retirement or retrofit of existing generating units, impacting the supply of capacity and energy 

to AEP-SPP companies. The resource planning process is becoming increasingly complex given 

pending legislative and regulatory restrictions, technology advancement, changing energy supply 

fundamentals, uncertainty of demand and energy efficiency advancements all of which necessitate 

flexibility in any ongoing plan. The ability to invest in capital-intensive infrastructure is increasingly 

challenged in light of current economic conditions, and the impact on the AEP-SPP customers will 

continue to be a primary planning consideration. 

AEP-SPP 2009 Integrated Resource Plan 

 1 

1.0 Introduction 

This document contains the assumptions and steps required to develop the recommended 

resource plan. Section 1 discusses the company and the resource planning process in general. Section 

2 describes emerging industry issues and commodity forecasts that impact utilities including AEP. 

Section 3 describes the implications of these issues as they relate to resource planning. Section 4 

describes current supply resources, including transmission integration, and Section 5 discusses 

projected growth in demand and energy which serves as the underpinning of the plan. Then Section 6 

combines these two projected states (resources versus demand) to identify the need to be filled. 

Sections 7 through 12 describe the analysis and assumptions that are used to develop the plan such as 

planning objectives (Section 7), resource options (Section 8), evaluation of demand side measures 

(Section 9), and fundamental modeling parameters (Section 10). The modeling process and portfolio 

development, including the selection of the “Hybrid Plan” is covered in Section 11, and finally a risk 

analysis of selected portfolios is performed in Section 12. Section 13 describes the findings and 

recommendations and lastly, Section 14 describes the plan implementation. 

1.1 IRP Process Overview

This report presents the results of the Integrated Resource Plan (IRP) analysis for the AEP-SPP 

zone of the AEP System, covering the period 2009-2019, with additional planning modeling and 

analyses conducted through the year 2030. The information presented with this IRP (“Plan”) includes 

descriptions of assumptions, study parameters, methodologies, and results including the integration of 

supply-side resources and demand-side management (DSM) programs. The IRP process is displayed 

graphically in Exhibit 1-1. 

The goal of the IRP process is to identify the amount, timing and type of resources required to 

ensure a reliable supply of power and energy to customers at the least reasonable cost. 

In addition to the need to set forth a long-term strategy for achieving regional reliability/reserve 

margin requirements, capacity resource planning is critical to AEP due to its impact on: 

 Determining Capital Expenditure Requirements—which represents one of the basic 

elements of the Company’s long-term business plan. 

 Rate Case Planning—many of AEP’s regulated operating companies will plan rate 

recovery filings that will reflect input based on a prudent planning process. 

 Integration with other Strategic Business Initiatives—generation/capacity resource 

planning is naturally integrated with the Company’s current and anticipated environmental 

compliance, transmission planning, and other corporate planning initiatives such as 

gridSMARTsm. 

1.2 Introduction to AEP 

AEP, with more than five million American customers and serving parts of 11 states, is one of 

the country’s largest investor-owned utilities. The service territory covers 197,500 square miles in 

Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and 

West Virginia. 
AEP-SPP 2009 Integrated Resource Plan 

 2 

AEP owns and/or operates 58 generating stations in the United States, with a capacity of 

approximately 37,000 megawatts. AEP’s customers are served by one of the world’s largest 

transmission and distribution systems. System-wide there are more than 39,000 circuit miles of 

transmission lines and more than 213,000 miles of distribution lines. 

AEP’s operating companies are managed in two geographic zones for resource planning 

purposes. Its SPP zone, which comprises two companies in the Southwest Power Pool (SPP): Public 

Service Company of Oklahoma (PSO) and Southwestern Electric Power Company (SWEPCO); and 

its eastern zone, comprising Indiana & Michigan Power Company (I&M), Kentucky Power Company 

(KPCo), Ohio Power Company (OPCo), Columbus Southern Power Company (CSP), Appalachian 

Power Company (APCo), Kingsport Power Company (KgP), and Wheeling Power Company 

(WPCo).2

Exhibit 1-1: IRP Process Overview 

IRP Process IRP Process

Integrated 

Resource

Plan

for 

Capacity

Resources

Integrated 

Resource

Plan

for 

Capacity

Resources

Q1 Q2

“Demand-Side” 

Inputs CP&B, Commercial 

Operations

 Load & Demand 

Forecast

 (Market) Purchase & 

Sale of Firm Capacity & 

Energy

 (Incremental) DR/EE 

estimates

 Regional (PJM/SPP) 

Reserve Requirements

“Supply-Side” 

Inputs

Generation, 

Commercial 

Operations,Trans. 

Planning

 Existing Unit Cap., 

Cost & Performance 

Parameters

 New & Emerging 

Generation Alternatives, 

Cost & Perf. Parameters

 (Existing) Gen Oppor. 

(Size, type, cost)

 (Emerging) 

Transmission Issues & 

Constraints

Unit Disposition Evaluation

Generation, Comm Ops, CP&B

 Development of Potential Unit 

Retirement Profile

Tranche/Timing

Major Process Input/Parameters

‘MECO’ 

Modeling

Generation, 

Strategic 

Policy 

Analysis

Least-cost

Environ. 

Compliance 

Analyses re

SO2, NOx, Hg

Strategist

Resource 

Modeling CP&B

 Least-Cost

Optimal Resource 

Plan

 Sensitivity 

Analyses (re price, 

load, etc.)

 Create multiple 

Generation 

“Portfolio” Views

Utility Risk Simulation 

Analysis (URSA) 

Modeling

Market Risk Oversight

 Risk Simulation of Discrete, 

Strategist-based LT Portfolios 

across “Key Risk Drivers”

BASE 

Plan 

&

Scenarios

Financial / 

Regulatory 

Modeling

CP&B

 Financial / 

Budgetary 

Proformas

 Opco/Juris. 

Cost-of-Service 

and Revenue 

Requirement 

Impacts

Iterative Modeling

Iterate, as necessary, based on 

emerging issues / planning criteria, risk 

profiles, as well as corporate financial 

and regulatory recovery constraints.

Plan Develop. & Validation

Emerging Planning Policies / Scenarios

Generation, SPA, Commercial Ops, Transmission Planning, CP&B, Regulatory, Legal

 Add’l Environmental Constraints (e.g. GHG/CO2)... Demand Response/Energy Efficiency / Renewable Portfolio 

Standards / Carbon Offsets / Other Emerging Technology Alternatives

 AEP-Ohio, generation/planning ‘status’ post-ESP; other emerging opco/state-specific requirements

 RTO (PJM & SPP) business rule/protocol migrations & LT Transmission Planning (RTEP & STEP)

AEP 

Strategic 

Plan

Aurora

Fundamental 

Pricing 

Modeling

CP&B,Strategic Policy 

Analysis, 

Generation

Long-term

(regional) 

Commodity 

Pricing 

Forecasts re

Energy, Natural Gas, Coals, Emissions

Modeling within CP&B

Modeling outside of CP&B

Q4 Q3

Document / Filing

Corporate 

(E & W) and

Operating 

Co./Statespecific Plan 

Documentation 

and Filings

Louisiana

(rules pending)

Ohio

(rules pending)

Kentucky

Virginia

Indiana

Arkansas

Oklahoma

Source: AEP Resource Planning 

 

2

 Both KgP and WPCo are non-generating companies purchasing all power and energy under FERC-approved 

wholesale contracts with affiliates APCo and OPCo, respectively. AEP also has two operating companies that 

reside in the Electric Reliability Council of Texas (ERCOT), AEP Texas North Company (TNC) and Texas 

Central Company (TCC). These companies are essentially “wires” companies only, as neither owns nor 

operates generating assets within ERCOT. 
AEP-SPP 2009 Integrated Resource Plan 

 3 

Other than a discussion of the requirements of the FERC-approved AEP System Integration 

Agreement (SIA), this document will only address 2009 resource planning for the AEP-SPP zone. 

Planning for AEP affiliates residing in AEP-East has been communicated in separate documents. 

1.2.1 AEP-SPP Zone: 

The operating companies in AEP's SPP zone collectively serve a population of about 3.83 

million customers (995,050 retail) in a 36,000 square mile area in parts of Arkansas, Louisiana, 

Oklahoma, and Texas (see Exhibit 1-2). In 2008, the residential, commercial, and industrial 

customers accounted for 29%, 27%, and 27%, respectively, of AEP-SPP's total internal energy 

requirements of 42,868 GWh, including energy losses. The remaining 17% was supplied for use in 

the other retail and wholesale categories. 

AEP-SPP experienced an all-time peak internal demand of 9,120 MW on August 4, 2008. An 

all-time winter peak internal demand, 6,902 was experienced on February 16, 2007.The capacity 

resource planning of the respective AEP-SPP and East zones is performed on a mutually-exclusive 

basis regardless of the covenants of the System Interchange Agreement (SIA). 

Exhibit 1-2: AEP System, East and West Zones 

Source: AEP Internal Communications 

1.2.2 Embedded Baseload Assets 

Both the proposed Turk (SWEPCO) baseload ultra-supercritical pulverized coal (USC-PC) plant 

and a Stall Combined Cycle (CC) plant were considered embedded for 2009 AEP-SPP resource 

planning purposes, as they were secured during the SWEPCO 2006 Long-term Baseload Resource 

Request For Proposal (RFP) process. The 2008 PSO RFP process resulted in the selection of a 

purchase power agreement (PPA) with Exelon for the 512 MW Green Country combined cycle 

Focus of this 

IRP 
AEP-SPP 2009 Integrated Resource Plan 

 4 

facility which is also embedded in this IRP. These additions were approved by the appropriate state 

regulatory commissions based, in part, on the demonstrated need at the time the applications were 

filed. During the past year, the economic downturn has lead to reduced load growth forecasts in the 

near term. However, SWEPCO and PSO, respectively, still find these facilities necessary to the meet 

the peak demand and energy needs of their customers. To illustrate this point, the Exhibit 1-2 for 

PSO and Exhibit 1-3 for SWEPCO have been prepared to show the reserve margin exposure with 

and without these resources. 

Exhibit 1-3: PSO Reserve Margin With and Without Exelon PPA 

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Reserve Margin

Under "Base" Demand Forecast:

Per 2009 Resource Plan 13.8% 13.2% 19.2% 19.7% 19.9% 20.3% 19.5% 19.3% 18.7% 18.1%

Exclusive of Exelon PPA (2012) 13.8% 13.2% 6.9% 7.4% 7.6% 7.9% 7.2% 7.1% 6.5% 6.1%

Under "Accelerated (High)" Demand Forecast:

Per 2009 Resource Plan 11.0% 8.2% 15.2% 14.8% 14.2% 14.2% 13.2% 12.6% 11.6% 10.9%

Exclusive of Exelon PPA (2012) 11.0% 8.2% 3.2% 3.0% 2.5% 2.5% 1.5% 1.1% 0.2% -0.5%

Reserve Margin -- MW Position

 Above / <Below> 13.6% SPP Requirement)

Under "Base" Demand Forecast:

Per 2009 Resource Plan 6 (18) 232 253 259 275 242 237 211 190

Exclusive of Exelon PPA (2012) 6 (18) (280) (259) (251) (235) (268) (271) (297) (318)

Under "Accelerated (High)" Demand Forecast:

Per 2009 Resource Plan (108) (228) 65 51 26 24 (19) (46) (92) (124)

Exclusive of Exelon PPA (2012) (108) (228) (447) (461) (484) (486) (529) (554) (600) (632)

 * Excludes short-term capacity transfers to/from affiliate Southwestern Electric Power Company

Note: Minimum Reserve Margin Requirement per SPP Criteria is 13.6%

PSO

Stand-Alone Reserve Margins*

Based on (April 2009) Demand Forecast "Banding" 

10-Year 2009 IRP Period: 2010-2019

Source: AEP Resource Planning 

Exhibit 1-4: SWEPCO Reserve Margin With and Without Turk and Stall Plants

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Reserve Margin

Under "Base" Demand Forecast:

Per 2009 Resource Plan 13.8% 14.0% 13.3% 22.0% 20.6% 22.3% 20.9% 19.4% 17.6% 19.2%

Exclusive of Turk (2013) 13.8% 14.0% 13.3% 13.1% 11.9% 12.8% 11.6% 10.1% 8.5% 7.1%

Exclusive of Stall (2011) & Turk (2013) 13.8% 3.7% 3.1% 3.1% 1.9% 2.0% 0.9% -0.4% -1.8% -3.1%

Under "Accelerated (High)" Demand Forecast:

Per 2009 Resource Plan 11.0% 10.6% 9.4% 16.9% 14.9% 15.6% 14.0% 12.0% 10.0% 11.2%

Exclusive of Turk (2013) 11.0% 10.6% 9.4% 8.5% 6.6% 6.6% 5.2% 3.4% 1.5% -0.1%

Exclusive of Stall (2011) & Turk (2013) 11.0% 0.6% -0.4% -1.2% -2.9% -3.6% -4.9% -6.5% -8.2% -9.6%

 * Excludes short-term capacity transfers to/from affiliate Public Service Company of Oklahoma

Note: Minimum Reserve Margin Requirement per SPP Criteria is 13.6%

SWEPCO

Stand-Alone Reserve Margins*

Based on (April 2009) Demand Forecast "Banding" 

10-Year 2009 IRP Period: 2010-2019

Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 5 

As these exhibits illustrate, reserve margin requirements would fall below the minimum SPP 

criteria of 13.6% without these facilities under the most recent load forecast. AEP also prepared an 

“Accelerated (High)” Demand Forecast which assumes a more robust recovery from the current 

recession. Under this scenario, the need for the embedded assets is even more pronounced. 

1.2.3 AEP System Interchange Agreement (East and West) 

The 2000 System Interchange Agreement among AEPSC, as agent for the AEP-East, Central 

and Southwest Inc. (CSW), and AEP-SPP operating companies, was designed to operate as an 

umbrella agreement between the FERC-approved 1997 Restated and Amended CSW Operating 

Agreement for its western (former CSW) operating companies and the FERC-approved 1951 AEP 

Interconnection Agreement for its eastern operating companies. The System Interchange Agreement 

provides for the integration and coordination of AEP’s eastern and western companies’ zones. In that 

regard, the SIA provides for the option to transfer capacity and energy between the AEP-SPP zone 

and under certain conditions the AEP-East zone. Since the inception of the SIA, AEP has continued 

to reserve annually, the transmission rights associated with a prescribed (up to) 250 MW of capacity 

from the AEP-East zone to the AEP-West zone. This transmission capacity has now been reserved 

through 2013 and this reservation may be extended in five year increments. 

1.2.4 AEP-SPP Operating Agreement –Company-Specific Obligations 

The fundamental construct for this AEP-SPP IRP is that the initial planning evaluation be 

performed on an integrated basis among the applicable operating companies–PSO and SWEPCO–so 

as to leverage any opportunities such joint planning may offer as per the Operating Agreement. 

Specifically, Section 9.2 of that 1997 Restated and Amended SPP (CSW) Operating Agreement 

establishes that “...ownership share in each Joint Unit shall be allocated insofar as practical to 

achieve a Prorated Reserve Level for all Companies participating in the Unit.” 

However, the Operating Committee of the AEP-West Operating Agreement issued a formal 

recommendation in December 2005, stating that the PSO and SWEPCO capacity-build as established 

by the 2005 IRP cycle, and embedded within this 2009 IRP cycle, should not be considered for jointownership. This is due to the significant amount of capacity required by both companies for each duty 

cycle/type, and the parallel timing of those significant needs. 

For the same reasons identified in 2005 by the Operating Committee, at a minimum, the 

(embedded) build tranche through the nearer-term 2012 timeframe will naturally continue to be set 

forth on a “stand-alone” (PSO and SWEPCO) basis. Therefore, largely for consistency and 

considering the current, known intercompany firm transmission constraints between PSO and 

SWEPCO that will be discussed in this 2009 report, as well as specific regulatory (needs 

determination/cost recovery and competitive bidding) issues, subsequent new capacity resource 

tranches (beyond 2012) will also be considered from a company-specific, stand-alone perspective. 

That said, the ultimate makeup/ownership of such subsequent AEP-SPP capacity resource tranches 

will likewise need to be reconsidered over future planning cycles from a shared-benefit perspective. 
AEP-SPP 2009 Integrated Resource Plan 

 6 
AEP-SPP 2009 Integrated Resource Plan 

 7 

2.0 Current Resource Planning Issues in the Electric Utility Industry 

2.1 Regulation/Deregulation 

Both SWEPCO and PSO are regulated, and are expected to remain regulated throughout the IRP 

ten-year period. This includes the portion of SWEPCO’s retail load residing in Texas, but outside of 

ERCOT. Texas Senate Bill 547, which was signed into law in May 2009, statutorily delays retail 

electric competition for SWEPCO in Texas until the proper infrastructure is in place. The new law 

becomes effective September 1, 2009 and virtually assures that SWEPCO will remain regulated 

during the period of the IRP. 

2.2 Climate Change and Greenhouse Gases 

A growing consensus of scientists concludes that the Earth’s climate is warming and that the 

warming is due, at least in part, to anthropomorphic production of greenhouse gases (GHG). Many 

gases exhibit greenhouse properties; some occur naturally, others are exclusively man-made. While 

Carbon Dioxide (CO2) is the most prevalent and significant greenhouse gas in terms of its global 

warming potential, there are other major greenhouse gases including methane (CH4), nitrous oxide 

(N2O) and chlorofluorocarbons (CFCs). 

Gases are typically quoted in terms of either CO2, carbon dioxide equivalents (CO2e) or carbon 

equivalents (Ce). CO2 has an atomic weight of 44 while carbon has an atomic weight of 12. Thus, 

CO2 equivalents are 3.67 times the mass of carbon equivalents, but the two measures have the same 

relative purpose and can be used interchangeably if consistently applied. Anthropomorphic CO2 is 

produced primarily from burning fossil fuels, a portion of which is used to produce electricity. In the 

U.S., roughly one-third of GHG (measured in CO2e) result from the conversion of fossil fuels to 

electricity. 

Finally, the fuel and heat rate of the plant used in the production of electricity makes a 

difference in the quantity of CO2 produced. Exhibit 2-1 demonstrates the advantage lower heat rates 

(Btu/kWh) and fuel types can have. 

Exhibit 2-1: Fossil Fuel-to-Electricity Emissions, by Fuel Type 

0

0.2

0.4

0.6

0.8

1

1.2

6,000 6,500 7,000 7,500 8,000 8,500 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000

Heat Rate

Tons CO2/MWh

Ultra Super Critical/ IGCC

Super Critical

Existing

Existing Steam

Combustion Turbine

Combined Cycle

Natural Gas

Coal

IGCC

Combined Cycle

Ultra-Supercritical

Supercritical Subcritical

Units with 90% Carbon Capture

Units without Carbon Capture

Natural Gas Coal

Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 8 

2.2.1 Environmental Legislation 

The electric utility industry, as a major producer of CO2, will be significantly affected by any 

GHG legislation. During the 109th Congress (2005-2006), 106 bills, resolutions, and amendments 

specifically addressing global climate change and greenhouse gas emissions were introduced. In 

110th Congress, more than 235 bills were introduced that would put controls on the emissions of 

greenhouse gases. One Senate bill, Lieberman-Warner, was voted out of the Senate Environmental 

Committee and received floor consideration in June 2008. However, after a few days of debate, the 

bill failed to pass a Senate cloture vote. The push towards federal climate change legislation is 

continuing within the 111th Congress as well. The Waxman-Markey “American Climate and Energy 

Security Act of 2009” was recently passed out of the House Energy and Commerce Committee, was 

subsequently approved by the House of Representatives in June, and is now being considered by the 

Senate. Virtually all of these bills employed “cap and trade” mechanisms (rather than carbon taxes) 

with declining CO2 caps over time. 

2.2.2 Impact of Environmental Legislation on Industry 

Any binding legislation is likely to be “economy-wide”–generally meaning all fossil fuel use 

will be targeted–because the production of GHG is not limited to specific sectors. Most legislation 

that has been introduced to date is economy-wide. Furthermore, most legislation caps electric utility 

emissions “downstream.” That is, electric generator emissions are limited, similar to the EPA’s 

current programs that limit utility SO2 and NOx emissions. 

2.2.2.1 AEP’s Assumption on CO2 Policy/Price 

For the 2009 IRP cycle, the impact of CO2/GHG legislation on AEP’s long-term planning is 

essentially modeled as a simple CO2 price beginning in 2015, as shown in Exhibit 2-2, that would 

impact fossil unit dispatch cost. 

Exhibit 2-2: CO2 Price Forecast 

Emissions CO2 Index 2015 $/metric tonne = 1.0

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

CO2 2H08

Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan 

 9 

2.2.2.2 Renewable Portfolio Standards 

As identified in Exhibit 2-3, 29 states and the District of Columbia have set standards 

specifying that electric utilities generate a certain amount of electricity from renewable sources. Most 

of these requirements take the form of “renewable portfolio standards,” or RPS, which require a 

certain percentage of a utility sales to ultimate customers come from renewable generation sources by 

a given date. The standards range from modest to ambitious, and definitions of renewable energy 

vary. Though climate change may not always be the primary motivation behind some of these 

standards, the use of renewable energy does deliver significant GHG reductions. For instance, Texas 

is expected to avoid 3.3 million tons of CO2 emissions annually with its RPS, which requires 2,000 

MW of new renewable generation by 2009. 

At the federal level, an RPS ranging from 10-20% was proposed for inclusion in the Energy 

Independence and Security Act of 2007; but the final bill as passed into law did not contain an RPS. 

However, a combined federal renewable energy standard (RES) and energy efficiency standard (EES) 

of 20% was adopted as part of the Waxman-Markey bill passed by the House. The Senate also passed 

out of Committee a combined 15% RES/EES and is also considering the House legislation. 

Therefore, a federal RPS remains a distinct possibility in 2009 or 2010. 

Exhibit 2-3: Renewable Standards by State 

Renewable Portfolio Standards

State renewable portfolio standard

State renewable portfolio goal

www.dsireusa.org / July 2009

Solar water heating eligible

*

†

Extra credit for solar or customer-sited renewables

Includes separate tier of non-renewable alternative resources

WA: 15% by 2020*

OR: 25% by 2025 (large utilities)

5% - 10% by 2025 (smaller utilities)

CA: 20% by 2010

☼ NV: 25% by 2025*

☼ AZ: 15% by 2025

☼ NM: 20% by 2020 (IOUs)

10% by 2020 (co-ops)

HI: 20% by 2020

☼ Minimum solar or customer-sited requirement

TX: 5,880 MW by 2015

UT: 20% by 2025*

☼ CO: 20% by 2020 (IOUs)

10% by 2020 (co-ops & large munis)*

MT: 15% by 2015

ND: 10% by 2015

SD: 10% by 2015

IA: 105 MW

MN: 25% by 2025

(Xcel: 30% by 2020)

☼ MO: 15% by 2021

IL: 25% by 2025

WI: Varies by utility; 

10% by 2015 goal

MI: 10% + 1,100 MW 

by 2015*

☼ OH: 25% by 2025†

ME: 30% by 2000

New RE: 10% by 2017 

☼ NH: 23.8% by 2025

☼ MA: 15% by 2020

+ 1% annual increase

(Class I Renewables)

RI: 16% by 2020

CT: 23% by 2020

☼ NY: 24% by 2013

☼ NJ: 22.5% by 2021

☼ PA: 18% by 2020†

☼ MD: 20% by 2022

☼ DE: 20% by 2019*

☼ DC: 20% by 2020

VA: 15% by 2025*

☼ NC: 12.5% by 2021 (IOUs)

10% by 2018 (co-ops & munis)

VT: (1) RE meets any increase 

in retail sales by 2012;

(2) 20% RE & CHP by 2017

29 states & DC

have an RPS

5 states have goals

KS: 20% by 2020
AEP-SPP 2009 Integrated Resource Plan 

 10 

2.2.3 AEP’s Voluntary Greenhouse Gas Mitigation Strategy 

2.2.3.1 Plan through 2010 

As a founding member of the Chicago Climate Exchange (CCX), AEP committed to 

cumulatively reduce or offset 48 million metric tons of CO2 emissions from 2003 to 2010. Through 

2008, AEP reduced or offset 51 million metric tons of CO2 — exceeding our target. We’ve done this 

in a number of ways, such as improving power plant efficiency, replacing or retiring less efficient and 

higher emitting units, increasing our use of renewable power, reducing SF6 emissions and investing in 

forestry projects in the United States and abroad. For example, we have signed contracts to add 903 

MW of wind capacity in the past two years — about 90 percent of our goal toward adding 1,000 MW 

of wind by 2011. Consequently, we will double this goal and add a total of 2,000 MW of renewable 

energy by the end of 2011, with regulatory support. 

This will help AEP to further diversify its fuel portfolio. This plan contains a minimal 10 

percent renewable energy target by 2020. AEP already plans to go beyond its initial commitment. 

AEP has made significant progress in reducing a potent GHG — SF6 — which is found in some 

electrical equipment. When AEP joined the Environmental Protection Agency’s (EPA) SF6 Emission 

Reduction Partnership in 1999, our SF6 leakage rate was 10 percent. In 2008, this rate had been 

reduced to 0.38 percent based on total system capacity, falling well below a self-imposed goal to 

achieve a maximum 2.5 percent leak rate from 1996 levels. This was done by employing a 

combination of technologies such as replacing SF6 insulated circuit breakers on lines to lower leakage 

rates. 

2.2.3.2 Post-2010 Plan For Voluntary Reductions 

AEP’s post-2010 strategy is to voluntarily reduce or offset an additional 5 million tons of CO2

per year by purchasing offsets from projects such as forestry, reducing methane from agriculture, 

adding more renewable energy in our portfolio and improving the efficiency of our power plants. The 

investments AEP has made in its coal-fired power plants make them more efficient than the national 

average for coal plants. Between 2001 and 2007, these improvements helped us to avoid burning 16.2 

million tons of coal, preventing the release of 39 million tons of CO2. 

AEP has signed contracts to add 903 MW of wind capacity in the past two years — about 90 

percent of our original goal toward adding 1,000 MW of wind by 2011. In light of the increasing 

number of state mandates and potential federal legislation, as well as the upcoming expiration of the 

PTC, AEP will double this goal and add a total of 2,000 MW of renewable energy by the end of 2011, 

with regulatory support. This will help us to further diversify our fuel portfolio. This integrated 

resource plan contains a 10 percent renewable energy target by 2020. 

As discussed in the following section, additional actions, including a future carbon capture and 

storage program, will also help offset the anticipated growth in AEP’s carbon footprint. 

2.2.3.3 The Role of Technology 

Throughout its 100-year history, AEP has led the industry in advancing technology. The time is 

right, with climate legislation on the horizon, to advance carbon capture technology to a commercial 

scale. In March 2007 AEP signed agreements with world-renowned technology providers for carbon 
AEP-SPP 2009 Integrated Resource Plan 

 11 

capture and storage. A “product validation facility” is being constructed at the Mountaineer Plant in 

West Virginia. 

The Mountaineer project will employ Alstom’s chilled ammonia carbon capture technology 

(Exhibit 2-4). Laboratory testing has shown that this process could capture more than 90 percent of 

CO2 at a lower cost than other technologies that could be retrofitted at pulverized coal power plants. 

A vendor-sponsored project demonstrating the technology was successfully completed on a 1.7 MW 

(electric) slipstream at Pleasant Prairie a Wisconsin plant in 2008. This projected operated around the 

clock for over 4,600 hours capturing 88 – 90 percent of CO2 emissions, and achieved purity levels 

exceeding 99 percent. 

Exhibit 2-4: CO2 Capture and Sequestration Process 

Source: 2007AEP Corporate Responsibility Report 

The chilled ammonia technology equipment is now being installed on AEP’s 1,300-MW 

Mountaineer Plant as a 20MW (electric) product validation in the second half of 2009. It is designed 

to capture approximately 100,000 metric tons of CO2 per year over a four to five year period, which 

will be stored in deep geologic reservoirs. Battelle Memorial Institute is serving as AEP’s consultant 

on geological storage. Following the completion of commercial verification AEP plans to scale up 

the Mountaineer Chilled Ammonia Process (CAP) to capture CO2 from a 235 MWe slip stream. 

AEP is seeking funding from the U.S. Department of Energy to then further scale up the Mountaineer 

CAP to capture carbon dioxide from the entire flue gas stream. The expectation is for the commercial 

scale technology to have a 90% capture rate of approximately 1.5 million tons of CO2 per year. 

A second carbon capture technology AEP considered involves oxy-coal combustion. This 

technology uses pure oxygen for the combustion of coal. Current generation technologies use air, 

which contains nitrogen that is not used in the combustion process and is emitted with the flue gas. 

By eliminating the nitrogen, this process leaves a flue gas that is a relatively pure stream of CO2 that 

is ready for storage. At commercial scale, the CO2 likely would be stored in deep geologic 

formations. 
AEP-SPP 2009 Integrated Resource Plan 

 12 

AEP’s vendor B&W completed a pilot demonstration and retrofit feasibility study in 2nd 

Quarter 2008. Unfortunately, this technology proved to be cost prohibitive for use on our sub-critical 

coal fleet. 

2.3 Role and Impact of Commodity Pricing on Planning 

Note: This section includes excerpts from the “Long Term Price Forecast 2009-2030: Return to 

Fundamentals, 2H-2008” prepared by AEPSC’s Strategic & Economic Analysis Group (SEA) and 

issued February 2009). Price forecasts are included in the Confidential Supplement. 

The internal process utilized by AEP-SEA for projecting fundamental commodity pricing 

utilized in long-term resource planning is 

a time-intensive and iterative process. 

Many factors ultimately affect power 

prices as shown in Exhibit 2-5. 

These numerous layers are also 

interdependent. For instance, oil prices 

affect rail transportation costs, which 

impact coal prices, which impact SO2, 

NOX, and power prices. It is easy to see 

how minor deviations in one commodity 

can have a trickle-down effect to power 

prices. 

The fundamental price drivers in the 

modeling performed for the entire eastern 

interconnect, as well as PJM, are the 

assumptions around fuel prices, new 

capacity builds and retirement, and load 

growth. In the near term, fuel prices and 

load growth play the most important role. 

2.3.1 Power Prices 

In the short-term, wholesale electricity prices remain extremely volatile due to the uncertainty in 

the economy, environmental policy, and commodity markets. As such, the short term Reference price 

does not fully capture the most recent market signals – see Confidential Supplement for a revised 

short term forecast. In general, the Reference forecast overestimates current market prices. 

In the mid-term, the value of the forecast resides less in the ability to precisely predict the power 

price and more in the ability to accurately capture the trends in the power market. Starting in the midterm, the Reference Case begins to deviate from the external forecasts due to a range of views on 

environmental policy and commodity markets. In particular, resolution on greenhouse gas (GHG) 

legislation is expected to result in a range of power market trends. 

In the Reference Case, carbon policy (2015) is incorporated in the power price – see Exhibit 2-

6. To an average coal market, the Reference carbon policy could represent an immediate increase in 

Exhibit 2-5: Power Price Layers 

Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan 

 13 

the power price. In addition, the Reference carbon policy disproportionately impacts coal markets on 

and off peak power prices. For example, in SPP on-peak prices increase 28% compared to 32% in the 

off-peak market over the same period. 

Exhibit 2-6: SPP On-Peak Price Index 

SPP On-Peak Power Prices Index 2009 $/MWh = 1.0

0.0

0.5

1.0

1.5

2.0

2.5

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Source: AEP Fundamental Analysis 

2.3.2 Fuel 

2.3.2.1 Natural Gas

United States natural gas supply and consumption is currently rather loosely balanced because 

of the global recession, but the market is still vulnerable to price spikes resulting from weather or 

supply disruptions. Prices in 2009, while still reflective of Hurricane Ike-related supply loss, will 

decline through 2012 as domestic natural gas production reverses its traditional decline due to 

heretofore unconventional exploitation plays (see Exhibit 2-7). 

Beyond 2014, unconventional natural gas production, buoyed by technology advancements, 

provide adequate supply to meet demand when given long-term price signals above finding and 

production costs of approximately $5.00 - $6.00/MMBtu (in 2008 dollars). The factor that will most 

likely shape the fundamentals of overall gas demand will be the growth of gas consumption for 

electricity generation. Additionally, the Alaskan Pipeline, projected to be on line in 2023, will deliver 

gas from the North Slope to the Chicago Citygate. 

Exhibit 2-7: Natural Gas Price Index 

Gas Price PEPL TX-OK Index (2H08 2009 $/mmBtu = 1.0)

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

PEPL TX-OK 2H08

Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan 

 14 

2.3.2.2 Coal

Coal is a unique commodity that comes with many different specifications. Coal is traded overthe-counter at relatively thin volumes. The majority of coal transactions are done through contracts 

between sellers and buyers, which sometimes results in significant differences between coal spot 

prices and contract prices. Because of the high percentage of transportation cost relative to total 

delivered coal cost and the significant capital investment required for a boiler to switch from one type 

of coal to another, Btu and/or SO2 spreads may not hold when comparing different types of coal. In 

addition to coal quality, reliability of coal delivery is another factor to consider in coal pricing. The 

forecast (Exhibit 2-8) represents coal prices under a contract of 2-5 years, rather than spot prices. 

During 2008, both international and U.S. domestic coal markets were on a rollercoaster. In 

January of 2008, the international coal supply chain was disrupted by coal mine region flooding in 

Australia, severe winter storm in China, and power outages in South Africa. As a result of these 

events, coal producers in Australia declared force majeure for their mines in the flooding region, the 

Chinese government issued an order to suspend its coal exports, and South Africa reduced its coal 

output and exports. 

International coal markets reacted to the coal supply disruptions and pushed coal prices even 

higher for both thermal and metallurgical coals. High coal prices in international markets created a 

great opportunity for U.S. coal producers to gain higher profits by exporting coal to international 

markets rather than selling it in domestic markets. The increase in U.S. coal exports drained U.S. 

domestic coal supply, especially in the Appalachian region, because of its location advantage for coal 

export and its high energy content. 

Exhibit 2-8: PRB Coal Price Index 

COAL PRB FOB Index 2H08 2009 $/ton = 1.0

0.0

0.5

1.0

1.5

2.0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

PRB 8800 2H08

Source: AEP Fundamental Analysis

Now, the situation of supply shortage of metallurgical coal has reversed due to the global 

economic downturn. Demand for steel has been reduced dramatically, and the international 

metallurgical coal benchmark at Newcastle of Australia is expected to be around $130/metric ton. 

This is much lower than the $300/metric ton peak in 2008. The U.S. metallurgical coal exports fell 

and the metallurgical coal producers in Appalachia are cutting their production, in contrast to 

production expansion in early and middle 2008. For example, Consol closed its Mine 84, citing low 

metallurgical coal prices. 
AEP-SPP 2009 Integrated Resource Plan 

 15 

2.3.3 New Build Cost 

The capital cost forecast trends for pulverized coal, integrated gasification combined cycle 

(IGCC), and nuclear power plants show similar trends. Capital costs have increased significantly from 

rising materials, equipment, and labor. However, costs have declined recently due to the credit crisis 

and economic concerns. Demand has dropped as companies look to delay their project schedules or 

cancel projects outright. Demand has also dropped from industries that share similar materials and 

labor with the energy industry. These factors lead to a downward trend in forecasts in the near term. 

Longer term shows a slight upward trend, as demand returns in future years. 

Given the trend for natural gas units to be built due to the combination of low capital cost, short 

time frame to build, environmental uncertainty, and relatively lower gas price projections, the cost of 

a gas plant will be driven more on the physical supply chain constraints of constructing the plant 

versus the variable cost of the plants as seen in the base load unit profile. Gas plants are unlikely to 

follow the downward projection of steel prices. 

Renewable capacity offers almost no variable cost and for some renewables, reasonable capital 

cost. However, the reliability and the amount of land required for renewable is a concern. The 

primary driver for renewable build will be the environmental policies and technical improvements to 

lower the cost of renewable generation and the build out of transmission capacity to move the wind 

energy to the load centers. 

 Wind power has also experienced recent high material and equipment costs, as well as a 

sharp increase in demand. U.S. wind power projects have increased significantly in recent years. 

Reduced material costs and slower future growth rates may lead to wind power cost forecasts trending 

downward in the near term. 

 Solar power is still in its early stage for wide commercial applications for power generation. 

It is not as prevalent commercially as other types. Near term solar forecasts will benefit from reduced 

material costs. Longer term forecasts show additional benefits as the technology develops and solar 

power enjoys a better economy of scale. 

2.3.4 Load Growth 

The most overriding short-term concern for the economy is the recession. The National Bureau 

of Economic Research (NBER), the official arbiter of the timing of recessions, has stated that the 

recession began in December 2007. NBER utilizes data beyond the classic real Gross Domestic 

Product (GDP) to gauge the beginning and ending of recessions. As an aside, the common definition 

of recession is two consecutive quarters of negative GDP growth. The current recession has been 

lengthy when compared with previous post World War II recessions. The longest recessions in this 

period were 16 months and it appears likely that this economic downturn will exceed this length. 

2.3.5 Emissions 

2.3.5.1 SO2, NOX, and Mercury (Hg) 

Environmental policy is one of the most fluid and unstable factors impacting the accuracy of the 

long-term forecast. Policy options range from the Business-As-Usual Case (government policy is 
AEP-SPP 2009 Integrated Resource Plan 

 16 

very unlikely to become less regulated) to an extremely restrictive option with the potential to 

significantly alter how the country fuels its electricity consumption. 

On February 8, 2008, the D.C. Court vacated the Clean Air Mercury Rule (CAMR) governing 

the release of mercury emissions. Today, there are no uniform technology standards or market-based 

programs for mercury in the states in which AEP operates, although some other states have 

established mercury control programs. According to the Environmental Group, Federal action is 

anticipated and could become effective in 2014 when a command-and-control policy could require all 

coal units to install either a mercury-specific control technology such as Activated Carbon Injection 

(ACI) or Flue Gas Desulphurization/Selective Catalytic Reduction (FGD/SCR) emissions control 

equipment. For development of market scenarios, the 2H08 forecast limits the FGD/SCR 

installations to projects currently under construction as a result of equipment economics and the 

evolution in emission regulations. 

There is also a strong possibility that a plant-by-plant standard will replace a mercury trading 

system. If this is the case, a dispatch price would not be required, but additional controls such as 

baghouses or ACI would be needed. This could have an impact on proposed retirement dates of older, 

non-controlled units and ultimately the timing for new capacity. When new standards and 

implementation timelines are known, our plan will be re-evaluated and adjusted accordingly. 

On July 11, 2008, the D.C. Circuit Court invalidated the Clean Air Interstate Rule (CAIR), and 

the rule has been remanded to EPA. Today, policy alternatives remain fluid. The AEP Environmental 

Group expects the CAIR program to be replaced with a more restrictive policy. In particular, the 

absence of any guidance from EPA, the Environmental Group has postulated a scenario in which SO2

and NOx emissions will be 10 percent below the CAIR Phase II limits (fully implemented by 2025) 

and exclude an allowance bank to meet emission targets. In the 2H08 forecast, annual NOx emissions 

require a $1,000/ton price signal to remain in compliance, while SO2 emissions require a significant 

price signal and an allowance bank to meet emission targets (Exhibit 2-9). The consultant forecast 

represents the uncertainty associated with a replacement to CAIR, where policy options range from a 

command-and-control policy (CERA-Breakpoint) to an additional constraint applied to the current 

policy. However, the cap-and-trade policies typically include an allowance bank to meet emission 

targets. 
AEP-SPP 2009 Integrated Resource Plan 

 17 

Exhibit 2-9: SO2 Emission Price Index 

Emissions SO2 Index 2H08 2009 $/ton = 1.0

0

5

10

15

20

25

2009

20102011

2012

201320142015

2016

20172018

2019202020212022

202320242025

20262027

2028

20292030

SO2 2H08

Source: AEP Fundamental Analysis 

2.3.5.2 CO2 

The forecasting of future CO2 allowance prices is subject to considerable uncertainty as the 

underlying assumptions are entirely predicated upon a yet to be defined federal climate policy. 

Strategic Policy Analysis has developed three potential CO2 price forecasts for each of the cases 

(Exhibit 2-10). These forecasts attempt to represent a range of potential policy outcomes and 

resulting pricing to account for the uncertainty. The Abundance and Constrained Cases are based on 

the realistic limits of U.S. climate policy given current political and economic realities, while the 

Reference Case is a weighting of the high and low forecasts and represents the most likely price 

trajectory. Note: As the political and economic situation changes so will the politically acceptable 

pricing range and likely pricing trajectory. 

Exhibit 2-10: CO2 Emission Price Index 

 CO Price Index, Reference Case 2015 $/metric tonne = 1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Low CO2 Reference High CO2

Source: AEP Fundamental Analysis

The price forecasts were developed at the beginning of 2009 based on public analyses of two of 

the most prominent pieces of comprehensive U.S. climate legislation; the “Low Carbon Economy Act 

of 2007” introduced by Senators Bingaman and Specter and the “Climate Security Act of 2008” 
AEP-SPP 2009 Integrated Resource Plan 

 18 

introduced by Senators Lieberman and Warner. The Bingaman-Specter bill was widely supported by 

industry for its moderate emission reduction timeline, while the Lieberman-Warner was praised by 

environmentalists for its more aggressive emission reduction timeline. Thus, these bills represent 

relative “bookends” for likely climate policy outcomes. 

*******************End of 2H08 Fundamental Analysis excerpt*********************** 

2.4 Issues Summary 

The increasing number of variables and their uncertainty has added to the complexity of 

producing an integrated resource plan. No longer are the variables merely the cost to build the 

generation, a forecast of what had traditionally been stable fuel prices and growth in demand over 

time. Highly volatile fuel prices, and uncertainty surrounding the economy and environmental 

legislation require that the process used to determine a resource plan is sufficiently flexible to 

incorporate more subjective criteria. The introduction of a cap-and-trade system and high capital 

construction costs weigh unfavorably on solid-fuel options, but conclusions must be metered with the 

knowledge that there is a great deal of uncertainty. 

One way of dealing with uncertainty is to hedge one’s bets. That is, if there exists the potential 

for very expensive carbon legislation, one might favor a solution that minimizes carbon emissions, 

even if that solution is not the least expensive. While there may not yet be a national RPS, procuring 

or adding wind generation resources now will put a company ahead of the game if one does come to 

pass. In this way, the company is trading future uncertainty for a known cost. Lastly, adding 

diversity to the generating portfolio reduces the risk of the overall portfolio. That may not be the least 

expensive option in a “base” (or most probable) case, but it minimizes exposure to adverse future 

events and could reduce the ultimate cost of compliance if the resultant demand for renewable 

resources continues to grow, outpacing the supplier resource base akin to past experience associated 

with the “dash to gas”.. 

The long-term planning horizon is characterized by several primary variables. First and 

foremost, the prospect of legislation that in some way regulates GHGs. Any system enacted will likely 

result in: 

 Ultimate development and implementation of CO2 capture and sequestration technologies 

which, in the east where higher-quality bituminous coals are prevalent, could ultimately 

favor current Integrated Gasification Combined Cycle (IGCC) design technology over 

traditional Pulverized Coal (PC) plants. 

 Implementation of Renewable Portfolio Standards, either at a state or, ultimately, a national 

level. 

 Efficiency improvements, both supply and demand side. 

 A system for offsetting CO2 emissions. 

 Potential for volatile natural gas pricing marked by the offsetting effects of both increased 

supply and increased demand. 
AEP-SPP 2009 Integrated Resource Plan 

 19 

 Emissions allowance prices in light of the as yet unresolved CAIR and CAMR/mercury 

requirements, assumptions directly affecting the economic viability of uncontrolled coal 

generation. 

Finally, the IRP process was complicated further by the economic slowdown that escalated in 

late 2008, which resulted in very different near-term commodities forecasts. The 2H08 forecast was 

completed prior to this economic slow down. However, after comparing the long-term commodities 

forecasts used in this IRP (the 2H08 Forecast) to the subsequent long term forecast prepared in the 

Spring of 2009 (1H09 Forecast) as shown in Exhibit 2-11 it was apparent that the effects of the revised pricing 

estimates were negligible after 2013 and did not warrant a new resource evaluation. 
AEP-SPP 2009 Integrated Resource Plan 

 20 

Exhibit 2-11: 2H08 vs. 1H09 Commodities Comparison 

SPP On-Peak Power Prices Index (2H08 2009 $/MWh = 1.0)

0.0

0.5

1.0

1.5

2.0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

On-Peak 1H09 On-Peak 2H08

COAL PRB FOB Index (2H08 2009 $/ton = 1.0)

0.0

0.5

1.0

1.5

2.0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

PRB 8800 1H09 PRB 8800 2H08

Gas Price PEPL TX-OK Index (2H08 2009 $/mmBtu = 1.0)

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

PEPL TX-OK 1H09 PEPL TX-OK 2H08

Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan 

 21 

3.0 Implications of Industry Issues in this IRP Cycle 

3.1 Demand Response/Energy Efficiency (DR/EE) 

The AEP System (East and West/SPP zones) has adopted peak demand reduction and energy 

efficiency goals which are 1,000 MW and 2,250 GWh, respectively by year-end 2012. Concurrently, 

several states served by the AEP System have mandated levels of efficiency and demand reduction. 

There also exists the possibility of federally mandated efficiency levels. While this IRP establishes a 

method for obtaining an estimate of DR/EE that is reasonable to expect for the zone, as a whole; the 

ratemaking process in the individual states will ultimately shape the amount and timing of DR/EE 

investment. As those processes evolve and mature, the “order of magnitude” estimates can be refined 

and replaced with definitive programs. 

3.2 Renewables 

Renewable Portfolio Standards and goals have been enacted in over one half of the states in the 

U.S. Adoption of further RPS at the state level or the enactment of Federal carbon limitations or 

RPS, will impose the need for adding more renewables and the potential expenditure of billions of 

dollars. 

Wind is currently one of the most viable large-scale renewable technologies (with incentives) 

and has been added to utility portfolios mainly via long-term power purchase agreements. Recently, 

many IOUs have begun to add renewable assets to their portfolios. The best sites in terms of wind 

resource and transmission are rapidly being secured by developers. Further, while an extension of the 

Federal Production Tax Credit (PTC) for wind projects - to the end of 2012 - was enacted in February 

2009, it will probably not be extended further as the implementation of Federal carbon or RPS is 

expected to make unnecessary the incentive provided by the PTC. Acquiring this renewable energy 

and/or the associated Renewable Energy Credit (REC) or Carbon Offset now will likely limit the risk 

of increased cost that comes with waiting for further legislative clarity in the AEP states. 

 In early 2007, AEP committed to the acquisition of energy from 1,000 MW (nameplate) of 

additional wind generation projects by the end of 2010 via long-term purchase power agreements as 

part of AEP’s comprehensive strategy to address greenhouse gas emissions. In light of progress in 

meeting this commitment, the goal was expanded in early 2009 to 2,000 MW by the end of 2011. 

SWEPCO is already receiving energy from one wind project with nameplate rating of 79.5 MW. 

Additional contracts have been executed for PSO for an additional 198 MW to be placed in service by 

December, 2009 which will result in a total of 591 MW or approximately 12 percent of PSO’s energy 

needs being met with renewables. Exhibit 3-1 lays out the AEP-SPP zone’s renewable plan by 

operating company to meet its share of this target. 

As can be seen in Exhibit 3-1, PSO and SWEPCO have a greater contribution to the renewable 

goal than the remaining AEP companies. This is due to wind being economically favored in states 

like Oklahoma and Texas, particularly due to the higher wind profile. Wind is the primary source of 

renewable energy in the AEP plan. 
AEP-SPP 2009 Integrated Resource Plan 

 22 

Exhibit 3-1: Renewable Energy Plan Through 2030 

AEP SYSTEM

Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl

Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent

(MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales

2009 0 393 0 9.4% 0 31 0 0.6% 0 424 0 5.0% - 499 - 1.3%

2010 0 393 0 9.0% 0 111 0 2.3% 0 503 0 5.6% 10 1,029 - 2.5%

2011 0 591 0 13.3% 0 211 0 4.3% 0 801 0 8.6% 13 2,027 10 4.5%

2012 0 591 0 12.8% 0 311 0 6.3% 0 901 0 9.5% 15 2,827 109 6.4%

2013 (b) 0 591 0 12.7% 0 461 0 9.3% 0 1,051 0 10.9% 29 3,477 235 8.0%

2014 0 591 0 12.6% 0 461 0 9.2% 0 1,051 0 10.9% 42 3,477 235 8.0%

2015 0 658 0 14.0% 0 494 0 9.8% 0 1,151 0 11.8% 56 3,577 385 8.8%

2016 0 658 0 13.9% 0 594 0 11.6% 0 1,251 0 12.7% 70 3,777 385 9.1%

2017 0 858 0 18.0% 0 594 9 11.7% 0 1,451 9 14.7% 83 3,977 394 9.6%

2018 0 858 0 17.9% 0 594 9 11.6% 0 1,451 9 14.6% 100 3,977 521 10.1%

2019 0 858 0 17.8% 0 594 9 11.4% 0 1,451 9 14.5% 118 3,977 650 10.5%

2020 0 1,058 0 21.8% 0 594 9 11.3% 0 1,651 9 16.3% 133 4,377 650 11.3%

2021 0 1,058 0 21.6% 0 694 9 12.9% 0 1,751 9 17.0% 168 4,627 777 12.2%

2022 0 1,058 0 21.4% 0 794 9 14.6% 0 1,851 9 17.9% 220 4,827 777 12.6%

2023 0 1,158 0 23.3% 0 794 9 14.4% 0 1,951 9 18.6% 220 5,027 904 13.3%

2024 0 1,158 0 23.1% 0 894 9 16.0% 0 2,051 9 19.4% 271 5,327 904 13.9%

2025 0 1,158 0 22.9% 0 994 9 17.4% 0 2,151 9 20.0% 271 5,527 904 14.1%

2026 17 1,258 0 24.8% 17 994 9 17.3% 35 2,251 9 20.8% 340 5,727 904 14.5%

2027 17 1,258 0 24.6% 17 1,094 9 18.8% 35 2,351 9 21.5% 340 5,927 1,032 15.2%

2028 35 1,258 0 24.5% 35 1,094 9 18.7% 69 2,351 9 21.4% 409 6,127 1,032 15.5%

2029 35 1,358 0 26.2% 35 1,194 9 20.0% 69 2,551 9 22.8% 409 6,327 1,032 15.7%

2030 56 1,358 0 26.0% 56 1,394 9 23.1% 112 2,751 9 24.4% 496 6,527 1,032 16.1%

 (a) Data EXCLUDES: 

 o AEP-Texas Central Co. & AEP-Texas Northern Co... as current and potential future state/federal RPS would be applicable to LSEs only. 

 o Conventional (run-of-river) hydro energy as a renewable source as it has been excluded from certain state and proposed federal RPS criteria... 

 Should hydro be ultimately included, it would contribute roughly 1% to the AEP System target by 2020. 

 (b) 2012/2013 represent the initial years for Federal RPS/RES mandates as currently proposed by several draft bills before Congress. Further, 2013 

 would represent the initial year after the likely expiration of Production Tax Credits (PTC) for, particularly, wind resources. The notion being that

 establishment of a Federal renewables standard would likely eliminate further extension of such PTC opportunities.

PSO SWEPCO AEP-SPP

AEP Sytem - SPP Zone

Potential Renewables Profile to Achieve a 7% System Target by 2013, 10% by 2020, and 15% by 2030 (a)

...as well as Known or Emerging State-Specific Mandates

2009 IRP

Source: AEP Resource Planning 

3.3 Carbon Capture & Storage/Sequestration (CCS) 

Utility applications of CCS technologies continue to be developed and tested, and as such are 

not yet commercially available on a large scale. However, given the focus on the advancement and 

associated cost reduction of such technologies, it is likely to become both available and cost-effective 

at some point over the IRP’s longer-term planning horizon (through 2030). However, this is very 

dependent on the type of federal climate legislation that is passed and the degree to which there is 

financial support for CCS technology in such legislation. Assuming carbon capture and storage 

becomes commercially viable weight must be given to the options that are most readily adaptable to 

this technology 

3.4 Emission Compliance 

Emission compliance requirements have a major influence on the consideration of supply-side 

resources for inclusion in the IRP because of their potential significant effects on both capital and 

operational costs. The AEP System’s strategy for complying with Title IV of the Clean Air Act 

Amendments of 1990, as well as recent regulations tied to environmental air emissions, takes into 

consideration additional power plant emission reduction requirements for SO2

, NOx, and mercury 

(Hg) emissions. 

Specifically, in 2005, the U.S. Environmental Protection Agency (USEPA) established new 

emission regulations for these pollutants as part of the CAIR (which the D.C. Circuit Court 
AEP-SPP 2009 Integrated Resource Plan 

 23 

overturned on July 11, 2008), the now vacated Clean Air Mercury Rule (CAMR), and Clean Air 

Visibility Rule (CAVR) rulemaking. Further, on-going debate over CO2/GHG emissions, particulate 

matter (PM), and regional haze, as well as the previously mentioned potential enactment of additional 

state and/or Federal RPS will likewise influence future capacity resource planning surrounding 

decisions to retrofit, modify operations, or retire/mothball generating assets. 

Certain PSO and SWEPCO coal and gas-fired generating units are subject to CAVR and 

application of Best Available Retrofit Technology (BART) for SO2 and NOX. PSO will be equipping 

its units with NOX combustion technology to meet BART limits for NOX and is expected to install 

flue gas desulfurization technology (FGD) at the Northeastern 3 & 4 coal units to meet BART limits 

for SO2 and PM. The specific timing of these installations is uncertain as the Oklahoma Department 

of Environmental Quality is still developing its State Implementation Plan for the CAVR program. 

SWEPCO plans to install FGD at Flint Creek station to meet CAVR. 
AEP-SPP 2009 Integrated Resource Plan 

 24 
AEP-SPP 2009 Integrated Resource Plan 

 25 

4.0 Current Resources 

The initial step in the IRP process is the demonstration of the region-specific capacity resource 

requirements. This “needs” assessment must consider projections of: 

 Existing capacity resources—current levels and anticipated changes 

 Anticipated changes in capability due to efficiency and/or environmental retrofit projects 

 Changes resulting from decisions surrounding unit disposition evaluations 

 Regional and sub-regional capacity and transmission constraints/limitations 

 Load and (peak) demand (see Section 5.2.) 

 Current DR/EE (see Section 5.3.) 

 SPP capacity reserve margin and reliability criteria (see Section 6.1.) 

In addition to the establishment of the absolute annual capacity position, an additional “need” to 

be discussed in this section will be a determination of the specific operational expectation (duty type) 

of generating capacity–baseload vs. intermediate vs. peaking. 

4.1 Existing PSO and SWEPCO Generating Resources 

Appendix A offers a summary of all owned supply resources for the AEP-SPP zone plus longterm wind contracts. The current (June 1, 2009) AEP-SPP summer supply of 9,216 MW is composed 

of the following (with wind projects’ capacity at ratings allowed by SPP, generally about 8% of 

nameplate): 

Exhibit 4-1: Existing PSO and SWEPCO Generating Resources 

PSO SWEPCO Total

Coal/Lignite 1,026 MW 2,680 MW 3,706 MW

Gas/Diesel 3,384 MW 2,086 MW 5,470 MW

Wind 17 MW -- 17 MW

Total 4,427 MW 4,766 MW 9,193 MW

Source: AEP Resource Planning 

4.2 Capacity Impacts of Environmental Compliance Plan 

As detailed in Exhibit 4-2 and Appendix D, the capability forecast of the existing generating 

fleet reflects 27 MW in unit de-ratings associated with environmental retrofits - largely flue gas 

desulphurization (FGD), and activated carbon injection with a baghouse (ACIBH) or with an 

electrostatic precipitator (ACIESP) over the IRP period. 
AEP-SPP 2009 Integrated Resource Plan 

 26 

Exhibit 4-2: PSO and SWEPCO Capacity Change After June 2009 

Unit and Cause Year (a) Capacity Impact Year (a) Capacity Impact

Welsh 2 (FGD) 2013 -8 2015 -8

Flint Creek 1 (FGD) 2014 -4 2014 -4

Pirkey 1 (ACIESP) 2014 0 -- --

Dolet Hills 1 (ACIESP) 2014 0 -- --

Flint Creek 1 (ACIESP) 2014 0 -- --

Welsh 1 (ACIBH) 2014 -11 -- --

Welsh 2 (ACIESP) 2014 0 -- --

Welsh 3 (ACIBH) 2014 -11 -- --

Northeastern 3 (FGD + ACIESP) 2014 -7 2016 -7

Northeastern 4 (FGD + ACIESP) 2014 -8 2016 -8

Oklaunion 1 (ACIESP) 2014 0 -- --

Net Change -49 -27

Note : (a) Summer season of effective SPP delivery year.

As Modeled In Final Plan

AEP West Capacity Changes (MW) after June 1, 2009

Source: AEP Resource Planning 

4.3 Existing Unit Disposition 

A long-term view of disposition alternatives facing older units in the AEP-SPP region was 

established. The work group affirmed the findings of previous studies, recommending no unit 

disposition planned for the IRP period. In general, the capacity value provided by the older units far 

outweigh the fixed costs associated with their continued operations, The work group report is include 

in the technical addendum. 

4.4 AEP-SPP Transmission 

4.4.1 Transmission System Overview 

The western Transmission System, which consists of the transmission facilities of the four 

western AEP operating companies, is operated in both the SPP and ERCOT. The western 

Transmission System spans portions of four states and comprises nearly 10,000 miles of circuitry 

operating at or above 69 kV. 

The portion of the western Transmission System operating in SPP (AEP-SPP zone) consists of 

approximately 1,270 miles of 345 kV, approximately 3,400 miles of 138 kV, and 2,197 miles of 69 

kV. The AEP-SPP zone is also integrated with and directly connected to ten other companies at 87 

interconnection points, of which 69 are at or above 69 kV and to ERCOT via two high voltage direct 

current (HVDC) ties. These interconnections provide an electric pathway to provide access to offsystem resources, as well as a delivery mechanism to neighboring systems. 

4.4.2 Current AEP-SPP Transmission System Issues 

Historically, the AEP SPP Transmission System was planned to deliver operating company 

generation to their respective loads, as well as to provide interconnections with neighboring utilities 
AEP-SPP 2009 Integrated Resource Plan 

 27 

for replacement and emergency power exchanges when needed and available. With the creation of 

the SPP Regional Transmission Organization (RTO), the system is primarily planned under the 

current SPP Transmission Expansion Plan (STEP) annual process for reliability and transmission 

owner projects. The STEP process also identifies transmission reliability improvements to 

accommodate approved transmission service and approved economic upgrades on an annual basis 

looking out over a ten year period. SPP RTO’s process addresses transmission service needs to 

deliver energy to loads and generation interconnection requests in separate studies. Going forward, 

the SPP RTO will be using an Integrated Transmission Planning (ITP) process that is being 

developed. 

The limited capacity of interconnections between SPP and neighboring systems, as well as the 

electrical topology of the SPP footprint transmission system, influences the ability to deliver nonaffiliate generation, both within and external to the SPP footprint, to AEP-SPP loads and from 

sources within AEP-SPP balancing authority to serve AEP-SPP loads. Moreover, a lack of seams 

agreements between SPP and its neighbors has significantly slowed down the process of developing 

new interconnections. Despite the robust nature of the AEP-SPP transmission system as originally 

designed, its current use is in a different manner than originally designed, in order to meet SPP RTO 

requirements, which can stress the system. In addition, factors such as outages, extreme weather, and 

power transfers also stresses the system. This has resulted in a transmission system in the AEP-SPP 

zone that is constrained when generation is dispatched in a manner inconsistent with the original 

design of utilizing local generation to serve local load. The resulting use of the AEP-SPP system is 

inconsistent with the assumptions used to develop the models AEP provides to SPP to develop and 

plan the system. SPP uses models provided by all load serving entities to study the reliability needs 

of the SPP footprint. As discussed above, SPP currently uses separate modeling and studies to 

address transmission service and interconnection requests. 

4.4.2.1 The SPP Transmission Planning Process 

Currently, SPP produces an annual SPP transmission expansion plan (STEP) that includes a ten 

year system forecast. The STEP is developed through an open stakeholder process with AEP 

participation. SPP studies the transmission system, checking for base case and contingency overload 

and voltage violations in all of the SPP base case load flow models, plus models which include power 

transfers biased in the various transfer directions. 

The 2008 STEP summarizes 2008 activities, including expansion planning and long-term SPP 

Open Access Transmission Tariff studies (Tariff Studies) that impact future development of the SPP 

transmission grid. Six key topics are included in the STEP: 

1) Tariff Studies, 

2) Regional reliability assessment 2009-2018, 

3) Subregional and local area planning, 

4) High priority economic studies, 

5) Interregional coordination; and 

6) Project tracking. 
AEP-SPP 2009 Integrated Resource Plan 

 28 

These topics are critical to meeting mandates of either the SPP strategic plan or the nine 

planning principles in FERC Order 890. As a RTO under the domain of the Federal Energy 

Regulatory Commission (FERC), SPP must meet requirements of FERC and the SPP Open Access 

Transmission Tariff (OATT or Tariff). The SPP RTO acts independently of any single market 

participant or class of participants. It has sufficient scope and configuration to maintain electric 

reliability, effectively perform its functions, and support efficient and non-discriminatory power 

markets. Regarding short-term reliability, the SPP RTO has the capability and exclusive authority to 

receive, confirm, and implement all interchange schedules. It also has operational authority for all 

transmission facilities under its control. The 10-year RTO regional reliability assessment continues to 

be a primary focus. 

STEP projects are categorized by the following designations: 

 Economic: Projects identified for economic benefit; 

 Generation Interconnect – Projects associated with a FERC-filed Interconnection 

Agreement; 

 Interregional- Projects developed with neighboring Transmission Providers; 

 Regional reliability - Base Plan projects needed to meet the reliability of the region; 

 Transmission service – Projects associated with a FERC-filed Service Agreement; and 

 Zonal Reliability - Projects identified to meet more stringent local Transmission Owner 

criteria. 

The 2008 STEP identified approximately $2.7 billion of transmission Network Upgrades. 

These include Network Upgrades required for NERC Reliability Standards or SPP Criteria; Zonal 

Reliability Upgrades (compliance to Transmission Owner company-specific planning criteria); 

requests for transmission service under the Tariff with a FERC-filed Service Agreement; and 

generation interconnections with a FERC-filed interconnection agreement. 

In addition, the SPP Regional State Committee and SPP Board of Directors/Members 

Committee approved a long-awaited group of extra high voltage economic transmission expansion 

upgrade projects totaling over $700 million, to be funded by FERC-approved "postage stamp" rates, 

applicable to SPP's transmission-owning members across the region. The adjusted production cost 

benefits of this group of transmission upgrades have been demonstrated by model analysis to 

outweigh the costs (benefits greater than costs), thus achieving a "balanced portfolio" of projects. A 

portfolio approach alleviates potential disputes that may arise from the construction of a single project 

that may benefit one zone but not others. The balanced portfolio includes five new 345 kV 

transmission lines, a 345 kV transformer, and a new connection between two existing 345 kV lines. 

Details of the balanced portfolio results can be found at: 

http://www.spp.org/publications/2009%20Balanced%20Portfolio%20-%20Final%20Approved%20Report.pdf

The SPP Board of Directors also recently approved a new report, prepared by the Synergistic 

Planning Project Team that recommends restructuring the organization's regional planning processes 

to focus on the construction of a robust transmission system, large enough in both scale and 

geography to provide flexibility to meet SPP's future needs. The new Integrated Transmission 
AEP-SPP 2009 Integrated Resource Plan 

 29 

Planning (ITP) process is intended to integrate or replace the STEP, balanced portfolio, and the ExtraHigh Voltage Overlay process.

4.4.2.2 PSO-SWEPCO Interchange Capability 

Operational experience and internal assessments of company transmission capabilities indicate 

that, when considering a single contingency outage event, the present firm capability transfer limit 

from PSO to SWEPCO is about 200 MW, and from SWEPCO to PSO is about 900 MW. As much as 

900 MW may be available bi-directionally for economical energy transfers when no transmission 

facilities are out of service. However, the intra-company available transmission capability between 

the two companies is available to all transmission users under the provisions established by FERC 

Order 888 and subsequent orders. Thus, there is some question as to whether, in the future, as SPP 

grants further transmission rights, any transfer capability will in fact be available without further 

upgrades to the transmission system. 

Increasing the firm transfer capability from PSO to SWEPCO beyond about 200 MW may not 

be cost-effective. As previously indicated each, company’s capacity additions are planned so that 

each meets its own reserve requirement over the long-term. Any capacity transfers (i.e. “reserve 

sharing”) should be considered for short time frames only. Specifically, the practice has been that, as 

the last step of the planning process, the respective PSO and SWEPCO expansion plans are adjusted 

to take advantage of any surplus of one company that might match a potential deficit of the other, and 

thereby delay some of the identified new capacity. Because of the sizes, demand growth rates, and 

peak coincidence of the two companies, it rarely appears that either company would ever have more 

than 200 MW of surplus capacity in any year that could be transferred to the other company. 

4.4.2.3 AEP-SPP Import Capability 

Currently the transmission system cannot accommodate incremental firm imports to the AEPSPP area, based on preliminary AEP studies. Generally, the transfers are limited by the facilities of 

neighboring systems rather than by transmission lines or equipment owned by AEP. 

Increasing the import capabilities with AEP-SPP’s neighboring companies could require a large 

capital investment for new transmission facilities by the neighboring systems or through sponsored 

upgrades by SPP transmission owners. An analysis of the cost of the upgrades cannot be performed 

until the capacity resources are determined. For identified resources, the cost of any transmission 

upgrades necessary on AEP’s transmission system can be estimated by AEP once SPP has identified 

the upgrade. AEP’s Southwest Transmission Planning group can identify constraints on third-party 

systems through ad hoc power flow modeling studies, but Southwest Transmission Planning does not 

have information to provide estimates of the costs to alleviate those third-party constraints. 

4.4.2.4 SPP Studies that may Provide Import Capability 

Besides the annual STEP process, SPP also performs other special studies or area studies on an 

as needed basis. Two recent SPP studies could in time lead to improved transfer capability between 

AEP-SPP and neighboring companies and regions.
AEP-SPP 2009 Integrated Resource Plan 

 30 

4.4.2.4.1 EHV Overlay Study 

SPP hired a consultant, Quanta, to determine if SPP should build a 345, 500 or 765 kV overlay 

to the existing SPP footprint. As of May 2008, the most recent version of this EHV Overlay Study 

included plans for construction of a 765 kV transmission system across much of SPP that would 

accommodate 13.5 GW of wind generation resources. One 765 kV loop would encompass much of 

the Texas Panhandle and portions of western Oklahoma. Another 765 kV loop would encompass 

much of the Oklahoma Panhandle and southwestern Kansas. These loops could be used to connect 

large amounts of potential wind generation and wind generation in the generation interconnection 

queue to the transmission grid. From these loops, two 765 kV paths would be extended, one to 

Lawton and Muskogee, Oklahoma, and then northward toward the Kansas City area; the other to 

Wichita, Kansas and eastward toward the Kansas City area. The 765 kV system would also extend 

eastward with two 765 kV lines, one to the southeast to Entergy and one to the northeast to 

Associated Electric Cooperative, Inc. (AECI). The plan also includes a new 500 kV line extending 

eastward from Oklahoma Gas and Electric’s (OG&E) Fort Smith Station across central Arkansas to 

Entergy, a large amount of 345 kV in northwestern Arkansas and southwestern Missouri, and five 345 

kV lines in Kansas and Oklahoma. The total cost to implement the plan is approximately $8 billion. 

The future of the overlay is uncertain. SPP performed an economic analysis of the original overlay 

study. However, routing changes to the original projects have been proposed since the inclusion of 

the Nebraska entities into SPP and the study is not yet completely vetted among stakeholders. From 

an AEP perspective, the proposed overlays in the various study versions would enhance bulk power 

transfers among the involved regions, but it is not known what additional, local facilities would be 

required to create increased import capability. The SPP Board of Directors has yet to approve an 

overlay plan but is now looking at a new synergistic integrated transmission planning process that 

may incorporate the results of the study. 

4.4.2.4.2 Ozark Transmission Study 

This study, completed by SPP in June 2007, provides a long-range plan for the northern 

Arkansas and southern Missouri region and provides guidance for future reinforcements to the 

transmission system in this area. The recommendations include 500 kV lines from Entergy’s 

Arkansas Nuclear One Station to OG&E’s VBI Station to AEP’s South Fayetteville Station. The 

recommendations also included a 345 kV loop around the Fayetteville / Springdale area of 

northwestern Arkansas as well as 345 kV expansion eastward to SWPA’s Table Rock Station located 

in southwestern Missouri. From Table Rock Station, 345 kV lines to AECI’s Gobbler Knob Station 

in southeastern Missouri and City Utilities of Springfield’s Brookline Station in southwestern 

Missouri were also recommended. AEP and Arkansas Electric Cooperative Corporation (AECC) 

have asked SPP to further study the 345 kV loop around the south side of the Fayetteville / Springdale 

area as a complex priority project. 

4.4.3 Recent AEP-SPP Bulk Transmission Improvements 

Over the past several years, there have been several major transmission enhancements initiated 

to reinforce the AEP-SPP transmission system. These enhancements include: 
AEP-SPP 2009 Integrated Resource Plan 

 31 

 Northwest Arkansas— Northwest Arkansas is one of the fastest growing areas on the 

AEP-SPP Transmission System. The approximate 1,200 MW of load in this area, about 

47% of which is AECC retail load, is supplied primarily by the SWEPCO and AECC 

jointly-owned Flint Creek generating plant, the SWEPCO Mattison generating plant, the 

GRDA-Flint Creek 345 kV line, and the Clarksville-Chambers Spring 345 kV line. WalMart’s international headquarters and its supplying businesses’ offices and Tyson’s 

headquarters are all located in this area. A significant conversion of the 69 kV transmission 

system to 161 kV and extensive rebuilding and upgrading of portions of the existing 161 kV 

system have been completed in recent years. In May 2008, the conversion of the 69 kV line 

between Dyess and South Fayetteville stations to 161 kV and the construction of a new 345 

kV line between Chambers Spring and Tontitown stations were completed. In May 2009, a 

rebuild and reconductoring of the Flint Creek-Motley Road 161 kV line section was also 

completed. 

 Port of Shreveport (Port), Louisiana— A 138 kV loop is under construction, in phases, 

around the Port to increase system reliability and to serve the increasing area load. In May 

2008, a six -mile 138 kV transmission line was completed from Wallace Lake Station to 

Port Robson Station to supply new loads under development at the Port. The 138 kV loop 

has been extended from Port Robson Station to Bean Station and was further extended to 

Caplis Station in June 2009. A 138 kV line approximately 23 miles long, connecting Caplis 

Station to Red Point Station is also planned to complete the 138 kV loop. Together, these 

improvements will supply power to the Port and the new distribution station site near 

Caplis; correct contingency low voltage and thermal overloads in Bossier City, Louisiana 

and the vicinity; and supply a second feed to Bean, Caplis, McDade, and Haughton stations. 

This loop is currently expected to be completed in 2012. 

 Shreveport line upgrades for Stall Plant generation addition – Several 138 kV and 69 

kV lines in Shreveport, Louisiana have been or are being upgraded to accommodate the 

Stall generation unit that is to be added at the Arsenal Hill Power Plant.

4.4.4 Impacts of New Generation: 

There has been significant growth of approximately 5,700 MW of merchant generation in the 

AEP-SPP zone. The total generation connected to the AEP-SPP Transmission System, including 

electric cooperative generation, is approximately 15,600 MW. Integration of additional generation 

capacity within the AEP-SPP zone will likely require significant transmission upgrades. At most 

locations, any additional generation resources will aggravate existing transmission constraints. 

Specifically: 

 Western Oklahoma/Texas Panhandle—there are very few EHV transmission lines in this 

area. In fact, transmission facilities above 69 kV are limited. However, the area is one of 

the highest wind density areas within the SPP RTO footprint. The potential wind farm 

capacity for this area has been estimated to exceed 4,000 MW. Several wind farms have 

already been built, and several more are in the development stages. Wind generation 

additions in the SPP footprint in this region will likely require significant transmission 
AEP-SPP 2009 Integrated Resource Plan 

 32 

enhancements, including EHV line and station construction, to address thermal, voltage, and 

stability constraints. 

 PSO/SWEPCO Interface - There is one 345 kV EHV line linking PSO’s service area with 

the majority of SWEPCO’s generation resources in its service area. Until recently, 

constraints on the underlying transmission system limited the amount of firm generation that 

can flow from PSO to SWEPCO and from SWEPCO to PSO to approximately zero in a 

single contingency situation. However, an SPP approved project to rebuild the Danville to 

North Magazine 161 kV line will increase the transfer capability from SWEPCO to PSO to 

approximately 900 MW when completed in the Summer of 2009. Also, an SPP approved 

project to rebuild the Broken Bow to Craig Junction 138 kV line has been completed and 

has increased the transfer capability from PSO to SWEPCO to approximately 200 MW. 

Significant generation additions to the AEP-SPP transmission facilities (or connection to 

neighbor’s facilities) may require significant transmission enhancements, possibly including 

EHV line and station construction, to address thermal, voltage, and stability constraints. 

 Tulsa Metro Area—the Tulsa metro area load is supplied primarily by the PSO 

Northeastern, Riverside, and Tulsa Power Station generating plants. Additionally, 

Oklahoma Gas & Electric Company has large generation plants located to the southeast and 

southwest of Tulsa, and there are large merchant plants just east and south of Tulsa. The 

Grand River Dam Authority has a large plant located to the east of Tulsa. Generation 

additions in the Tulsa area would likely require significant enhancements in the EHV and 

sub-transmission system to address thermal, voltage and stability constraints. 

 SPP Eastern Interface—there are only five east-west EHV lines into the SPP region, 

which stretches from the Gulf of Mexico (east of Houston) north to Des Moines, Iowa. This 

limitation constrains the amount of imports and exports along the eastern interface of SPP 

with neighboring regions. It also constrains the amount of transfers from the capacity rich 

western SPP region to the market hubs east and north of the SPP RTO region. Significant 

generation additions near or along the SPP eastern interface would likely require significant 

transmission enhancements, including EHV line and station construction, to address thermal 

and stability constraints should such generation additions adversely impact existing 

transactions along the interface. SPP has addressed some of these potential ties in the EHV 

Overlay Study discussed above. 

Integration of generation resources at any location within the AEP-SPP zone will require 

significant analysis by SPP to identify potential thermal, short circuit, and stability constraints 

resulting from the addition of generation. Depending on the specific location, EHV line and station 

construction, in addition to connection facilities, could be necessary. Other station enhancements, 

including transformer additions and breaker replacements may be necessary. Some of the required 

transmission upgrades could be reduced or increased in scope if existing generating capacity is retired 

concurrent with the addition of new capacity. 

4.4.5 Horizon Transmission LLC, Joint Venture in the SPP 

On July 15, 2008, Electric Transmission America (ETA), a joint venture of American Electric 

Power and MidAmerican Energy Holdings, formed a joint venture company with OGE Energy Corp. 
AEP-SPP 2009 Integrated Resource Plan 

 33 

to build and own new electric transmission assets in Oklahoma. The joint venture, Horizon 

Transmission LLC, will build the Tallgrass Project, which will include approximately 170 miles of 

extra-high voltage 765 kilovolt transmission from the Kansas-Oklahoma border north of Woodward, 

Oklahoma, that will link into OGE ́s station at Woodward and then extend west into the Oklahoma 

panhandle to a new station that will be built near Guymon, Oklahoma. 

SPP’s estimated cost for the project is approximately $500 million based on SPP ́s Extra-High 

Voltage Overlay Study, but final costs will depend on the routing of the line, equipment and 

commodity costs. Anticipated completion would be in 2013. AEP ́s ownership share of the joint 

venture will be 25 percent. 

The ETA-OGE joint venture anticipates filing for the necessary state and federal regulatory 

approvals for the project in the coming months. 

ETA also has formed a joint venture with Westar to build 765 kV transmission in Kansas 

(Prairie Wind Project) that will connect with the OGE project at the Kansas-Oklahoma border. The 

combined projects encompass the first two phases of the SPP EHV Overlay Study plan. 

"This collaboration with Oklahoma Gas and Electric will build a segment of a larger extra-high 

voltage transmission highway that has been proposed by the Southwest Power Pool to enhance 

reliability and support development of the sizable renewable generation resources available in the 

region..." 

Mike Morris, AEP Chairman, President and CEO 

4.4.6 Summary of Transmission Overview 

 In the SPP region, the process of truly integrating Generation and Transmission planning is 

still developing. AEP continues to stand ready to engage in that process. At this time, though, PSO 

and SWEPCO can do very little to import capacity from outside of its control area. Both companies 

have been open to such imports as evidenced by the issuing of recent RFP’s for non-site specific 

generation types. These RFP’s allow bidding entities to offer generation coupled with transmission 

solutions, which would be subject to SPP approvals. 
AEP-SPP 2009 Integrated Resource Plan 

 34 
AEP-SPP 2009 Integrated Resource Plan 

 35 

5.0 Demand Projections 

5.1 Load and Demand Forecast - Process Overview

One of the most critical underpinnings of the IRP process is the projection of anticipated 

resource “needs,” which, in turn, centers on the long-term forecast of load and (peak) demand. The 

AEP-SPP internal long-term load and peak demand forecasts were based on the AEP Economic 

Forecasting group’s load forecast performed in May 2009. 

The electric energy and demand forecast process involves three specific forecast model 

processes, as identified in Exhibit 5-1. 

Exhibit 5-1: Load and Demand Forecast Process—Sequential Steps 

Source: AEP Economic Forecasting 

The first process models the consumption of electricity at the aggregated customer level: 

Residential, Commercial, Industrial, Other Ultimate customers, and Municipals and Cooperatives. It 

involves modeling both the short- and long-term sales. The second process contains models that 

derive hourly load estimates from blended short- and long-term sales, estimates of energy losses for 

distribution and transmission, and class and end-use load shapes. The aggregate revenue class sales 

and energy losses is generally called “net internal energy requirements.” The third process reconciles 

historical net internal energy requirements and seasonal peak demands through a load factor analysis 

which results in the load forecast. 

The long-term forecasts are developed using a combination of econometric models to project 

load for the Industrial, Other Ultimate and Municipal and Cooperative customer classes, as well as 

Statistically-Adjusted End-use (SAE) models for the modeling of Residential and Commercial 

classes. 

1. Monthly Sales Forecast

(by FERC Revenue Classes)

Short & Long Term

2. Hourly Demand Models

(Load Shapes / Losses)

3. Net Internal Energy Requirements

& Demand Forecast

Load & Demand Forecast Process – Sequential Steps
AEP-SPP 2009 Integrated Resource Plan 

 36 

The long-term process starts with an economic forecast provided, under proprietary license, by 

Moody’s Economy.com for the United States as a whole, each state, and regions within each state. 

These forecasts include projections of employment, population, and other demographic and financial 

variables for both the U.S. as a whole and for specific AEP service territories. The long-term 

forecasting process incorporates these economic projections and other inputs to produce a forecast of 

kilowatt-hour (kWh) sales. Other inputs include regional and national economic and demographic 

conditions, energy prices, weather data, and customer-specific information. 

The AEP Economic Forecasting department uses Statistically Adjusted End-use (SAE) models 

for forecasting long-term Residential and Commercial kWh energy sales. 

 SAE models are econometric models with end-use features included to specifically 

account for energy efficiency impacts, such as those included in the Energy Policy Act 

of 2005 (EPAct 2005) and the Energy Independence and Security Act of 2007 (EISA). 

 SAE models start with the construction of structured end-use variables that embody 

end-use trends, including equipment saturation levels and efficiency. Factors are also 

included to account for changes in energy prices, household size, home size, income, 

and weather conditions. 

 Regression models are used to estimate the relationship between observed customer 

usage and the structured end-use variables. The result is a model that has implicit enduse structure, but is econometric in its model-fitting technique. 

 The SAE approach explicitly accounts for energy efficiency which has served to 

slightly lower the forecast of Residential and Commercial class demand and energy in 

the forecast horizon particularly when EPAct 2005 and EISA impacts begin to 

manifest. 

AEP uses processes that take advantage of the relative strengths of each method. The regression 

models typically used in the shorter-term modeling employ the latest available sales and weather 

information to represent the variation in sales on a monthly basis for short-term applications. While 

these models generally produce accurate forecasts in the short run, without specific ties to economic 

factors they are less capable of capturing the structural trends in electricity consumption that are 

important for longer-term planning. The long-term modeling process, with its explicit ties to 

economic and demographic factors, is appropriate for longer-term decisions and the establishment of 

the most likely, or base case, load and demand over the forecast period. By overlaying these 

respective output profiles, AEP Economic Forecasting can then effectively apply the strengths of both 

load-modeling approaches, thereby achieving a reasonable validation of such forecasted results. 

5.2 Peak Demand Forecast 

Exhibit 5-2 reflects the AEP Economic Forecasting Group’s forecast of annual peak demand for 

the AEP-SPP zone, utilized in this IRP process. 

Specifically, Exhibit 5-2 identifies the AEP-SPP region’s internal demand profile as having 

1.5% Compound Annual Growth Rate (CAGR). This equates to roughly a 140 MW per year 

increase (one-third PSO, two-thirds SWEPCO) over the IRP planning period if the load growth was 

steady. As the graph shows, the impact of the existing recession depresses peak demand in 2009 and 
AEP-SPP 2009 Integrated Resource Plan 

 37 

2010 with a rapid increase in 2011 from the assumed economic recovery. In addition, the chart 

indicates a comparable rate of growth for internal energy sales over the 10-year period, with load 

factors increasing in 2011 due to the recovery of recession impacted industrial load. 

Exhibit 5-2: AEP-SPP Peak Demand and Energy Projection 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Net Energy Requirement (GWh)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Peak Demand (MW)

Energy Peak Demand

Source: AEP Economic Forecasting 

It is critical to note some of the major assumptions driving these demand profiles for the AEPSPP zone: 

1. Any major wholesale load obligations (largely, municipalities and cooperatives who 

currently have or have had a relationship with AEP as a “FERC tariff” customer) would 

largely be renewed or extended over the planning period under long-term contracts. 

However, an observation from the underlying data to support Exhibit 5-2 is that such firm or 

“committed” wholesale demand projections are relatively constant over the long-term 

forecast period and, in total, represent approximately 15% of the zone’s (predominantly 

SWEPCO) overall load obligation. 

2. Additionally, as described below, this forecast incorporates the effects of all current 

Demand Response and Energy Efficiency (DR/EE) program offerings. It also includes 

energy efficiency and peak demand reduction that “occurs naturally” as a function of 

shifting consumer behavior. Consumer-driven, naturally occurring DR/EE has a significant 

impact on energy consumption, and can be masked by increased energy use for other 

activities. The impacts from energy policy such as the Energy Independence and Security 
AEP-SPP 2009 Integrated Resource Plan 

 38 

Act of 2007 (EISA) are expected to be on the demand side. These will predominantly come 

through increased lighting, appliance, and building efficiency standards and codes. The 

efficiency of lighting is set to increase by 20-30% by 2012-24. Standards for appliance 

equipment including residential boilers, clothes washers and dishwashers are also set to 

increase during the period of 2008 to 2014. Strides to promote energy efficiency in 

commercial buildings as well as in industrial energy use are expected as well. The current 

forecast does not include impacts of the Energy Improvement and Extension Act of 2008 

(EIEA) or the American Recovery and Reinvestment Act of 2009 (ARRA). The impacts of 

these acts were being determined at the time of this forecast. The acts are not expected to 

have the as significant of an impact to forecasted load growth as did the 2005 and 2007 acts. 

3. The economic impacts of any carbon dioxide cap regime will be wide reaching and impact 

electricity demand through market adjustments in various sectors. As an early attempt to 

quantify some type of initial impact, an “own-price effect” on demand is estimated. The 

timing and impact of this scenario is truly speculative, and represents only one of many 

possible policy actions. 

5.3 Current DR/EE Programs 

PSO and SWEPCO have numerous peak demand shifting programs. These consist of 

“Interruptible” contracts with larger industrial customers and, in PSO, the tariff-based “Value 

Choice” program which provides large users of electricity with advance notice of pricing changes, 

enabling them to avoid using power during expensive, peak periods. 

SWEPCO’s Texas region currently has several traditional utility-sponsored Energy Efficiency 

programs in place: 

 Home$avers Low Income Program. The Home$avers is an energy efficiency and 

weatherization program that targets households that are 125% below the poverty level. 

 SWEPCO CARE$ Energy Efficiency Improvement Program (EEIP) for Not-for-Profit 

agencies. 

 Standard Offer Programs (SOPs). These programs are available for commercial and 

industrial (C&I) consumers (>100 kW) and residential and small commercial (<100 kW), 

where incentives are paid for new and retrofit projects that provided verifiable demand or 

energy savings. 

 Appliance Recycling Pilot Market Transformation Program. This program seeks to decrease 

the number of inefficient refrigerators and freezers in general use, and by doing so, deliver 

long-term electric energy savings and peak demand reduction. 

 Home$avers low-income weatherization 

 Load Management. The Load Management standard offer program targets commercial 

customers with a minimum peak electric demand of 500 kW or more. Incentives are paid to 

project sponsors that provide curtailment of peak interruptible electric load on short (1-hour 

ahead) notice. 

 Texas Statewide ENERGY STAR® Residential (Compact Fluorescent Lighting). 

SWEPCO will be participating for the second year with other Transmission and Distribution 
AEP-SPP 2009 Integrated Resource Plan 

 39 

Utilities in a statewide effort to promote the awareness, understanding, and use of compact 

fluorescent light bulbs (CFLs) by residential customers. 

 Commercial Solutions Pilot Market Transformation Program (CS MTP). This program 

targets commercial customers that do not have the in-house capacity or expertise to: 1) 

identify, evaluate, and undertake efficiency improvements; 2) properly evaluate energy 

efficiency proposals from vendors; and/or 3) understand how to leverage their energy 

savings to finance projects. 

 SCORE Market Transformation Program (SCORE MTP). This provides energy efficiency 

and demand reduction solutions for public schools and local government entities. 

Consistent with recent rule-making in SWEPCO-Arkansas, the following programs were 

proposed and became effective in October 2007 as part of the Arkansas Public Service Commission’s 

(APSC) “Quick Start” initiative: 

 Energy Education Arkansas (EEA). This is a state-wide program that provides energy 

efficiency information to customers through a website and various media outlets. 

 C&I Standard Offer Program - A “traditional” DR/EE program offered to customers with 

>100 kW of load. 

 Load Management Standard Offer Program. The LM SOP targets commercial and 

industrial customers with a minimum peak demand of 250 kW. Incentives are paid to 

customers that provide curtailment of peak load on short notice. 

 Residential and Small Commercial CFL Program (RSC CFL). This program targets 

residential and commercial customers. 

 ENERGY STAR® Appliance Program. This program targets residential and small 

commercial customers. Incentives are paid to customers who purchase a new qualifying 

central air conditioner or heat pump with an ENERGY STAR rating 

 Arkansas Weatherization Program (AWP). This is a residential weatherization program that 

targets severely inefficient homes (SIEH). It is designed as a “piggyback” program that 

uses the existing infrastructure/resources of the DOE Weatherization Assistance Program 

(WAP). 

 Commercial Solutions Market Transformation Program. This targets commercial and 

industrial customers. 

 Residential Solutions Market Transformation Program. This targets residential customers 

and provides incentives to homeowners for eligible energy efficient improvements. A 

network of qualified energy efficiency service providers will become partnering contractors 

and can both offer and accept incentives for program eligible upgrade measures. 

 

 
AEP-SPP 2009 Integrated Resource Plan 

 40 

As part of PSO’s last base rate case (cause number PUD 200600285), the Company proposed 

two additional Real-Time Pricing pilot programs for both residential and general services 

(commercial) classes. A slate of “quick start” programs have been implemented. The quick start 

programs consist of 

 low income weatherization, 

 ENERGY STAR® new homes, 

 C&I standard offer, 

 residential ENERGY STAR® Appliance and CFL, and 

 Emergency Load Management. 

In September 2009 PSO will file its recommended changes to the Quick Start programs based 

on the results of the first year of implementation. 

The peak demand and annual energy conservation that results from the currently approved, but 

not fully implemented, SPP programs are summarized in Exhibit 5-3: 

Exhibit 5-3: AEP-SPP Current DR/EE Programs full-year impacts 

Operating Company 2009 2010 2011 2012 2013 2014 2015

PSO 9 13 16 19 21 22 23 

SWEPCO 10 16 20 24 26 29 30 

AEP-SPP (MW) 19 29 36 43 47 51 53 

Operating Company 2009 2010 2011 2012 2013 2014 2015

PSO 40 56 70 81 90 97 102 

SWEPCO 38 57 73 87 96 103 109 

AEP-SPP (GWh) 78 113 143 168 186 200 211 

Load Forecast - Embedded DR/EE Demand Impacts (MW) - Summer

Load Forecast - Embedded DR/EE Energy Impacts (GWh)

Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 41 

6.0 Capacity Needs Assessment 

Based on the assessment of the AEP-SPP Current Resources (Section 4) and its (Peak) Demand 

Projections (Section 5); a “Capacity Needs” assessment can be established that will determine the 

Amount and Timing of capacity resources for this 2009 IRP cycle. 

Exhibits 6-1 and 6-2 are companion charts that summarize the “going-in” need to add over 900 

MW of capacity through the 10-year 2009 IRP window, beyond the current commitments of 

SWEPCO to construct the Stall natural gas combined cycle unit (509 MW) and its share of the Turk 

USC-PC Unit (447 MW). No other new capacity additions are included. Exhibit 6-1 compares the 

demand (line) and capacity (bar) trends over the period. Exhibit 6-2 reflects the culmination of these 

separate impacts. Based on the assumptions discussed, the capacity of the AEP-SPP zone will be in a 

deficit position in 2010. 

Exhibit 6-1: Capacity vs. SPP Minimum Required Reserves 

PSO Capacity and Required Reserve

With no new capacity and no new firm purchases

0

1,000

2,000

3,000

4,000

5,000

6,000

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Load or Capacity, MW

PSO Capacity PSO Capacity Requirement PSO Peak

SWEPCO Capacity and Required Reserve

With no new capacity and no new firm purchases

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Load or Capacity, MW

SWEPCO Capacity SWEPCO Capacity Requirement SWEPCO Peak

Source: AEP Resource Planning 

Note: SWEPCO 2015 peak demand and supply are adjusted to reflect the shift of the NTEC wholesale contract from a full 

requirements basis (inclusive of NTEC self supply) to a fixed (200 MW) demand only basis. 
AEP-SPP 2009 Integrated Resource Plan 

 42 

Exhibit 6-2: Summary of Capacity Deficiency Positions

PSO Capacity Position

With no new (uncommitted) capacity and no new firm purchases

(200)

(100)

-

100

200

300

400

Position, MW

PSO 343 (30) (159) 125 102 73 48 15 (5) (32) (53)

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

SWEPCO Capacity Position

With no new (uncommitted) capacity and no new firm purchases

(500)

(400)

(300)

(200)

(100)

-

100

200

300

400

Position, MW

SWEPCO (177) (382) (45) (105) 278 186 208 139 69 (12) 71 

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Source: AEP Resource Planning

6.1 RTO Requirements 

A minimum planning reserve margin of 13.6% of demand (12% of capacity) is currently 

required by the Southwest Power Pool Criteria and has been assumed to apply throughout the 

planning period. As previously discussed, for purposes of its detailed planning, PSO and SWEPCO 

are assumed to meet this criterion separately, under the assumption that the transmission system 

would limit intra-system capacity transfers. (However, this constraint was relaxed in forming the 

final plan, which allowed up to 200 MW of intercompany capacity transfer.) Moreover, such separate 

planning is in keeping with the spirit of the SPP operating agreement, which intended for reserve 

sharing to be limited among these affiliate companies. Finally, note that this does not preclude PSO 

and SWEPCO assuming joint ownership of future generation asset(s) if the circumstances – inclusive 

of such inter-company firm transfer issues – would warrant.
AEP-SPP 2009 Integrated Resource Plan 

 43 

6.2 Capacity Positions—Historical Perspective 

To provide a perspective, a historical relative capacity position for the AEP-SPP zone is 

presented in Exhibit 6-3. The AEP-SPP zone has experienced minimal capacity reserves above 

minimum SPP requirements throughout the current decade, such positions shifting as a direct function 

of relative peak demand shifts since no long term capacity has been added over that timeframe, until 

the recent addition of 600 MW of peaking capacity. During this period AEP-SPP has relied on 

limited-term (market) capacity purchases to achieve the necessary SPP 13.6% reserve criterion. 

Exhibit 6-3: AEP-SPP Zone, Historical Capacity Position 

AEP -- SPP Zone

HISTORICAL CAPACITY POSITION

Based on a 13.6% SPP Reserve Margin Requirement

Period: 2000 - 2007 (post-AEP/CSW Merger) 

-500

0

500

1,000

1,500

2,000

2,500

2000 2001 2002 2003 2004 2005 2006 2007

 MW

6,500

7,000

7,500

8,000

8,500

9,000

9,500

Summer Peak MW

Capacity Position

Summer Peak Demand 

Y2:Y1 scale is 1:1

Note: AEP's 'going-in" capacity planning positions in 2000 and 2006 were predicated on forecasted 

peak demands that were ultimately exceeded by actual summer peaks.

Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan 

 44 
AEP-SPP 2009 Integrated Resource Plan 

 45 

7.0 Planning Objectives 

In addition to the determination of a fundamental capacity “needs assessment,” the other 

objective of the resource planning effort was to recommend an optimum system expansion plan, not 

only from a least-cost perspective, but also from the perspectives of planning flexibility, creation of 

an optimum asset mix, adaptability to risk and, ultimately, from the perspective of affordability. In 

addition, given its unique impact on generation, the Integrated Resource Planning modeling effort 

must ultimately be in concert with anticipated long-term environmental compliance requirements as 

established by the Environmental Compliance planning process. 

7.1 Planning Flexibility—Covering Capacity Deficient Positions with Market Opportunities 

It has been established in the previous section that, in spite of the recent additions of the 

Mattison (SWEPCO), Riverside (PSO) and Southwestern (PSO) gas generation assets, the AEP-SPP 

zone is faced with a capacity deficiency through 2011 that will need to be met through short-term 

capacity purchases. 

Power market opportunities in the form of limited-term bilateral capacity purchases from nonaffiliated sources and asset purchases at significant discounts relative to new generation will continue 

to be pursued, subject to the firm transportation limitations previously discussed. Therefore, the 

resource modeling and its ultimate results that will drive recommended regional long-term resource 

plans must maintain sufficient implementation flexibility to consider such market or “purchase or 

buy” opportunities in the future. 

7.2 Planning Horizon 

Recognizing the significant time period typically encompassed by the capacity planning 

process–both from the perspective of the ultimate cost exposure of these long-lived assets as well as 

considering the typical in-service lead-time requirement–the evaluations were performed over a 22 

year (2009-2030) detailed capacity resource planning period. In order to recognize the ultimate costbased end-effects of any capacity option established in the latter years of that study period, the 

economics were extended an additional 5 years, resulting in an overall 2009-2035 evaluation period. 

7.3 Establishing the Optimal Asset “Mix” 

Another important “needs” consideration in the planning process is the establishment of longterm regional generating capacity profiles that consider the optimal distribution or “mix” of 

generation technology and, with that, fuel types. As will be discussed later in this section, these 

capacity profiles will need to be practical and useful in terms of operational requirements (dictated 

by operation within the RTO) and affordable in terms of their ability to be funded corporately. 

7.4 Other Operational Factors 

In addition to focusing on the creation of a capacity resource plan that would be considered the 

lowest reasonable life-cycle costs for those customers for whom it is being established, such planning 

must likewise consider the practicality of the Plan from the perspective of it addressing the on-going 

operational needs of the system. Given that, the Strategist modeling (to be discussed) currently 
AEP-SPP 2009 Integrated Resource Plan 

 46 

considers in its costing-profile traditional commodities including energy, fuels, environmental 

(allowance) values, as well as an emerging capacity market. Pricing or value points not currently 

considered represent those factors often thought of as “ancillary” services/values. 

7.5 Affordability 

Any Resource Plan is subjected to a test of affordability. In traditional ratemaking, utilities fund 

the construction of a power plant from start to finish, at which point they seek recovery of the 

investment over time. The initial outlay of capital for such a major investment can be onerous to the 

utility. While earnings are typically not affected by investment program through the accounting of 

“Allowance for Funds Used During Construction” (AFUDC) (which allows utilities to defer to the 

balance sheet book recognition of project financing expenses that are associated with spending capital 

until the project is complete), cash flow will be negatively affected. To fund this cash need, capital 

must be raised; there is a practical limit, however, to how much can be raised before corporate credit 

ratings and, with that, earnings are negatively affected. 

As a result, AEP Corporate Planning & Budgeting and Corporate Finance, among others, 

continually assess plans generated through the IRP cycle process, making recommendations to alter 

the timing, amount, and nature of resource additions specified in the Plan, as warranted. 
AEP-SPP 2009 Integrated Resource Plan 

 47 

8.0 Resource Options 

8.1 Market Options and “Build vs. Buy” Considerations 

In addition to the fundamental capacity pricing information utilized in the modeling, available 

information suggests that capacity reserve margins–inclusive of current and anticipated merchant 

capacity–is declining in the Southwest Power Pool. These pressures may become more pronounced 

as the impact of potential CO2 legislation could depress regional capacity resources. In addition, as 

suggested in Section 4.4, future limitations surrounding inter- and intra-regional transmission 

adequacy could limit planned capability. 

Exhibit 8-1: Projected SPP Capacity Margin

Projected SPP Capacity Margin from 2008 EIA-411 Report

0

5

10

15

20

25

30

35

2007 2009 2011 2013 2015 2017

Capacity Margin, percent

Existing Capacity Committed Capacity Requirement Existing and Planned Capacity

Source: AEP Resource Planning 

Due to various factors discussed here and elsewhere in this document, firm capacity supply as 

well as the firm power mobility of existing merchantable generating assets cannot be assured 

significantly beyond the middle portion of the next decade. Therefore, the intent of this resource 

planning process is to suggest that capacity requirements beyond approximately the year 2013 will be 

met with a combination of new build (or buy) and DR/EE alternatives. 

8.1.1 Non-Affiliated (Market) Purchases 

AEP’s planning position for its SPP zone is to take advantage of market opportunities when they 

are available and economic, either in the form of limited-term bilateral capacity purchases from nonaffiliated sources or by way of available, discounted, merchant generation asset purchases. Such 

market opportunities could be utilized to hedge capacity planning exposures should they emerge and 

create (energy) option value to the company. However, such opportunities must be tempered with the 
AEP-SPP 2009 Integrated Resource Plan 

 48 

realization that two of the AEP west jurisdictions (Louisiana and Oklahoma) have competitive bidder 

rules under which such exceptions must be granted to realize the benefit of an arm’s length bilateral 

transaction. 

As with the need to maintain resource planning and implementation flexibility for various 

supply or demand exposures as identified above, the Plan should likewise seek to continually consider 

such market “buy” prospects, since: 

 this IRP assumes the need to ultimately build generating capability to meet the requirements 

of its customers for which it has assumed an obligation to serve; 

 the regional market price of capacity will likely approach the fixed cost of new-build 

generation; 

 the purchase of merchant generation assets relative to new build generation represents a 

different risk profile with respect to siting, costs and schedule, and 

 the planning flexibility that market purchases could enable is critical to the process. 

8.1.2 Generation Acquisition Opportunities 

AEP investigates the viability of placing indicative offers on additional utility or IPP-owned 

natural gas peaking and combined cycle facilities as such opportunities arise. Analyses are performed 

in the Strategist model based on the most recent IRP studies, to estimate a break-even purchase price 

that could be paid for the early acquisition of such an asset, in lieu of an ultimate greenfield 

installation. As shown in Exhibit 8-2, the cost of these assets now approaches that of a greenfield 

project. 

Exhibit 8-2: Recent Merchant Generation Purchases 

0

150

300

450

600

750

900

1,050

1,200

2003 2004 2005 2006 2007 2008 2009

Purchase Price, $/kW

McClain Energy CC

Dogwood CC

Acadia CC

Redbud CC

Spring Creek CT

Range of current greenfield CT/CC costs

 Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 49 

8.2 Traditional Capacity-Build Options 

8.2.1 Generation Technology Assessment and Overview 

AEP’s New Technology Development organization is responsible for the tracking and 

monitoring of estimated cost and performance parameters for a wide array of generation technology 

alternatives. Utilizing access to industry collaboratives such as EPRI and Edison Electric Institute 

(EEI), AEP’s association with architects and engineering firms (A&Es) and original equipment 

manufacturers (OEMs), as well its own experience and market intelligence, this group continually 

monitors such supply-side trends. Appendix C offers a summary of the most recent technology cost 

and performance parameter data developed. 

8.2.2 Baseload Alternatives 

Coal-based baseload technologies include pulverized coal combustion designs, integrated 

gasification combined cycle facilities, and circulating fluidized bed combustors. Nuclear is becoming 

a more viable option, and the application process for the construction of nuclear power plants has 

been initiated by several utilities. It is AEP’s current view that, while great difficulty and risk still 

exist in the siting and construction of nuclear power plants, nuclear power should be among our 

baseload options for the future. Nuclear power was modeled in the AEP-SPP planning scenarios and 

sensitivities, primarily due to the sheer (MW Nameplate) size of economical nuclear unit options visà-vis the relative capacity requirements of PSO and SWEPCO. Nuclear power, however, should not 

be excluded from future plans, especially if partners could be found. 

8.2.2.1 Pulverized Coal (PC) 

PC plants have been considered to be the workhorse of the U.S. electric power generation 

infrastructure. In a PC plant, the coal is ground into fine particles that are blown into a furnace where 

combustion takes place. The heat from the combustion of coal is used to generate steam to supply a 

steam turbine that drives a generator to make electricity. Major by-products of combustion include 

SO2, NOX, CO2, and ash, as well as various forms of elements in the coal ash including Mercury (Hg). 

The steam cycle for the pulverized coal-fired units – which determines the efficiency of 

generating electricity – falls into one of two categories, subcritical or supercritical. Subcritical 

operating conditions are generally accepted to be at up to 2,400 psig/1,000°F superheated steam, with 

a single reheat to 1,000°F, while supercritical steam cycles typically operate at up to 3,600 psig, with 

1,000-1,100°F main steam and reheat steam temperatures. AEP has recognized the benefits of the 

supercritical design for many years. All eighteen of the units in the AEP-East system built since 1964 

have utilized the supercritical design. There have been advances in the supercritical design over the 

years, and there are now commercial units operating at or above 3,600 psig and >1,100°F steam 

temperatures. This is known as an ultra supercritical (USC) design, as defined by temperature. 

The initial capital costs of subcritical units are lower than those of a comparable supercritical 

unit by about 4 to 6 percent, but the overall efficiency of the supercritical design is higher than the 

subcritical design by approximately 3 percent. Due to cycle design improvements, the new variable 

pressure ultra supercritical units are projected to have–at commercial quantities–an initial capital cost 

of only 1-2 percent greater than a comparable supercritical unit. While the overall efficiency remains 
AEP-SPP 2009 Integrated Resource Plan 

 50 

approximately 3 percent better than the comparable supercritical unit, the efficiency improvement is 

present throughout the entire load range, not just at full load conditions. 

8.2.2.2 Integrated Gasification Combined Cycle (IGCC) 

Given the long time-horizons of most resource planning exercises, IRP processes must be able 

to consider new technologies with uncertain costs, such as IGCC. The assessment of such 

technologies is based on cost and performance estimates from commonly cited public sources, 

consortiums where AEP is actively engaged, vendor relationship, as well as AEP’s own experience 

and expertise. 

IGCC technology has the potential to achieve the environmental benefits closer to those of a 

natural gas-fired plant, and thermal performance closer to that of a combined cycle facility, yet with 

the low fuel cost associated with coal. As discussed in this year’s IRP report for the AEP East Zone, 

IGCC appears well-positioned for integration of ultimate carbon capture and sequestration 

technologies, which will be a critical measure in any future mitigation of greenhouse gas emissions. 

As an additional observation, the small number of IGCC equipment suppliers means a large share of 

technology and performance risk falls on owners, although the on-going collaboration with 

technology developers, including GE/Bechtel, mitigates some of this risk. However, as it applies to a 

design that would utilize sub-bituminous (PRB) coal, IGCC technology is less mature and therefore is 

not a viable resource option in this near (2010-2019) term. 

8.2.2.3 Circulating Fluidized Bed Combustion (CFB) 

A CFB plant is similar to a PC plant except that the coal is crushed rather than pulverized, and 

the coal is combusted in a reaction chamber rather than the furnace of a PC boiler. CFB boilers are 

capable of burning a wide range of fuels that cannot be accommodated by PC designs, including 

bituminous and sub-bituminous coal, coal waste, lignite, petroleum coke, a variety of waste fuels, and 

biomass. Units are sometimes designed to fire using several fuels, which emphasizes this 

technology’s major advantages: its inherent fuel flexibility. Coal is combusted in a hot bed of sorbent 

particles that are suspended in motion (fluidized) by combustion air blown in from below through a 

series of nozzles. CFB boilers operate at lower temperatures than pulverized coal-fired boilers. The 

energy conversion efficiency of CFB plants tends to be slightly lower than that of pulverized coalfired counterparts of the same size and steam conditions because of higher excess air and auxiliary 

power requirements. 

CFB boilers capitalize on the unique characteristics of fluidization to control the combustion 

process, minimize NOX formation, and capture SO2 in-situ. Specifically, SO2 is captured during the 

combustion process by limestone being fed into the bed of hot particles that are fluidized by the 

combustion air blown in from below. The limestone is converted into free lime, which reacts with the 

SO2. The chemical process does disadvantage CFB by contributing to relative Hg emission exposure. 

8.2.2.4 Nuclear 

Although new reactor designs and ongoing improvements in safety systems make nuclear power 

a potentially viable option as a new-build alternative due to it being an emission-free power source, 
AEP-SPP 2009 Integrated Resource Plan 

 51 

concerns about public acceptance/permitting, spent nuclear fuel storage, lead-time, and capital costs 

continue to temper its consideration. Because of the long lead time to bring a nuclear unit on-line, and 

the large generating capacity of nuclear units, AEP does not view nuclear as a viable candidate to 

meet the capacity resource needs of AEP-SPP within this near-term period (2010-2019). 

8.2.3 Intermediate Alternatives 

Intermediate generating sources are typically expected to serve a load-following and cycling 

duty and shield baseload units from that obligation. 

8.2.3.1 Natural Gas Combined Cycle (NGCC) 

An NGCC plant combines a steam cycle and a combustion gas turbine cycle to produce power. 

Hot gases (~1,100°F) from a combustion turbine exhaust pass through a heat recovery steam 

generator (HRSG) where they are cooled to about 250°F, and in doing so, produce steam. The steam 

drives a steam turbine generator which produces about one-third of the NGCC plant power with, 

depending upon the gas-to-steam turbine design “platform,” while one or more combustion turbines 

produce the other two-thirds. 

The main features of the NGCC plant are high reliability, reasonable capital costs, operating 

efficiency (at 45-55% LHV), low emission levels, and shorter construction period than coal-based 

plants. In the past 8 to 10 years NGCC plants were most widely selected to meet new intermediate 

and certain baseload needs. Although cycling duty is typically not a concern, an issue faced by 

NGCC when load-following is the erosion of efficiency due to inability to maintain optimum air-tofuel pressure and turbine exhaust and steam temperatures. Methods to address these include: 

 Installation of advanced automated controls. 

 Installation of gas dampers to bypass gas from turbine exhaust, maintaining exhaust/steam 

temperatures while steam flow to the steam turbine generator is decreased with load. 

 Supplemental firing while at full load with a reduction in firing when load decreases. When 

supplemental firing reaches zero, fuel to the gas turbine is cutback. This approach would 

reduce efficiency at full load, but would likewise greatly reduce efficiency degradation in 

lower-load ranges. 

 Use of a multiple gas turbine coupled with a waste heat boiler that will give the widest load 

range with minimum efficiency penalty. 

8.2.4 Peaking Alternatives 

Peaking generating sources are required to provide needed capacity during extreme high-use 

peaking periods and/or periods in which significant shifts in the load (or supply) curve dictate the 

need for “quick-response” capability. As a result, fuel efficiency and other variable cost are of lesser 

concern. In addition, in certain situations, peaking capacity such as combustion turbines can provide 

backup and some have the ability to provide emergency (black-start) capability to the grid. 
AEP-SPP 2009 Integrated Resource Plan 

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8.2.4.1 Simple Cycle Combustion Turbines (NGCT) 

In “industrial” or “frame-type” combustion turbine systems, air compressed by an axial 

compressor (front section) is mixed with fuel and burned in a combustion chamber (middle section). 

The resulting hot gasses then expand and cool while passing through a turbine (rear section). The 

rotating rear turbine not only runs the axial compressor in the front section but also powers an electric 

generator. The exhaust from a combustion turbine can range in temperature between 800 and 1,150 

degrees Fahrenheit and contains substantial thermal energy. A simple cycle combustion turbine 

system is one in which the exhaust from the gas turbine is vented to the atmosphere and its energy 

lost. While not as efficient (at 30-35% LHV), they are, however, inexpensive to purchase, compact, 

and simple to operate. Further, simple cycle CTs can be started up and placed in service far more 

rapidly than any system involving a steam turbine. 

8.2.4.2 Aeroderivatives (AD) 

Aeroderivatives are aircraft jet engines used in ground installations for power generation. They 

are smaller in size, lighter weight, and can start and stop quicker than their larger industrial or "frame" 

counterparts. For example, the GE 7EA requires 20 minutes to ramp up to full load while the smaller 

LM6000 aeroderivative only needs 10 minutes to full load. However, the cost per kW of an 

aeroderivative is on the order of 50% higher than a frame machine. 

Their performance requirements, calling for rapid startup and shutdown, make the 

aeroderivatives well suited to peaking generation needs. The aeroderivatives can operate at full load 

for a small percentage of the time allowing for multiple daily startups to meet peak demands, 

compared to industrial units which are more commonly expected to start up once per day and operate 

at continuous full load for 10 to 16 hours per day. The cycling capabilities provide aeroderivatives 

the ability to backup intermittent renewables such as solar and wind. 

Aeroderivatives weigh less than their industrial counterparts allowing for skid or modular 

installations. Efficiency is also a consideration in choosing an aeroderivative over an industrial 

turbine. Aeroderivatives in the below 50 MW range are more efficient and have lower heat rates in 

simple cycle operation than industrial units of the same size. Exhaust gas temperatures are also lower 

in the aeroderivative units. 

Some of the better known aeroderivative vendors and their models include GE's LM series, Pratt 

& Whitney's FT8 packages, and the Rolls Royce Trent and Avon series of machines. 

8.2.5 Energy Storage 

Energy storage refers to technologies that allow for storage of energy during periods of reduced 

demand and discharge of energy during periods of peak demand. This has the effect of flattening the 

load curve by reducing the peaks and “filling the valleys.” In this sense, it is considered a peaking 

asset. Energy storage consists of batteries (Sodium Sulfur “NaS,” Lithium Ion, and others), super 

capacitors, flywheels, or pumped hydro storage. Pumped storage hydro uses two water reservoirs, 

separated vertically. During off peak hours water is pumped from the lower reservoir to the upper 

reservoir. When required, the water flow is reversed to generate electricity. 
AEP-SPP 2009 Integrated Resource Plan 

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The investment requirements for pumped hydro storage are significant. Further, site-selection 

and attainment of FERC licensing represent huge challenges. NaS Batteries are the leading 

technology under consideration for storage-related utility planning. 

Appendix C, page 2 describes an energy storage technology screening curve which could be 

used to indicate whether a particular technology warrants further investigation. 

8.2.5.1 Sodium Sulfur Batteries (NaS): 

Storage technologies have begun to receive greater consideration due partly to the improved 

battery-storage technologies; efficiencies now are approaching 90%. That, coupled with the ability to 

offer market time-of-day pricing arbitrage by charging during low-cost off-peak periods and 

discharging at higher-cost daytime periods, works to its advantage. Batteries can be sited near load 

points, thus avoiding peak line losses. The downside currently is the significant cost per kW and, due 

to their weight and transportation, total costs approaching $1,800-2,000 per kW. 

In light of battery-storage’s potential for 1) the market arbitrage, 2) line loss reduction, 3) 

deferral of selected distribution infrastructure through selective siting of storage capacity, coupled 

with the prospect for reduced capital costs due to improvements in battery technology, its 

consideration as a potential capacity resource is warranted. 

8.2.5.2 Community Energy Storage (CES) 

Community energy storage (CES) is being tested for distributed storage. The use of distributed 

storage technology, which will involve the placement of small energy storage batteries throughout 

residential areas, will look similar to the small transformer boxes currently seen throughout 

neighborhoods. Each box should be able to power four to six houses. AEP is testing this potential 

game-changing technology, which should also provide voltage sag mitigation as well as emergency 

transformer load relief. 

8.2.5.3 Flywheel Energy Storage and Frequency Regulation 

AEP has contracted with Beacon Power Corp., to build a 1 MW, 250 kWh energy storage and 

frequency regulation facility at AEP’s Groveport, Ohio, site using Beacon’s flywheel-based 

technology. 

The new agreement supports grid efficiency and reliability and follows closely on contracts 

Beacon has entered with independent system operators (ISO) in New England and New York to 

deploy its system, which stores kinetic energy on spinning flywheels. Beacon can then release that 

energy on command from ISOs to balance the grid in a more cost-effective manner than using peaker 

plants, the method now used by grid operators. Under the contract with AEP, which includes the 

utility’s Columbus Southern Power Co. operating unit, Beacon will deliver, install, test and operate 

the 1 MW facility at its own expense beginning mid-year 2009. AEP will provide materials and 

services needed to interconnect the flywheel system to PJM, including the foundation, electrical 

transformer, associated wiring and connection to power lines. However, given the existing limitations 

associated with the energy storage capabilities, flywheel technology is not a practical alternative for 

AEP-SPP capacity planning. 
AEP-SPP 2009 Integrated Resource Plan 

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8.3 Renewable Alternatives 

Renewable generation alternatives represent those in which nontraditional (e.g., non-fossil) fuel 

sources that are either naturally occurring (wind, solar, hydro or geothermal), or are sourced from a 

by-product or waste-product of another process (biomass or landfill gas), are utilized. Numerous 

renewable energy sources are under development or exist, but many sources like solar, geothermal, 

and tidal, are simply not economic options for AEP within our service territory, based on the current 

state of development for those technologies or for meteorological or geographical reasons. Within the 

AEP service territory and without significant leaps in technology, biomass co-firing in coal power 

plants and wind plants are the primary options for economically (or realistically) generating 

electricity on a significant scale from renewable sources. 

As highlighted in the Section 2 Overview, although effective in 29 states and the District of 

Columbia, a mandatory RPS exists today in Ohio, Michigan, West Virginia and Texas, and a 

voluntary RPS exists in Virginia. This being said, the notion of a potential Federal RPS is sufficiently 

tenable to warrant an evaluation of the merits of renewable generation in conjunction with this IRP 

process. Further, renewable energy sources have the ability to deliver attractive CO2 benefits in a 

potentially carbon-constrained policy environment. 

AEP’s New Technology Development group evaluated a wide range of renewable technologies 

beginning in 2005, with the latest updates in early 2009. The evaluations involved a multifaceted 

effort using input from many AEP groups. Technologies were evaluated on cost, location, feasibility, 

applicability to AEP’s service territory, and commercial availability. After a high-level evaluation, 

economic screening was carried out considering each technology’s estimated costs and effectiveness, 

to develop a levelized dollar-per-renewable-MWh cost. Costs and benefits considered in the 

screening included project capital and O&M costs; avoided capacity and energy costs; alternative fuel 

costs; alternative emission rates and associated allowance costs; and available federal or state 

production tax credits, if any. The levelized cost was used to rank the various technologies. 

The renewable technologies ultimately screened include: 

 biomass co-firing on existing coal-fired units 

 separate injection of biomass on existing coal-fired units 

 wind farms 

 evaluated separately for the East and West regions 

 with and without the federal production tax credit 

 solar generation 

 incremental hydroelectric production 

 landfill gas with microturbine 

 geothermal generation 

 distributed generation 

Although some of the renewable technologies listed above could be economic, AEP is 

constrained from doing some of these projects because the energy sources are geographically 

constrained in AEP service territory (e.g., geothermal). Similarly, biomass co-firing is constrained by 

a supply of suitable fuel and/or transportation options anticipated to be in proximity to the host coal 

units evaluated. Thus, the renewable resources available to be included in the Plan are not 
AEP-SPP 2009 Integrated Resource Plan 

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necessarily the least expensive options screened, but rather those that provide suitable economics and 

practicality. A complete list of screened renewable technologies and their incremental levelized life 

cycle costs is included in Appendix B. 

8.3.1 Wind 

Wind is currently the fastest growing form of electricity generation in the world. Utility wind 

energy is generated by wind turbines with a range 1.0 to 2.5 MW, with a 1.5 MW turbine being the 

most common size used in commercial applications today. Typically, multiple wind turbines are 

grouped in rows or grids to develop a wind turbine power project which requires only a single 

connection to the transmission system. Location of wind turbines at the proper site is particularly 

critical from the perspective of both the existing wind resource and its proximity to a transmission 

system with available capacity. 

Ultimately, as production increases to match the significant increase in demand, the high capital 

costs of wind generation should begin to decline. Currently, the cost of electricity from wind 

generation is competitive within the PSO and SWEPCO service territories only because of the 

accompanying subsidies, such as the federal production tax credit as well as consideration given to 

REC values, rising fuel costs or future carbon costs. 

A drawback of wind is that it represents a sporadic or fluctuating source of power in most noncoastal locales, with capacity factors ranging from approximately 35 to 40+ percent in the west; thus 

its life-cycle cost ($/MWh) is more often higher than traditional generating sources, in spite of wind’s 

zero fuel cost. Another obstacle with wind power is that its most critical factors (i.e., wind speed and 

sustainability) are typically highest in very remote locations, and this forces the electricity to be 

transmitted long distances to load centers necessitating the buildout of EHV transmission to optimally 

integrate large additions of wind into the grid. Exhibit 8-3 shows the potential wind resource 

locations in the United States 
AEP-SPP 2009 Integrated Resource Plan 

 56 

Exhibit 8-3: United States Wind Power Locations 

Source: NREL 

8.3.2 Solar 

 Solar power takes a couple of viable forms to produce electricity: concentrating and 

photovoltaics. Concentrating solar – which heats a working fluid to temperatures sufficient to power 

a turbine - produces electricity on a large scale (100 MW) and is similar to traditional centralized 

supply assets in that way. Photovoltaics produce electricity on a smaller scale (2-500 kW per 

installation) and are distributed throughout the grid. Exhibit 8-4 shows direct normal solar radiation 

in the United States. 
AEP-SPP 2009 Integrated Resource Plan 

 57 

Exhibit 8-4: United States Solar Resource Map 

8.3.3 Biomass 

Biomass is a term that includes organic waste products (sawdust or other wood waste), organic 

crops (switchgrass, poplar trees, willow trees, etc.), or biogas produced from organic materials. 

It is generally accepted that biomass represents a carbon neutral fuel. Biomass is part of the 

carbon cycle. Carbon from the atmosphere is converted into biological matter by photosynthesis. On 

combustion the carbon goes into the atmosphere as carbon dioxide (CO2). This happens over a 

relatively short timescale and plant matter used as a fuel can be replaced by planting for new growth. 

Therefore a reasonably stable level of atmospheric carbon results from its use as a fuel. 

In the United States today, a large percentage of biomass power generation is based on woodderived fuels, such as waste products from the pulp and paper industry and lumber mills. Biomass 

from agricultural wastes also plays a dominant role in providing fuels. These agricultural wastes 

include rice and nut hulls, fruit pits, and animal manure. 

A relatively low-cost option to produce electricity by burning biomass is by co-firing it with 

coal in an existing boiler using existing coal feeding mechanisms. In a typical biomass co-firing 

application, 1.5% to 6% of the generating unit’s heat input is provided by biomass, depending on the 

boiler’s method of firing coal. A more capital-intensive option is separate injection, which involves 

separate handling facilities and separate injection ports for the biomass. Separate injection can 

achieve a 10% heat input from biomass. 
AEP-SPP 2009 Integrated Resource Plan 

 58 

Co-firing generally provides a lower-cost method of energy generation from biomass than 

building a dedicated biomass-to-energy power plant. In addition, a coal-fired power plant typically 

uses a more efficient steam cycle and consumes relatively less auxiliary power than a dedicated 

biomass plant, and thus generates more power from the same quantity of biomass. 

Some possible drawbacks associated with biomass co-firing or separate injection include 

reduced plant efficiencies due to lower energy content fuels, loss of fly ash sales, and fouling of SCR 

catalysts. Although these relatively minor obstacles can be mitigated through various means, the 

major obstacle to the utilization of biomass as a feedstock is the transportability and resulting cost of 

the biomass fuel. Biomass has many competing demands, such as the pulp and paper, agriculture 

industries, as well as the ethanol market, which can dramatically escalate the market price for the 

material along with the transportation of such a low energy-density fuel. Another issue associated 

with biomass is the significant quantities of land dedicated and required to generate sufficient 

quantities of biomass as identified in Exhibit 8-5. 

Exhibit 8-5: Land Area Required to Support Biomass Facility 

Source: AEP Resource Planning 

Biomass co-firing provides many valuable benefits and holds some promise for the AEP 

generating fleet, but the high fuel/transportation costs and the limited deployment potential on a heatinput basis could inhibit the near-term viability of the technology on a large scale. Exhibit 8-6 shows 

potential biomass resources. 

Biomass co-firing is not a substitute for generation. Because it simply substitutes “carbonneutral” fuel for fossil fuels, it does not eliminate the need for building generation as (peak) demand 

grows and assets are retired. However, if and when GHG become regulated, biomass co-firing could 

become an economically viable way to reduce the CO2 output of certain coal-fired plants. 

Switchgrass Wood Chips / Sawdust 

 (per Purdue University Study) (per AEP-Forestry) 

o 6 -to- 8 tons /yr. per acre yield o 70 -to-100 tons /yr. per acre yield*

o @ 6700 Btu/lb (non-dried, as harvested) * "clear cutting" on a 40-year cycle

o @ 4800 Btu/lb (green, non-dried)

 A 200-MW Dedicated Biomass Facility A 200-MW Dedicated Biomass Facility

 (70% C.F.) would require... (70% C.F.) would require...

110k -to- 150k harvested acres 510k -to- 730k timbered acres 

 (172 - 234 sq. mi,) (795 - 1,140 sq. mi,)

 10-GW (~60 Twh/yr.) of switchgrass-fired biomass capacity 10-GW of (clear-cut) wood chip-fired capacity would 

 would require approx. 45 MM t/yr. of switchgrass which require approx. 64 MM t/yr. of wood product which would

 would require dedicated agri-land mass = 6.5 MM acres require dedicated forested-land mass = 31 MM acres

 ... or 100% of the cropland and pasture/grassland ... or 100% of the forested acreage identified by the USDA

 identified by the USDA in the state of Georgia in North Carolina and South Carolina combined
AEP-SPP 2009 Integrated Resource Plan 

 59 

Exhibit 8-6: Biomass Resources in the United States 

Source: NREL 

8.3.4 Renewable Alternatives—Economic Screening Results 

AEP has established an internal renewable target of 10% of System energy (total SPP and East 

zones) from renewable resources by 2020 (see Appendix E). Based on current AEP system renewable 

resources, and considering an additional 1,000 MW of renewable resources recently committed to by 

the year-end 2011 this internal commitment is projected to be satisfied as reflected in Exhibit 8-7. 
AEP-SPP 2009 Integrated Resource Plan 

 60 

Exhibit 8-7: Renewable Sources Included in AEP-SPP and East 2009 IRP

AEP System

Existing and Projected Renewables for 2009 IRP

Cumulative Percent of

Operating Company First Annual Annual Projected 

Size (Existing or Awarded No. of Full Energy Energy Retail

Unit, Plant, or Contract (MW) Contracts) Units Year (GWh) (GWh) Sales

Existing Wind 

SW Mesa 31 SWEPCO Existing 99 99 0.1% Note 1

Weatherford 147 PSO Existing 569 668 0.5%

Blue Canyon 151.2 PSO Existing 581 1,249 0.9%

Sleeping Bear 94.5 PSO Existing 346 1,595 1.2%

Camp Grove Wind 75 APCo Existing 250 1,845 1.3%

Executed PPA Contracts

Fowler Ridge I Wind 200 APCo/I&M 2010 605 2,450 1.8%

Grand Ridge II & III Wind 100.5 APCo 2010 288 2,738 2.0%

Fowler Ridge II Wind 150 I&M/CSP/OPCo 2010 454 3,192 2.3%

Majestic Wind 79.5 SWEPCO 2010 300 3,492 2.3%

Solar (Wyandotte) 10.0 CSP/OPCo 144 2010 10 3,502 2.5%

Blue Canyon V Wind 99 PSO 2011 373 3,875 2.6%

Beech Ridge Wind 100.5 APCo 2011 288 4,164 2.8%

Elk City Wind 98.9 PSO 2011 373 4,536 3.0%

New Projects

East Wind 600 2011 1722 5,224 3.5%

West Wind 100 2011 377 5,601 3.8%

Muskingum River 5 0 2011 63 6,698 4.5% Note 2

Solar (Distributed) 3.1 45 2011 3 6,702 4.5%

Biomass Plant 60 2012 463 7,164 4.8% Note 3

Amos 3 0 2012 144 7,308 4.9% Note 2

East Wind 600 2012 1722 9,030 6.0%

 (Indiana-specific) Wind 100 2012 287 9,317 6.2%

West Wind 100 2012 377 9,694 6.4%

Solar (Distributed) 1.5 22 2012 2 9,696 6.4%

 West Wind 150 2013 566 10,261 6.8%

 East Wind 400 2013 1148 11,409 7.5%

 (Indiana-specific) Wind 100 2013 287 11,696 7.7%

 Rockport 1-2 0 2013 385 12,081 8.0% Note 2

Solar (Distributed) 14 200 2013 15 12,096 8.0%

Solar (Distributed) 14 200 2014 15 12,110 8.0%

 West Wind 100 2015 377 12,487 8.2%

Solar (Distributed) 14 200 2015 15 12,502 8.2%

 Muskingum R 5 0 2015 350 12,852 8.4% Note 4

 Big Sandy 2 0 2015 571 13,423 8.8% Note 4

 West Wind 100 2016 377 13,800 9.0%

 East Wind 100 2016 287 14,087 9.1%

Solar (Distributed) 14 200 2016 15 14,101 9.1%

 West Wind 200 2017 754 14,855 9.6%

 East Wind 0 2017 0 14,855 9.6%

Solar (Distributed) 13 190 2017 14 14,869 9.6%

 Welsh one unit 0 2017 54 14,923 9.6% Note 2

 East Wind 0 2018 0 14,923 9.5%

Muskingum River unit 127 2018 779 15,702 10.0% Note 5

Solar (Distributed) 17 250 2018 18 15,720 10.1%

 Amos 3 0 2019 792 16,512 10.5% Note 4

Solar (Distributed) 17 250 2019 18 16,530 10.5%

 West Wind 200 2020 754 17,284 10.9%

 East Wind 200 2020 574 17,858 11.3%

Solar (Distributed) 16 230 2020 17 17,875 11.3%

These new projects after 2010 represent the results of a high level economic screen only

Note 1: RECs only Note 3: Potential Dedicated Facility PPA Note 5: Convert to Biomass Stoker

Note 2: Potential Biomass Cofire Note 4: Biomass Separate Injection 

Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 61 

8.4 Carbon Capture 

CO2 capture is the separation of CO2 from emissions sources or the atmosphere and the recovery 

of a concentrated stream of CO2 that is suitable for sequestration or conversion. Efforts are focused 

on systems for capturing CO2 from coal-fired power plants, although the technologies developed will 

also be applicable to natural-gas-fired power plants, industrial CO2 sources, and other applications. In 

PC plants, which are 99% of all coal-fired power plants in the United States, CO2 is exhausted in the 

flue gas at atmospheric pressure at a concentration of 10-15% of volume. This is a challenging 

application for CO2 capture because: 

 The low pressure and dilute CO2 concentration dictate a high volume of gas to be treated. 

 Trace impurities in the flue gas tend to reduce the effectiveness of the CO2 absorption 

processes. 

 Compressing captured CO2 from atmospheric pressure to pipeline pressure (1,200 to 2,000 

pounds per square inch) requires a large parasitic load. 

Aqueous amines are the current state-of-the-art technology for CO2 capture for PC power 

plants. The 2020 Department of Energy aspirational goal for advanced CO2 capture systems is that 

CO2 capture and compression added to a newly constructed power plant increases the cost of 

electricity no more than 35%, versus the current 65%, relative to a no-capture case. 

However, with IGCC technology CO2 can be captured from a synthesis gas (coming out of the 

coal gasification reactor) before it is mixed with air in a combustion turbine. The pre-combusted CO2

is relatively concentrated (50% of volume) and at higher pressure. These conditions offer the 

opportunity for lower-cost CO2 capture. The state-of-the-art technology for CO2 capture from an 

IGCC power plant is the glycol-based Selexol sorbent. The 2012 Department of Energy aspirational 

goal as of April 2009 for advanced CO2 capture and sequestration systems applied to an IGCC is no 

more than a 10% increase in the cost of electricity from the current 30%. It is a more stringent goal 

given that the conditions for CO2 capture are more favorable in an IGCC plant. 

8.4.1 Carbon Storage/Sequestration 

Storage is the placement of CO2 into a repository in such a way that it will remain sequestered 

for hundreds of thousands of years. 

Geologic formations considered for CO2 storage are layers of porous rock deep underground 

that are “capped” by a layer of nonporous rock above them. The storage process consists of drilling a 

well into the porous rock and then injecting pressurized (“spongy” liquid) CO2 into it. The CO2 is 

buoyant and flows upward until it encounters the layer of nonporous rock and becomes trapped. 

There are other mechanisms for CO2 trapping as well. CO2 molecules dissolve in brine and react with 

minerals to form solid carbonates, or be absorbed by porous rock. The degree to which a specific 

underground formation is suitable for CO2 storage can be difficult to discern. Research is aimed at 

developing the ability to characterize a formation before CO2 injection to be able to predict its CO2

storage capacity. Another area of research is the development of CO2 injection techniques that 

achieve broad dispersion of CO2 throughout the formation, overcome low diffusion rates, and avoid 

fracturing the cap rock. These two areas, site characterization and injection techniques, are 
AEP-SPP 2009 Integrated Resource Plan 

 62 

interrelated because improved formation characterization will help determine the best injection 

procedure. 

8.4.2 Carbon Capture Technology and Alternatives 

While not yet considered as an economically viable supply-side option, the costs to remove CO2

from the effluent stream and sequester it in geological formations will have increasing efficacy as the 

cost of CO2 increases over time. 

Reducing CO2 emissions from a fossil-fuel technology can be accomplished in three ways: 

increased generating efficiency, removing the CO2 from the flue gas, or reducing the carbon content 

of the fuel. While effective, increasing the generating efficiency of a coal-based plant has its practical 

limitations from a design and performance perspective. Removing the CO2 from the flue gas of a PC 

plant is a very expensive process. Currently, the only demonstrated technology used to “scrub” the 

CO2 from the flue gas is by using a monoethanolamine (MEA) or methyldiethanlamine (MEDA) 

absorption process. 

As previously mentioned in this report, AEP is pursuing an alterative approach. The Company 

is currently conducting commercial validation of Alstom’s chilled ammonia PC carbon capture 

technology at its 1,300 MW Mountaineer plant in West Virginia. It is anticipated that this technology 

can achieve 50% CO2 capture at a lower cost than other retrofit technologies. Based on that 

Mountaineer (20 MW) slip-stream test, a subsequent 235 MW commercial installation of this chilled 

ammonia technology has been proposed for Mountaineer. 

Reducing the carbon content of the fuel can be accomplished by either switching from coal to 

natural gas (natural gas has approximately 44% less carbon than coal and a correspondingly greater 

hydrogen content) or by removing the carbon from synthetic gas derived from coal before it is 

combusted, as would be the case for CO2 removal in an IGCC system. 

8.5 Demand Side Alternatives 

8.5.1 Background 

“Demand Side Management” (DSM) refers to, for the purposes of this IRP, utility programs, 

including tariffs, which encourage reduced energy consumption, either at times of peak consumption 

or throughout the day/year. Programs or tariffs that reduce consumption at the peak are “demand 

reduction” (DR) programs, while round-the-clock measures are “energy efficiency” (EE) programs. 

The distinction between peak demand reduction and energy efficiency is important, as the solutions 

for accomplishing each objective are typically different, but not necessarily mutually exclusive. 

8.5.2 Demand Response 

Peak demand, measured in megawatts (MW), can be thought of as the amount of power used at 

the time of maximum power usage. In the AEP-West zone, this maximum (peak demand) is likely to 

occur on the hottest summer weekday of the year, in the late afternoon. This happens as a result of 

the near-simultaneous use of air conditioning by the majority of customers, as well as the normal use 
AEP-SPP 2009 Integrated Resource Plan 

 63 

of other appliances and (industrial) machinery. At all other times during the day, and throughout the 

year, the use of power is less. 

As peak demand grows with the economy and population, new capacity must ultimately be 

built. To defer construction of new power plants, the amount of power consumed at the peak must be 

reduced. This can be addressed several ways via both “active” and “passive” measures: 

 Interruptible loads. This refers to a contractual agreement with the utility and a heavy 

consumer of power, typically an industrial customer. In return for reduced rates, an 

industrial customer allows the utility to “interrupt” or turn off his power during peak 

periods, freeing up that capacity for other consumers. 

 Direct load control. Very much like an (industrial) interruptible load, but accomplished 

with many more, smaller, individual loads. Commercial and residential customers, in 

exchange for monthly credits or payments, allow the utility to (remotely) deactivate discrete 

appliances, typically air conditioners, hot water heaters, or pool pumps during periods of 

peak demand. These power interruptions can be accomplished through radio signals that 

activate switches or through a digital “smart” meter that allows activation of thermostats and 

other control devices. 

 Variable rates. Offers customers different rates for power at different times during the year 

and even the day. During periods of peak demand, power would be relatively more 

expensive, encouraging conservation. Rates can be split into as few a two rates (peak and 

off-peak) and to as often as hourly in what is known as “real-time pricing”. Accomplishing 

real-time pricing requires digital metering. 

 Energy Efficiency measures. If the appliances that are in use during peak periods use less 

energy to accomplish the same task, peak energy requirements will likewise be less. This 

represents a “passive” demand response. 

 Line loss mitigation. A line loss results during the transmission and distribution of power 

from the generating plant to the end user. To the extent that these losses can be reduced, 

less energy is required from the generator. 

What may be apparent is that, with the exception of Energy Efficiency measures, the amount of 

power consumed is not typically reduced. Less power is consumed at the peak, but to accomplish the 

same amount of work, that power will be consumed at some point during the day. Instead of the air 

conditioner operating at four o’clock, it will come on at six to get the house cooled down. If rates 

encourage someone to avoid running their dishwasher at four, they will run it at some other point in 

the day. This is also referred to as load shifting. 

8.5.3 Energy Efficiency 

EE measures save money for customers billed on a “per kilowatt-hour” usage basis. The tradeoff is the reduced utility bill for any up-front investment in an appliance/equipment modification, 

upgrade, or new technology. If the consumer feels that the new technology is a viable substitute and 

will pay him back in the form of reduced bills over an acceptable period, he will adopt it. 
AEP-SPP 2009 Integrated Resource Plan 

 64 

EE measures will, in all cases, reduce the amount of energy consumed. They will accomplish 

the same task for less energy. However, EE may have limited effectiveness at the time of peak 

demand and, in fact, that is often the case. 

Some examples will illustrate this point. First, a more efficient air conditioner will likely reduce 

consumption at the peak; the same amount of cool air is being generated with less energy. A more 

efficient refrigerator will have a lesser impact on the peak as the chance of it running consistently at 

the peak time (“peak coincidence”) is less than that of the air conditioner. A compact fluorescent 

light bulb (CFL), while using considerably less energy to accomplish the same task, has low 

coincidence (the peak occurs during the daylight hours), and outdoor lighting has coincidence of zero 

(for the same reason). 

Conversely, the efficiency measures that have the greatest effectiveness at the peak save the 

least energy (in very broad terms) because they are seasonal. This is less true in warmer climates 

where the summer season is longer; an efficient air conditioner will conserve more energy in 

Oklahoma than in Michigan (note the ratio of peak savings to energy conservation differences for air 

conditioning measures between AEP’s East and West service territories in the following chart). 

Exhibit 8-8 shows the relationship of typical measures on the continuum of “Demand 

Response” to “Energy Efficiency.” Demand response measures, which interrupt load at the peak and 

have no energy savings, are at the far left. Measures with larger energy efficiency components–with 

little corresponding peak demand reduction–are to the right. The y-axis is merely a ratio of energy 

conservation (kWh) to demand reduction (kW). 

Notably, the air conditioning measures (“Residential AC” and “Commercial HVAC”) show 

distinct differences by region. Because air conditioners are likely to be on during the peak (high 

coincidence), there is a significant peak demand reduction component. In the West, where the 

cooling season is longer, there is a larger energy conservation component. Thus, the ratio of demand 

reduction to energy conservation is lower for these measures in the West, relative to the East. While 

there are differences, it is perhaps equally notable that the differences aren’t that great and nonexistent or nearly so for the majority of the measures. 
AEP-SPP 2009 Integrated Resource Plan 

 65 

Exhibit 8-8: Typical DR/EE Measure Conservation Load Factor 

Sample DR/EE Measure Conservation Load Factors

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Demand Response

Residential Windows

(Film)

Residential A/C

Commercial Windows

(Film)

Residential Insulation

Commercial HVAC

Weatherization

Residential Heat Pump

Commercial Insulation

Pool Pump

Commercial Systems

Commercial Motors

Commercial Refrigeration

Commercial Lighting

Appliance Recycling

Residetial Water Heater

Residential CFL

Conservation Load Factor (kWh/kW)

East West

Demand Reduction Energy Conservation

Source: AEP Resource Planning 

8.5.3.1 Energy Conservation 

Often used interchangeably with efficiency, conservation results from foregoing the benefit of 

electricity either to save money or simply to reduce the impact of generating electricity. Higher rates 

for electricity typically result in lower consumption. Inclining block rates, or rates that increase with 

usage, are rates that encourage conservation. 
AEP-SPP 2009 Integrated Resource Plan 

 66 
AEP-SPP 2009 Integrated Resource Plan 

 67 

9.0 Evaluating DR/EE Impacts for the 2009 IRP 

9.1 gridSMARTSM

AEP continues to evaluate distribution technologies that operate off the gridSMARTSM

platform. These include “smart meters” that allow the consumer of electricity to receive pricing 

signals, or variable rates, encouraging the migration of consumption from times of peak demand, to 

times when power is more readily available. 

Pilot programs employing smart meters are currently underway in Texas, Ohio and Indiana. 

The results of these pilots will greatly inform the impacts assigned to larger roll-outs of these meters, 

should they ultimately be approved. 

The bulk of the impacts of DR/EE modeled in this IRP are the forecasted results of “traditional” 

residential and commercial DR/EE programs, including tariff offerings. 

9.2 Demand Response/Energy Efficiency Mandates and Goals 

In November of 2007, the Energy Independence and Security Act of 2007 (“EISA”) became 

law. The Act requires, among other things, a phase-in of lighting efficiency standards, appliance 

standards, and building codes. The increased standards will have a discernable effect on energy 

consumption as is shown in Exhibit 9-1. As Exhibit 9-1 indicates, by 2019 AEP-SPP energy 

consumption will be about 4.5 percent lower than a business-as-usual case. Additionally, mandated 

levels of demand reduction and/or energy efficiency attainment, subject to cost effectiveness criteria, 

are in place in Texas. 

Exhibit 9-1: Impact of Legislation on Energy Consumption 

Effects of Energy Efficiency

30,000

32,500

35,000

37,500

40,000

42,500

45,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

AEP-SPP Annual Energy Consumption (GWh)

Embedded EE programs

Baseline Forecast

BAU (excludes EISA 2007)

Resultant Energy Consumption

Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan 

 68 

As identified in this document, AEP has internally committed to (system-wide) peak demand 

reductions of 1,000 MW by year-end 2012 and energy reductions of 2,250 GWh for the entire AEPSystem, approximately 20-25% of which is in the AEP-SPP zone. 

The IRP does not necessarily assume that these state DR/EE targets, currently set fourth, will be 

explicitly met over the long-term, preferring a more conservative approach that certainly recognizes 

the mandates, but prepares for the possibility that costs or other factors may intercede, triggering a 

revision or, perhaps, reaffirmation of the targets. The time horizon associated with building fossil fuel 

supply options is such that there will be other opportunities to further rationalize the appropriate 

levels of peak demand reduction and energy efficiency for the zone, prior to financially committing to 

non-renewable supply options. 

9.3 Assessment of Achievable Potential 

The amount of DR/EE that are available are typically described in three buckets: technical 

potential, economic potential, and achievable potential (Exhibit 9-2). 

Exhibit 9-2: Achievable versus Technical Potential (Illustrative)

Technical Efficiency Potential

Economic Efficiency Potential

Achievable Efficiency Potential

Source: AEP Resource Planning

Briefly, the technical potential encompasses all known efficiency improvements that are 

possible, regardless of cost, and thus, cost-effectiveness. The logical subset of this pool is the 

economic potential. Most commonly, the total resource cost test is used to define economic. This 

compares the avoided cost savings achieved over the life of a measure/program with its cost to 

implement it, regardless of who paid for it. The third set of efficiency assets is that which is 

achievable. 

Of the total potential, only a fraction is achievable, and only then over time. Why all economic 

measures are not adopted by rational consumers speaks to the existence of “market barriers”. Barriers 

such as lack of access to capital and lack of information are addressed with utility-based energy 
AEP-SPP 2009 Integrated Resource Plan 

 69 

efficiency and demand response programs. How much effort and money is deployed towards 

removing or lowering the barriers is a decision made state by state. 

9.4 Determining Programs for the IRP 

Market Potential Studies (MPS) have been commissioned for 10 of AEP’s 11 jurisdictions. In 

the SPP zone, at the time the analysis for this IRP was performed, only the Oklahoma MPS study was 

complete. Additionally, one national study of energy efficiency was published by the Electric Power 

Research Institute (EPRI). These two studies formed the basis for the analysis in the IRP. 

The EPRI study, Assessment of Achievable Potential from Energy Efficiency and Demand 

Response Programs in the United States, "documents the results of an exhaustive study to assess the 

achievable potential for energy savings and peak demand reduction from energy efficiency and 

demand response programs." EPRI further defines the "achievable potential" as an estimated range of 

savings attainable through programs that encourage adoption of energy efficient technologies, taking 

into consideration technical, economic, and market conditions. The study differentiates what these 

programs can achieve prospectively from what may occur through the natural adoption of efficiency 

by consumers, either through preferences or codes and standards. The EPRI study provides a useful 

basis for assigning realistic levels of energy efficiency and demand response in lieu of jurisdictionspecific studies as well as a basis for assessing jurisdiction-specific study results which are typically 

stated as a range of possible outcomes. 

The economic potential for Energy Efficiency lies in the 10-23 percent range (relative to the 

Baseline forecast) for the 20-year period presented in each of the two studies. More importantly, 

estimates for what is achievable are a 1.8 percent reduction after five years (Oklahoma MPS – Base 

Case) and 3.3 percent after 12 years (EPRI). Both studies include periods of ramping up from a 

standing start. 

Embedded in the load forecast are the effects of DR/EE programs that are either currently in 

place or have been filed with the appropriate regulatory commission. The Oklahoma study was used 

as the basis for the construction of DR/EE “blocks” to be used in the modeling process. The blocks 

are proxies for actual programs that are likely to be implemented, incremental to the programs that 

have already been filed. The blocks have the cost, energy, and peak demand reduction characteristics 

of the programs evaluated in the Oklahoma study. 

9.4.1 Validating the DR/EE Program “Blocks” 

Because the blocks represent possible programs as recommended by the Oklahoma MPS, the 

blocks should be economically cost effective. Prior to allowing the resource modeling to optimize 

with the blocks as possible capacity and energy alternatives, their impacts were validated using 

current avoided costs. Exhibit 9-3 shows the recommended programs and their relative cost 

effectiveness. To reduce the problem set for the more holistic modeling that considered all resource 

alternatives, not all of the recommended programs were available for selection. From the exhibit, the 

green programs were not modeled. The red programs were modeled but not selected. The yellow 

programs are representative of the proxy resources. 
AEP-SPP 2009 Integrated Resource Plan 

 70 

Exhibit 9-3: AEP-SPP Zone Cost Effectiveness of Relative Programs 

$0

$50

$100

$150

$200

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Capacity Factor of EE /DR Program

Cost of Effiiciency $/MWh levelized

RC

CL

CM RTE

RES

Cost Effective 

Not Cost Effective 

Avoided Cost Curve

Key:

CC: Commercial Cooling

CL: Commercial Lighting

CM: Commercial Motors

RC: Residential Cooling

RAC: Residential A/C

RES: Residential Energy Star - All

ESWAC: Energy Star Window A/C

RTE: Residential Thermal Envelope

CIPR: C&I Peak Reduction

CC

ESWAC

CIPR

RAC

Source: AEP Resource Planning

Not shown on the chart are the Commercial & Industrial Demand Response (CIDR) resource 

which would be off the chart on the upper left side, but still cost effective, and the Residential Peak 

Reduction (RDR) which was not cost effective. Note that all of the other resources are cost effective 

with the exception of the Residential Cooling and Residential Energy StarTM (All). As modeled, these 

program blocks consist of many measures and even programs, some cost effective, others not. As the 

green blocks show, there are both Energy Star and residential cooling measures that are cost effective. 

Modeling constraints limit the ability to optimize all measures or programs, thus similar programs 

were aggregated for the purpose of quantifying typical impacts that could be expected from 

implementation of a portfolio of cost effective programs. 

The use of these proxy resources is necessary to model supply-side and demand-side resources 

within the same optimization process. In no way does this process imply that these programs, in their 

current form and composition must be done in equal measure and in all jurisdictions. All states are 

different and may have specific rules regarding the ability of C&I customers to “opt out” of utility 

programs, influencing the ultimate portfolio mix. Some states have a collaborative process that can 

greatly influence the tenor and composition of a program portfolio. That said, these blocks provide a 

reasonable proxy for demand-side resources within the context of an optimization model. 

A list of the programs and impacts used to develop the proxy resources is included in the 

Technical Addendum. 
AEP-SPP 2009 Integrated Resource Plan 

 71 

9.5 Optimizing the Incremental DR/EE Resources 

Using the red and yellow program characteristics, DR/EE “blocks” were constructed of equal 

energy impacts, corresponding demand impacts and costs. The proxy “blocks” available for 

optimization and their monthly characteristics are summarized in Exhibit 9-4. The modeling 

limitations placed on the respective DR/EE “blocks” and cost data are provided in Exhibit 9-5. 

Exhibit 9-4: AEP-SPP Zone DR/EE Proxy Blocks 

CC CL CM RC ES TE RPR CIPR

Jan 0.01 3.34 4.43 1.60 2.40 2.35 

Feb 0.52 3.08 3.92 1.60 2.37 2.39 

Mar 0.05 2.59 2.95 1.90 2.41 2.37 

Apr 3.09 3.03 3.84 3.89 2.43 2.38 

May 7.97 3.60 4.94 7.51 2.50 2.60 

Jun 17.83 4.65 6.91 10.69 2.67 2.79 8.00 8.00 

Jul 26.49 5.21 7.93 14.78 3.06 3.24 8.00 8.00 

Aug 26.84 5.33 8.15 13.05 3.11 3.29 8.00 8.00 

Sep 11.36 4.80 7.19 9.96 2.53 2.63 

Oct 6.10 3.40 4.55 2.98 2.42 2.38 

Nov 0.92 2.89 3.56 2.58 2.40 2.36 

Dec 0.01 3.02 3.81 1.60 2.33 2.33 

Peak 26.84 5.33 8.15 14.78 3.11 3.29 8.00 8.00 

CC CL CM RC ES TE RPR CIPR

Jan 0.01 1.55 1.40 1.28 1.66 1.65 - - 

Feb 0.01 1.37 1.20 1.15 1.51 1.50 - - 

Mar 0.01 1.44 1.16 1.27 1.70 1.69 - - 

Apr 0.12 1.39 1.13 1.24 1.66 1.65 - - 

May 0.73 1.58 1.46 1.39 1.70 1.69 - - 

Jun 2.68 1.84 2.04 1.84 1.63 1.64 - - 

Jul 7.93 2.33 2.97 3.40 1.76 1.80 - - 

Aug 6.34 2.23 2.77 2.95 1.74 1.77 - - 

Sep 1.96 1.83 2.03 1.69 1.64 1.64 - - 

Oct 0.18 1.54 1.37 1.29 1.71 1.70 - - 

Nov 0.02 1.39 1.11 1.23 1.64 1.63 - - 

Dec 0.01 1.52 1.35 1.28 1.65 1.65 - - 

Annual 20.00 20.00 20.00 20.00 20.00 20.00 - - 

Monthly Energy Reduction (GWh)

Monthly Peak Reduction (MW)

Source: AEP Resource Planning

Note: See Exhibit 9-3 Legend for all program acronyms 
AEP-SPP 2009 Integrated Resource Plan 

 72 

Exhibit 9-5: AEP-SPP Zone DR/EE Modeling Constraints

Strategist Model Block

Block 

Type Life

Incremental 

cost $(000)

Annual 

Cost 

($000) MW MWh

Max 

Incremental 

Blocks Per 

Year

Commercial Cooling (CC) EE 15 11,808 - 18.0 13,400 1

Commercial Lighting (CL) EE 12 3,846 - 3.6 13,400 2

Commercial Motors (CM) EE 15 4,689 - 5.5 13,400 1

Residential Cooling (RC) EE 15 14,576 - 9.9 13,400 1

Residential Energy Star (ES) EE 8 11,749 - 2.1 13,400 1

Residential Thermal Envelope (TE) EE 20 5,009 - 2.2 13,400 2

C&I Peak Reduction (CIPR) DR 20 585 287 10.1 - 2

Residential Peak Reduction (RPR) DR 20 6,021 280 10.1 - 1

Source: AEP Resource Planning

These individual program constraints, coupled with an over-arching ceiling on the annual level 

of resources allowed, keep Strategist from selecting DR/EE resources faster than is practical. The 

result of the constraints is a roll out of programs that is consistent with both the Oklahoma MPS 

recommendations and the EPRI Reasonably Achievable level of demand side resources. 

Exhibit 9-6 shows the blocks selected by the resource modeling, by year. Again, this does not 

imply that blocks that were not selected are not cost effective and should not be part of any future 

portfolios in any jurisdiction. It does show, however, that certain characteristics of programs are 

more desirable than others in the context of a dynamic, constrained optimization. As a practical 

matter, actual DR/EE programs are likely to contain elements of many of these programs but not 

match the blocks exactly. However, for the purposes of validating the cost-effectiveness of demand 

options, and quantifying the benefits relative to supply options, the proxy demand resources are 

suitable. 
AEP-SPP 2009 Integrated Resource Plan 

 73 

Exhibit 9-6: AEP-SPP Zone DR/EE Blocks Selected in Resource Modeling (AEP-SPP)

CC CL CM TE Total

Cumulative 

Total

2010 12 24 12 24 72 72

2011 12 24 12 24 72 144

2012 12 24 12 24 72 216

2013 12 24 12 24 72 288

2014 12 24 12 24 72 360

2015 12 24 12 24 72 432

2010 9 18 9 18 55 55

2011 9 18 9 18 55 110

2012 9 18 9 18 55 166

2013 9 18 9 18 55 221

2014 9 18 9 18 55 276

2015 9 18 9 18 55 331

CC CL CM TE Total

Cumulative 

Total

2010 16 6 5 4 31 31

2011 16 6 5 4 31 63

2012 16 6 5 4 31 94

2013 16 6 5 4 31 125

2014 16 6 5 4 31 157

2015 16 6 5 4 31 188

2010 12 5 4 3 24 24

2011 12 5 4 3 24 48

2012 12 5 4 3 24 72

2013 12 5 4 3 24 96

2014 12 5 4 3 24 120

2015 12 5 4 3 24 144

Strategist Optimized Demand Side Proxy Resources (GWh)

Strategist Optimized Demand Side Proxy Resources (MW)

PSO

SWEPCO

PSO

SWEPCO

Source: AEP Resource Planning

 Exhibit 9-7 shows the relative cohesiveness of the two studies, the internal AEP target 

applicable to AEP-SPP and the amount of EE in this AEP-SPP IRP cycle. 
AEP-SPP 2009 Integrated Resource Plan 

 74 

Exhibit 9-7: AEP-SPP Internal EE Target versus IRP 

30,000

35,000

40,000

45,000

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Total Retail Sales (GWh)

@meter SPP forecast (no embedded EE)

PSO MPS Mid Case

EPRI Realistically Achievable

IRP

AEP Internal Goal

PSO MPS High Case

 

Source: AEP Resource Planning 

Results: 

By 2015, peak demand at the meter is reduced by 385 MW in the AEP-SPP zone; 

consumption is reduced by 974 GWh at the generator. These reductions are consistent with 

studies performed in the AEP-SPP zone and internal goals. 

9.6 Discussion and Conclusion 

The assumption of aggressive peak demand reduction and energy efficiency achievements 

reflect AEP’s commitment to demand-side resources. 

The amount of DR/EE included in this Plan is significantly higher than past IRP plans have 

included. There are a few reasons why this is valid: 

 Mandates at the state and potentially at the federal level will encourage adoption of demand 

side resources at a pace higher than would have been reasonably forecast in the past. 

 Increased awareness and acceptance of the purported link between global warming and the 

consumption of fossil fuels will drive increased adoption of conservation measures, 

independent of economic benefit.

 Increased interest in demand response resulting from FERC initiatives. 

As the mechanism for regulatory cost recovery and the appetite for utility-sponsored DR/EE is 

formalized through the legislative and ratemaking processes in the various jurisdictions in which AEP 

operates, the amount and type of DR/EE programs will likely change. 

The following Exhibit 9-8 summarizes the AEP-SPP Zone DR/EE assumptions for the 2009 

IRP. AEP leadership has committed to initiatives that include the latest, most environmentally 

friendly technologies and protocols. Adoption of these measures is predicated on securing adequate 
AEP-SPP 2009 Integrated Resource Plan 

 75 

cost recovery. For this planning cycle, it is assumed that such recovery would be forthcoming. For 

planning purposes, the 2015 DR/EE levels are held constant for 2016 and beyond. For the 10 year 

planning horizon, this level of DR/EE still closely matches the EPRI Realistically Achievable level. 

By keeping this DR/EE level constant after 2015, future demand and energy requirements are not, 

potentially, made artificially lower. An artificially lower future demand and energy requirement could 

result in a plan that ultimately does not provide for adequate reserves. As more experience is gained 

implementing DR/EE programs, and results are observed, the level of DR/EE in future plans will be 

adjusted accordingly. 

Exhibit 9-8: AEP-SPP Zone DR/EE Assumption Summary 

Year

Forecast 

(Embedded) IRP Blocks Total

Forecast 

(Embedded) IRP Blocks Total

2009 40 40 9 9

2010 56 72 128 13 31 44

2011 70 144 214 16 63 79

2012 81 216 297 19 94 113

2013 90 288 378 21 125 146

2014 97 360 457 22 157 179

2015 102 432 534 23 188 211

Year

Forecast 

(Embedded) IRP Blocks Total

Forecast 

(Embedded) IRP Blocks Total

2009 38 38 10 10

2010 57 55 112 16 24 40

2011 73 110 184 20 48 68

2012 87 166 252 24 72 96

2013 96 221 317 26 96 122

2014 103 276 379 29 120 149

2015 109 331 440 30 144 174

PSO

SWEPCO

Energy Efficiency Impacts (GWh) Peak Demand Impacts (MW)

Energy Efficiency Impacts (GWh) Peak Demand Impacts (MW)

Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 76 
AEP-SPP 2009 Integrated Resource Plan 

 77 

10.0 Fundamental Modeling Parameters 

10.1 Modeling and Planning Process—An Overview 

A chart summarizing the IRP planning process, identifying the fundamental input requirements, 

major modeling activities, and process reviews and outputs, is presented in Exhibit 1-1. Given the 

diverse and far-reaching nature of the many elements as well as participants in this process, it is 

important to emphasize that this planning process is naturally a continuous, evolving activity. 

In general, assumptions and plans are continually reviewed and modified as new information 

becomes available. Such continuous analysis is required by multiple disciplines across AEP to ensure 

that: market structures and governances; technical parameters; regulatory constructs; capacity supply; 

energy adequacy and operational reliability; and environmental mandate requirements are constantly 

reassessed to ensure optimal capacity resource planning. 

Further impacting this process are growing numbers of federal and state initiatives that address 

many issues relating to industry restructuring, customer choice, and reliability planning. Currently, 

fulfilling a regulatory obligation to serve native load customers represents one of the cornerstones of 

this 2009 AEP-SPP IRP process. Therefore, as a result, the “objective function” of the modeling 

applications utilized in this process is the establishment of the least-cost plan, with cost being more 

accurately described as revenue requirement under a traditional ratemaking construct. 

That does not mean, however, that the best or optimal plan is the one with the absolute least cost 

over the planning horizon evaluated. As discussed in this (and previous) section, other factors–some 

more difficult to monetize than others–were considered in the determination of the AEP-SPP 

integrated resource plan to be utilized by PSO and SWEPCO. To challenge the robustness of the 

Plan, sensitivity analyses were performed to address these factors. 

10.2 Methodology 

The IRP process aimed to address the long-term “gap” between resource needs and current 

resources (Section 6). Given the various assets and resources that can satisfy this expected long-term 

gap, a tool is needed to sort through the myriad of potential combinations and return an optimum 

solution–or portfolio–subject to constraints. Strategist 3

 is the primary modeling application, used by 

AEP for identifying and ranking portfolios that address the gap between needs and current available 

resources. Given the set of proxy resources–both supply and demand side–and a scenario of 

economic conditions that include fuel prices, capacity costs, energy costs, effluent prices including 

CO2, and demand, Strategist will return all combinations of the proxy resources (portfolios) that meet 

the resource need. The portfolios are ranked on the basis of cost, or cumulative present worth (CPW), 

of the resulting stream of revenue requirements. The least cost option was considered the initial 

“optimum” portfolio for that unique input parameter scenario. 

 

3 A Ventyx Co., long-term resource optimization tool utilized extensively in the utility industry for over two 

decades. 
AEP-SPP 2009 Integrated Resource Plan 

 78 

10.3 Key Fundamental Modeling Input Parameters 

(This section includes excerpts from the “Long Term Price Forecast 2009-2030: Return to 

Fundamentals, 2H-2008” prepared by AEPSC’s Strategic & Economic Analysis (AEP-SEA) 

Organization and issued February 2009..) 

The AEP-SEA long-term power sector suite of commodity forecasts are derived from the 

Aurora model. Aurora is a fundamental production-costing tool that is driven by inputs into the 

model, not necessarily past performance. AEP-SEA models the eastern synchronous interconnect and 

ERCOT using Aurora. Fuel and emission forecasts established by AEP Fuel, Emissions and 

Logistics, are fed into Aurora. Capital costs for new-build generating assets by duty type are vetted 

through AEP Engineering Services. The CO2 forecast is based on assumptions developed by AEP 

Strategic Policy Analysis. 

Exhibit 10-1 shows the AEP-SEA process flow for solution of the long-term (power) 

commodity forecast. The input assumptions are initially used to generate the output report. The output 

is used as “feedback” to change the base input assumptions. This iterative process is repeated until the 

output is congruent with the input assumptions (e.g., level of natural gas consumption is suitable for 

the established price and all emission constraints are met). 

Exhibit 10-1: Long-term Forecast Process Flow 

Input Output

Fuel Forecast

Load Forecast

Emissions Forecast

Capital Cost Forecast

Generate Report

Emission Totals 

Fuel Burn Totals

Market Prices

Longterm Capacity 

Expansion

Annual Dispatch

Emission Retrofits

Recycle

Source: AEP-SEA 

In this report, four distinct scenarios were developed: the Reference Case, Business As Usual 

(BAU) Case, Abundance Case, and Constrained Case. Exhibit 10-2 presents the key inputs for the 

scenarios and how they have changed relative to the Reference Case. 
AEP-SPP 2009 Integrated Resource Plan 

 79 

Exhibit 10-2: Input Scenarios and Sensitivities 

Case Name Reference Constrained Abundance BAU

Demand Reference Case Same Same Higher

Natural Gas Price

Fuel Price Reference Case Higher Lower Same

Carbon Price Reference Case Higher Lower Zero

Coal Price

Fuel Price Reference Case Higher Lower Blend

Carbon Price Reference Case Higher Lower Zero

Emission Price

SO2 Reference Case Same Same Same

NOX Reference Case Same Same Same

CO2 Reference Case Higher Lower Zero

Capital Costs Reference Case Higher Lower Same

Scenarios

Source: AEP Fundamental Analysis 

The Abundance Case is a world where the economics, policies and/or the technology allow the 

overbuilding of capacity to produce commodities. In this world, the long-term price equilibrium will 

be set near the cost of production. The Constrained Case is a world where the economics, policies, 

and/or the lack of technology allow the market to be near balance. In this world, a scarcity premium 

can occur as result of supply chain disruptions via weather or political issues. The “Reference Case” 

sits inside the Abundance and Constrained Case. The “BAU” case is essentially a case where there is 

no carbon policy, and no attendant cost of CO2. 

Though the commodities are changing in each case, the key driver is the CO2 price used. The 

CO2 price in this report is elevated versus last year’s outlook. The mid-range CO2 price from our 

April 2008 forecast is now the lower forecast while the mid-range forecast and high-range forecast 

went higher. This dampens any change applied to the other key inputs. 

In the Reference Case, AEP-Hub power prices cross the SPP power prices in 2024. The 

significant rise in price and the relative change in market area prices put in doubt whether the full 

impact of this carbon outlook was completely dialed-in. Regional economical dislocations and the 

political reality constraints of carbon policy were not applied in the model. 

Overall commodities are expected to retract back to supply/demand economic principles of 

marginal production cost. In the natural gas markets, this does not mean back to the 1990’s $2-$3 

market – only because demand is much more elevated and the marginal supply source is more costly. 

However, this new marginal source, unconventional production, will likely be in play for quite 

sometime limiting any future massive runs as long as producers believe they will realize an average 

price above $5 - $6/MMBtu throughout the life of the reserves. In the long-term, natural gas prices 

will remain below the low teens ($/MMBtu). 

For coal, the 2008 price spike will likely be just a price spike. This was the perfect storm for 

coal with many issues occurring at the same time. There is ample amount of coal in the world, 

particularly when the demand is being constrained by Carbon policy. Nonetheless, as in gas the 

1990’s world of around $24-$28/ton of bituminous coal will not likely come back. Central 

Appalachian (CAPP) prices will remain high due to local supply issues. However, very similar to gas 

there is another coal supply source – Powder River Basin (PRB). Unlike unconventional gas, the 
AEP-SPP 2009 Integrated Resource Plan 

 80 

ultimate end product of this supply will take modification to be able to use it due to the much lower 

energy content. 

The metals market proved out the concern addressed in previous reports – the most cyclical 

market of all time is likely to be in a cycle near its peak. The steel markets have crashed to below 

some producers’ variable cost ($450-$850/ton). U.S. steel mill production is at a level not seen in 25 

years. The long-term outlook for steel is expected to be within this variable cost range. The 

purchases of new plants and environmental control equipment should go down. However much of 

our industrial load will likely be damaged if prices continue to stay low. 

10.3.1 CO2 Forecast 

The forecasting of future CO2 allowance prices is subject to considerable uncertainty as the 

underlying assumptions are entirely predicated upon a yet to be defined federal climate policy. AEP 

Strategic Policy Analysis organization has developed three potential CO2 price forecasts to match 

potential prospective legislated outcomes. The Abundance (“High CO2”) and Constrained (“Low 

CO2”) Cases are based on the realistic limits of U.S. climate policy given current political and 

economic realities, while the Reference Case is a weighting of such high and low forecasts and 

represents the most likely price trajectory. As the political and economic situations change, so will 

the politically acceptable pricing range and likely pricing trajectory. 

Specifically, the price forecasts were developed based on public analyses of two of the most 

prominent pieces of comprehensive U.S. climate legislation; the “Low Carbon Economy Act of 2007” 

introduced by Senators Bingaman and Specter and the “Climate Security Act of 2008” introduced by 

Senators Lieberman and Warner. The Bingaman-Specter bill was widely supported by industry for its 

moderate emission reduction timeline, while the Lieberman-Warner was praised by environmentalists 

for its more aggressive emission reduction timeline. Thus, these bills represent relative “bookends” 

for likely climate policy outcomes. 

The Abundance Case CO2 price forecast is predicated upon legislation similar to the BingamanSpecter bill passing in 2011, with the resulting policy coming into effect in 2016, given the need for a 

five year policy “lead-in” period. This forecast also assumed that the “backstop” allowance price 

specified in the bill ($12 escalated) would be reached in every effective year, thus setting the price 

forecast. The Constrained CO2 price forecast is based on an average of four modeling scenarios of 

the Lieberman-Warner bill: two conducted by EIA and two conducted by EPA. For this forecast we 

assume that climate legislation would pass in 2010 and become effective in 2015. Given concerns 

over the environmental leniency of the Bingaman-Specter bill and the potential negative economic 

ramifications of the Lieberman-Warner Bill, the Reference Forecast was developed using a 70%/30% 

relative weighting of these two bills. This forecast represents a pricing scenario which likely could 

occur under some level of political compromise within the United States government. 
AEP-SPP 2009 Integrated Resource Plan 

 81 

11.0 Resource Portfolio Modeling 

11.1 The Strategist Model—An Overview 

The Strategist optimization model served as the calculation tool from which the PSO and 

SWEPCO capacity requirements were examined and resource addition recommendations were made 

as part of the IRP process. In this process Strategist offers unique “portfolios” of capacity resource 

options for PSO and SWEPCO that can be assessed from a discrete, revenue requirement perspective. 

As its objective function, Strategist determines the lowest revenue requirement resource mix for 

the AEP-SPP generation (G) system. The solution is bounded by user-defined set of resource 

technologies, commodity pricing, and prescribed sets of constraints. 

Strategist develops a least-cost resource mix by considering a variety of expansion planning 

assumptions including: 

 Resource alternative characteristics (e.g., capital cost, construction period, project life). 

 Operating parameters (e.g., capacity ratings, heat rates, outage rates, emission effluent rates, 

must-run status, etc.) of existing and new units. 

 Unit dispositions (retirement/mothballing). 

 Delivered fuel prices. 

 Prices of external market energy as well as SO2, NOX, and CO2 emission allowances. 

 Reliability constraints (in this study, minimum reserve margin targets). 

 Transmission limitations 

 Emission limits and environmental compliance options. 

 Alternative DR/EE program costs and impacts on peak load and energy requirements. 

These and other assumptions are considered in the development of an integrated plan that best 

fits the utility system being analyzed. Strategist is a holistic model in that existing units may operate 

differently under different scenarios. The model determines and reflects such impacts on overall 

system variable operating costs. Strategist does not develop a full regulatory cost-of-service (COS) 

profile. Rather, it typically considers only those generation-COS components that change from plan 

to plan. It does not consider embedded costs associated with existing generating capacity that would 

remain constant under any scenario. Likewise, transmission costs are included only to the extent that 

they are associated with new generating capacity, or are linked to specific supply alternatives. In 

other words, generic (nondescript or non site-specific) capacity resource modeling would not 

typically incorporate significant capital for transmission interconnection. 

Specifically, Strategist includes and recognizes in its revenue requirement calculation: 

 Fixed costs of capacity additions, i.e., carrying charges on capacity and associated 

transmission (based on a PSO and SWEPCO’s weighted average cost of capital), and fixed 

O&M; 

 Fixed costs of any capacity purchases; 

 Installation and administrative costs of DR/EE alternatives. 

 Affiliate energy purchases and sales based on split-savings per West Operating Agreement. 
AEP-SPP 2009 Integrated Resource Plan 

 82 

 Variable costs associated with the entire fleet of new and existing generating units (using its 

probabilistic unit dispatch optimization engine). This includes fuel, purchased energy, 

market replacement cost of emission allowances, and variable O&M costs; 

 Market revenues from external energy transactions (i.e., off-system sales). These are netted 

against costs. 

In the PROVIEW module of Strategist, the least-cost expansion plan is empirically formulated 

from potentially tens of thousands of resource alternative combinations created by the module’s 

dynamic programming algorithm. On an annual basis, each capacity resource combination that 

satisfies various user-defined constraints (to be discussed below) is considered to be a “feasible state” 

and is saved by the program for consideration in following years. As the years progress, the previous 

years’ feasible states are used as starting points for the addition of more resources that can be used to 

meet the current year’s minimum reserve requirement. As the need for additional capacity on the 

system increases, the number of possible combinations and the number of feasible states increases 

exponentially with the number of resource alternatives being considered. 

11.1.1 Modeling Constraints and Economic Scenarios 

Given that the model’s algorithm has the potential for creating a vast number of alternative 

combinations and feasible states, it can create an extremely large computational and data storage 

problem, if not constrained in some manner. The Strategist model includes a number of input 

variables specifically designed to allow the user to limit the size of the problem. There were 

numerous other known physical and economic issues that needed to be considered during the 

modeling in order to reduce the problem size: 

 Maintain an installed minimum capacity reserve margin of 13.6% per SPP criteria. 

 Intercompany (PSO-SWEPCO) firm capacity transfer capability was limited to zero MW in 

the Strategist model. This constraint was subsequently modified in the creation of final, 

“Hybrid” plan by way of assuming such temporary “reserve sharing” between the two 

companies could approach 200 MW. 

 PSO’s and SWEPCO’s combined interface with the SPP energy market was constrained to 

300 MW for non-firm hourly energy sales; likewise it was constrained to 900 MW for nonfirm hourly energy purchases. 

 All generation installation costs represent AEP-SEA view of capacity build prices that were 

predicated upon information from AEP Generation Technology Development. 

 Blocks of DR/EE programs were limited to one or two a year per program, depending on the 

program. The blocks were equal in size from an energy reduction perspective but varied in 

their cost and their impact on peak demand. This constraint specifically addresses the 

practical limit of the ability to market and subsequently install that level of DR/EE, 

independent of cost effectiveness. 

Strategist was used to develop optimal and suboptimal plans given the fundamental power and 

CO2 pricing scenarios and sensitivity cases developed by AEP’s Fundamental Analysis group. 
AEP-SPP 2009 Integrated Resource Plan 

 83 

11.2 Strategist Optimization 

11.2.1 Purpose 

Strategist should be thought of as a tool used in the development of potentially economically 

viable resource portfolios. It does not produce “the answer;” rather, it produces or suggests many 

portfolios that have different cost profiles under different scenarios and sensitivities. Portfolios that 

fare well under all scenarios and sensitivities are considered for further evaluation. The optimum, or 

least-cost, portfolio under one scenario may not be the least-cost portfolio in other scenarios. 

Portfolio selection may reflect strategic decisions embraced by AEP leadership, including a 

commitment to DR/EE, renewable resources, and/or clean coal technology. Strategist results, both 

“optimum” and “sub-optimum” serve as a starting point for constructing a company’s final capacity 

expansion plan. 

For example, if under a given a scenario the Strategist model consistently adds peaking capacity 

in large quantities, a portfolio that substitutes a combined cycle plant for an equivalent amount of CTs 

might be constructed and tested to determine whether the revenue requirements are significantly 

different. Constraining the model to insert some additional practical constraints or conform to a 

company’s strategy often can yield a more diversified solution that is not significantly more 

expensive. The optimum or least expensive portfolio under a scenario may have practical limitations 

that Strategist does not take into full account or may result in a plan that is very expensive under a 

different scenario. 

11.2.2 Strategic Portfolios 

Management commitments as outlined in the AEP 2009 Corporate Sustainability Report that 

were considered when constructing the underlying AEP-SPP resource portfolios include: 

 Renewable Resources: 

 On a AEP system-wide basis, to achieve 7% of energy sales from renewable energy 

sources by 2013, 10% by 2020 and 15% by 2030. 

 Recognition of potential for a Federal RPS and existing or potential state RPS 

 Assumptions on “early mover” commitment to these GHG and renewable strategies

 Limit exposure to scarce resource pricing. 

 Take advantage of current tax credit for renewable generation. 

 Reduce exposure to potential GHG legislation, as initial mitigation requirements unfold. 

 Plan to be in concert with other CO2/GHG reduction options (offsets, allowances, etc.). 

 Energy efficiency: Consideration of increased levels of cost-effective DR/EE over 

previous resource planning cycles reflect stakeholder desires for such measures, as well as 

regulator willingness in the form of revenue recovery certainty. 

11.3 AEP–SPP Supply-side Resource “Type” Options/Characteristics 

There are many variants of available supply- and demand-side resources. It is a practical 

limitation that not all known resource types are made available as modeling options. A screening of 

available supply-side technologies was performed and the optimum assets then were made available 

as options in Strategist. Such screening for typical supply-side alternatives was performed for each of 
AEP-SPP 2009 Integrated Resource Plan 

 84 

the major generating duty-cycle “families” (baseload, intermediate, and peaking) as discussed in 

Section 8. 

The selected technology alternatives from this screening process do not necessarily represent 

the optimum technology choice for that duty cycle family. Rather, they reflect proxies for modeling 

purposes. 

Other factors will be considered which will determine the ultimate technology (for example, for 

“peaking” duty cycle the options include GE frame E or F machines, GE LM5100 aeroderivative 

machine, or others). 

Appendix C lists the screened supply-side technologies. In fact the results of this screening are 

very similar to those previously determined in prior AEP-SPP IRP processes. Based on the 

established comparative economic screenings, the following specific supply alternatives were 

modeled in Strategist for each duty cycle: 

 Peaking capacity was added in blocks of two, 164 MW GE-7FA Combustion Turbine units 

(summer rating of 157 MW x 2 = 314 MW), available beginning in 2013. 

 Intermediate capacity was modeled as single natural gas Combined Cycle (GE7FB 

platform) unit, rated 538 MW (505 MW summer) available beginning in 2013. 

 Baseload capacity burning PRB coals was modeled as a 618 MW Supercritical PC unit 

considering availability beginning in 2017. Due to previous agreements with various third 

parties, it was assumed that if PSO or SWEPCO added a coal unit, the company making the 

addition would receive a 450 MW share of this unit. It was also assumed that the units 

installed between 2017 and 2019 would be retrofitted with carbon capture and storage 

(CCS) technology in 2020 and units installed in 2020 and thereafter would be constructed 

with CCS technology. 

 Nuclear capacity was represented by a 1,606 MW Mitsubishi US-APWR unit. It was 

assumed that PSO or SWEPCO would be a joint owner in this unit and would receive a 417 

MW (400 MW summer) share of the unit so that this option would have capacity 

comparable to the other supply alternatives. 

It should be realized that the costs shown in Appendix C and used for screening are baseline 

costs, given the state of markets for commodities, labor, etc., at the time the estimates were made. 

The costs used in the Strategist model for various scenarios may be different, depending on the 

inflation or deflation assumed for these factors in each scenario. These inflation or deflation factors 

should have little influence on screening because within each family the costs should generally move 

up and down in concert. 

11.4 AEP-SPP DR/EE and Renewable Resource Options/Characteristics 

Exhibit 11-1 shows the DR/EE program blocks and their estimated cost, energy, and demand 

reduction parameters utilized in Strategist. Hourly demand reduction profiles were developed for 

each program for both PSO and SWEPCO. Depending on the program, blocks of one or two could be 
AEP-SPP 2009 Integrated Resource Plan 

 85 

added each year starting in 2010 through 2015. A full description of the DR/EE measures and the 

underlying evaluation/screening process are included in Section 8.5 and Section 9 of this report. 

Costs are fully installed device costs with an 8 percent addition for administrative expenses. 

Exhibit 11-1: AEP Sponsored DSM Programs 

Program Type

Life 

(Years)

Incremental 

Cost $(000)

Annual 

Cost ($000) MW MWh

Commercial Cooling EE 15 17,623 26.84 20,000 

Commercial Lighting EE 12 5,740 5.33 20,000 

Commercial Motors EE 15 6,999 8.15 20,000 

Residential Cooling EE 15 21,756 14.78 20,000 

Residential Energy Star EE 8 17,536 3.11 20,000 

Residential Thermal Envelope EE 20 7,476 3.29 20,000 

C&I Peak Reduction DR 20 873 428 15 0

Residential Peak Reduction DR 20 8,986 418 15 0

Source: AEP Resource Planning

AEP-SPP Sponsored DSM (Energy Efficiency and Demand Reduction) Programs

Capacity, energy and cost assumptions were made for a new 100 MW (nameplate) wind 

resource block in the AEP-SPP IRP analysis. The energy varies by month. Costs were assumed to 

escalate 2.25 percent each contract year beginning in 2012. Descriptions of the renewable resource 

alternatives evaluated and the evaluation process are found in Section 8.3 of this report. 

11.5 PSO Plan Development 

One of the benefits of using Strategist’s dynamic programming optimization algorithm is the 

ability to not only determine the optimal plan, but also evaluate suboptimal plans created in the same 

optimization run. The impact of adding different types of resources can be evaluated by comparing 

the economics of suboptimal plans to the optimal plan. PSO has purchased a sufficient amount of 

firm capacity from third parties to meet their reserve requirements through 2010. It was assumed that 

PSO would purchase approximately 400 MW of firm market capacity for 2011. 

In the Oklahoma Corporation Commission’s (OCC) final order in Cause number 200600030, 

the OCC found that PSO had a need for 450 MW of additional baseload generation in or around 2012. 

In response to this order, PSO re-issued a Request for Proposals (RFP) in 2008 for supply-side 

capacity and energy resources. As a result of the RFP, PSO has successfully negotiated a Power 

Purchase Agreement (PPA) with Exelon Generation Company for approximately 512 MW4

 of firm 

capacity from the Green Country unit during the period June 1, 2012 through February 28, 2022. 

Although this agreement must still be approved by the OCC, it was assumed to be “embedded” in 

this 2009 PSO IRP analysis due to having undergone its own unique merit evaluates as part of the 

formal application with the Commission to approve the transaction.

The IRP analysis assumed that no other capacity additions would be available until 2013. 

 

4

 512 MW rating is based on SPP criteria. 520 MW rating is based on contractual capacity testing 

criteria. 
AEP-SPP 2009 Integrated Resource Plan 

 86 

11.5.1 Comparison of PSO Plans for Base Power Price Scenario 

Exhibit 11-2 compares some of the suboptimal plans by screened supply technology to the 

optimal PSO plan for the Base Power price scenario. A review of this exhibit shows the diversity of 

plans created by the model, as well as the economic impact created by the addition of each supply 

alternative. For example, a comparison of the Optimal Plan to the best plan that includes a coal unit, 

shows that PSO’s costs would increase by approximately $104 million, versus the lowest-cost 

scenario reflective of only gas-fired capacity and energy. 

Exhibit 11-2: Comparison of PSO Optimal and Suboptimal Plans 

Plan Description

Cumulative Cumulative Cumulative Cumulative

Peak Peak Peak Peak

Supply-side and Reduction Supply-side and Reduction Supply-side and Reduction Supply-side and Reduction

DSM Additions (MW) DSM Additions (MW) DSM Additions (MW) DSM Additions (MW)

2010 1 - Com. Cooling 27 1 - Com. Cooling 27 1 - Com. Cooling 27 1 - Com. Cooling 27

2 - Com. Lighting 38 2 - Com. Lighting 38 2 - Com. Lighting 38 2 - Com. Lighting 38

1 - Com. Motors 46 1 - Com. Motors 46 1 - Com. Motors 46 1 - Com. Motors 46

2 - Res. Thermal Env. 52 2 - Res. Thermal Env. 52 2 - Res. Thermal Env. 52 2 - Res. Thermal Env. 52

2011 1 - Com. Cooling 79 1 - Com. Cooling 79 1 - Com. Cooling 79 1 - Com. Cooling 79

2 - Com. Lighting 90 2 - Com. Lighting 90 2 - Com. Lighting 90 2 - Com. Lighting 90

1 - Com. Motors 98 1 - Com. Motors 98 1 - Com. Motors 98 1 - Com. Motors 98

2 - Res. Thermal Env. 104 2 - Res. Thermal Env. 104 2 - Res. Thermal Env. 104 2 - Res. Thermal Env. 104

2012 1 - Com. Cooling 131 1 - Com. Cooling 131 1 - Com. Cooling 131 1 - Com. Cooling 131

2 - Com. Lighting 142 2 - Com. Lighting 142 2 - Com. Lighting 142 2 - Com. Lighting 142

1 - Com. Motors 150 1 - Com. Motors 150 1 - Com. Motors 150 1 - Com. Motors 150

2 - Res. Thermal Env. 157 2 - Res. Thermal Env. 157 2 - Res. Thermal Env. 157 2 - Res. Thermal Env. 157

2013 1 - Com. Cooling 184 1 - Com. Cooling 184 1 - Com. Cooling 184 1 - Com. Cooling 184

2 - Com. Lighting 194 2 - Com. Lighting 194 2 - Com. Lighting 194 2 - Com. Lighting 194

1 - Com. Motors 202 1 - Com. Motors 202 1 - Com. Motors 202 1 - Com. Motors 202

2 - Res. Thermal Env. 209 2 - Res. Thermal Env. 209 2 - Res. Thermal Env. 209 2 - Res. Thermal Env. 209

2014 1 - Com. Cooling 236 1 - Com. Cooling 236 1 - Com. Cooling 236 1 - Com. Cooling 236

2 - Com. Lighting 246 2 - Com. Lighting 246 2 - Com. Lighting 246 2 - Com. Lighting 246

1 - Com. Motors 255 1 - Com. Motors 255 1 - Com. Motors 255 1 - Com. Motors 255

2 - Res. Thermal Env. 261 2 - Res. Thermal Env. 261 2 - Res. Thermal Env. 261 2 - Res. Thermal Env. 261

2015 1 - Com. Cooling 288 1 - Com. Cooling 288 1 - Com. Cooling 288 1 - Com. Cooling 288

2 - Com. Lighting 299 2 - Com. Lighting 299 2 - Com. Lighting 299 2 - Com. Lighting 299

1 - Com. Motors 307 1 - Com. Motors 307 1 - Com. Motors 307 1 - Com. Motors 307

2 - Res. Thermal Env. 313 2 - Res. Thermal Env. 313 2 - Res. Thermal Env. 313 2 - Res. Thermal Env. 313

2016

2017 2 - 164 MW CTs 2 - 164 MW CTs 2 - 164 MW CTs 2 - 164 MW CTs

2018

2019

2020

2021

2022 4 - 164 MW CTs 4 - 164 MW CTs 4 - 164 MW CTs 1 - 538 MW CC

2023 

2024 2 - 164 MW CTs

2025

2026 2 - 164 MW CTs 1 - 450 MW PC w/ CCS 1 - 400 MW Nuclear 

2027

2028

2029 

2030

2009 - 2035 CPW ($000)

PSO Cost 17,107,470 17,211,227 17,576,440 17,140,635

Cost Over Optimal Plan 103,757 468,971 33,165

Source: AEP Resource Planning

Best Combined Cycle Plan 

Comparison of PSO Optimal and Suboptimal Plans

Reference Price Scenario

Optimal Plan Best Coal Plan Best Nuclear Plan

11.5.2 Optimal PSO Results by Scenario 

Strategist was used to develop the above optimal and suboptimal plans under the Reference case 

power and CO2 pricing scenario along with the constraints summarized in (Sections 2 and 10.3). 

(The scenarios above are defined in Chapter 10.) In addition, optimal plans for each of the other 

power and CO2 price scenarios were developed. A summary of these optimal plans can be found in 

Exhibit 11-3. 
AEP-SPP 2009 Integrated Resource Plan 

 87 

Exhibit 11-3: PSO Optimal Plan Comparison for Power and CO2 Price Scenarios 

PSO Optimal Plan Comparison for Power and CO2 Price Scenarios

Power or CO2 

Price Scenario BAU Abundance Case

Cumulative Cumulative Cumulative Cumulative

Peak Peak Peak Peak

Supply-side and Reduction Supply-side and Reduction Supply-side and Reduction Supply-side and Reduction

DSM Additions (MW) DSM Additions (MW) DSM Additions (MW) DSM Additions (MW)

2010 1 - Com. Cooling 27 2 - Com. Lighting 11 1 - Com. Cooling 27 1 - Com. Cooling 27

2 - Com. Lighting 38 1 - Com. Motors 19 2 - Com. Lighting 38 2 - Com. Lighting 38

1 - Com. Motors 46 2 - Res. Thermal Env. 25 1 - Com. Motors 46 1 - Com. Motors 46

2 - Res. Thermal Env. 52 2 - Res. Thermal Env. 52 2 - Res. Thermal Env. 52

2011 1 - Com. Cooling 79 2 - Com. Lighting 36 1 - Com. Cooling 79 1 - Com. Cooling 79

2 - Com. Lighting 90 1 - Com. Motors 44 2 - Com. Lighting 90 2 - Com. Lighting 90

1 - Com. Motors 98 2 - Res. Thermal Env. 51 1 - Com. Motors 98 1 - Com. Motors 98

2 - Res. Thermal Env. 104 2 - Res. Thermal Env. 104 2 - Res. Thermal Env. 104

2012 1 - Com. Cooling 131 2 - Com. Lighting 61 1 - Com. Cooling 131 1 - Com. Cooling 131

2 - Com. Lighting 142 1 - Com. Motors 70 2 - Com. Lighting 142 2 - Com. Lighting 142

1 - Com. Motors 150 2 - Res. Thermal Env. 76 1 - Com. Motors 150 1 - Com. Motors 150

2 - Res. Thermal Env. 157 2 - Res. Thermal Env. 157 2 - Res. Thermal Env. 157

2013 1 - Com. Cooling 184 2 - Com. Lighting 87 1 - Com. Cooling 184 1 - Com. Cooling 184

2 - Com. Lighting 194 1 - Com. Motors 95 2 - Com. Lighting 194 2 - Com. Lighting 194

1 - Com. Motors 202 2 - Res. Thermal Env. 102 1 - Com. Motors 202 1 - Com. Motors 202

2 - Res. Thermal Env. 209 2 - Res. Thermal Env. 209 2 - Res. Thermal Env. 209

2014 1 - Com. Cooling 236 2 - Com. Lighting 112 1 - Com. Cooling 236 1 - Com. Cooling 236

2 - Com. Lighting 246 1 - Com. Motors 120 2 - Com. Lighting 246 2 - Com. Lighting 246

1 - Com. Motors 255 2 - Res. Thermal Env. 127 1 - Com. Motors 255 1 - Com. Motors 255

2 - Res. Thermal Env. 261 2 - Res. Thermal Env. 261 2 - Res. Thermal Env. 261

2015 1 - Com. Cooling 288 2 - Com. Lighting 138 1 - Com. Cooling 288 1 - Com. Cooling 288

2 - Com. Lighting 299 1 - Com. Motors 146 2 - Com. Lighting 299 2 - Com. Lighting 299

1 - Com. Motors 307 2 - Res. Thermal Env. 152 1 - Com. Motors 307 1 - Com. Motors 307

2 - Res. Thermal Env. 313 2 - 164 MW CTs 2 - Res. Thermal Env. 313 2 - Res. Thermal Env. 313

2016

2017 2 - 164 MW CTs 2 - 164 MW CTs 2 - 164 MW CTs

2018

2019

2020

2021

2022 4 -164 MW CTs 4 -164 MW CTs 4 -164 MW CTs 1 - 450 MW PC w/ CCS

2023 1 - 450 MW PC w/ CCS

2024

2025

2026 2 - 164 MW CTs 2 - 164 MW CTs 2 - 164 MW CTs

2027

2028

2029 

2030

PSO CPW

System Cost

($millions) 14,399 13,500 17,107 22,743

Source : AEP Resource Planning

Reference Case Constrained Case

11.5.3 Observations: PSO Optimal Plan Composition 

The economically optimum plans (i.e., lowest study period CPW revenue requirement) under 

the four power and CO2 price scenarios and sensitivities produced essentially two choices. The 

optimization runs under the “Reference” and “BAU” price scenarios and sensitivities produced the 

same optimum plan adding eight 164 MW of generic gas-fired combustion turbine unit/blocks (i.e. 

“peaking” duty cycle), between 2017 and 2026, in addition to 313 MW of cumulative DSM peak 

demand reduction from four program measures. The optimum plan under the Abundance scenario is 

very similar, with the exception of one fewer DR/EE program selected resulting in only 152 MW of 

cumulative peak reduction, thus advancing the need for the first two peaking blocks to 2015. Under 

the Constrained scenario and sensitivity respectively, the optimum plan includes two combustion 

turbine units and 313 MW of DSM, as in the BAU and Reference cases, but adds a baseload block (as 

proxied by a 450 MW supercritical coal unit with CCS technology) unit/block in each of the years 

2022 and 2023 rather than additional combustion turbine units. 

The same four DR/EE programs, Commercial Cooling, Commercial Lighting, Commercial 

Motors, and Residential Thermal Envelope, were found to provide cumulative CPW savings under 
AEP-SPP 2009 Integrated Resource Plan 

 88 

three of the four price scenarios. Each optimum plan requires the addition of capacity in 2022 to 

replace the Exelon PPA which expires at that time. In addition, the optimization runs under all four 

discrete price scenarios and sensitivities selected the addition of only peaking supply-side resources 

until 2022.

11.5.4 Development of the PSO Hybrid Plan 

The Hybrid plan is developed by determining which of the various developed plans appears to 

be most “robust” (i.e., least-cost while also representing a practical solution) under the various price 

scenarios being driven by, particularly, implicit CO2 price loads. In order to make this comparison, 

the optimal plans for each price scenario are effectively “forced” into the other scenarios. Exhibit 

11-4 summarizes the CPW of each PSO plan under each scenario for the full Study Period and 

Exhibit 11-56 shows the differences. 

Exhibit 11-4: PSO Full Study Period Revenue Requirements 

PSO Full Study Period Revenue Requirement Comparison

(2009-2035 CPW $ millions)

Commodity and CO2 Price Scenario BAU Abundance Reference Constrained

No CO2 Price Optimal Plan 14,399 13,507 17,107 23,054

Low Power Price Optimal Plan 14,400 13,500 17,114 23,085

Base Power Price Optimal Plan 14,399 13,507 17,107 23,054

High Power Price Optimal Plan 15,159 14,003 17,357 22,743

Source: AEP Resource Planning

Exhibit 11-5: PSO Full Study Period Cost over Optimal Plan 

PSO Full Study Period Revenue Requirement Comparison (2009-2035 CPW)

Cost Over Optimal Plan ($ millions)

Commodity and CO2 Price Scenario BAU Abundance Reference Constrained

No CO2 Price Optimal Plan 7 0 311

Low Power Price Optimal Plan 1 7 342

Base Power Price Optimal Plan 0 7 311

High Power Price Optimal Plan 760 503 250

Source: AEP Resource Planning

In order to provide additional information for use in developing the Hybrid plan, Strategist was 

also used to identify optimal and suboptimal plans under the fundamental pricing scenarios using 

additional modeling constraints and scenarios: 

 Best Contrary Baseload Coal Plan – the best suboptimal plan identified under the Reference 

and Constrained scenario optimizations containing a baseload coal supply-side resource. 

Separate plans were identified for PSO and SWEPCO. 

 Best Contrary Baseload Nuclear Plan – Separate suboptimal plans for PSO and SWEPCO 

were also identified that included a baseload nuclear resource. 
AEP-SPP 2009 Integrated Resource Plan 

 89 

 Optimization with Carbon Capture and Storage (CCS) Requirements on New Coal – the 

optimal plan without a requirement that new baseload coal additions be either retrofitted or 

constructed with CCS technology. 

 Enhanced Renewables – the optimal plan when additional renewable resources are added to 

achieve a target of 15% of (AEP System-wide) energy sales from renewable sources by 

2020, in lieu of the previously noted going-in objective of achieving a 10% target by 2010. 

 “Green” Plan – the best suboptimal plan from the Enhanced Renewables scenario that 

contains a baseload nuclear resource. Separate plans were identified for PSO and 

SWEPCO. 

 Demand Destruction – the optimal plans under the Reference and Constrained scenarios 

when the load forecast was reduced from year 2009 to 2010 and held constant during 2010 

through 2013. After 2013, the annual load was increased at a reduced rate of 1.2%. 

 Demand Destruction and Unit Retirements – this scenario assumes both the “Demand 

Destruction” load forecast described above as well as the currently-not-contemplated 

retirement of five PSO units (549 MW) between 2018 and 2024 and nine units (668 MW) 

at SWEPCO between 2020 and 2025. 

 High Demand Reduction/Energy Efficiency (DR/EE) Bandwidth – the optimal plan under 

the Constrained scenario if the DSM blocks are increased by a relative 50%. 

 CO2 Limited – In this scenario, CO2 emission limits were assumed to be placed on the 

AEP’s East and SPP systems based on the continued prospect for comprehensive Climate 

Change/CO2 legislation that would seek to reduce such emission levels. As a proxy for 

such reductions, H.R. 2454 (the Waxman-Markey Bill) that was introduced in draft form in 

April, 2009 (as was ultimately passed by the U.S. House in June) was used. In 2020, the 

CO2 emission limit was based on a 15% reduction (W-M called for 17%) from 2005 actual 

CO2 emissions. In 2030, the CO2 emissions limit was based on a 40% reduction (W-M 

called for 42%) in 2005 CO2 emissions of 145 million (metric) tonnes, or a limit of 

approximately 82 million tonnes for the AEP System. These emission limits were also 

developed under the assumption that the AEP System would receive a maximum of 20 

million tonnes of carbon offsets. These offsets were assigned to the East and West systems 

based on their prorate share of 2005 CO2 emissions, with the East being allocated 

approximately 15.5 million tonnes and the West receiving 4.5 million tonnes. In 

recognition of a CO2 constrained environment, this scenario includes options to meet 

system CO2 emission limits in 2020 and 2030, including the “Enhanced Renewables” and 

“High DR/EE” bandwidth scenarios described above plus the retrofitting of existing coal 

units with CCS technology. 

Exhibit 11-6 provides a comparison of the optimal plans under each of the four price scenarios 

along with the results of the additional modeling constraints and scenarios listed above run under 

some or all of the price scenarios. 
AEP-SPP 2009 Integrated Resource Plan 

 90 

Exhibit 11-6: PSO Plan Comparisons 

PSO Plan Comparison

New Capacity

(Summer Rating)

Units Capacity

No CO2 Price Optimal Plan

CT 8 1,256 Total NPV-$B 14.40 13.51 17.11 23.05

CC 0 0 $/MWh 70.21 66.19 81.79 107.23

PC w/CCS 0 0 Fuel NPV-$B 12.22 10.54 13.38 17.99

Winda 5 500 $/MWh 52.29 44.95 57.23 76.94

Total 1,296

DRb 313

Low Power Price Optimal Plan

CT 8 1,256 Total NPV-$B 14.40 13.50 17.11 23.09

CC 0 0 $/MWh 70.21 66.16 81.82 107.36

PC w/CCS 0 0 Fuel NPV-$B 12.27 10.58 13.43 18.06

Winda 5 500 $/MWh 52.49 45.13 57.45 77.24

Total 1,296

DRb 152

Base Power Price Optimal Plan

CT 8 1,256 Total NPV-$B 14.40 13.51 17.11 23.05

CC 0 0 $/MWh 70.21 66.19 81.79 107.23

PC w/CCS 0 0 Fuel NPV-$B 12.22 10.54 13.38 17.99

Winda 5 500 $/MWh 52.29 44.95 57.23 76.94

Total 1,296

DRb 313

High Power Price Optimal Plan

CT 2 314 Total NPV-$B 15.16 14.00 17.36 22.74

CC 0 0 $/MWh 73.45 68.30 82.86 105.90

PC w/CCS 2 910 Fuel NPV-$B 11.12 9.36 11.73 15.55

Winda 5 500 $/MWh 47.57 39.93 50.16 66.50

Total 1,264

DRb 313

Best Contrary Coal Plan

CT 6 942 Total NPV-$B 14.68 13.70 17.21 22.96

CC 0 0 $/MWh 71.41 66.99 82.24 106.81

PC w/CCS 1 455 Fuel NPV-$B 11.82 10.12 12.78 17.10

Winda 5 500 $/MWh 50.58 43.15 54.69 73.14

Total 1,437

DRb 313

Best Contrary Nuclear Plan

CT 6 942 Total NPV-$B 15.05 14.03 17.58 23.35

CC 0 0 $/MWh 73.01 68.42 83.80 108.50

Nuclear 1 400 Fuel NPV-$B 11.79 10.11 12.76 17.08

Winda 5 500 $/MWh 50.43 43.13 54.60 73.05

Total 1,382

DRb 313

Notes: a) Wind assumed to contribute 8 MW of summer capacity for every 100 MW of nameplate capacity.

b) Demand Reduction, cumulative DSM peak reduction through 2015. 

BAU 

(No CO2)

Abundance 

(Low Power)

Reference 

(Base Power)

Constrained 

(High Power)
AEP-SPP 2009 Integrated Resource Plan 

 91 

Exhibit 11-6: PSO Plan Comparisons (Cont’d) 

PSO Plan Comparison

New Capacity

(Summer Rating) BAU Abundance Reference Constrained

Units Capacity

Optimized Without CCS Requirement

CT 8 1,256 Total NPV-$B 14.40 13.50 17.11

CC 0 0 $/MWh 70.21 66.16 81.79

PC w/CCS 0 0 Fuel NPV-$B 12.22 10.58 13.38

Winda 5 500 $/MWh 52.29 45.13 57.23

Total 1,296

DRb 313

Enhanced Renewables

CT 8 1,256 Total NPV-$B 13.63 17.14 22.69

CC 0 0 $/MWh 66.73 81.93 105.67

PC w/CCS 0 0 Fuel NPV-$B 10.73 13.44 15.69

Winda 7 700 $/MWh 45.76 57.51 67.13

Total 1,312

DRb 313

"Green" Plan

CT 6 942 Total NPV-$B 17.57 22.98

CC 0 0 $/MWh 83.75 106.91

Nuclear 1 400 Fuel NPV-$B 12.91 16.20

Winda 7 700 $/MWh 55.25 69.29

Total 1,398

DRb 313

Demand Destruction

CT 8 1,256 Total NPV-$B 15.77 21.03

CC 0 0 $/MWh 81.01 105.27

PC w/CCS 0 0 Fuel NPV-$B 12.32 15.14

Winda 5 500 $/MWh 56.13 69.16

Total 1,296

DRb 152

Demand Destruction + Unit Retirements

CT 10 1,570 Total NPV-$B 12.62 15.92

CC 0 0 $/MWh 66.65 81.66

PC w/CCS 0 0 Fuel NPV-$B 9.71 12.24

Winda 5 500 $/MWh 44.24 55.77

Total 1,610

DRb 152

High DR/EE Bandwidth

CT 2 314 Total NPV-$B 22.57

CC 0 0 $/MWh 106.17

PC w/CCS 2 910 Fuel NPV-$B 15.53

Winda 5 500 $/MWh 67.06

Total 1,264

DRb 470

CO2 Limited 

CT 8 1,256 Total NPV-$B 17.06 22.39

CC 0 0 $/MWh 82.30 105.28

PC w/CCS 0 0 Fuel NPV-$B 13.28 15.54

Winda 7 700 $/MWh 57.35 67.09

Total 1,312

DRb 470

Notes: a) Wind assumed to contribute 8 MW of summer capacity for every 100 MW of nameplate capacity.

b) Demand Reduction, cumulative DSM peak reduction through 2015. 

Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 92 

Finally, in late-April 2009, prior to the development of the Hybrid Plan, but subsequent to the 

development of the optimal plans in Strategist described above, AEP’s Economic Forecasting 

organization issued an updated load forecast to reflect the results of the recent downturn in the 

economy, as discussed in Section 5 of this report. It is important to look at this most recent change to 

the load forecast in the context of previous revisions. The following Exhibit 11-7 provides a 

summary of recent peak demand forecasts prepared by AEP. As can be seen from this exhibit, the 

forecast from one period to the next may be higher or lower, depending on changes in economics or 

customer behavior both locally (for PSO) and nationally. However, the trend is generally consistent 

with compound annual growth rates between 0.93 percent and 1.19 percent. This is compared to the 

historical, weather normalized growth rate of 1.30 percent. 

Exhibit 11-7: PSO Load Forecast Trends 

Public Service Company of Oklahoma 

Historical and Forecast Peak Demand Trending (MW)

Reflecting Recent Forecast "Vintages"

(1995 - 2019) 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

Peak Demand in MW

Actual Peak MW

Weather Normalized

February 2008 Fcst ("Spring 2008" IRP)

August 2008 Fcst

November 2008 Fcst

February 2009 Fcst

April 2009 Fcst ("2009" IRP)

Compound Annual Growth Rates

Peak Demand 

1995-2008

Actual Peak... 1.89% 

"Weather-Normalized"... 1.30%

Compound Annual Growth Rates

Prior Vintage Forecasts (Base Views)

2010-2019 (10-Yr Fcst Period)

February 2008 Fcst ("Spring '08" IRP)... 0.94%

August 2008 Fcst... 1.13%

November 2008 Fcst... 1.19%

February 2009 Fcst... 0.93%

April 2009 Fcst ("2009" IRP)... 0.93%

Source: AEP Resource Planning 

Given this variability in forecasts, and noting that the current forecast grows at a rate lower than 

what has been PSO’s historical experience, an alternate “High Demand” forecast has also been 

prepared which assumes a more vigorous economic recovery in the near term, but is based on an 

overall growth rate for the 25 year period, 1995-2020, closely equal to the historical growth rate 

experienced since 1995 to 2008. This forecast was prepared to ensure that PSO would not find itself 

in a capacity deficit position should the economy turn around quicker than expected. Exhibit 11-8

compares the current April 2009 forecast to the “High Demand” forecast. 
AEP-SPP 2009 Integrated Resource Plan 

 93 

Exhibit 11-8: PSO Load Forecast Comparison 

Public Service Company of Oklahoma 

Historical and Forecast Peak Demand Trending (MW)

(1995 - 2019) 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019

Peak Demand in MW

Actual Peak MW

Weather Normalized

April 2009 Base Forecast

April 2009 "Accelerated (High Demand)" Forecast

Compound Annual Growth Rates

Peak Demand 

1995-2008

Actual Peak... 1.89% 

"Weather-Normalized"... 1.30%

Compound Annual Growth Rates

Forecasted Peak Demand (Apr '09)

2008(A)- 2019

Base View... 0.74%

"Accelerated (High Demand)" View... 1.29%

----------------------------------------------------------

Forecasted Peak Demand (Apr '09)

2010-2019 (10-Yr Fcst Period)

Base View... 0.93%

"Accelerated (High Demand)" View... 1.47%

Source: AEP Resource Planning 

As shown earlier in this document in Section 1.2 and repeated here as Exhibit 11-9, the 

embedded Exelon contract provides adequate capacity to meet PSO’s peak demand using the April 

2009 forecast, however PSO may find itself in a capacity deficit position in 2016 if actual demand 

growth is closer to the “High Demand” view. This deficiency occurs far enough in the future for PSO 

to continue to monitor changes in load and react as needed. Note that under both the “Base Demand” 

and “High Demand” “High Demand” scenarios, if the Exelon PPA is not executed, PSO’s capacity 

position would be deficit in 2012 and beyond. An alternate Capacity, Demand, Reserve table 

incorporating this High Demand forecast is included in the Appendix. 
AEP-SPP 2009 Integrated Resource Plan 

 94 

Exhibit 11-9: PSO Reserve Margin 

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Reserve Margin

Under "Base" Demand Forecast:

Per 2009 Resource Plan 13.8% 13.2% 19.2% 19.7% 19.9% 20.3% 19.5% 19.3% 18.7% 18.1%

Exclusive of Exelon PPA (2012) 13.8% 13.2% 6.9% 7.4% 7.6% 7.9% 7.2% 7.1% 6.5% 6.1%

Under "Accelerated (High)" Demand Forecast:

Per 2009 Resource Plan 11.0% 8.2% 15.2% 14.8% 14.2% 14.2% 13.2% 12.6% 11.6% 10.9%

Exclusive of Exelon PPA (2012) 11.0% 8.2% 3.2% 3.0% 2.5% 2.5% 1.5% 1.1% 0.2% -0.5%

Reserve Margin -- MW Position

 Above / <Below> 13.6% SPP Requirement)

Under "Base" Demand Forecast:

Per 2009 Resource Plan 6 (18) 232 253 259 275 242 237 211 190

Exclusive of Exelon PPA (2012) 6 (18) (280) (259) (251) (235) (268) (271) (297) (318)

Under "Accelerated (High)" Demand Forecast:

Per 2009 Resource Plan (108) (228) 65 51 26 24 (19) (46) (92) (124)

Exclusive of Exelon PPA (2012) (108) (228) (447) (461) (484) (486) (529) (554) (600) (632)

 * Excludes short-term capacity transfers to/from affiliate Southwestern Electric Power Company

Note: Minimum Reserve Margin Requirement per SPP Criteria is 13.6%

PSO

Stand-Alone Reserve Margins*

Based on (April 2009) Demand Forecast "Banding" 

10-Year 2009 IRP Period: 2010-2019

Source: AEP Resource Planning 

After reviewing the results of the various optimal plans developed under the price scenarios and 

other modeling constraints and scenarios, and taking the new load forecast into account, the PSO 

Hybrid Plan was developed. The specific details and timing of the plan are displayed in Exhibit 11-

10.
AEP-SPP 2009 Integrated Resource Plan 

 95 

Exhibit 11-10: PSO Hybrid Plan 

MW

Unit 

Retirements/E

xpirations 

(summer-rating)

Environmental 

Retrofits(F)

Embedded 

Demand 

Reduction(B) 

(Cumul. 

Contribution)

New 

Demand 

Reduction(C) 

(Cumul. 

Contribution)

Solar 

(Nameplate)

Wind 

(Nameplate) 

2009 9 0

2010 13 31

2011 16 62 198 (E)

2012 19 94

2013 21 125

2014 22 157

2015 23 188 67

2016 NE 3&4 FGD (15) 24 188

2017 25 188 200

2018 25 188

2019 25 188

2019 Cumul. 

Contribution/N

ameplate

0 (15) 25 188 0 465

0 37

2020 25 188 200

2021 25 188

2022 PPA Expiration 

(512-MW)(D) 25 188

2023 25 188 100

2024 25 188

2025 25 188

2026 25 188 17 100

2027 25 188 17

2028 25 188 35

2029 25 188 35 100

2030 NE3 CCS (74 MW) 25 188 56

2030 Cumul. 

Contribution/Na

meplate

(512) (89) 25 188 160 965

112 77

1% 7% 6% 34%

1% 10% 6% 4%

Peaking 471 48%

'NET' CAPACITY RESOURCE ADDITIONS: Intermediate 505 52%

Intermediate Contract Expiration (512) -52%

2009-2019 747 Baseload 512 52%

2009-2030 1,288 976

 (F) CCS retrofit technology assumed to be chilled ammonia with a 15% parasitic load

 (E) Assumes Elk City and Blue Canyon V wind energy available by 2011, but firm transmission delayed until 2013 

 (A) Not shown are relatively small unit uprates and derates embedded in the current plan (e.g. FGD retrofit auxliary load losses)

 (B) "Embedded" DSM represents 'known & measurable', commission-approved program activity now projected by AEP-Economic Forecasting 

in the most recent load forecast

 (C) "New" DSM represents incremental activity projected based on estimated contribution & program cost (vs. avoided cost) parameters, from 

recent Market Potential Studies, and were generally limited to an EPRI Jan. '09 study identifying a "Realistically Achievable Potential"... Note: 

 (D) PPA term for PSO 2012 baseload capacity & energy: 9 years, 7 months (thru 2021)

Cumul. (Capacity) Contribution thru '30 79%

157-MW PKG

(SPP) Capacity Value (Wind 8%; Solar 70%(est.))

Cumul. (Nameplate) Contribution thru '30 53%

1,488

 157-MW PKG

 505-MW INT

(SPP) Capacity Value (Wind 8%; Solar 70%(est.))

157-MW PKG

512

(Grn Cntry PPA) 512-MW BL

Duty Cycle Type: 

BL=Baseload 

INT=Intermediate/Cyclic 

PKG=Peaking

Planned Resource 

Reductions (A)

Planned Resource Additions 

DSM RENEWABLE THERMAL

2009 IRP (Hybrid Plan) PSO

Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 96 

11.5.5 Observations: PSO Hybrid Plan Composition 

Several factors were considered in the development of the various elements of the PSO 2009 

Hybrid Plan: 

 Thermal Resources – It was determined from the price scenario optimal plans that the most 

cost effective planned thermal resource addition was generally peaking capacity and 

energy. It was also determined that the combustion turbine capacity should be provided in 

single unit/blocks rather than in blocks of two. Due to the reduced load forecast, the timing 

of the first new block was delayed until 2020. Recall, the Hybrid Plan also reflects the 

assumed addition of 512 MW of combined cycle capacity from the Exelon PPA starting in 

June 2012 through February 2022. As such, an intermediate resource is added to the plan 

in 2022 to replace this contract. The Strategist analysis showed that a plan with a combined 

cycle in 2022 was almost identical in cost to one showing a set of CT’s. 

 Renewable Resources – The renewable resource portfolio included both wind and solar 

resources required to achieve the renewable energy sales targets established for 2013, 2020, 

and 2030. Wind resources are being added throughout the planning period. 

 DSM – The four DR/EE programs that were found to be cost effective in the screening 

process (see Section 9) were included in the Hybrid Plan, but the cumulative demand 

reduction was reduced from 313 MW to 188 MW to reflect the “Realistically Achievable 

Potential” identified in the recent EPRI study for the same time frame. Additionally, as 

identified in Section 4, cumulative demand reduction of 25 MW of “known and 

measurable” OCC-approved program activity was reflected as part of the most recent load 

forecast. 

 CCS Retrofits – To acknowledge the potential requirement for significant CO2 emission 

reductions in the future, that may not be achievable via other means, a CCS technology 

retrofit is included in the plan at the Northeastern 3 unit in the 2030 out-year. This 

technology’s potentially significant relative CO2 reduction contribution was viewed as 

being critical to the prospect of achieving substantive CO2 reduction requirements such as 

those set forth by the Waxman-Markey Bill. 

11.5.6 Summary and Conclusions for PSO Plans 

The PSO resource expansion plan provides a robust and diverse approach to meeting PSO’s 

resource needs in both a cost effective manner and one that considers the long-term prospect of 

carbon mitigation. This study has shown that with the addition of 512 MW of capacity from the 

Exelon PPA, no additional thermal resources are required to meet additional capacity needs over the 

10 year planning horizon. The plan includes substantial clean energy renewable resources, including 

wind and, over the long term, solar, to meet aggressive renewable energy targets set by the Company. 

This study also shows that significant amounts of selected DR/EE programs are potentially cost 

effective and should be employed on PSO’s system. The long-term plan also addresses the issue of 

potential CO2 emission limits through retrofitting an existing coal unit with CCS technology. 
AEP-SPP 2009 Integrated Resource Plan 

 97 

11.6 SWEPCO Plan Development 

The SWEPCO resource expansion plan was developed in a manner similar to the PSO resource 

plan. The SWEPCO plan was created using many of the same resource addition assumptions and 

commodity price assumptions as the PSO plan. The PSO and SWEPCO plans are developed 

simultaneously with both systems adding capacity on an individual company basis to meet respective 

reserve requirements. However, the ability to transfer economy energy between the respective 

companies was considered in determining these capacity resources. 

The SWEPCO resource plans were based on the assumption that the 509 MW Stall CC would 

be in service by July, 2010. In addition, it was assumed that SWEPCO would receive its 447 MW 

share of the 600 MW Turk PC by the end of June, 2012. Both these facilities received certificates of 

need from the three states that SWEPCO 

operates within, Arkansas, Louisiana and 

Texas, and are currently under construction 

with Stall 60 percent physically complete and 

Turk 15 percent physically complete as of 

June 30, 2009. 

11.6.1 Comparison of SWEPCO Plans for Base Power Price Scenario 

Exhibit 11-11 compares some of the suboptimal plans to the optimal SWEPCO plan for the 

Reference price scenario. This exhibit shows the diversity of plans created by the model, as well as 

the economic impact created by the addition of each supply alternative. For example, a comparison 

of the Optimal Plan to the best plan that includes a coal unit, shows that SWEPCO’s costs would 

increase by approximately $212 million. 

Stall Turk

Arkansas 06-120-U 06-154-U

Louisiana U-29702/U-27866 B U-23327 B

Texas 33048 33891
AEP-SPP 2009 Integrated Resource Plan 

 98 

Exhibit 11-11: Comparison of SWEPCO Optimal and Suboptimal Plans 

Comparison of SWEPCO Optimal and Suboptimal Plans

Reference Price Scenario

Plan Description

Cumulative Cumulative Cumulative Cumulative

Peak Peak Peak Peak

Supply-side and Reduction Supply-side and Reduction Supply-side and Reduction Supply-side and Reduction

DSM Additions (MW) DSM Additions (MW) DSM Additions (MW) DSM Additions (MW)

2010 1 - Com. Cooling 27 1 - Com. Cooling 27 1 - Com. Cooling 27 1 - Com. Cooling 27

2 - Com. Lighting 38 2 - Com. Lighting 38 2 - Com. Lighting 38 2 - Com. Lighting 38

1 - Com. Motors 46 1 - Com. Motors 46 1 - Com. Motors 46 1 - Com. Motors 46

2 - Res. Thermal Env. 52 2 - Res. Thermal Env. 52 2 - Res. Thermal Env. 52 2 - Res. Thermal Env. 52

2011 1 - Com. Cooling 79 1 - Com. Cooling 79 1 - Com. Cooling 79 1 - Com. Cooling 79

2 - Com. Lighting 90 2 - Com. Lighting 90 2 - Com. Lighting 90 2 - Com. Lighting 90

1 - Com. Motors 98 1 - Com. Motors 98 1 - Com. Motors 98 1 - Com. Motors 98

2 - Res. Thermal Env. 104 2 - Res. Thermal Env. 104 2 - Res. Thermal Env. 104 2 - Res. Thermal Env. 104

2012 1 - Com. Cooling 131 1 - Com. Cooling 131 1 - Com. Cooling 131 1 - Com. Cooling 131

2 - Com. Lighting 142 2 - Com. Lighting 142 2 - Com. Lighting 142 2 - Com. Lighting 142

1 - Com. Motors 150 1 - Com. Motors 150 1 - Com. Motors 150 1 - Com. Motors 150

2 - Res. Thermal Env. 157 2 - Res. Thermal Env. 157 2 - Res. Thermal Env. 157 2 - Res. Thermal Env. 157

2013 1 - Com. Cooling 184 1 - Com. Cooling 184 1 - Com. Cooling 184 1 - Com. Cooling 184

2 - Com. Lighting 194 2 - Com. Lighting 194 2 - Com. Lighting 194 2 - Com. Lighting 194

1 - Com. Motors 202 1 - Com. Motors 202 1 - Com. Motors 202 1 - Com. Motors 202

2 - Res. Thermal Env. 209 2 - Res. Thermal Env. 209 2 - Res. Thermal Env. 209 2 - Res. Thermal Env. 209

2014 1 - Com. Cooling 236 1 - Com. Cooling 236 1 - Com. Cooling 236 1 - Com. Cooling 236

2 - Com. Lighting 246 2 - Com. Lighting 246 2 - Com. Lighting 246 2 - Com. Lighting 246

1 - Com. Motors 255 1 - Com. Motors 255 1 - Com. Motors 255 1 - Com. Motors 255

2 - Res. Thermal Env. 261 2 - Res. Thermal Env. 261 2 - Res. Thermal Env. 261 2 - Res. Thermal Env. 261

2015 1 - Com. Cooling 288 1 - Com. Cooling 288 1 - Com. Cooling 288 1 - Com. Cooling 288

2 - Com. Lighting 299 2 - Com. Lighting 299 2 - Com. Lighting 299 2 - Com. Lighting 299

1 - Com. Motors 307 1 - Com. Motors 307 1 - Com. Motors 307 1 - Com. Motors 307

2 - Res. Thermal Env. 313 2 - Res. Thermal Env. 313 2 - Res. Thermal Env. 313 2 - Res. Thermal Env. 313

2016

2017 

2018

2019

2020

2021

2022 2 - 164 MW CTs 2 - 164 MW CTs 2 - 164 MW CTs 2 - 164 MW CTs

2023 

2024

2025 2 - 164 MW CTs 2 - 164 MW CTs 1 - 400 MW Nuke 2 - 164 MW CTs

2026

2027

2028 2 - 164 MW CTs 1 - 450 MW PC w/ CCS 1 - 538 MW CC

2029 2 - 164 MW CTs

2030

2009 - 2035 CPW ($000)

SWEPCO Cost 19,082,410 19,294,788 19,634,502 19,202,563

Cost Over Optimal Plan 212,378 552,092 120,153

Source: AEP Resource Planning

Optimal Plan Best Coal Plan Best Nuclear Plan Best Combined Cycle Plan 

11.6.2 Optimal SWEPCO Results by Scenario 

Strategist was used to develop the above optimal and suboptimal plans under the Reference 

price scenario along with the constraints summarized in (Sections 2 and 10.3). In addition, optimal 

plans for each of the other power and CO2 price scenarios were developed. A summary of these 

optimal plans can be found in Exhibit 11-12. 
AEP-SPP 2009 Integrated Resource Plan 

 99 

Exhibit 11-12: SWEPCO Optimal Plan Comparison for Power and CO2 Price Scenarios 

SWEPCO Optimal Plan Comparison for Power and CO2 Price Scenarios

Scenario

Cumulative Cumulative Cumulative Cumulative

Peak Peak Peak Peak

Supply-side and Reduction Supply-side and Reduction Supply-side and Reduction Supply-side and Reduction

DSM Additions (MW) DSM Additions (MW) DSM Additions (MW) DSM Additions (MW)

2010 1 - Com. Cooling 27 2 - Com. Lighting 11 1 - Com. Cooling 27 1 - Com. Cooling 27

2 - Com. Lighting 38 1 - Com. Motors 19 2 - Com. Lighting 38 2 - Com. Lighting 38

1 - Com. Motors 46 2 - Res. Thermal Env. 25 1 - Com. Motors 46 1 - Com. Motors 46

2 - Res. Thermal Env. 52 2 - Res. Thermal Env. 52 2 - Res. Thermal Env. 52

1- Res. Cooling 67

2011 1 - Com. Cooling 79 2 - Com. Lighting 36 1 - Com. Cooling 79 1 - Com. Cooling 94

2 - Com. Lighting 90 1 - Com. Motors 44 2 - Com. Lighting 90 2 - Com. Lighting 105

1 - Com. Motors 98 2 - Res. Thermal Env. 51 1 - Com. Motors 98 1 - Com. Motors 113

2 - Res. Thermal Env. 104 2 - Res. Thermal Env. 104 2 - Res. Thermal Env. 119

1- Res. Cooling 134

2012 1 - Com. Cooling 131 2 - Com. Lighting 61 1 - Com. Cooling 131 1 - Com. Cooling 161

2 - Com. Lighting 142 1 - Com. Motors 70 2 - Com. Lighting 142 2 - Com. Lighting 172

1 - Com. Motors 150 2 - Res. Thermal Env. 76 1 - Com. Motors 150 1 - Com. Motors 180

2 - Res. Thermal Env. 157 2 - Res. Thermal Env. 157 2 - Res. Thermal Env. 186

1- Res. Cooling 201

2013 1 - Com. Cooling 184 2 - Com. Lighting 87 1 - Com. Cooling 184 1 - Com. Cooling 228

2 - Com. Lighting 194 1 - Com. Motors 95 2 - Com. Lighting 194 2 - Com. Lighting 239

1 - Com. Motors 202 2 - Res. Thermal Env. 102 1 - Com. Motors 202 1 - Com. Motors 247

2 - Res. Thermal Env. 209 2 - Res. Thermal Env. 209 2 - Res. Thermal Env. 253

1- Res. Cooling 268

2014 1 - Com. Cooling 236 2 - Com. Lighting 112 1 - Com. Cooling 236 1 - Com. Cooling 295

2 - Com. Lighting 246 1 - Com. Motors 120 2 - Com. Lighting 246 2 - Com. Lighting 306

1 - Com. Motors 255 2 - Res. Thermal Env. 127 1 - Com. Motors 255 1 - Com. Motors 314

2 - Res. Thermal Env. 261 2 - Res. Thermal Env. 261 2 - Res. Thermal Env. 320

1- Res. Cooling 335

2015 1 - Com. Cooling 288 2 - Com. Lighting 138 1 - Com. Cooling 288 1 - Com. Cooling 362

2 - Com. Lighting 299 1 - Com. Motors 146 2 - Com. Lighting 299 2 - Com. Lighting 373

1 - Com. Motors 307 2 - Res. Thermal Env. 152 1 - Com. Motors 307 1 - Com. Motors 381

2 - Res. Thermal Env. 313 2 - Res. Thermal Env. 313 2 - Res. Thermal Env. 387

1- Res. Cooling 402

2016

2017

2018

2019

2020 2 - 164 MW CTs

2021

2022 2 - 164 MW CTs 2 - 164 MW CTs

2023 2 - 164 MW CTs

2024 2 - 164 MW CTs

2025 2 - 164 MW CTs 2 - 164 MW CTs

2026 2 - 164 MW CTs

2027 2 - 164 MW CTs

2028 2 - 164 MW CTs 2 - 164 MW CTs 2 - 164 MW CTs

2029 

2030

CPW

($millions) 13,920 14,821 19,082 25,452

Source: AEP Resource Planning

BAU Abundance Reference Constrained

11.6.3 Observations: SWEPCO Optimal Plan Composition

The economically optimum plans (i.e. lowest study period CPW revenue requirement) under all 

four discrete price scenarios and sensitivities are very similar. The optimum runs under the BAU and 

Reference price scenarios and sensitivities produced the same optimum plan adding two 164 MW 

combustion turbine peaking units/blocks in each of the years 2022, 2025, and 2028. The plan also 

includes 313 MW of cumulative DSM peak reduction from four program measures. The optimum 

plan under the Abundance price scenario includes only three DR/EE programs with 152 MW of 

cumulative peak reduction and advances the blocks of two 164 MW peaking combustion turbines to 

years 2020, 2024, and 2027. Under the Constrained price scenario, the optimum plan includes five 

DSM programs with 402 MW of cumulative peak reduction. As a result, the addition of the 

combustion turbines is delayed to 2023, 2026, and 2028. 
AEP-SPP 2009 Integrated Resource Plan 

 100 

Under all four price scenarios and sensitivities, peaking duty cycle (proxied in the form of 

combustion turbine units), are the only supply-side resource selected. The only difference is the 

timing of the additions based on the number of DSM program measures added. The same four 

DR/EE programs, Commercial Cooling, Commercial Lighting, Commercial Motors, and Residential 

Thermal Envelope, were found to provide cumulative CPW savings under three of the four discrete 

price scenarios and sensitivities. This would indicate a high level of confidence in making 

peaking/combustion turbine and DR/EE additions under future scenarios. 

11.6.4 Development of the SWEPCO Hybrid Plan 

The Hybrid plan is developed by determining which optimal plan appears to be most “robust” 

(i.e., least cost) under the various price scenarios and sensitivities. As with the PSO analysis, in order 

to make this comparison, the SWEPCO optimal plans for each price scenario and sensitivities are 

forced into the other scenarios. Exhibit 11-13 summarizes the CPW of each SWEPCO plan under 

each scenario for the full Study Period and Exhibit 11-14 shows the differences. 

Exhibit 11-13: SWEPCO Full Study Period Revenue Requirements 

Commodity and CO2 Price Scenario BAU Abundance Reference Constrained

No CO2 Price Optimal Plan 13,920 14,830 19,082 25,356

Low Power Price Optimal Plan 13,924 14,821 19,087 25,387

Base Power Price Optimal Plan 13,920 14,830 19,082 25,356

High Power Price Optimal Plan 14,012 14,914 19,160 25,452

Source: AEP Resource Planning

(2009-2035 CPW $ millions)

SWEPCO Full Study Period Revenue Requirement Comparison

Exhibit 11-14: SWEPCO Full Study Period Cost over Optimal Plan 

Commodity and CO2 Price Scenario BAU Abundance Reference Constrained

No CO2 Price Optimal Plan 9 0 (96)

Low Power Price Optimal Plan 4 5 (65)

Base Power Price Optimal Plan 0 9 (96)

High Power Price Optimal Plan 92 93 78

Source: AEP Resource Planning

Cost Over Optimal Plan ($ millions)

SWEPCO Full Study Period Revenue Requirement Comparison (2009-2035 CPW)

In order to provide additional information for use in developing the Hybrid plan, Strategist was 

also used to identify optimal and suboptimal plans under the fundamental pricing scenarios using 

additional modeling constraints and scenarios. These additional constraints and scenarios were 

largely identical to those utilized in the PSO analysis that are described in detail in Section 11.5.4 of 

this report. 

Exhibit 11-15 provides a financial comparison of the optimal plans under each of the four price 

scenarios along with the results of the additional modeling constraints and scenarios run under some 

or all of the price scenarios over the 2009-2035 extended planning horizon. 
AEP-SPP 2009 Integrated Resource Plan 

 101 

Exhibit 11-15: SWEPCO Plan Comparisons 

SWEPCO Plan Comparison

New Capacity

(Summer Rating)

Units Capacity

No CO2 Price Optimal Plan

CT 6 942 Total NPV-$B 13.92 14.83 19.08 25.36

CC 0 0 $/MWh 56.23 59.19 73.82 95.42

PC w/CCS 0 0 Fuel NPV-$B 11.24 9.65 11.78 13.91

Winda 13 1,300 $/MWh 38.33 32.81 40.16 47.52

Total 1,046

DRb 313

Low Power Price Optimal Plan

CT 6 942 Total NPV-$B 13.92 14.82 19.09 25.39

CC 0 0 $/MWh 56.24 59.15 73.84 95.54

PC w/CCS 0 0 Fuel NPV-$B 11.28 9.68 11.82 13.96

Winda 13 1,300 $/MWh 38.45 32.90 40.28 47.69

Total 1,046

DRb 152

Base Power Price Optimal Plan

CT 6 942 Total NPV-$B 13.92 14.83 19.08 25.36

CC 0 0 $/MWh 56.23 59.19 73.82 95.44

PC w/CCS 0 0 Fuel NPV-$B 11.24 9.65 11.78 13.91

Winda 13 1,300 $/MWh 38.33 32.81 40.16 47.52

Total 1,046

DRb 313

High Power Price Optimal Plan

CT 6 942 Total NPV-$B 14.01 14.91 19.16 25.36

CC 0 0 $/MWh 56.54 59.47 74.09 95.42

PC w/CCS 0 0 Fuel NPV-$B 11.27 9.69 11.83 13.91

Winda 13 1,300 $/MWh 38.41 32.94 40.34 47.52

Total 1,046

DRb 402

Best Contrary Coal Plan

CT 4 628 Total NPV-$B 14.23 15.06 19.29 25.48

CC 0 0 $/MWh 57.27 59.98 74.55 95.84

PC w/CCS 1 455 Fuel NPV-$B 11.03 9.40 11.44 13.41

Winda 13 1,300 $/MWh 37.59 31.98 39.01 45.81

Total 1,187

DRb 313

Best Contrary Nuclear Plan

CT 4 628 Total NPV-$B 14.68 15.43 19.63 25.75

CC 0 0 $/MWh 58.83 61.24 75.71 96.78

PC w/CCS 0 0 Fuel NPV-$B 10.78 9.19 11.13 12.98

Nuclear 1 400 $/MWh 36.76 31.26 37.93 44.36

Winda 13 1,300

Total 1,132

DRb 313

Notes: a) Wind assumed to contribute 8 MW of summer capacity for every 100 MW of nameplate capacity.

b) Demand Reduction, cumulative DSM peak reduction through 2015. 

BAU 

(No CO2)

Abundance 

(Low Power)

Reference 

(Base Power)

Constrained 

(High Power)
AEP-SPP 2009 Integrated Resource Plan 

 102 

Exhibit 11-15: SWEPCO Plan Comparisons (cont’d): 

SWEPCO Plan Comparison

New Capacity

(Summer Rating) BAU Abundance Reference Constrained

Units Capacity

Optimized Without CCS Requirement

CT 6 942 Total NPV-$B 13.92 14.82 19.08

CC 0 0 $/MWh 56.23 59.15 73.82

PC w/CCS 0 0 Fuel NPV-$B 11.24 9.68 11.78

Winda 13 1,300 $/MWh 38.33 32.90 40.16

Total 1,046

DRb 313

Enhanced Renewables

CT 6 942 Total NPV-$B 15.16 19.18 25.28

CC 0 0 $/MWh 60.30 74.17 95.17

PC w/CCS 0 0 Fuel NPV-$B 10.07 11.96 14.01

Winda 19 1,900 $/MWh 34.25 40.76 47.88

Total 1,094

DRb 313

"Green" Plan

CT 4 628 Total NPV-$B 19.54 25.49

CC 0 0 $/MWh 75.37 95.89

Nuclear 1 400 Fuel NPV-$B 11.60 13.36

Winda 19 1,900 $/MWh 39.54 45.65

Total 1,180

DRb 313

Demand Destruction

CT 6 942 Total NPV-$B 17.61 23.44

CC 0 0 $/MWh 73.31 94.98

PC w/CCS 0 0 Fuel NPV-$B 10.53 12.22

Winda 13 1,300 $/MWh 38.25 44.62

Total 1,046

DRb 152

Demand Destruction + Unit Retirements

CT 10 1,570 Total NPV-$B 13.91 17.79

CC 0 0 $/MWh 60.02 74.15

PC w/CCS 0 0 Fuel NPV-$B 8.60 10.37

Winda 13 1,300 $/MWh 31.30 37.74

Total 1,674

DRb 313

High DR/EE Bandwidth

CT 6 942 Total NPV-$B 25.30

CC 0 0 $/MWh 96.09

PC w/CCS 0 0 Fuel NPV-$B 13.77

Winda 13 1,300 $/MWh 47.46

Total 1,046

DRb 603

CO2 Limited

CT 8 1,256 Total NPV-$B 19.32 24.56

CC 0 0 $/MWh 75.36 93.47

PC w/CCS 0 0 Fuel NPV-$B 11.86 13.81

Winda 19 1,900 $/MWh 40.88 47.60

Total 1,408

DRb 603

Notes: a) Wind assumed to contribute 8 MW of summer capacity for every 100 MW of nameplate capacity.

b) Demand Reduction, cumulative DSM peak reduction through 2015. 

Source: Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 103 

The load forecast issued by AEP’s Economic Forecast group in late-April 2009 to reflect the 

results of the downturn in the economy was taken into account in developing the SWEPCO Hybrid 

Plan along with the results of the various optimal plans developed under the price scenarios and other 

modeling constraints and scenarios. Exhibit 11-16 provides the specific details and timing of the 

plan.

Exhibit 11-16: SWEPCO Hybrid Plan 

MW

Unit 

Retirements/

Expirations 

(summer-rating)

Environmental 

Retrofits(E)

E mbedded 

Demand 

Reduction(B) 

(Cumul. 

Contribution)

New 

Demand 

Reduction(C) 

(Cumul. 

Contribution)

Solar 

(Nameplate)

Wind 

(Nameplate) 

2009 10 0

2010 16 24 79.5(D)

2011 20 48 100

2012 24 72 100

2013 26 96 150

2014 FC1 FGD (4) 29 120

2015 WSH2 FGD (8) 30 144 33

2016 31 144 100

2017 32 144

2018 32 144

2019 32 144

2019 Cumul. 

Contribution/N

ameplate

0 (12) 32 144 0 563

0 45

2020 32 144

2021 32 144 100

2022 32 144 100

2023 32 144

2024 32 144 100

2025 Turk CCS (67 

MW) 32 144 100

2026 32 144 17

2027 32 144 17 100

2028 32 144 35

2029 32 144 35 100

2030 Welsh 1&2 CCS 

(170 MW) 32 144 56 200

2030 Cumul. 

Contribution/N

ameplate

0 (249) 32 144 160 1,363

112 109

1% 4% 4% 36%

1% 6% 5% 4%

Peaking 1,099 53%

'NET' CAPACITY RESOURCE ADDITIONS: Intermediate 509 25%

2009-2020 1,322 Baseload 447 22%

2009-2030 2,203 2,055

(E) CCS retrofit technology assumed to be chilled ammonia with a 15% parasitic load

 (A) Not shown are relatively small unit uprates and derates embedded in the current plan (e.g. FGD retrofit auxliary load losses)

 (B) "Embedded" DSM represents 'known & measurable', commission-approved program activity now projected by AEP-Economic 

Forecasting in the most recent load forecast

 (C) "New" DSM represents incremental activity projected based on estimated contribution & program cost (vs. avoided cost) 

parameters, from recent Market Potential Studies, and were generally limited to an EPRI Jan. '09 study identifying a "Realistically 

Achievable Potential"... Note: Such 'New' (increm) DSM-DR activity modeled thru 2015 only

(D) Assumes Majestic wind energy available by 2010, but firm transmission delayed until 2012 

Planned Resource 

Reductions (A)

Planned Resource Additions 

DSM RENEWABLE THERMAL

2009 IRP (Hybrid Plan) SWEPCO

Duty Cycle Type: 

BL=Baseload 

INT=Intermediate/Cyclic 

PKG=Peaking

(Stall) 509-MW INT

 (Turk) 447-MW BL

1,113

(SPP) Capacity Value (Wind 8%; Solar 70%(est.))

 157-MW PKG

 314-MW PKG

 157-MW PKG

 157-MW PKG

Cumul. (Capacity) Contribution thru '30 84%

 157-MW PKG

2,055

(SPP) Capacity Value (Wind 8%; Solar 70%(est.))

Cumul. (Nameplate) Contribution thru '30 55%

 157-MW PKG

Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 104 

As discussed under the development of the PSO Hybrid Plan, a “High Demand” forecast was 

also prepared for SWEPCO to determine if the plan that was ultimately selected would be sufficient 

should the economic recovery be more robust than currently predicted. Exhibit 11-17 shows this 

“High Demand” forecast relative to historical trends and as compared to the April 2009 forecast used 

to develop the plan. 

Exhibit 11-17: SWEPCO Load Forecast Comparison 

Southwestern Electric Power Company 

Historical and Forecast Peak Demand Trending (MW)

(1995 - 2019) 

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

6500

7000

1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019

Peak Demand in MW

Actual Peak MW

Weather Normalized

April 2009 Base Forecast

April 2009 "Accelerated (High Demand)" Forecast

Compound Annual Growth Rate

Peak Demand 

1995-2008

Actual Peak... 1.79% 

"Weather-Normalized"... 1.74%

Compound Annual Growth Rate

Forecasted Peak Demand (Apr '09)

2008(A)- 2019

Base View... 1.59%

"Accelerated (High Demand)" View... 2.14%

----------------------------------------------------------

Forecasted Peak Demand (Apr '09)

2010-2019 (10-Yr Fcst Period)

Base View... 1.62%

"Accelerated (High Demand)" View... 2.02%

Note: For comparative purposes only, excludes the shift of the NTEC wholesale contract to a fixed (200 MW) basis eff: 2015 (i.e. assumes continuation 

of a 'full requirements' demand level over the comparison period)

Source: AEP Resource Planning 

As shown earlier in this document in Section 1.2 and repeated here as Exhibit 11-18, the 

embedded Turk and Stall plants provides adequate capacity to meet SWEPCO’s peak demand using 

the April 2009 forecast, however SWEPCO may find itself in a capacity deficit position in 2015 if 

actual demand growth is closer to the “High Demand” view. This deficiency occurs far enough in the 

future for SWEPCO to continue to monitor changes in load and react as needed. Note that under both 

the “Base Demand” and “High Demand” scenarios, if the either Turk and Stall plants are not 

completed, SWEPCO’s capacity position will be deficit (below the 13.6% SPP reserve margin 

requirement) in 2012 and beyond. An alternate Capacity, Demand, Reserve table incorporating this 

High Demand forecast is included in the Appendix. 
AEP-SPP 2009 Integrated Resource Plan 

 105 

Exhibit 11-18: SWEPCO Reserve Margin With and Without Turk and Stall Plants

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Reserve Margin

Under "Base" Demand Forecast:

Per 2009 Resource Plan 13.8% 14.0% 13.3% 22.0% 20.6% 22.3% 20.9% 19.4% 17.6% 19.2%

Exclusive of Turk (2013) 13.8% 14.0% 13.3% 13.1% 11.9% 12.8% 11.6% 10.1% 8.5% 7.1%

Exclusive of Stall (2011) & Turk (2013) 13.8% 3.7% 3.1% 3.1% 1.9% 2.0% 0.9% -0.4% -1.8% -3.1%

Under "Accelerated (High)" Demand Forecast:

Per 2009 Resource Plan 11.0% 10.6% 9.4% 16.9% 14.9% 15.6% 14.0% 12.0% 10.0% 11.2%

Exclusive of Turk (2013) 11.0% 10.6% 9.4% 8.5% 6.6% 6.6% 5.2% 3.4% 1.5% -0.1%

Exclusive of Stall (2011) & Turk (2013) 11.0% 0.6% -0.4% -1.2% -2.9% -3.6% -4.9% -6.5% -8.2% -9.6%

 * Excludes short-term capacity transfers to/from affiliate Public Service Company of Oklahoma

Note: Minimum Reserve Margin Requirement per SPP Criteria is 13.6%

SWEPCO

Stand-Alone Reserve Margins*

Based on (April 2009) Demand Forecast "Banding" 

10-Year 2009 IRP Period: 2010-2019

Source: AEP Resource Planning 

11.6.5 Observations: SWEPCO Hybrid Plan Composition 

Various factors were considered in the development of the different elements of the SWEPCO 

Hybrid Plan: 

 Thermal Resources – With the addition of the Stall CC and Turk PC units within the next 

five years, the most cost effective thermal resource additions in the long-term was 

determined to be peaking capacity and energy. It was determined that the proxied 

combustion turbine capacity, should be added as a single unit/block rather than in blocks 

of two. The first unit was added in 2019 to provide adequate reserve margin. Subsequent 

peaking capacity blocks were assumed over the balance of the longer-term planning 

horizon. 

 Renewable Resources – The renewable resource portfolio included both wind and solar 

resources required to achieve the renewable energy sales targets established for 2013, 

2020, and 2030. Wind resources of 1,363 MW of nameplate capacity are being added 

throughout the SWEPCO longer-term planning period, while solar resource additions are 

made during the last five years of the period. The portfolio also includes a biomass fuel 

Co-Firing option at the Welsh 1 unit beginning in 2017. Under this option, the unit 

would be assumed to burn approximately 3.0% by weight, of an appropriate biomass 

resource. 

 DSM – The four DR/EE programs found to be cost effective in the screening process 

were included in the Hybrid Plan, but the cumulative demand reduction was reduced 

from 313 MW to 144 MW to reflect the “Realistically Achievable Potential” identified in 

a recent EPRI study. In addition, cumulative demand reduction of 32 MW of “known 

and measurable” commission approved program activity was embedded in the most 

recent load forecast. 

 CCS Retrofits – To acknowledge the potential for significant CO2 emission limits in the 

future, CCS technology retrofits are included in the plan at the Turk plant in 2025 and at 
AEP-SPP 2009 Integrated Resource Plan 

 106 

the Welsh 1 and 2 units in 2030. As with the potential for the retrofitting of the PSO 

Northeastern 3 unit, this technology was viewed as a critical longer-term planning 

objective to achieve potentially significant federal CO2 reduction mandates. 

11.6.6 Summary and Conclusions for SWEPCO Plans 

The SWEPCO resource expansion plan provides a robust and diverse approach to meeting 

SWEPCO’s resource needs in a cost effective manner. This study has shown that peaking capacity 

and energy is the most cost effective thermal resource to meet future capacity needs. The plan 

includes substantial clean energy renewable resources, including wind, solar, and biomass to meet 

aggressive renewable energy targets set by the Company. This study also shows that significant 

amounts of selected DR/EE programs are potentially cost effective and should be employed on 

SWEPCO’s system. The longer-term plan also addresses the issue of potential CO2 emission limits 

through retrofitting a limited number of existing coal units with CCS technology. 
AEP-SPP 2009 Integrated Resource Plan 

 107 

12.0 Risk Analysis 

Seven portfolios for both PSO and SWEPCO were selected using Strategist that were then 

subjected to rigorous “stress testing” to ensure that none would have outcomes that would be 

deleterious under a probabilistic array of input variables. 

12.1 The URSA Model 

Developed internally by AEP Market Risk Oversight, the Utility Risk Simulation Analysis 

(URSA) model uses Monte Carlo simulation of the AEP–SPP Zone with 1,399 possible futures for 

certain input variables. The results take the form of a distribution of possible revenue requirement 

outcomes for each plan. The input variables or risk factors considered by URSA within this IRP 

analysis were: 

 Eastern and Western coal prices, 

 natural gas prices, 

 power prices, 

 SO2, CO2, and NOX emissions allowance prices, 

 full requirements loads.

These variables were correlated based on historical data. 

For each plan, the difference between its mean and its 95th percentile was identified as Revenue 

Requirement at Risk (RRaR). This represents a level of required revenue sufficiently high that it will 

be exceeded, assuming that the given plan were adopted, with an estimated probability of 5.0 percent. 

Exhibits 12-1A and 12-1B illustrates for one plan, the “Hybrid Plan,” the average levels of 

some key risk factors, both overall and in the simulated outcomes whose Cumulative Present Value 

(CPV) revenue requirement equals or exceeds the upper bound of Revenue Requirement at Risk. Note 

that these CPV’s are consistent with the CPW values calculated using the Strategist tool. The table is 

specific to the Hybrid Plan, but the numbers would be very similar under the other plans. (The 

particular alternative futures producing the highest levels are not the necessarily the same between 

different plans.) 

Variable Mean Mean Difference % Diff

PSO Internal Onpeak Load 2,625 2,626 1.81 0.07%

SPP Onpeak Power Spot 77.67 83.82 6.15 7.92%

PRB Coal Spot 16.61 17.98 1.37 8.25%

Henry Hub Gas Spot 8.37 9.30 0.93 11.11%

CO2 Allowance Spot 24.69 43.03 18.34 74.28%

NOx Allowance Spot 600 603 3.10 0.52%

SO2 Allowance Spot 1,591 2,235 644.22 40.49%

Simulated Outcomes – Hybrid Plan

All Outcomes RRaR-Exceeding Outcomes

Exhibit 12-1A: Key Risk Factors–Weighted Means for 2009-2035 (PSO)

Source: AEP Market Risk Oversight 
AEP-SPP 2009 Integrated Resource Plan 

 108 

Variable Mean Mean Difference % Diff

SWEPCo Internal Onpeak 

d

3,564 3,572 7.97 0.22%

SPP Onpeak Power Spot 77.67 83.40 5.73 7.38%

PRB Coal Spot 16.61 17.86 1.25 7.53%

Henry Hub Gas Spot 8.37 9.14 0.77 9.20%

CO2 Allowance Spot 24.69 44.29 19.60 79.38%

NOx Allowance Spot 600 605 4.66 0.78%

SO2 Allowance Spot 1,591 2,279 687.50 43.21%

Exhibit 12-1B: Key Risk Factors–Weighted Means for 2009-2035 (SWEPCO)

Simulated Outcomes – Hybrid Plan

All Outcomes RRaR-Exceeding Outcomes

Source: AEP Market Risk Oversight 

The price of CO2 and SO2 allowances is greater among the RRaR-exceeding outcomes, 

suggesting that they are critical sources of risk to revenue requirements. The relative difference 

between that “tail” and mean outcomes are 70%+ and 40%+, which is significantly greater than the 

relative difference of other risk factors. On the other extreme, the possible futures associated with the 

RRaR-exceeding outcomes are characterized by only slightly higher levels for load and NOX

allowance prices. 

It might be assumed that the very worst possible futures would be characterized by high fuel and 

allowance prices and low power prices. But according to the analysis of the historical values of risk 

factors that underlies this study, such futures have essentially no chance of occurring. Any possible 

future with high fuel prices would essentially always have high power prices. Likewise the risk factor 

analysis implies an inverse correlation between NOX allowance prices and some of the other risk 

factors that determine the tail cases, so that in these tail cases, the average NOX allowance price is 

actually less than the average across all possible futures. 

The Technical Addendum shows the percentiles of annual average values of key risk factors, 

estimated for distribution across the 1,399 simulated futures. 

12.2 URSA Modeling Results 

Exhibits 12-2A, 12-2B, 12-3A, and 12-3B illustrate the distribution of outcomes for the Hybrid 

Plan on both a cumulative distribution “S-curve” and probability distribution (“bell-curve”) basis, 

respectively. The graphs for the other six plans examined would be quite similar. The costs included 

in this analysis are the same as were included in the Strategist analysis, as described in section 11.1, 

namely fixed costs of capacity additions; fixed costs of any capacity purchases; installation and 

administrative costs of DR/EE alternatives; variable costs for the entire fleet; and market revenues 

netted against costs. 
AEP-SPP 2009 Integrated Resource Plan 

 109 

Exhibit 12-2A: Cumulative Probability Distribution of AEP-SPP Revenue Requirement (PSO) 

Source: AEP Market Risk Oversight 

Exhibit 12-2B: Cumulative Probability Distribution of AEP-SPP Revenue Requirement (SWEPCO)

Source: AEP Market Risk Oversight 
AEP-SPP 2009 Integrated Resource Plan 

 110 

Exhibit 12-3A: Probability Distribution of Revenue Requirement (PSO) 

Source: AEP Market Risk Oversight 

Exhibit 12-3B: Probability Distribution of Revenue Requirement (SWEPCO) 

Source: AEP Market Risk Oversight 
AEP-SPP 2009 Integrated Resource Plan 

 111 

12.3 Capital Cost Risk Assessment 

In order to further scrutinize the seven plans under the 1399 possible futures, the impacts of 

Capital Cost Risk on the URSA results were examined. A six-point capital cost distribution for each 

of the seven plans was created. (See Exhibit 12-4 for its basis.) In creating the distribution for each 

plan, the capital costs of all types of capacity were assumed to be perfectly correlated with each other. 

The fixed representation of capital costs in URSA was removed from each URSA output distribution 

and the resulting distributions were convolved with the capital cost distributions. 

Exhibit 12-4: Basis of Capital Cost Distributions 

5% 19% 33% 23.67% 14.33% 5%

-15% -7% Base +10% +20% +30%

-10% -5% Base +6.67% +13.33% +20%

-15% -7% Base +10% +20% +30%

Probability of occurrence, Percent 

Capital Cost Variance:

Solid-fuel Units

Gas-fuel Units

Nuclear Units

Source: AEP Resource Planning 

12.4 Results Including Capital Cost Risk 

Exhibits 12-5A and 12-5B summarizes the Capital Cost Risk-adjusted results for all seven 

AEP-SPP plans. 

Exhibit 12-5A: Capital Cost Risk-Adjusted CPW 2009-2035 Revenue Requirement ($ Millions) (PSO) 

PLAN 50th

Percentile

95th

Percentile

Revenue

Requirement

at Risk

BASE 15,968 18,928 2,960

CONTRARY NUKE 16,304 19,048 2,744

CONTRARY COAL 15,960 18,728 2,768

ENHANCED RENEWABLES 15,992 18,904 2,912

GREEN 16,352 19,088 2,736

CO2 LIMITED 15,771 18,116 2,345

HYBRID 15,699 18,347 2,648

Source: AEP Market Risk Oversight 

Exhibit 12-5B: Capital Cost Risk-Adjusted CPW 2009-2035 Revenue Requirement ($ Millions) (SWEPCO) 

PLAN 50th

Percentile

95th

Percentile

Revenue

Requirement

at Risk

BASE 14,586 19,437 4,851

CONTRARY NUKE 14,938 19,613 4,675

CONTRARY COAL 14,608 19,349 4,741

ENHANCED RENEWABLES 14,608 19,437 4,829

GREEN 14,938 19,635 4,697

CO2 LIMITED 14,643 18,432 3,789

HYBRID 14,670 18,760 4,090

Source: AEP Market Risk Oversight 

Exhibits 12-5A and 12-5B show reasonably consistent results across all plans modeled. These 

comparative results also suggest that, given the fuel/generation diversity of the capacity resource 
AEP-SPP 2009 Integrated Resource Plan 

 112 

options introduced into the analysis, the relative economic exposure would appear to be small 

irrespective of the plan selected. 

The three lowest-cost plans at the 50th percentile are the CO2 Limited, Hybrid, and Contrary 

Coal for PSO and the Base, Contrary Coal, and Enhanced Renewables for SWEPCO. However, the 

lowest plan at Revenue Requirement at Risk and at the 95th percentile is the CO2 limited plan, 

followed by the Hybrid plan. 

RRaR measures the risk relative to the 50th percentile, or expected, result of a plan. The plan 

with the least RRaR is not necessarily preferred for risk avoidance. Instead, low values of required 

revenue at extreme percentiles, such as the 95th, are preferred. 

The estimated distributions of revenue required under the seven plans are rather similar. 

Exhibits 12-6A, 12-6B, 12-7A, and 12-7B show the superimposed graphs of all seven distribution 

functions. 

Exhibit 12-6A: Distribution Function for All Portfolios (PSO) 

Cumulative Distribution Curves

0.0000

0.1000

0.2000

0.3000

0.4000

0.5000

0.6000

0.7000

0.8000

0.9000

1.0000

$9 $10 $11 $12 $13 $14 $15 $16 $17 $18 $19 $20 $21 $22 $23 $24 $25

Cost ($Billions)

Cumulative Probability

BASE CONTRARY NUKE CONTRARY COAL ENHANCED RENEWABLES GREEN CO2 LIMITED HYBRID

Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 113 

Exhibit 12-6B: Distribution Function for All Portfolios (SWEPCO) 

Cumulative Distribution Curves

0.0000

0.1000

0.2000

0.3000

0.4000

0.5000

0.6000

0.7000

0.8000

0.9000

1.0000

$9 $10 $11 $12 $13 $14 $15 $16 $17 $18 $19 $20 $21 $22 $23 $24 $25

Cost ($Billions)

Cumulative Probability

BASE CONTRARY NUKE CONTRARY COAL ENHANCED RENEWABLES GREEN CO2 LIMITED HYBRID

Source: AEP Resource Planning 

Exhibit 12-7A: Distribution Function for All Portfolios at > 95% Probability (PSO) 

Cumulative Distribution Curves

0.9500

0.9600

0.9700

0.9800

0.9900

1.0000

$18 $19 $20 $21 $22 $23 $24 $25

Cost ($Billions)

Cumulative Probability

BASE CONTRARY NUKE CONTRARY COAL ENHANCED RENEWABLES GREEN CO2 LIMITED HYBRID

Source: AEP Resource Planning 
AEP-SPP 2009 Integrated Resource Plan 

 114 

Exhibit 12-7B: Distribution Function for All Portfolios at > 95% Probability (SWEPCO) 

Cumulative Distribution Curves

0.9500

0.9600

0.9700

0.9800

0.9900

1.0000

$18 $19 $20 $21 $22 $23 $24 $25

Cost ($Billions)

Cumulative Probability

BASE CONTRARY NUKE CONTRARY COAL ENHANCED RENEWABLES GREEN CO2 LIMITED HYBRID

Source: AEP Resource Planning 

12.5 Conclusion From Risk Modeling 

For both SWEPCO and PSO the Hybrid Plan and the CO2 Limited Plan had the lowest cost at 

the 95% probability level. Their RRaR was also among the lowest of all plans. As the CO2 Limited 

Plan includes assumptions regarding potential legislation that has not yet been approved by the Senate 

or signed into law, the Hybrid Plan appears to be the best option. In the near term, these plans are 

similar and selecting one over the other will have no significant impact prior to any potential 

legislation passing into law. The Hybrid Plan is a reasonable, lower cost plan across a wide range of 

potential outcomes. 
AEP-SPP 2009 Integrated Resource Plan 

 115 

13.0 Conclusions and Recommendations 

The selection of the Hybrid Plans for both PSO and SWEPCO, which embed the respective 

Arkansas, Louisiana, and Texas commission-approved Turk baseload facility and Stall combined 

cycle facility, and the Exelon PPA reflects management’s commitment to clean coal technology, 

renewable energy alternatives, energy efficiency, and the economic vitality of the territories served by 

AEP. These resource portfolios fare well when compared to the other portfolios when subjected to 

robust scenario and attendant risk modeling/ analysis. Other benefits include: 

 Pre-positioning for the prospects of federal carbon legislation. 

 Likewise, with the prospects for a Federal Renewable Portfolio Standard, becoming an 

early-mover to secure wind power ensures that AEP will be well positioned to ultimately 

achieve those standards as they become effective. 

 Increased DR/EE, assuming customer acceptance and full and contemporaneous rate 

recovery, could offer an effective means to reduce demand, energy usage and, with that, our 

attendant carbon footprint. 

 Keeping coal as a viable fuel in a carbon-constrained world requires that commercial USCPC technology be championed and built. AEP’s steeped history and core competency 

surrounding coal-based generation would also naturally support such a commitment. This 

coal-based technology advancement would also be continued by way of positioning both 

PSO and SWEPCO for the potential need for introducing CCS retrofits as part of its longerterm planning. 

13.1 Capacity and Energy Plan 

The charts found on Exhibits 13-1 through 13-3 offer a summary of the resulting AEP-SPP 

generating fleet. From a capacity mix standpoint, the most significant take-away would be that the 

profile represents a diverse technology and fuel mix. From an environmental stewardship 

perspective, note that from Exhibit 13-1 that the AEP-SPP fleet continues to migrate to a lower 

carbon emitting portfolio. 
AEP-SPP 2009 Integrated Resource Plan 

 116 

Exhibit 13-1: AEP-SPP Generation Capacity 

Source: AEP Resource Planning

AEP-SPP Generation Capacity

0

8,0006,0004,0002,000

14,00012,00010,000

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

MW of Summer Capability

New CT

Turk PC (Limited) ICAP 

Purchases

Existing CC

Existing CT

Stall CC

Existing Coal w/Environmental Retrofits 

(includes FGD and ACIESP)

Gas-Steam

Existing Coal, no Retrofits

Existing Wind

New Wind

Long-term PPA

 DSM
AEP-SPP 2009 Integrated Resource Plan 

 117 

Exhibit 13-2: AEP-SPP Current Capacity Mix 

Current AEP-SPP Generation Fleet 

Capacity

Coal W/O CCS

36.70%

Solar

0.000%

Interruptible Demand

0.267%

DSM

0.535%

Bio Mass

0.000%

Wind

0.168%

Gas (CC & CT & Diesel)

54.16%

Coal W/ CCS

0.00%

Purchases

8.17%

Coal W/O CCS Coal W/ CCS Purchases

Gas (CC & CT & Diesel) Bio Mass DSM

Solar Interruptible Demand Wind

Source: AEP Resource Planning 

Exhibit 13-3: AEP-SPP 2019 Capacity Mix 

2019 AEP-SPP Generation Fleet

Capacity

Coal W/O CCS

36.45%

Interruptible Demand

0.308%

Wind

0.978%

Solar

0.000%

DSM

3.728%

Bio Mass

0.079%

Gas (CC & CT & Diesel)

53.98%

Coal W/ CCS

0.00%

Purchases

4.48%

Coal W/O CCS Coal W/ CCS Purchases

Gas (CC & CT & Diesel) Bio Mass DSM

Solar Interruptible Demand Wind

Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan 

 118 

Exhibit 13-4: AEP-SPP 2030 Capacity Mix 

2030 AEP-SPP Generation Fleet 

Capacity 

Wind

1.285%

Bio Mass

0.061%

DSM

2.847%

Solar

0.538%

Coal W/O CCS

14.83%

Coal W/ CCS

26.07%

Purchases

0.00%

Gas (CC & CT & Diesel)

54.14%

Interruptible Demand

0.236%

Coal W/O CCS Coal W/ CCS Purchases

Gas (CC & CT & Diesel) Bio Mass DSM

Solar Interruptible Demand Wind

Source: AEP Resource Planning 

Exhibit 13-5 incorporates the recommended capacity additions and their attendant energy 

profiles. Note that the 2019 and 2030 plan relies more heavily on renewable resources and nuclear 

and less on baseload coal to meet its needs. 
AEP-SPP 2009 Integrated Resource Plan 

 119 

Exhibit 13-5: Change in Energy Mix With Hybrid Plan - Current vs. 2019 and 2030 

Current AEP-SPP Generation Fleet 

Energy

Bio Mass

0.000%

DSM

0.172%

Solar

0.000%

Wind

3.826%

Gas (CC & CT & Diesel)

18.28%

Purchases 

(Including SPOT)

23.16%

Coal W/ CCS

0.00%

Coal W/O CCS

54.56%

Coal W/O CCS Coal W/ CCS Purchases (Including SPOT)

Gas (CC & CT & Diesel) Bio Mass DSM

Solar Wind

2019 AEP-SPP Generation Fleet 

Energy

Coal W/ CCS

0.00%

Purchases 

(Including SPOT)

14.81%

Gas (CC & CT & Diesel)

23.91% Bio Mass

0.018%

DSM

2.013%

Solar

0.000%

Wind

8.377%

Coal W/O CCS

50.87%

Coal W/O CCS Coal W/ CCS Purchases (Including SPOT)

Gas (CC & CT & Diesel) Bio Mass DSM

Solar Wind
AEP-SPP 2009 Integrated Resource Plan 

 120 

2030-SPP AEP Generation Fleet 

Energy

Wind

14.916%

Coal W/O CCS

22.60%

Solar

0.412%

DSM

1.789%

Bio Mass

0.02%

Coal W/ CCS

20.57%

Purchases 

(Including SPOT)

10.56%

Gas (CC & CT & Diesel)

29.13%

Coal W/O CCS Coal W/ CCS Purchases (Including SPOT)

Gas (CC & CT & Diesel) Bio Mass DSM

Solar Wind

Source: AEP Resource Planning 

Exhibit 13-6 incorporates the recommended capacity additions and their attendant energy profiles. 

Note that the 2009 plan relies more heavily on DR/EE and renewables and less on baseload (coal) to meet 

its needs. 
AEP-SPP 2009 Integrated Resource Plan 

 121 

Exhibit 13-6: 2009 AEP-SPP IRP 

RENEWABLE RENEWABLE

Environmental 

Retrofits(G)

E mbedded 

Demand 

Reduction(B) 

(Cumul. 

Contribution)

New 

Demand 

Reduction(C) 

(Cumul. 

Contribution)

Wind (Nameplate) Environmental 

Retrofits(G)

E mbedded 

Demand 

Reduction(B) 

(Cumul. Contribution)

New 

Demand 

Reduction(C) 

(Cumul. 

Contribution)

Wind (Nameplate) 

2009 9 0 10 0

2010 13 31 16 24 79.5(F)

2011 16 62 198 (E) 20 48 100

2012 19 94 24 72 100

2013 21 125 26 96 150

2014 22 157 FC1 (4) 29 120

2015 23 188 67 WSH2 (8) 30 144 33

2016 NE3&4 (15) 24 188 31 144 100

2017 25 188 200 32 144

2018 25 188 32 144

2019 25 188 32 144

Nameplate 

Capacity (15) 25 188 465 (12) 32 144 563

(SPP) Capacity 

Value (Wind 8%; )

37 45

Cumul. 

(Nameplate) 2% 16% 39% 2% 8% 30%

Cumul. 

(Capacity) 

Contribution 3% 25% 5% 2% 11% 42%

(G) Derate associated with the addition of an FGD system

 (A) Not shown are relatively small unit uprates and derates embedded in the current plan (e.g. FGD retrofit auxliary load losses)

512

67% 83%

 (Grn Cntry PPA) 

512-MW BL

Duty Cycle Type: 

BL=Baseload 

INT=Intermediate 

PKG=Peaking

(F) Assumes Majestic wind energy available by 2010, but firm transmission delayed until 2012 

(E) Assumes Elk City and Blue Canyon V wind energy available by 2011, but firm transmission delayed until 2013 

(C) "New" DSM represents incremental activity projected based on estimated contribution & program cost (vs. avoided cost) parameters, from recent Market Potential 

Studies, and were generally limited to an EPRI Jan. '09 study identifying a "Realistically Achievable Potential". This 'New' (increm) DSM-DR activity modeled thru 

2015 only

(D) PPA term for PSO 2012 baseload capacity & energy: 9 years, 7 months (thru 2021)

43% 60%

Planned Resource Additions (MW) Planned Resource Additions (MW)

DSM

 (Turk) 447-MW BL

DSM

 (B) "Embedded" DSM represents 'known & measurable', commission-approved program activity now projected by AEP-Economic Forecasting in the most recent 

load forecast

 157-MW PKG

1,113

THERMAL

Duty Cycle Type: 

BL=Baseload 

INT=Intermediate 

PKG=Peaking

(Stall) 509-MW INT

2009 AEP-SPP Integrated Resource Plan (Hybrid Plan) 

THERMAL

Planned 

Resource 

Reductions

Planned 

Resource 

Reductions

PSO SWEPCO

Source: AEP Resource Planning 

13.2 Comparison to 2008 IRP 

In comparison to the 2008 IRP for AEP-SPP, the 2009 IRP, represented in Exhibit 13-6, reflects 

additional DR (an additional 140 MW by 2015) and renewable resources (an additional 463 MW of wind 

capacity), the replacement of a (generic) PSO 492 MW CC with the Green Country PPA in 2012, and the 

elimination of two PSO peaking/combustion turbine blocks in 2016 and 2017. For SWEPCO, a peaking 

block is now shown in 2019 (the 2008 plan only showed additions through 2017). 

13.3 Plan Impact on Carbon Mitigation (“Prism” Analysis) 

Global Climate Change and the prospect for comprehensive CO2 legislation has had a direct bearing 

on the outcome of the 2009 AEP-SPP Plan. To gauge the respective CO2 mitigation impacts incorporated 

into this resource planning, an assessment was performed that emulates an approach undertaken by the 

Electric Power Research Institute (EPRI). This profiling seeks to measure the contributions of various 

“portfolio” components that could, when taken together, effectively achieve such carbon mitigation: 

 Energy Efficiency 

 Renewable Generation 

 Fossil Plant Efficiency, including coal-unit retirements 

 Nuclear Generation
AEP-SPP 2009 Integrated Resource Plan 

 122 

 Technology Solutions, including Carbon Capture and Sequestration

The following Exhibit 13-7 reflects those comparable components within this 2009 IRP–set forth as 

uniquely-colored “prisms”—that are anticipated to contribute to the overall AEP System’s (combined 

East and West regions) initiatives to reduce its carbon footprint: 

Exhibit 13-7: CO2 Emission Profile 

AEP-SYSTEM (East & West) 

CO2 Emission Profile

Hybrid Plan (2009 IRP) 

Including: 20 MW CCS by 20 1 0... 235 MW by 2013... 1,300 MW by 2020... 1,740 MW by 2025... 5,800 MW by 2030

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

CO2 Emissions, K Tonnes

(Pre-Committed) NSR Caps & Retirements

DR/EE

Renewables

Retirements (post-'R/R/R')

Cook Uprates

CCS Retrofits @ 90%

Hybrid Plan

2009 Hybrid Plan

(Assuming No Carbon Offsets or 

Allowance Purchases)

"Business-As-Usual"

2005 (A)

144.9 M

62.5 M

Tonne 

(35.8%)

Reduction

Source: AEP Resource Planning 

While these results would suggest significant improvement in the AEP System CO2 emission 

profile over time, it could still fall short of prospective legislation that would attempt to further limit CO2. 

Specifically, using H.R. 2454 (the Waxman-Markey Bill) that passed the U.S. House in June, 2009 as a 

proxy, this profile would require reduction in CO2 emissions that would have to consider acquisition of 

carbon “offsets”—financial instruments that represent certified initiative to remove 1 ton of carbon—to 

begin to approximate the levels of reduction set forth by such mandates. The following Exhibit 13-8

offers such a comparison for the AEP System: 
AEP-SPP 2009 Integrated Resource Plan 

 123 

Exhibit 13-8: CO2 Emission Profile With Caps 

AEP-SYSTEM (East & West) 

CO2 Position vs. W-M Emission "Caps"

Hybrid Plan (2009 IRP) 

Including: 20 MW CCS by 2010... 235 MW by 2013... 1,300 MW by 2020... 1,740 MW by 2025... 5,800 MW by 2030

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

CO2 Emissions, K Tonnes

(Pre-Committed) NSR Caps & Retirements

DR/EE

Renewables

Retirements (post-'R/R/R')

Cook Uprates

CCS Retrofits

Offsets (Domestic & Int'l)

Hybrid Plan with Offsets

W-M CO2 Target

62.5 M

Tonne 

(35.8%)

Reduction

Waxman-Markey 

(Physical Compliance) Targets 

(3% by '12... 17% by '20... 42% by '30) 

Assuming

20 M Tonne 

of Carbon Offsets 

Attainable by 2020 

Source: AEP Resource Planning 

Further, under the assumption that a cap-and-trade mechanism could emerge from any set of carbon 

legislation, it is reasonable to assume that such CO2 mitigation efforts, inclusive of offset acquisitions, 

may not provide for an adequate CO2 position within that mechanism. Specifically, if the legislation 

provides for the allocation of an insufficient level of (free) CO2 allowances to the utility, any such 

remaining CO2 position “shortfall” must subsequently be borne by the utilities’ customers through 

additional, potentially more costly, CO2 mitigation efforts, including the purchase of additional 

allowances. The following Exhibit 13-9 identifies this potential position based on the current allowance 

allocation format set forth by the Waxman-Markey Bill: 
AEP-SPP 2009 Integrated Resource Plan 

 124 

Exhibit 13-9: CO2 Emission Profile vs. Estimated Waxman-Markey Allocation 

AEP-SYSTEM (East & West) 

CO2 Position vs. Est. W-M LDC Allocations & Wholesale Recoveries

Hybrid Plan (2009 IRP) 

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

CO2 Emissions, K Tonnes

(Pre-Committed) NSR Caps & Retirements

DR/EE

Renewables

Retirements (post-'R/R/R')

Cook Uprates

CCS Retrofits

Offsets (Domestic & Int'l)

Hybrid Plan with Offsets

W-M CO2 Target

Wholesale Allow. Recovery

W-M LDC Est. Allowance Alloc.

62.5 M

Tonne 

(35.8%)

Reduction

~40 MM 

Allowances 

Required (2012)

~24 MM 

Allowances 

Required (2020)

or...

~4,800 MW "CCS-Equiv."

(@ ~5 MM T per 1GW CCS)

~69 MM 

Allowances 

Required (2030)

or...

~13,800 MW "CCS-Equiv."

(@ ~5 MM T per 1GW CCS)

Est. Utility (Retail) Allow. Allocation @ 

79 MM in 2012 under W-M "50/50" 

distribution basis for Electricty Sector 

allowance alloc

Waxman-Markey 

(Physical Compliance) 

Target 

(17% by '20... 42% by '30)

Est. increm. allowance/cost 

recovery from Wholesale 

Customers

Source: AEP Resource Planning 

 In summary, this prism analysis would suggest that the carbon mitigation requirements in the 

AEP System (East and SPP) 2009 IRPs offer a meaningful pathway to the attainment of potential Climate 

Change/CO2 legislation, however, additional contributions–over-and-above the acquisition of CO2

allowances—may be required in future planning cycles to protect AEP’s customers from significant cost 

exposures. 

13.4 Arkansas Stakeholder Process - SWEPCO 

In December 2008 SWEPCO facilitated a meeting of Stakeholders to collect input for this IRP as 

required by the State of Arkansas. The Stakeholders issued their report in February 2009 and it is included 

in the Appendix of this IRP. This Plan recognizes the work of the Arkansas Stakeholder group’s report 

and incorporates their priorities into the SWEPCO plan. One of the Stakeholder’s priorities was 

diversification of the resource mix, primarily through adding renewable sources. For SWEPCO, this plan 

has 300 MW (nameplate) more wind generation than SWEPCO’s 2008 plan. The Stakeholder’s also 

stressed reliability at low cost as a priority item. This IRP includes the completion of both Stall and Turk 

to maintain SWEPCO’s reserve margin above the SPP required levels. These projects were selected 

through a competitive bidding process which assures ratepayers that the lowest reasonable cost option has 

been selected. The Stakeholders also listed demand side options as a priority item. This IRP increases the 

level of demand side programs in the forecast well above previous plans. Other Stakeholder concerns 
AEP-SPP 2009 Integrated Resource Plan 

 125 

were taken into account and addressed throughout the report. SWEPCO appreciated the opportunity to 

gather input from their Stakeholders and looks forward to working with them again for future IRP filings. 

13.5 Conclusion 

The recommended plan provides the “least, reasonable cost” solution through a combination of 

traditional supply, renewable and demand side investments. The tempered load growth combined with 

additional renewable resources, increased DR/EE initiatives, completion of Stall and Turk plants, and the 

execution of the Exelon PPA, will allow AEP-SPP to meet its resource requirements through 2019 at 

which point new peaking capacity will be required. No new uncommitted baseload capacity is required 

over the term of the forecast period. 

Finally, the plan positions AEP to meet state renewable portfolio standards and energy efficiency 

requirements, and sets in place the framework to meet potential CO2 reduction targets at the intended least 

reasonable cost to its customers. 
AEP-SPP 2009 Integrated Resource Plan 

 126 
AEP-SPP 2009 Integrated Resource Plan 

 127 

14.0 Implementation 

14.1 Current Commitments 

While the resource plan described in this report covers an extended time period, the only 

implementation commitments for which a firm consensus must be drawn at this time are those affecting 

resources that are timed to enter service roughly “one lead-time” into the future. New generation lead 

time naturally varies depending upon the resource type being contemplated. Depending on siting, land 

acquisition, permitting, design, engineering, and construction timetables–and whether certain elements 

(e.g. land or permitting) are already in-place–such lead-times may vary as follows: 

 Simple Cycle Combustion Turbine units – about 18 to 30 months 

 Wind Energy Projects – 12 to 36 months from issuance of RFP 

 Natural Gas Combined Cycle units – about 30 to 42 months 

 Solid Fuel units – about 60 months or more 

14.1.1 AEP-SPP Implementation Status 

1. Wind (PSO and SWEPCO) (2010-2012): An RFP was issued on June 1, 2009 for 1,100 MW of 

renewable energy for both the AEP-East and AEP-SPP zones to be operational no later than 

12/31/2011. Additional RFP’s will be issued at a later date for resources required after 2011. 

2. DR/EE

Oklahoma: 

 Quick start programs filed and approved June 2008 - Seven programs approved and 

implementation under way. 

 The Emergency Load Management (ELM) - Currently have 10.5 MW subscribed for 

summer 2009. 

 Energy Star New Homes program - Completed approximately 150 ES homes to date - 

plans to complete 700 by December 2009. 

 Low Income Weatherization - Partnering with Department of Commerce, Choctaw Nation 

and Rebuild Together Tulsa on low- income weatherization program - completed 30 

homes with another 68 to be completed July 2009. This results in an energy savings of 

approximately 160,500 kWh and 28.6 kW. 

 ES Res/Comm appliance rebate program - Began implementation of air conditioner 

replacement rebate program in April 2009 in partnership with Sears and Kmart. 

 C&I SOP - Have projects completed that resulted in a reduction of 150 kW and 965,800 

kWh with projects pending that will provide another 1,100 kW and 6 million kWh in 

energy savings by December 2009. 

 Model Cities LED Traffic signal change out program - Paid incentives for energy savings 

of 214 kW and 1.2 GWh but have commitments for remaining 1,400 kW and 6.3 GWh. 

 Higher Education Loan program - Paid incentives to OSU Tulsa and Tulsa Community 

College for completion of energy audits. 
AEP-SPP 2009 Integrated Resource Plan 

 128 

PSO received approval to file new proposed programs 2010-2012 on September 15th. 

Texas: 

 SWEPCO-Texas is currently operating ten programs, including one demand response 

program, with a mandated goal to achieve a 20 percent reduction in the five-year average 

demand growth during 2009. The associated energy goal is derived by applying a 20 

capacity factor to the demand goal. SWEPCO-Texas currently has over 5,000 kW 

subscribed for the summer of 2009. 

 An appliance recycling program and an additional comprehensive commercial program 

(Commercial Solutions) were “kicked off” in late 2008 and are in full swing in 2009. A 

solar PV pilot program will be initiated in the 3rd quarter of 2009. In addition, SWEPCOTexas continues to negotiate with Comverge in developing a small scale (250 air 

conditioners or heat pumps) direct load control R&D project for the summer of 2010 in the 

City of Longview. 

Louisiana: 

 SWEPCO - Louisiana is giving consideration to proactively filing a portfolio of programs 

in 2009 which would include a low-income weatherization program and a solar PV 

program. The proposed program portfolio would be similar to that in SWEPCO’s 

Arkansas and Texas jurisdictions. 

Arkansas: 

 As a result of the collaborative that was initiated by the Arkansas Public Service 

Commission in 2006, energy efficiency rules were adopted in May 2007. To comply with 

these rules, SWEPCO began one “Quick Start” demand response program and five “Quick 

Start” energy efficiency programs in late 2007 and will continue these programs through 

2009. SWEPCO filed a comprehensive program plan on April 1, 2009 where it proposed 

two additional energy efficiency programs for 2010 and beyond. 

 SWEPCO - Arkansas currently has over 5,000 kilowatts subscribed for the summer of 

2009. 

3. Stall Combined Cycle Unit (by 6/1/2011): All permits have been received and construction 

continues.

4. PSO baseload capacity (by 6/1/2012): PSO and Exelon Generation Company LLC, a subsidiary 

of Exelon Corporation, have executed a long-term PPA and filed an application seeking its 

approval with the Oklahoma Corporation Commission (OCC). The PPA is for the purchase of up 

to 520 megawatts (MW) of electric generation from the 795-MW natural gas-fueled Green 

Country Generating Station, located in Jenks, Okla. 

5. Turk USC Pulverized Coal Unit (by 6/1/2013): The Arkansas Court of Appeals overturned the 

APSC decision granting a CECPN. AEP filed an appeal to Arkansas Supreme Court. The air 

permit appeal hearings were held in June, and a decision is expected by year-end. As of July 1, 

2009, over $713 million has been spent on plant construction, and $1.3 billion of the total $1.6 

billion project has been committed. 
AEP-SPP 2009 Integrated Resource Plan 

 129 

14.1.2 AEP Capital Expenditures For This Plan 

To implement the recommendations included in this plan, significant capital expenditures will be 

required. These expenditures are outlined in the Confidential Supplement. As stated earlier, this plan, 

while making specific recommendations based on available data, is not a commitment to a specific course 

of action. 
AEP-SPP 2009 Integrated Resource Plan 

 130 

APPENDICES 
AEP-SPP 2009 Integrated Resource Plan 

 131 

Appendix A, Figure 1 Existing Generation Capacity, AEP-SPP Zone 

AEP System - SPP Zone

Existing Generation Capacity as of June 1, 2009

Plant Name

Unit 

No.

InService 

Date

Mode of 

Operation

Winter 

Capability 

(MW)

Summer 

Capability 

(MW)

Fuel 

Type SCR CCS FGD

FGD 

Upgr

ACIESP ACI-BHSuper 

critical Age

PSO

Northeastern 3 1979 Base 460 455 Coal -- 2030 2016 -- 2016 -- Y 30

Northeastern 4 1980 Base 470 470 Coal -- -- 2016 -- 2016 -- Y 29

Oklaunion (a) 1 1986 Base 108 101 Coal -- -- -- -- -- -- N 23

PSO Coal 1,038 1,026 29

Comanche 1 1973 Base/Intermediate 285 255 Gas -- -- -- -- -- -- -- 36

Northeastern 1 1961 Base/Intermediate 470 422 Gas -- -- -- -- -- -- N 48

Northeastern 2 1970 Intermediate 470 470 Gas -- -- -- -- -- -- Y 39

Riverside 1 1974 Intermediate 463 454 Gas -- -- -- -- -- -- Y 35

Riverside 2 1976 Intermediate 465 453 Gas -- -- -- -- -- -- Y 33

Riverside 3 2008 Peaking 83 75 (b) Gas -- -- -- -- -- -- -- 1

Riverside 4 2008 Peaking 83 75 (b) Gas -- -- -- -- -- -- -- 1

Southwestern 1 1952 Intermediate 80 78 Gas -- -- -- -- -- -- N 57

Southwestern 2 1954 Intermediate 80 78 Gas -- -- -- -- -- -- N 55

Southwestern 3 1967 Intermediate 315 311 Gas -- -- -- -- -- -- N 42

Southwestern 4 2008 Peaking 83 75 (b) Gas -- -- -- -- -- -- -- 1

Southwestern 5 2008 Peaking 83 75 (b) Gas -- -- -- -- -- -- -- 1

Tulsa 2 1956 Intermediate 165 160 Gas -- -- -- -- -- -- N 53

Tulsa 3 1958 Intermediate 71 65 Gas -- -- -- -- -- -- N 51

Tulsa 4 1958 Intermediate 165 155 Gas -- -- -- -- -- -- N 51

Weleetka 4 1975 Peaking 65 54 Gas -- -- -- -- -- -- -- 34

Weleetka 5 1975 Peaking 65 52 Gas -- -- -- -- -- -- -- 34

Weleetka 6 1976 Peaking 65 52 Gas -- -- -- -- -- -- -- 33

PSO Gas 3,556 3,359 37

Diesels 1962 Peaking 6 6 Oil -- -- -- -- -- -- -- 47

Diesels 1963 Peaking 4 4 Oil -- -- -- -- -- -- -- 46

Diesels 1967 Peaking 8 8 Oil -- -- -- -- -- -- -- 42

Diesels 1968 Peaking 3 3 Oil -- -- -- -- -- -- -- 41

Diesels 1976 Peaking 3 3 Oil -- -- -- -- -- -- -- 33

Diesels 1980 Peaking 1 1 Oil -- -- -- -- -- -- -- 29

PSO Oil 25 25 42

Weatherford Wind (c) 2005 Intermittent 15 15 Wind -- -- -- -- -- -- -- 4

Sleeping Bear Wind (c) 2007 Intermittent 2 2 Wind -- -- -- -- -- -- -- 2

PSO Wind 17 17 4

Total PSO 4,636 4,427

SWEPCO

Flint Creek (d) 1 1978 Base 264 264 Coal -- -- 2014 -- -- -- N 31

Welsh 1 1977 Base 528 528 Coal -- 2030 -- -- -- -- N 32

Welsh 2 1980 Base 528 528 Coal -- 2030 2015 -- -- -- N 29

Welsh 3 1982 Base 528 528 Coal -- -- -- -- -- -- N 27

SWEPCO Coal 1,848 1,848 30

Dolet Hills (e) 1 1986 Base 262 262 Lignite -- -- 2006 2012 -- -- N 23

Pirkey (f) 4 1985 Base 580 580 Lignite -- -- 2006 -- -- -- N 24

SWEPCO Lignite 842 842 24

Arsenal Hill 5 1960 Intermediate 110 110 Gas -- -- -- -- -- -- N 49

Knox Lee 2 1950 Intermediate 31 30 Gas -- -- -- -- -- -- N 59

Knox Lee 3 1952 Intermediate 32 29 Gas -- -- -- -- -- -- N 57

Knox Lee 4 1956 Intermediate 79 73 Gas -- -- -- -- -- -- N 53

Knox Lee 5 1974 Intermediate 345 345 Gas -- -- -- -- -- -- N 35

Lieberman 1 1947 Intermediate 25 25 Gas -- -- -- -- -- -- N 62

Lieberman 2 1949 Intermediate 26 26 Gas -- -- -- -- -- -- N 60

Lieberman 3 1957 Intermediate 115 109 Gas -- -- -- -- -- -- N 52

Lieberman 4 1959 Intermediate 112 108 Gas -- -- -- -- -- -- N 50

Lone Star 1 1954 Intermediate 50 50 Gas -- -- -- -- -- -- N 55

Mattison 1 2007 Peaking 83 72 Gas -- -- -- -- -- -- -- 2

Mattison 2 2007 Peaking 83 72 Gas -- -- -- -- -- -- -- 2

Mattison 3 2007 Peaking 83 72 Gas -- -- -- -- -- -- -- 2

Mattison 4 2007 Peaking 83 72 Gas -- -- -- -- -- -- -- 2

Wilkes 1 1964 Intermediate 178 174 Gas -- -- -- -- -- -- N 45

Wilkes 2 1970 Intermediate 360 355 Gas -- -- -- -- -- -- N 39

Wilkes 3 1971 Intermediate 359 354 Gas -- -- -- -- -- -- N 38

SWEPCO Gas 2,154 2,076 37

Total SWEPCO 4,844 4,766

TOTAL AEP-West 9,480 9,193

(a) PSO owns 15.62% of the 650 MW jointly-owned Oklaunion Unit No. 1.

(b) PSO combustion turbine units were uprated after its IRP was completed early in 2008.

(c) Power purchase agreements.

(d) SWEPCO owns 50% of the 528 MW jointly-owned Flint Creek Unit No. 1.

(e) SWEPCO owns 40.234% of the 650 MW jointly-owned Dolet Hills Unit No. 1.

(f) SWEPCO owns 85.936% of the 675 MW jointly-owned Pirkey Unit No. 1.
AEP-SPP 2009 Integrated Resource Plan 

 132 

Appendix B, Figure 1 Economically Screened Renewable Alternatives Unit or Series Renewable Type $/MWh Unit or Series Renewable Type $/MWh Hydro, Existing Dam, PTC Hydro -$16.08 Mountaineer Biomass Separate Injection $25.32 Wind Project, SPP with PTC Wind -$10.50 Big Sandy 1 Biomass Separate Injection $25.49 Amos 3 Biomass Cofire -$3.60 Conesville 5 Biomass Separate Injection $25.51 Big Sandy 2 Biomass Cofire -$1.32 Conesville 6 Biomass Separate Injection $26.06 Amos 1 Biomass Cofire $0.14 Pirkey 1 Biomass Separate Injection $26.08 (a) Tanners Creek 4 Biomass Separate Injection $1.71 Kanawha River 1 Biomass Separate Injection $26.15 Rockport 1 Biomass Cofire $2.98 Flint Creek 1 Biomass Separate Injection $26.30 Stoker conversion, 100% biomass High fuel cost $4.54 Cardinal 1 Biomass Separate Injection $26.42 (a) Muskingum River 5 Biomass Cofire $4.91 Mitchell 1 Biomass Separate Injection $29.55 (a) Stuart 1 Biomass Separate Injection $7.21 Dolet Hills 1 Biomass Separate Injection $30.51 Muskingum River 5 Biomass Separate Injection $9.04 (a) Tanners Creek 3 Biomass Separate Injection $32.49 Glen Lyn 6 Biomass Separate Injection $11.53 Tanners Creek 1 Biomass Separate Injection $32.70 Big Sandy 2 Biomass Separate Injection $12.09 (a) Northeastern 3 Biomass Cofire $32.79 Mountaineer Biomass Cofire $12.69 Clinch River 1 Biomass Cofire $37.48 Amos 3 Biomass Separate Injection $13.04 (a) Northeastern 3 Biomass Separate Injection $38.64 (a) Amos 1 Biomass Separate Injection $13.65 (a) Clinch River 1 Biomass Separate Injection $41.79 (a) Oklaunion 1 Biomass Cofire $14.47 Wind Project, PJM w/o PTC Wind $45.04 Welsh 1 Biomass Cofire $14.51 Sporn 1 Biomass Separate Injection $47.21 Mitchell 1 Biomass Cofire $15.09 Landfill Gas0.8Recip Engine Gas $57.00 Wind Project, SPP w/o PTC Wind $16.62 Muskingum River 3 Biomass Separate Injection $75.23 Rockport 1 Biomass Separate Injection $16.79 (a) Glen Lyn 5 Biomass Separate Injection $86.09 Wind Project, PJM with PTC Wind $17.94 Muskingum River 1 Biomass Cofire $104.54 Welsh 1 Biomass Separate Injection $18.51 (a) Sporn 5 Biomass Cofire $130.46 Oklaunion 1 Biomass Separate Injection $20.45 (a) Muskingum River 1 Biomass Separate Injection $135.04 Pirkey 1 Biomass Cofire $20.80 Picway 5 Biomass Separate Injection $141.28 Cardinal 1 Biomass Cofire $21.01 Conesville 3 Biomass Cofire $316.90 Zimmer Biomass Separate Injection $22.04 Residential Wind, PJM w/o PTC Wind $394.03 Kammer 1 Biomass Separate Injection $22.34 Central Station Solar Solar $445.00 Conesville 4 Biomass Separate Injection $22.82 Gavin 1 Biomass Separate Injection $24.28 Beckjord 6 Biomass Separate Injection $24.32 Note: (a) The cost of a second technology at a unit is incremental, that is, additional renewable energy divided by additional cost.
AEP-SPP 2009 Integrated Resource Plan 

 133 

Appendix C, Figure 1 Key Supply Side Resource Assumptions 

AEP System-West Zone 

New Generation Technologies

Key Supply-Side Resource Option Assumptions (a)(b)

Trans. Full Load Capacity Overall

Capability (MW) Cost (c) Heat Rate SO2 NOx CO2 Factor Availability 

Type Std. ISO ($/kW) (HHV,Btu/kWh) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (%) (%)

Base Load

Pulv. Coal (Subcritical) (PRB) 618 20 9,527 0.0125 0.070 212.70 85 90.7

Pulv. Coal (Subcritical) (PRB) 736 17 9,516 0.0125 0.070 212.70 85 89.6

Pulv. Coal (Supercritical) (PRB) 618 20 9,249 0.0125 0.070 212.70 85 90.7

Pulv. Coal (Supercritical) (PRB) 736 17 9,239 0.0125 0.070 212.70 85 89.6

Pulv. Coal (Ultra-Supercritical) (PRB) 618 20 8,980 0.0125 0.070 212.70 85 89.6

Pulv. Coal (Ultra-Supercritical) (PRB) 736 17 8,970 0.0125 0.070 212.70 85 89.6

IGCC (PRB) 621 20 9,220 0.0193 0.062 212.70 85 87.5

Pulv. Coal (Subcritical) (Lignite) 618 20 10,245 0.0773 0.070 215.40 85 90.7

Pulv. Coal (Subcritical) (Lignite) 736 17 10,235 0.0773 0.070 215.40 85 89.6

Pulv. Coal (Supercritical) (Lignite) 618 20 9,947 0.0773 0.070 215.40 85 90.7

Pulv. Coal (Supercritical) (Lignite) 736 17 9,936 0.0773 0.070 215.40 85 89.6

Pulv. Coal (Ultra-Supercritical) (Lignite) 607 21 9,657 0.0773 0.070 215.40 85 89.6

Pulv. Coal (Ultra-Supercritical) (Lignite) 736 17 9,647 0.0773 0.070 215.40 85 89.6

IGCC (Lignite) 585 21 9,156 0.0773 0.057 215.40 85 87.5

Nuclear (MHI ABWR) 1,606 52 10,500 0.0000 0.000 0.00 85 94.0

Base Load (50% CO2 Capture New Unit)

Pulv. Coal (Subcritical) (PRB) 515 24 11,432 0.0125 0.070 106.35 85 89.6

Pulv. Coal (Supercritical) (PRB) 515 24 11,099 0.0125 0.070 106.35 85 89.6

Pulv. Coal (Ultra-Supercritical) (PRB) 515 24 10,776 0.0125 0.070 106.35 85 89.6

IGCC (PRB) 569 22 10,058 0.0193 0.062 106.35 85 87.5

Pulv. Coal (Subcritical) (Lignite) 515 24 12,294 0.0773 0.070 107.70 85 89.6

Pulv. Coal (Supercritical) (Lignite) 515 24 11,936 0.0773 0.070 107.70 85 89.6

Pulv. Coal (Ultra-Supercritical) (Lignite) 505 25 11,588 0.0773 0.070 107.70 85 89.6

IGCC (Lignite) 537 23 9,988 0.0773 0.057 107.70 85 87.5

Base Load (90% CO2 Capture New Unit)

Pulv. Coal (Subcritical) (PRB) 433 29 13,610 0.0125 0.070 21.27 85 89.6

Pulv. Coal (Subcritical) (PRB) 515 24 13,595 0.0125 0.070 21.27 85 89.6

Pulv. Coal (Supercritical) (PRB) 433 29 13,213 0.0125 0.070 21.27 85 89.6

Pulv. Coal (Supercritical) (PRB) 515 24 13,199 0.0125 0.070 21.27 85 89.6

Pulv. Coal (Ultra-Supercritical) (PRB) 433 29 12,829 0.0125 0.070 21.27 85 89.6

Pulv. Coal (Ultra-Supercritical) (PRB) 515 24 12,814 0.0125 0.070 21.27 85 89.6

IGCC (PRB) 528 24 10,847 0.0193 0.062 21.27 85 87.5

IGCC (w/ CCS) (PRB) 528 24 10,847 0.0193 0.062 21.27 85 87.5

Pulv. Coal (Subcritical) (Lignite) 433 29 14,636 0.0773 0.070 21.54 85 89.6

Pulv. Coal (Subcritical) (Lignite) 515 24 14,621 0.0773 0.070 21.54 85 89.6

Pulv. Coal (Supercritical) (Lignite) 433 29 14,210 0.0773 0.070 21.54 85 89.6

Pulv. Coal (Supercritical) (Lignite) 515 24 14,195 0.0773 0.070 21.54 85 89.6

Pulv. Coal (Ultra-Supercritical) (Lignite) 425 29 13,796 0.0773 0.070 21.54 85 89.6

Pulv. Coal (Ultra-Supercritical) (Lignite) 515 24 13,781 0.0773 0.070 21.54 85 89.6

IGCC (Lignite) 498 25 10,772 0.0773 0.057 21.54 85 87.5

IGCC (w/ CCS) (Lignite) 498 25 10,772 0.0773 0.057 21.54 85 87.5

Intermediate

Combined Cycle (2X1 GE7FA) 507 30 7,040 0.0007 0.008 116.00 85 89.1

Combined Cycle (2X1 GE7FA, w/ Duct Firing) 619 24 7,660 0.0007 0.008 116.00 85 89.1

Combined Cycle (2X1 GE7FB) 538 28 6,917 0.0007 0.008 116.00 85 89.1

Combined Cycle (2X1 GE7FB, w/ Duct Firing) 650 23 7,537 0.0007 0.008 116.00 85 89.1

Intermediate (70% CO2 Capture New Unit)

Combined Cycle (2X1 GE7FA) 447 34 7,969 0.0007 0.008 34.80 85 89.1

Combined Cycle (2X1 GE7FA, w/ Duct Firing) 546 27 8,671 0.0007 0.008 34.80 85 89.1

Combined Cycle (2X1 GE7FB) 475 32 7,831 0.0007 0.008 34.80 85 89.1

Combined Cycle (2X1 GE7FB, w/ Duct Firing) 574 26 8,533 0.0007 0.008 34.80 85 89.1

Peaking

Combustion Turbine (2X1GE7EA) 165 60 12,156 0.0007 0.033 116.00 5 90.1

Combustion Turbine (2X1GE7EA,w/ Inlet Chiller 165 60 12,339 0.0007 0.009 116.00 5 90.1

Combustion Turbine (4X1GE7EA) 329 60 12,156 0.0007 0.033 116.00 5 90.1

Combustion Turbine (4X1GE7EA,w/ Inlet Chiller 329 60 12,339 0.0007 0.009 116.00 5 90.1

Combustion Turbine (6X1GE7EA) 494 60 12,156 0.0007 0.033 116.00 5 90.1

Combustion Turbine (6X1GE7EA,w/ Inlet Chiller 494 60 12,339 0.0007 0.009 116.00 5 90.1

Combustion Turbine (8X1GE7EA) 658 60 12,156 0.0007 0.033 116.00 5 90.1

Combustion Turbine (8X1GE7EA,w/ Inlet Chiller 658 60 12,339 0.0007 0.009 116.00 5 90.1

Combustion Turbine (2X GE7FA) 328 60 10,390 0.0007 0.033 116.00 5 90.1

Combustion Turbine (2X GE7FA, w/ Inlet Chiller) 328 60 10,545 0.0007 0.009 116.00 5 90.1

Combustion Turbine (3X GE7FA) 492 60 10,390 0.0007 0.033 116.00 5 90.1

Combustion Turbine (3X GE7FA, w/ Inlet Chiller) 492 60 10,545 0.0007 0.009 116.00 5 90.1

Combustion Turbine (4X GE7FA) 657 60 10,390 0.0007 0.033 116.00 5 90.1

Combustion Turbine (4X GE7FA, w/ Inlet Chiller) 657 60 10,545 0.0007 0.009 116.00 5 90.1

Aero-Derivative (4X GE LM6000PC) 181 60 9,598 0.0007 0.056 116.00 5 89.1

Aero-Derivative (1X GE LMS100) 96 60 8,402 0.0007 0.056 116.00 5 89.1

Aero-Derivative (1X GE LMS100, w/ Inlet Chiller) 96 60 8,528 0.0007 0.009 116.00 5 90.1

Aero-Derivative (2X GE LMS100) 191 60 8,402 0.0007 0.056 116.00 5 89.1

Aero-Derivative (2X GE LMS100, w/ Inlet Chiller) 191 60 8,528 0.0007 0.009 116.00 5 90.1

Notes: (a)Capability and heat rate numbers have been rounded.

(b) All costs in 2008 dollars. Assume 2% escalation rate for 2008 and beyond.

(c) Transmission Cost ($/kW,w/AFUDC).

 Source: "New Generation Technology Cost and Performance Estimates," 12/03/08, Corporate Technology Development (CTD).

Emission Rates
AEP-SPP 2009 Integrated Resource Plan 

 134 

Appendix C, Figure 2 Energy Storage Screening 

To ascertain a break-even screening curve for energy storage facilities, an hour-by-hour simulation 

was run. The simulation was based on the forecasted power prices of the reference case as used in this 

report. The facility was assumed to generate up to six hours per day (the most cost effective hours) in 

which: 

(Generation Price * Cycle Efficiency) – (Charging Price) > 0

 The simulation was run for 10 years at various cycle efficiencies while tracking the annual cost, in $/kWyear, and the capacity factor of the facility. For each efficiency the levelized $/kW-year cost was plotted 

against the average capacity factor. The most recent equivalent data for a combustion turbine (GE7FA) 

facility was also plotted on the same graph. 

 The fixed costs for the energy storage facility were then varied to create intercepts with the 

combustion turbine curve at various capacity factors thus yielding the following chart. 

Break-Even Energy Storage Capital Cost and Cycle Efficiency as Compared to a CT (GE7FA) 

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

60% 65% 70% 75% 80% 85% 90% 95% 100%

Storeage Cycle

Capital Costs 

($/kW)

Favorable

Unfavorable

Source: AEP Resource Planning

This exhibit depicts the break-even capital cost of the storage facility in terms of cycle efficiency. 

For example a storage facility costing $2,000/kW and having a cycle efficiency of 75% or higher 

would compare favorably against a CT. However, a facility costing $2,500/kW would need an 

efficiency of 95% or greater. 

This analysis considers only the value of storage as a supply-side resource. Additional value might 

be provided by the facility’s location with respect to the distribution system, if system capital 

improvements could be delayed. 
AEP-SPP 2009 Integrated Resource Plan 

 135 

Appendix D, Figure 1 AEP-SPP Capacity, Demand, Reserve Forecast 

AMERICAN ELECTRIC POWER OPERATING COMPANIES IN SOUTHWEST POWER POOL 

 CAPABILITY, DEMAND AND RESERVES FORECAST 

2008 Actual - 2019

(MW) 

2009 IRP

Public Service Company of Oklahoma

A Capability 08 ACT 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Existing Plants and new additions 4,405 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410

Adjustments -15 -15 -15 -15

New Combustion Turbines 

Wind Purchases 27 17 17 17 17 45 45 50 50 66 66 66

Transfer from SWEPCo 18

Transfer to SWEPCo -15

Other known Purchases w/o Reserves 254 390 138 100 512 512 510 510 510 508 508 508

Unknown Wholesale Purchase 70

Total Capability 4,686 4,817 4,565 4,615 4,924 4,967 4,965 4,970 4,955 4,969 4,969 4,969

Demand

Native Load Responsibility 4,152 3,976 4,051 4,100 4,181 4,187 4,180 4,171 4,186 4,203 4,226 4,245

Sales With Reserves

East to West Transfer w/ Reserves

Other Purchases With Reserves -39 -39 -39 -39 -39 -39 -39 -39 -39 -39 -39 -39

Net Demand Responsibility 4,113 3,937 4,012 4,061 4,142 4,148 4,141 4,132 4,147 4,164 4,187 4,206

Reserves

Reserve Capacity, MW 573 880 553 554 782 819 824 838 808 805 782 763

Capacity Margin, % 12.2 18.3 12.1 12.0 15.9 16.5 16.6 16.9 16.3 16.2 15.7 15.4

check 573 880 553 554 782 819 824 838 808 805 782 763

Southwestern Electric Power Company

A Capability 08 ACT 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Existing Plants and new additions 4,792 4,766 4,766 5,275 5,275 5,722 5,722 5,722 5,722 5,722 5,722 5,722

Adjustments -4 -12 -12 -12 -12 -12

New Combustion Turbine 157

Wind Purchases 8 22 34 34 37 45 45 45 45

Transfer from PSO 15

Transfer to PSO -18

East to West Transfer w/o Reserves

Other known Purchases w/o Reserves 702 816 743 381 381 432 432 42 42 42 42 42

Sales without Reserves -18 -18 -18 -18 -18 -18 -18 -18 -18 -18 -18 -18

Unknown Wholesale Purchase

Total Capability 5,476 5,564 5,491 5,628 5,675 6,170 6,166 5,771 5,779 5,779 5,779 5,936

Demand

Native Load Responsibility 4,920 4,798 4,954 5,082 5,121 5,186 5,239 4,544 4,605 4,666 4,735 4,801

Sales With Reserves 46 46 46 46 48 48 48 248 248 248 250 250

East to West Transfer w/ Reserves 

Other Purchases With Reserves -175 -175 -175 -175 -175 -175 -175 -73 -73 -73 -73 -73

Net Demand Responsibility 4,791 4,669 4,825 4,953 4,994 5,059 5,112 4,719 4,780 4,841 4,912 4,978

Reserves

Reserve Capacity, MW 685 895 666 675 681 1,111 1,054 1,052 999 938 867 958

Capacity Margin, % 12.5 16.1 12.1 12.0 12.0 18.0 17.1 18.2 17.3 16.2 15.0 16.1

check 685 895 666 675 681 1,111 1,054 1,052 999 938 867 958

Total PSO Market + Affiliate Purchase 254 390 138 188

Total SWEPCo Market + Affiliate Purchase 321 435 362 15

Total System Purchase 575 825 500 170

System Unknown Wholesale Purchase 70

Total Surplus 84 601 14 217 675 616 684 589 515 408 469
AEP-SPP 2009 Integrated Resource Plan 

 136 

Appendix D, Figure 2 AEP-SPP Capacity, Demand, Reserve Forecast (High Demand Scenario) 

AMERICAN ELECTRIC POWER OPERATING COMPANIES IN SOUTHWEST POWER POOL 

 CAPABILITY, DEMAND AND RESERVES FORECAST 

2008 Actual - 2019

(MW) 

 HIGH ECONOMIC FORECAST SCENARIO (2009 IRP EXPANSION PLAN)

Public Service Company of Oklahoma

A Capability 08 ACT 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Existing Plants and new additions 4,405 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410

Adjustments -15 -15 -15 -15

New Combustion Turbines 

Wind Purchases 27 17 17 17 17 45 45 50 50 66 66 66

Transfer from SWEPCo 18

Transfer to SWEPCo -65

Other known Purchases w/o Reserves 254 390 138 100 512 512 510 510 510 508 508 508

Unknown Wholesale Purchase 108 228 1 46 92 124

Total Capability 4,686 4,817 4,673 4,755 4,874 4,967 4,965 4,970 4,974 5,015 5,061 5,093

Demand

Native Load Responsibility 4,152 4,045 4,151 4,223 4,328 4,365 4,385 4,391 4,417 4,453 4,493 4,521

Sales With Reserves

East to West Transfer w/ Reserves

Other Purchases With Reserves -39 -39 -39 -39 -39 -39 -39 -39 -39 -39 -39 -39

Net Demand Responsibility 4,113 4,006 4,112 4,184 4,289 4,326 4,346 4,352 4,378 4,414 4,454 4,482

Reserves

Reserve Capacity, MW 573 811 561 571 585 641 619 618 597 602 607 611

Capacity Margin, % 12.2 16.8 12.0 12.0 12.0 12.9 12.5 12.4 12.0 12.0 12.0 12.0

check 573 811 561 571 585 641 619 618 597 602 607 611

Southwestern Electric Power Company

A Capability 08 ACT 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Existing Plants and new additions 4,792 4,766 4,766 5,275 5,275 5,722 5,722 5,722 5,722 5,722 5,722 5,722

Adjustments -4 -12 -12 -12 -12 -12

New Combustion Turbine 157

Wind Purchases 8 22 34 34 37 45 45 45 45

Transfer from PSO 65

Transfer to PSO -18

East to West Transfer w/o Reserves

Other known Purchases w/o Reserves 702 816 743 381 381 432 432 42 42 42 42 42

Sales without Reserves -18 -18 -18 -18 -18 -18 -18 -18 -18 -18 -18 -18

Unknown Wholesale Purchase 130 154 153 83 193 128

Total Capability 5,476 5,564 5,621 5,800 5,878 6,170 6,166 5,771 5,761 5,862 5,972 6,064

Demand

Native Load Responsibility 4,885 4,881 5,076 5,233 5,300 5,403 5,492 4,819 4,895 4,984 5,078 5,159

Sales With Reserves 46 46 46 46 48 48 48 248 248 248 250 250

East to West Transfer w/ Reserves 

Other Purchases With Reserves -175 -175 -175 -175 -175 -175 -175 -73 -73 -73 -73 -73

Net Demand Responsibility 4,756 4,752 4,947 5,104 5,173 5,276 5,365 4,994 5,070 5,159 5,255 5,336

Reserves

Reserve Capacity, MW 720 812 674 696 705 894 801 777 691 703 717 728

Capacity Margin, % 13.2 14.6 12.0 12.0 12.0 14.5 13.0 13.5 12.0 12.0 12.0 12.0

check 720 812 674 696 705 894 801 777 691 703 717 728

Total PSO Market + Affiliate Purchase 254 390 246 328 19 46 92 124

Total SWEPCo Market + Affiliate Purchase 321 435 492 154 218 83 193 128

Total System Purchase 575 825 738 482 153 1 129 285 252

System Unknown Wholesale Purchase 238 382 153 1 129 285 252

Total Surplus 84 429 226 96 120
AEP-SPP 2009 Integrated Resource Plan 

 137 

Appendix D, Figure 3 PSO Capacity, Demand, Reserve Forecast 

CAPABILITY

A Plant Capabilities 08 ACT 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

11 DIESEL UNITS @ PLANT LOCATIONS 25 25 25 25 25 25 25 25 25 25 25 25

10 OKLAUNION #1 101 101 101 101 101 101 101 101 101 101 101 101

9 COMANCHE # 1G1, 1G2, 1S 260 255 255 255 255 255 255 255 255 255 255 255

8 NORTHEASTERN # 1 & 2 883 892 892 892 892 892 892 892 892 892 892 892

7 NORTHEASTERN # 3 & 4 930 925 925 925 925 925 925 925 925 925 925 925

6 RIVERSIDE # 1 & 2 909 907 907 907 907 907 907 907 907 907 907 907

5 RIVERSIDE CTs 150 150 150 150 150 150 150 150 150 150 150 150

4 SOUTHWESTERN # 1, 2, 3 467 467 467 467 467 467 467 467 467 467 467 467

3 SOUTHWESTERN CTs 150 150 150 150 150 150 150 150 150 150 150 150

2 TULSA # 2, 3, 4 370 380 380 380 380 380 380 380 380 380 380 380

1 WELEETKA # 4, 5, 6 160 158 158 158 158 158 158 158 158 158 158 158

1 TOTAL 4,405 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,410

Adjustments to Plant Capability

NEW COMBUSTION TURBINE UNITS 

NE 3 & 4 Scrubbers, 1.6% (MW) 2016 -15 -15 -15 -15

2 TOTAL 0 0 0 0 0 0 0 0 -15 -15 -15 -15

3 Net Plant Capability ( 1 + 2 ) 4,405 4,410 4,410 4,410 4,410 4,410 4,410 4,410 4,395 4,395 4,395 4,395

Sales Without Reserves

TRANSFER TO SWEPCO 15

4 TOTAL 0 0 0 0 15 0 0 0 0 0 0 0

Purchases Without Reserves

MERRILL LYNCH/TENASKA/CALPINE 101 249 138 100

TRANSFER FROM SWEPCO 18

WEATHERFORD WIND 19 15 15 15 15 15 15 15 15 15 15 15

SLEEPING BEAR WIND 8 2 2 2 2222 2222

BLUE CANYON WIND 20 20 20 20 20 20 20

ADDITIONAL WIND PROJECTS 8 8 13 13 29 29 29

EXELON GREEN COUNTRY 512 512 510 510 510 508 508 508

TENASKA/UNION POWER 153 141

UNKNOWN WHOLESALE PURCHASE 70

5 TOTAL 281 407 155 205 529 557 555 560 560 574 574 574

6 Total Capability (3 - 4 + 5) 4,686 4,817 4,565 4,615 4,924 4,967 4,965 4,970 4,955 4,969 4,969 4,969

DEMAND 08 ACT 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

A Peak Demand Before Passive DSM 4,200 4,059 4,171 4,254 4,366 4,406 4,432 4,457 4,473 4,486 4,511 4,532

B Passive DSM 

APPROVED DSM PROGRAMS 9 13 16 19 21 22 23 24 25 25 25

NEW DSM 31 62 94 125 157 188 188 188 188 188

TOTAL 0 9 44 78 113 146 179 211 212 212 212 212

C Peak Demand ( A - B ) 4,200 4,050 4,127 4,175 4,253 4,260 4,253 4,246 4,261 4,273 4,299 4,320

D Active DSM

VALUECHOICE 35 35 35 35 35 35 35 35 35 35 35 35

INTERRUPTIBLE 13 17 17 17 17 17 17 17 17 17 17 17

TOTAL 48 52 52 52 52 52 52 52 52 52 52 52

E Firm Demand ( C - D ) 4,152 3,998 4,075 4,123 4,201 4,208 4,201 4,194 4,209 4,221 4,247 4,268

F Other Demand Adjustments

DIVERSITY 22 24 23 20 21 21 22 23 18 20 23

 

TOTAL 0 22 24 23 20 21 21 22 23 18 20 23

7 Native Load Responsibility ( E - F ) 4,152 3,976 4,051 4,100 4,181 4,187 4,180 4,171 4,186 4,203 4,226 4,245

Sales With Reserves

8 TOTAL 000 0 0000 0000

Purchases With Reserves

PSO - SWPA ENTITLEMENT 39 39 39 39 39 39 39 39 39 39 39 39

9 TOTAL 39 39 39 39 39 39 39 39 39 39 39 39

10 Load Responsibility ( 7 + 8 - 9 ) 4,113 3,937 4,012 4,061 4,142 4,148 4,141 4,132 4,147 4,164 4,187 4,206

RESERVES 08 ACT 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

11 Reserve Capacity, MW ( 6 - 10 ) 573 880 553 554 782 819 824 838 808 805 782 763

12 % Reserve Margin (( 11/10 ) * 100 ) 13.9 22.4 13.8 13.6 18.9 19.7 19.9 20.3 19.5 19.3 18.7 18.1

13 % Capacity Margin ( 11/(6) * 100 ) 12.2 18.3 12.1 12.0 15.9 16.5 16.6 16.9 16.3 16.2 15.7 15.4

14 Reserve Above 12% Capacity Margin, MW 12 343 6 0 217 253 259 275 242 237 211 190

PUBLIC SERVICE COMPANY OF OKLAHOMA

 CAPABILITY, DEMAND AND RESERVES FORECAST 

2008 Actual - 2019

(MW) 

2009 IRP
AEP-SPP 2009 Integrated Resource Plan 

 138 

Appendix D, Figure 4 SWPCO Capacity, Demand, Reserve Forecast 

CAPABILITY

Plant Capabilities 08 ACT 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

12 ARSENAL HILL # 5 110 110 110 110 110 110 110 110 110 110 110 110

11 J.L. STALL (ARSENAL HILL) CC 509 509 509 509 509 509 509 509 509

10 DOLET HILL #1 270 262 262 262 262 262 262 262 262 262 262 262

9 FLINT CREEK # 1 264 264 264 264 264 264 264 264 264 264 264 264

8 TURK (HEMPSTEAD) PC 447 447 447 447 447 447 447

7 KNOX LEE # 2, 3, 4, 5 485 477 477 477 477 477 477 477 477 477 477 477

6 LIEBERMAN # 1, 2, 3, 4 268 268 268 268 268 268 268 268 268 268 268 268

5 LONE STAR # 1 50 50 50 50 50 50 50 50 50 50 50 50

4 PIRKEY #1 580 580 580 580 580 580 580 580 580 580 580 580

3 MATTISON (TONTITOWN) CTs 300 288 288 288 288 288 288 288 288 288 288 288

2 WELSH # 1, 2, 3 1,584 1,584 1,584 1,584 1,584 1,584 1,584 1,584 1,584 1,584 1,584 1,584

1 WILKES # 1, 2, 3 881 883 883 883 883 883 883 883 883 883 883 883

1 TOTAL 4,792 4,766 4,766 5,275 5,275 5,722 5,722 5,722 5,722 5,722 5,722 5,722

Adjustments to Plant Capability

NEW COMBUSTION TURBINE UNITS 157

Adjustments for Environmental Retrofits -4 -12 -12 -12 -12 -12

2 TOTAL 0 0 0 0 0 0 -4 -12 -12 -12 -12 145

3 Net Plant Capability ( 1 + 2 ) 4,792 4,766 4,766 5,275 5,275 5,722 5,718 5,710 5,710 5,710 5,710 5,867

Sales Without Reserves

TRANSFER TO PSO 18

Backup contracts (Eastman, Domtar, & Internat'l Paper) 18 18 18 18 18 18 18 18 18 18 18 18

4 TOTAL 18 18 18 36 18 18 18 18 18 18 18 18

Purchases Without Reserves

NTEC - HCPP 165 165 165 165 165 165 165

NTEC GENERATION - PIRKEY/DOLET HILLS/TURK 117 117 117 117 117 168 168

NTEC - ENTERGY ISES 30 30 30 30 30 30 30

NTEC - SPA NARROWS 27 27 27 27 27 27 27

TEX-LA - ETEC - EPI 10 10 10 10 10 10 10 10 10 10 10 10

ADDITIONAL WIND PROJECTS 8 22 34 34 37 45 45 45 45

CUSTOMER GENERATION - MINDEN 32 32 32 32 32 32 32 32 32 32 32 32

MERRILL LYNCH/TENASKA/CALPINE 49 151 362

TRANSFER FROM PSO 15

TENASKA/UNION POWER 272 284

UNKNOWN WHOLESALE PURCHASES

5 TOTAL 702 816 743 389 418 466 466 79 87 87 87 87

6 Total Capability (3 - 4 + 5) 5,476 5,564 5,491 5,628 5,675 6,170 6,166 5,771 5,779 5,779 5,779 5,936

DEMAND 08 ACT 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

A Peak Demand Before Passive DSM 4,950 4,840 5,032 5,188 5,253 5,346 5,427 5,512 5,588 5,660 5,745 5,826

NTEC -754 -767 -782 -796 -809

Peak Demand Before Passive DSM Adjusted 4,950 4,840 5,032 5,188 5,253 5,346 5,427 4,758 4,821 4,878 4,950 5,018

B Passive DSM 

Approved Passive DSM 10 16 20 24 26 29 30 31 32 32 32

NEW DSM 0 24 48 72 96 120 144 144 144 144 144

TOTAL 0 10 40 68 96 122 149 174 175 176 176 176

C Peak Demand ( A - B ) 4,950 4,830 4,992 5,120 5,158 5,224 5,278 4,584 4,645 4,702 4,773 4,842

D Active DSM

INTERRUPTIBLE 10 14 15 16 17 18 18 18 18 18 18

TOTAL 0 10 14 15 16 17 18 18 18 18 18 18

E Firm Demand ( C - D ) 4,950 4,820 4,978 5,105 5,142 5,207 5,260 4,566 4,627 4,684 4,755 4,824

F Other Demand Adjustments

DIVERSITY 30 22 24 23 20 21 21 22 23 18 20 23

TOTAL 30 22 24 23 20 21 21 22 23 18 20 23

7 Native Load Responsibility ( E - F ) 4,920 4,798 4,954 5,082 5,121 5,186 5,239 4,544 4,605 4,666 4,735 4,801

Sales With Reserves

TEX-LA ERCOT 46 46 46 46 48 48 48 48 48 48 50 50

NTEC 200 200 200 200 200

8 TOTAL 46 46 46 46 48 48 48 248 248 248 250 250

Purchases With Reserves

NTEC SPA HYDRO PEAKING 102 102 102 102 102 102 102

LOUISIANA GENERATION (FORMERLY CAJUN) 50 50 50 50 50 50 50 50 50 50 50 50

SPA HYDRO-B'VILLE/R'BURN/MINDEN/TEXLA 23 23 23 23 23 23 23 23 23 23 23 23

9 TOTAL 175 175 175 175 175 175 175 73 73 73 73 73

10 Load Responsibility ( 7 + 8 - 9 ) 4,791 4,669 4,825 4,953 4,994 5,059 5,112 4,719 4,780 4,841 4,912 4,978

RESERVES 08 ACT 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

11 Reserve Capacity, MW ( 6 - 10 ) 685 895 666 675 681 1,111 1,054 1,052 999 938 867 958

12 % Reserve Margin (( 11/10 ) * 100 ) 14.3 19.2 13.8 13.6 13.6 22.0 20.6 22.3 20.9 19.4 17.6 19.2

13 % Capacity Margin ( 11/(6) * 100 ) 12.5 16.1 12.1 12.0 12.0 18.0 17.1 18.2 17.3 16.2 15.0 16.1

14 Reserve Above 12% Capacity Margin, MW 32 258 8 0 0 422 357 409 347 278 197 279

 SOUTHWESTERN ELECTRIC POWER COMPANY

 CAPABILITY, DEMAND AND RESERVES FORECAST 

2008 Actual - 2019

(MW) 

2009 IRP
AEP-SPP 2009 Integrated Resource Plan 

 139 

Appendix E, Figure 1 AEP Plan to Meet 10% of Renewable Energy Target by 2020 

AEP System - East Zone

Renewables to Achieve a 7% System Target by 2013 and 10% by 2020 (a)

Together with Known or Emerging State-Specific Mandates

2009 IRP

Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl

Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent

(MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales

2009 0 75 0 0.8% 0 0 0 0.0% 0 0 0 0.0% 0 0 0 0.0% 0 0 0 0.0% 0 0 0 0.0% - 75 - 0.2%2010 0 276 0 2.5% 1 50 0 0.8% 2 50 0 0.6% 10 100 0 0.7% 0 150 0 2.5% 0 0 0 0.0% 10 525 - 1.5%2011 0 551 0 4.5% 2 150 0 2.0% 4 175 10 2.0% 13 325 10 2.0% 0 300 0 4.7% 0 50 0 1.9% 13 1,226 10 3.2%2012 0 751 8 6.2% 6 276 57 5.1% 9 400 45 4.9% 15 675 101 5.0% 0 400 0 6.2% 0 100 0 3.8% 15 1,926 109 5.5%2013 (b) 0 851 8 6.9% 11 426 57 7.0% 17 550 45 6.4% 28 975 101 6.7% 0 500 107 9.3% 0 100 19 4.6% 28 2,426 235 7.0%

2014 0 851 8 6.9% 17 426 57 7.0% 25 550 45 6.4% 42 975 101 6.7% 0 500 107 9.2% 0 100 19 4.6% 42 2,426 235 7.0%2015 0 851 8 6.9% 22 426 57 7.0% 34 550 102 7.6% 56 975 159 7.4% 0 500 107 9.2% 0 100 112 12.1% 56 2,426 385 7.8%2016 0 851 8 6.8% 28 466 57 7.5% 42 550 102 7.6% 70 1,015 159 7.6% 0 560 107 10.0% 0 100 112 12.0% 70 2,526 385 8.0%2017 0 851 8 7.0% 33 466 57 7.7% 50 550 102 7.7% 83 1,015 159 7.5% 0 560 107 10.4% 0 100 112 11.9% 83 2,526 385 8.0%2018 0 851 8 6.7% 41 466 57 7.4% 59 550 229 10.3% 100 1,015 286 9.0% 0 560 107 9.8% 0 100 112 11.8% 100 2,526 512 8.6%2019 0 851 50 7.4% 49 466 57 7.4% 69 550 315 12.0% 117 1,015 372 10.0% 0 560 107 9.8% 0 100 112 11.7% 117 2,526 641 9.2%2020 0 851 50 7.3% 56 666 57 9.8% 78 550 315 12.0% 133 1,215 372 11.0% 0 560 107 9.7% 0 100 112 11.7% 133 2,726 641 9.7%2021 0 851 50 7.3% 77 666 57 9.8% 91 550 442 14.6% 168 1,215 499 12.5% 0 710 107 11.7% 0 100 112 11.6% 168 2,876 768 10.6%2022 0 851 50 7.2% 90 766 57 11.0% 130 550 442 14.7% 220 1,315 499 13.1% 0 710 107 11.7% 0 100 112 11.5% 220 2,976 768 10.9%2023 0 851 50 7.1% 90 866 57 12.1% 130 550 442 14.7% 220 1,415 499 13.5% 0 710 215 14.8% 0 100 131 12.9% 220 3,076 896 11.6%2024 0 851 50 7.1% 115 866 57 12.1% 156 550 442 14.7% 271 1,415 499 13.5% 0 910 215 17.4% 0 100 131 12.8% 271 3,276 896 12.1%2025 0 951 50 7.7% 115 866 57 12.0% 156 550 442 14.6% 271 1,415 499 13.4% 0 910 215 17.2% 0 100 131 12.7% 271 3,376 896 12.2%2026 35 951 50 7.8% 115 866 57 11.9% 156 550 442 14.5% 271 1,415 499 13.3% 0 1,010 215 18.4% 0 100 131 12.6% 306 3,476 896 12.4%2027 35 1051 50 8.4% 115 866 57 11.7% 156 550 442 14.5% 271 1,415 499 13.2% 0 1,010 324 21.3% 0 100 150 13.9% 306 3,576 1,023 13.1%2028 69 1151 50 9.1% 115 866 57 11.7% 156 550 442 14.4% 271 1,415 499 13.2% 0 1,110 324 22.5% 0 100 150 13.8% 340 3,776 1,023 13.5%2029 69 1151 50 9.0% 115 866 57 11.6% 156 550 442 14.4% 271 1,415 499 13.1% 0 1,110 324 22.2% 0 100 150 13.7% 340 3,776 1,023 13.4%2030 112 1151 50 9.1% 115 866 57 11.5% 156 550 442 14.3% 271 1,415 499 13.0% 0 1,110 324 22.0% 0 100 150 13.6% 383 3,776 1,023 13.3%

AEP SYSTEM

Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl Solar Wind

Biomass

Rnwbl

Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent

(MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales

2009 0 393 0 9.4% 0 31 0 0.6% 0 424 0 5.0% - 499 - 1.3%2010 0 393 0 9.0% 0 111 0 2.3% 0 503 0 5.6% 10 1,029 - 2.5%2011 0 591 0 13.3% 0 211 0 4.3% 0 801 0 8.6% 13 2,027 10 4.5%2012 0 591 0 12.8% 0 311 0 6.3% 0 901 0 9.5% 15 2,827 109 6.4%

2013 (b) 0 591 0 12.7% 0 461 0 9.3% 0 1,051 0 10.9% 29 3,477 235 8.0%

2014 0 591 0 12.6% 0 461 0 9.2% 0 1,051 0 10.9% 42 3,477 235 8.0%2015 0 658 0 14.0% 0 494 0 9.8% 0 1,151 0 11.8% 56 3,577 385 8.8%2016 0 658 0 13.9% 0 594 0 11.6% 0 1,251 0 12.7% 70 3,777 385 9.1%2017 0 858 0 18.0% 0 594 9 11.7% 0 1,451 9 14.7% 83 3,977 394 9.6%2018 0 858 0 17.9% 0 594 9 11.6% 0 1,451 9 14.6% 100 3,977 521 10.1%2019 0 858 0 17.8% 0 594 9 11.4% 0 1,451 9 14.5% 118 3,977 650 10.5%2020 0 1,058 0 21.8% 0 594 9 11.3% 0 1,651 9 16.3% 133 4,377 650 11.3%2021 0 1,058 0 21.6% 0 694 9 12.9% 0 1,751 9 17.0% 168 4,627 777 12.2%2022 0 1,058 0 21.4% 0 794 9 14.6% 0 1,851 9 17.9% 220 4,827 777 12.6%2023 0 1,158 0 23.3% 0 794 9 14.4% 0 1,951 9 18.6% 220 5,027 904 13.3%2024 0 1,158 0 23.1% 0 894 9 16.0% 0 2,051 9 19.4% 271 5,327 904 13.9%2025 0 1,158 0 22.9% 0 994 9 17.4% 0 2,151 9 20.0% 271 5,527 904 14.1%2026 17 1,258 0 24.8% 17 994 9 17.3% 35 2,251 9 20.8% 340 5,727 904 14.5%2027 17 1,258 0 24.6% 17 1,094 9 18.8% 35 2,351 9 21.5% 340 5,927 1,032 15.2%2028 35 1,258 0 24.5% 35 1,094 9 18.7% 69 2,351 9 21.4% 409 6,127 1,032 15.5%2029 35 1,358 0 26.2% 35 1,194 9 20.0% 69 2,551 9 22.8% 409 6,327 1,032 15.7%2030 56 1,358 0 26.0% 56 1,394 9 23.1% 112 2,751 9 24.4% 496 6,527 1,032 16.1%

 (a) Data EXCLUDES: 

 o AEP-Texas Central Co. & AEP-Texas Northern Co... as current and potential future state/federal RPS would be applicable to LSEs only. 

 o Conventional (run-of-river) hydro energy as a renewable source as it has been excluded from certain state and proposed federal RPS criteria...  Should hydro be ultimately included, it would contribute roughly 1% to the AEP System target by 2020. 

 (b) 2012/2013 represent the initial years for Federal RPS/RES mandates as currently proposed by several draft bills before Congress. Further, 2013 

 would represent the initial year after the likely expiration of Production Tax Credits (PTC) for, particularly, wind resources. The notion being that

 establishment of a Federal renewables standard would likely eliminate further extension of such PTC opportunities.

AEP-East

PSO SWEPCO AEP-SPP

AEP Sytem - SPP Zone

Potential Renewables Profile to Achieve a 7% System Target by 2013, 10% by 2020, and 15% by 2030 (a)

...as well as Known or Emerging State-Specific Mandates

2009 IRP

OPCo AEP-Ohio I&M KPCo APCo CSP
AEP-SPP 2009 Integrated Resource Plan 

 140 

Appendix F: DSM By Operating Company 

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

APCO Va 0 45 90 113 140 168 195 195 195 195

APCO WV 0 45 90 113 140 168 195 195 195 195

KngsP 0 9 16 22 27 33 38 38 38 38

I&M - I 3 50 97 125 152 179 206 206 206 206

I&M - M 2 5 9 25 31 36 42 42 42 42

KPCo 1 19 39 51 63 76 88 88 88 88

OPCo 30 81 147 186 225 264 303 303 303 303

CSP 25 68 130 160 191 222 252 252 252 252

WP 0 9 16 22 27 33 38 38 38 38

AEP-East Zone 61 330 635 816 997 1,177 1,357 1,357 1,357 1,357 

PSO 10 45 80 114 148 181 213 213 213 213 

SWEPCO 11 41 70 98 125 152 177 177 177 177 

AEP-SPP Zone 21 87 150 212 273 332 391 391 391 391 

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

APCO Va 98 199 233 266 299 332 332 332 332

APCO WV 98 199 233 266 299 332 332 332 332

KngsP 17 28 30 31 33 35 35 35 35

I&M - I 15 113 213 225 235 244 250 250 250 250

I&M - M 10 27 53 56 60 63 67 67 67 67

KPCo 1 38 77 88 98 109 119 119 119 119

OPCo 88 240 453 604 754 905 1055 1055 1055 1055

CSP 68 187 356 469 583 697 811 811 811 811

WP 17 28 30 31 33 35 35 35 35

AEP-East Zone 183 836 1,607 1,967 2,325 2,682 3,037 3,037 3,037 3,037 

PSO 40 128 214 297 378 457 534 534 534 534 

SWEPCO 38 112 184 252 317 379 440 440 440 440 

AEP-SPP Zone 78 240 397 549 695 836 974 974 974 974 

Demand (MW)

Energy (GWh)
 1 

 Appendix G, Arkansas Stakeholder Report 

AEP/Southwestern Electric Power Company 

Integrated Resource Plan 

Stakeholder Report 

Created During SWEPCO Hosted Stakeholder Meeting 

December 3-4, 2008 

Little Rock, Arkansas 
 2 

Table of Contents 

I. Executive Summary 3 

II. Stakeholder Authors 3 

III. Pros & Cons of Stakeholder Issues 4 

Working Group Prioritization of Issues

IV. Independent Power Producers 17 

V. Renewable Energy Group 18 

VI. Wholesale, Retail & Commercial Consumers Group 20 

VII. Other Invited Stakeholder Ad Hoc Comments 24 

VIII. Conclusion 26 
 3 

I. Executive Summary 

On December 3-4, 2008, AEP hosted an IRP Stakeholder Committee Meeting. The meeting was 

attended by Stakeholders and members of the Utility Commission, the Arkansas Energy Office 

and the Attorney General’s office. The first day of the meeting consisted of presentations by 

AEP on the objectives and goals of the Integrated Stakeholder Committee Meeting consisting of 

Resource Planning Guidelines, AEP Integrated Resource Planning Process, Transmission 

Overview, and Incorporating Renewable Energy into the AEP IRP Process. 

Prior to the beginning of the meeting, stakeholders were asked to complete worksheets 

addressing Key Issues to be addressed in the IRP process. We then broke into three randomly 

selected groups in which stakeholders developed pro’s and con’s of pre-submitted key issues. 

Then the Stakeholders were grouped based on segment representation. The three group 

segments were: Independent Power Producers (IPP), Renewable Energy, and the Wholesale, 

Retail and Municipal Users. Each group then prioritized the Key Issues based on their segment 

perspective. 

II. Stakeholder Authors 

The following were present during the two day AEP/Southwestern Electric Power Company IRP 

Stakeholder Meeting. 

Name Company E-mail

 

John Alhen Arkansas Science & Technology Authority john.alhen@arkansas.gov

Ken Baker Wal-Mart Ken.baker@wal-mart.com

Karen Bassett ADEQ bassett@adeq.state.ar.us

Chris Benson Arkansas Energy Office Cbenson@ArkansasEDC.com

Frank Costanza Tradewind Energy fcostanza@tradewindenergy.com

Clark Cotten Arkansas Public Service Commission clark_cotten@psc.state.ar.us

Kelly Crouch Domtar, Inc. kelley.crouch@domtar.com

Don Erbach Entegra Power Group don@paschallstrategic.com

David Fincher Hope Water and Light dfincher@hope-wl.com

Mike Hughes City of Bentonville mhughes@bentonvillear.com

Paul Kelso, P.E Fibrowatt paul.kelso@fibrowattusa.com

Forrest Kessinger AECC FKessinger@aecc.com

Andrew Lachowsky AECC ALachowsky@aecc.com

Shawn McMurray Attorney General shawn.mcmurray@arkansasag.gov

Mak Nagle Southwest Power Pool mnagle@spp.org

Wally Nixon Arkansas Public Service Commission Wnixon@psc.state.ar.us
 4 

David Ozment Wal-Mart James.Ozment@wal-mart.com

Kevin Smith Tenaska Power Services ksmith@tnsk.com

Sarah Tacker Attorney General sarah.tacker@arkansasag.gov

Scott Turley University of Arkansas lturley@uark.edu

Becky Turner Entegra Power Group rturner@entegrapower.com

III. Pros and Cons of Stakeholder Issues

The order that these issues are presented in does not indicate any prioritization by the 

stakeholders. 

Issue #1 DSM, Energy Efficiency, & Conservation 

The Issue:  Expand $ DSM programs and options 

 Energy efficiency programs should be ramped up 

 Role of conservation and demand side response 

Description of the 

Issue: 

 Current DSM programs and tariffs in general seem to discourage 

participation in DSM, Dist, Gen, and other load management 

tools 

 EE is the least cost energy resource available to a utility. 

However, goals are not being set and resources are inadequate to 

realize the returns on investment 

 Historical lack of serious conservation and demand response 

goals 

 Ownership of environmental attributes: customer, utility, both 

 Program flexibility, simplicity, customer opt-out, self direct 

options 

Why is this issue 

important? 

 Potential lower cost 

 Maximize portfolio of possible solutions 

 Needed for “balanced” IRP outcome 

Risks of failing to 

address: 

 May miss opportunities to meet load needs with alternative 

supply options 

 Reduced roles long term supply plans 

 Negative environmental impacts 

 Continued in efficient use of energy 

Possible Obstacles:  Concerns over administering complex tariffs 

 Reliability of load coverage and complexity of dispatch 

 Old Arkansas rules 

 Lack of “true commitment” to conservation and demand response 

Pros of Addressing 

this Issue: 

 May provide a lower cost of service – brings additional 

competition and intellectual capital to meet resources 

requirements 

 Can be the cheapest alternative - Must remove disincentive 
 5 

 Subcontract programs to experts 

Cons of 

Addressing this 

Issue: 

 Currently no profit incentive 

 Difficult to measure its value 

 Utility may not be experienced in implementing programs 

 Difficult to evaluate its effectiveness 

 Sustainability issues 

 Is it a results of what people are doing currently or should certain 

goals / targets be required 

Issue #2 Combined Heat & Power (CHP) & Distributed Gen 

Description of the 

Issue: 

CHP and some distributed generation is cost effective to implement 

given the right signals from the market and government. It has clear 

additional benefits for reduced CO2 emissions and increased 

efficiency and reliability for the customer 

Why is this issue 

important? 

See above 

Risks of failing to 

address: 

This is a missed opportunity to capture important efficiency and 

technology potential. 

Possible Obstacles: Regulatory policies are a disincentive and should be changed, but 

there is much a utility can do in the marketplace primarily in the 

industrial sector. 

Pros of Addressing 

this Issue: 

CHP can be an important resource in terms of additional capacity that 

could be dispatchable under certain circumstances as well as dramatic 

reductions in energy and demand requirements for the utility. 

Cons of 

Addressing this 

Issue: 

NA 

Issue #3 Options for renewable supply purchasing 

The Issue: Green Power Program (customer buying green power through utility) 

Description of the 

Issue: 

Currently there is a very limited quantity of renewable energy on 

system – and it is “blended” into the portfolio. 

Why is this issue 

important? 

Certain customers may choose to set internal environmental objectives 

related to GHG reduction. The LDC/utility needs to be a partner in 

achieving these objectives. 

Risks of failing to 

address: 

 Will not meet customer’s requirements. 

 Will not drive renewable market (RPS?) 

Possible Obstacles: Regulatory Issues, Operational Issues 

Pros of Addressing  There are no real external options as the energy must come across 
 6 

this Issue: the utility. 

 Allows customers to achieve internal objective of carbon neutral 

 Allow utility to directly assign renewable energy costs. 

Cons of 

Addressing this 

Issue: 

 May not meet need if renewable energy credits not included. 

 Administrative burden. 

Issue #4 Jointly procure larger base load with other utilities 

The Issue: Consideration of partnerships with surrounding utilities where 

economy of scale makes sense. 

Description of the 

Issue: 

Economy of scale can exist with new coal or nuclear plants. Coownership may allow for a larger plant and overall lower cost of 

energy 

Why is this issue 

important? 

Possible opportunity for lower cost. 

Risks of failing to 

address: 

Potential lost opportunity if not included. 

Possible Obstacles: Additional participants in a project makes decision making process 

more complex. Additional risks w/co-owners. Possibly additional 

time required to develop contracts. 

Pros of Addressing 

this Issue: 

 Potential lower cost. 

 Economy of scale 

 Cost savings 

 Cost sharing 

Cons of 

Addressing this 

Issue: 

 Anti-trust issue 

 Prices more complex 

 Regulatory issues 

 Address Transmission issues 

Issue #5 How will plan address the need for ensuring high 

level of reliability of supply to the customer 

Description of the 

Issue: 

Have experienced multiple power failures – wires breaking, capacitors 

blowing, etc. which is extremely costly to our facility in terms of 

equipment & downtime and lost production. 

Why is this issue 

important? 

Is a high cost issue for our facility; includes damage to equipment and 

lost production. 
 7 

Risks of failing to 

address: 

Continuing power failures 

Possible Obstacles: Power/transmission lines replacement could/would cause additional 

downtime for reliability improvement. However, on planned basis, 

costs would be mitigated. 

Pros of Addressing 

this Issue: 

Would be evidence that resolving reliability issues is a priority for 

SWEPCO. 

Cons of 

Addressing this 

Issue: 

Transmission issue – Not seen as an IRP Issue. 

Issue #6 Consider poultry litter power plant for power purchases 

Description of the 

Issue: 

Poultry litter is considered biomass, and therefore a renewable carbon 

neutral energy, and besides GHG credit benefits, it provides benefits 

to the poultry industry and the water system. 

Why is this issue 

important? 

The poultry industry is extremely large and important for Arkansas. 

Helping to sustain the industry will also maintain a large group of 

power purchases. Water quality issues have also been raised in both 

Arkansas and Oklahoma. 

Risks of failing to 

address: 

Governmental mandates may eventually dictate renewable energy, and 

waiting could negatively impact projects with potential increased 

costs. 

Possible Obstacles: Cost of renewable energy from poultry litter is higher than gas or coal 

power pricing. 

Pros of Addressing 

this Issue: 

This provides additional base load renewable energy to the SWEPCO 

system. 

Renewable. 

Carbon neutral 

Lowers TMDL (oxygen issue in waterways) 

Cons of 

Addressing this 

Issue: 

Cost. 

Transmission access for rural location. 

Issue #7 For year 2012 on slide #12, planned capacity is less 

than demand 

Description of the 

Issue: 

Is this a data error as slide #32 indicates enough capacity margin for 

year 2012? 

Why is this issue 

important? 

IRP not meeting demand for certain years. 
 8 

Risks of failing to 

address: 

Not meeting SPP criteria 

Possible Obstacles: None 

Pros of Addressing 

this Issue: 

Ensure that supply forecast meets demand in the final IRP. 

Cons of 

Addressing this 

Issue: 

Issue #8 Renewables 

The Issue: Renewable energy supply & customer access to supplies 

Integration of renewable/sustainable resources into SWEPCO 

generation resource mix 

Description of the 

Issue: 

Historical lack of renewable energy goals; goals too low. 

Customer owned renewable energy vs. utilities owned renewable 

energy. 

Ownership of environmental attributes. 

Renewable resources provide sustainable energy and further diversify 

traditional fossil fuel generation resources. Many renewable resources 

also have the benefit of eliminating greenhouse gas and other 

emissions (SO2, NOx, particulates) 

Properly sited wind generation is competitive with other forms of 

generation on a delivered to busbar basis (new plant to new plant 

comparison basis.) 

Why is this issue 

important? 

Need “balance” of supply alternatives 

Need to leverage with customers; not compete with customers. 

Bad outcome: renewable energy not being fully utilized. 

Renewable resources (e.g. wind, solar) eliminate fuel costs and 

provide a hedge re: generation that require fuel inputs and have the 

potential for cost increases over time. Historically, the societal 

impacts of emissions from conventional fossil fuel plants (e.g. health 

impacts) are not normally captured as a cost in the when decision are 

made to add capacity. These costs wile hard to quantify are real. 

Renewable energy helps obviate some portion of these emission 

related impacts. 
 9 

What are the risks 

of failing to 

address this issue 

in the IRP? 

Bad IRP outcome 

Negative environmental outcome 

Higher costs 

State of Arkansas suffers 

Additional dependence on expensive fossil fuel sources and continued 

environmental degradation. Costs of new generation sources will 

continue to rise for all types of generation. Planning for the 

introduction and transition to multiple resources today will ultimately 

result in fewer impacts to utility customers and the general public at a 

lower cost. 

Possible Obstacles 

to Addressing the 

issue and How to 

Overcome: 

Overcome “Renewable energy costs more” mentality 

Potential Existing Rules: 

 Net Metering Limitations 

 Interconnection Agreements 

 Ability of customers to use 3rd party 

 Purchased power Agreements 

Lack of financial Incentives 

Reluctance to utilize customer resources 

Risks to REC ownership 

Cost of renewable energy is often cited as an impediment. Integrating 

the most cost effective resources initially (e.g. wind) and phasing in 

promising but not yet low cost alternatives (e.g. solar) can be done 

over time. Mixing renewable from the most productive regions of the 

country could also provide the lowest cost approach, but it would also 

require investment in new high capacity transmission lines. 

Pros of Addressing 

this Issue 

A mix of generation assets/resources is important to hedge future 

costs/need for rate increases. Further, a reduction of emissions is 

important to promote a healthy environment particularly in the face of 

growth in energy consumption. Planning for additions of a variety of 

generation sources will allow for the introduction of next generation 

of power sources at the lowest possible cost. Renewables can provide 

economic development benefits and are usually distributed across the 

utility’s service territory. 

 End result should be good balance. 

 Energy security 

 Low fuel costs (wind, solar, hydro & geothermal) 

 Environmental attributes 

 Portfolio diversity 

 Health 

Cons of 

Addressing this 

Issue 

 Cost 

 Environmental (siting and transmission) 

 Transmission infrastructure (wind, solar, geo) 

 Intermittent supply 
 10 

Issue #9 Demand capacity through pumped hydro 

The Issues: Peak demand load (and Daily Peaking) of Pump Hydro 

Description of the 

Issue: 

Meet peak demand 

Why is this issue 

important? 

Allows use of lower cost/more-efficient base load units at night and 

off-peak to pump water. 

Displaces costs of peaking units (gas, etc.) 

What are the risks 

of failing to 

address this issue 

in the IRP? 

Higher cost of operating gas peaking units. 

Possible Obstacles 

to Addressing the 

issue and How to 

Overcome: 

FERC license – Study & File 

Environmental permits – Assessments 

Transmission Access – Study 

 Very effective peaking units (pump hydro) used by GRDA. 

 There was (may still be) a license to develop 500+/- MW 

pump hydro near Russellville, AR 

Pros of Addressing 

this Issue 

 Option for cost models. 

 Lower cost on peak power 

 Quick response/dispatch 

 Integrates well w/other renewables (wind) 

Cons of 

Addressing this 

Issue 

 Initial high capacity cost. 

 Environmental elements – physical, CO2, etc. 

Issue #10 Incentivize Utilities to consider PPA’s. 

The Issue: Utility owning assets (generation) vs. long term power supply 

controls. 

Description of the 

Issue: 

Utilities earn money via rate basing, traditional regulation only allows 

utility to pass through costs incurred through contracts, therefore no 

return element. 

Why is this issue 

important? 

Utilities need to be neutral and allowed to select cost effective 

solutions. 
 11 

What are the risks 

of failing to 

address this issue 

in the IRP? 

Non-utility solutions are ignored. 

Possible Obstacles 

to Addressing the 

issue and How to 

Overcome: 

Tradition. At the PSC/Legislators utility has no interest to push this 

concept due to lack of profit potential. 

Pros of Addressing 

this Issue 

 Broadens supply options and can lower cost. 

 Places PPA on equal footing w/self build from IOU’s 

stockholder perspective. 

 May reduce power rates. 

Cons of 

Addressing this 

Issue 

 May drive up power rates. 

Issue #11 Including External Costs (Env. Societal Costs) in 

Cost Model 

The Issue: Distinguish methodology for determining low cost – This traditional 

driver and historical methods will lead to same answers – fossil plants. 

Value all externalities of supply options – that includes environmental, 

health, economic, societal 

Description of the 

Issue: 

Conventional power vs. Renewables vs. DSM 

All “costs” including externalities must be incorporated in a more 

dynamic way and alter past low cost determination approaches. 

Traditional cost analysis is usually focused only on capey, O&M, Fuel 

– impacts of emissions are (admittedly) hard to quantify) but must be 

addressed. 

Why is this issue 

important? 

Until renewable technology is mainstream (i.e. production increase to 

lower cost of mfg, or technology is further improved – solar,) they 

will not be low cost. 

Need to address GHG, Hg other impacts from fossil vs. using nonpolluting renewable options. 
 12 

What are the risks 

of failing to 

address this issue 

in the IRP? 

Status quo on supply side – fossil fuel translates to no change 

environmentally, fuel dependency, etc. 

Improved environmental, health, long term economic benefits to the 

state & public. 

Possible Obstacles 

to Addressing the 

issue and How to 

Overcome: 

Cost of renewables may cost slightly more in the near term. 

Solution integrate renewables over reasonable period of time 5-10 

years. 

Hidden costs of externalities are easy to ignore because they are 

difficult to quantify in typical fashion used by engineers. 

Pros of Addressing 

this Issue 

 Indicates to regulators that utility needs latitude to adopt 

broader supply options. 

 Regulation needs to reward utilities for taking steps to 

incorporate new technology. 

 Improved environmental, health, long term economic benefits 

to the state & public. 

 Power rate considers all societal costs 

 Health benefits 

 Reduction in GHG 

 Reduced air emission pollutants 

 Broader supply options. 

Cons of 

Addressing this 

Issue 

 Very hard to quantify 

 Inclusion will show higher rates 

 Redistribution of wealth 

 Additional risk elements in model 

 National perspective Required / Not local 

 Do not connect rebate to environmental attribute waiver. 

Issue #12 Economic development benefits related to renewable 

project development inside SWEPCO/Arkansas 

Description of the 

Issue: 

Economic development benefits are rarely if ever considered in 

selecting location for power projects. 

Why is this issue 

important? 

A 100 MW NINO Project in Arkansas (vs. another state) will bring 

$10’s of million in local economic spending, tax payments, jobs, etc. 
 13 

What are the risks 

of failing to 

address this issue 

in the IRP? 

Energy consumed in Arkansas and produced in Arkansas may bring 

greatest overall economic benefit. 

Possible Obstacles 

to Addressing the 

issue and How to 

Overcome: 

Power cost for in state may be higher is viewed alone, but when local 

economic impacts are added it could be the better solution. 

Pros of Addressing 

this Issue 

 This issue should be part of the “lost” determination process 

used by utilities & APSC in approving new supply options 

 Increases positive economic benefits in-state. 

 Redistribution of wealth 

Cons of 

Addressing this 

Issue 

 An increase in power rates 

 Redistribution of wealth 

 No most efficient use of resources when viewed nationally 

Issue #13 Maintaining reasonable costs to customers 

Description of the 

Issue: 

Increasing costs of power are passed to total manufacturing cost of 

product. 

Why is this issue 

important? 

Higher manufacturing costs could end up putting facility operation in 

question. 

Risks of failing to 

address: 

The concern of prices increasing beyond reasonable. 

Possible Obstacles: Fuel sources and pricing fluctuations. 

Pros of Addressing 

this Issue: 

Keep business running. 

Low cost for industry. 

Low cost for customers. 

Cons of 

Addressing this 

Issue: 

How to define reasonable cost as a balance with renewables. 

Issue #14 Greenhouse Gas Mitigation Options 

Description of the 

Issue: 

GHG emissions are a concern for our facility (Domtar) as well 

because when we market our products, we have to consider impacts 

on the environment from the source of the power we buy. 

Why is this issue 

important? 

It supports the company’s sustainability goals. 
 14 

Risks of failing to 

address: 

Might not receive attention/focus that is required to have impact. 

Possible Obstacles: Cost of alternative fuels could compete with out fuel costs; could 

cause our costs for power increase. 

Pros of Addressing 

this Issue: 

Supports environmental goals 

NERC top concern 

Good for environment 

Cons of 

Addressing this 

Issue: 

Difficult to get a carbon footprint baseline. 

Cost. 

Issue #15 Long Term Pricing Constraints 

The Issue: If customer made decision to expand operations, increasing the 

demand for power, how will that be addressed by IRP to ensure costs 

remain effective? 

Description of the 

Issue: 

If increase in cost to purchase additional power is too great, would 

possibly halt expansion activities 

Why is this issue 

important? 

Increasing production at facility insures jobs are maintained because 

are low cost producers for company and improves economy in SW 

Arkansas 

Risks of failing to 

address: 

May not account for increase (potential) in demand 

Possible Obstacles: Is “potential” concern: not present “actual” concern 

Pros of Addressing 

this Issue: 

 Would offer guidance for company as work on business plan 

 Benefit customer by being able to forecast retail power cost 

 Promotes economic development 

 Adds jobs 

Cons of 

Addressing this 

Issue: 

 Cost of credit associated with fixed prices 

 Exposure to market margins 

 Long term hedges difficult 

Issue #16 CO2 Mitigation 

Description of the 

Issue: 

SWEPCO’s portfolio consists of significant amounts of coal/lignite 

based resources. Displacing coal/lignite resources with efficient 

natural gas resources is an effective CO2 mitigation strategy. 

Why is this issue 

important? 

Natural gas resources existing on the SPP/Entergy systems are under 

utilized. The resources emit significantly lower CO2 emissions per 

MWh that coal/lignite resources and can be a low cost alternative (as 

compared to wind resources) to meet future CO2 regulations 
 15 

(anticipated) 

Risks of failing to 

address: 

Higher costs to ratepayers. 

Possible Obstacles: Transmission congestion across the SPP/Entergy Seam. See previous 

sheet 1 for implementation strategy. 

Pros of Addressing 

this Issue: 

Low cost alternative to mitigate CO2 output for SWEPCO 

Use existing gas resource 

Reduces CO2

Could replace construction a coal plant 

Cons of 

Addressing this 

Issue: 

Transmission access 

Fuel price volatility 

Issue #17 Transmission Constraints 

The Issue:  Transmission congestion 

 Transmission constraints – Today all supply assets inside he 

constraint are required limiting other supply options 

 Transmission expansion in conjunction with purchase power 

alternatives to meet incremental capacity needs 

Description of the 

Issue: 

 Need for adequate transmission to meet AEP load and loads that 

rely on AEP for transmission 

 Lower cost supply options can’t be sourced due to deliverability / 

reliability 

 Significant unsubscribed generation existing on the Entergy 

system (built in the ~2000 timeframe) should be considered a 

viable alternative to self-build alternatives. Natural gas prices 

have stabilized and significant volumes of natural gas. Frame 

shale sources are being produced and should stabilize gas prices 

in the future. 

Why is this issue 

important? 

 Transmission affects reliability and cost 

 Lower cost options (eg: wind) exists within the SPP but can’t be 

delivered to SWEPCO. 

 Natural gas fired generation is clean, efficient alternative to meet 

base, intermediate and peaking needs of the utility. 

 Existing generation was built at a lower cost than new build 

alternatives and this economic benefit can be realized by the 

utility under purchase power arrangements. 

Risks of failing to 

address: 

 Limitations for supply options from siting constraints, cost, 

environmental, etc 

 Higher cost to ratepayers 

Possible Obstacles:  Planning done at SPP, difficulty with seams agreements 

 Issues with cost recovery 
 16 

 Near term cost to build transmission solutions vs. cost recovery 

 Transmission ownership conflicts. The ASPC has an open docket 

to address transmission congestion across Entergy / SPP seam. 

SWEPCO should consider addressing improving imports / 

exports from / to the Entergy system in this docketed proceeding 

Pros of Addressing 

this Issue: 

 Improved reliability and potential for lower cost 

 Highlights need for PSC / Legislators to adopt, pressure, and 

accelerate transmission solutions 

 Lower all end costs to rate payers 

Cons of 

Addressing this 

Issue: 

 Without addressing cost constraints, end result could be forgoing 

low cost energy outside of the constraint area 

 There seems to be no pressure to address transmission constraints. 

It seems very far out into the future. SPP, AEP, and SWEPCO 

seem to be making legitimate efforts but it is being bogged down 

by other parties 

 Cost recovery of transmission costs for IPP dis-incentivizes 

transmission solutions to new capacity needs. 

 IPP doesn’t have power of eminent domain 

 Issues with NERC 

Suggestions:  Participate in APSC Docket 08-136-U 

 Any IRP should consider transmission constraint-free options – if 

there were no constraints what options would be available 

 When considering new build options, consider transmission 

upgrades as well 

 AEP should buy EAI and then fix the seams issues 

 IRP should consider cost-sharing options re: transmission upgrade 

to make existing IPP a more viable option 

Solution

 Cost evaluation 

 Spirit of cooperation among various players 

Issue #18 Transparency of Modeling Assumptions 

Description of the 

Issue: 

The assumptions utilized in the evaluation process are the basis upon 

which the final resource selections will be made. 

Why is this issue 

important? 

Understanding these assumptions as a potential supplier allows the 

supplier to better structure a product to meet SWEPCO’s needs. 

Risks of failing to 

address: 

SWEPCO may not receive the best supply products to meet their 

needs in the most cost effective manner. 

Possible Obstacles: May provide ammunition for opponents. 

Pros of Addressing 

this Issue: 

Should result in meeting SWEPCO’s needs in a more cost effective 

manner. 
 17 

Confidence of stakeholders in process because it is very complicated 

Encourage participation of stakeholders 

Consider working with SPP on DR since IRP model is also used in 

RFP process. 

Transparency of modeling assumptions allows the market to more 

fairly compete with self build options 

Cons of 

Addressing this 

Issue: 

How do you value non-traditional resources in modeling (e.g. no 

emissions, etc.)? 

Is it quantifiable? How do you value/quantify diversity of fuel. 

IV. Prioritization of Issues by IPP Stakeholder Group

The above working group evaluated the consolidated 18 issues compiled by the general 

stakeholders group for evaluation and prioritization with respect to the specific concerns, 

operational issues, and priorities of this customer group of AEP / SWEPCO. 

Members of the Independent Power Producer (IPP) working group were: 

Don Erbach Entegra Power Group don@paschallstrategic.com

Kevin Smith Tenaska Power Services ksmith@tnsk.com

Becky Turner Entegra Power Group rturner@entegrapower.com

The approach for this group was as follows: 

1st – Created 3 buckets of priorities (A=highest, C=lowest) 

2nd – Created priorities within buckets 

A1 17 Access to market 

A2 18 Fairness of competition against self-build, lower cost 

A3 10 Fairness of competition against self-build 

A4 4 Lower cost 

A5 11 Fairness of competition between technologies 

A6 16 Lower cost, Environmental 

A7 2 Reliability, Environmental 

B1 8 Environmental, Reliability 

B2 14 Environment, lower cost 

B3 9 Reliability 

B4 3 Customer Service 

B5 6 Environmental 

C1 13 Cost, Customer Service 

C2 1 Environmental, Lower cost, Customer Service 
 18 

C3 15 Cost 

C4 12 Economic Development, Environmental 

C5 5 Reliability 

C6 7 N/A 
 19 

V. Prioritization of Issues by the Renewable 

Energy Stakeholder Group 

The above working group evaluated the consolidated 18 issues compiled by the general 

stakeholders group for evaluation and prioritization with respect to the specific concerns, 

operational issues, and priorities of this customer group of AEP / SWEPCO. Members of the 

Renewable Energy working group were: 

Frank Costanza Tradewind Energy fcostanza@tradewindenergy.com

Ken Baker Wal-Mart Ken.baker@wal-mart.com

Paul Kelso, P.E Fibrowatt paul.kelso@fibrowattusa.com

David Ozment Wal-Mart James.Ozment@wal-mart.com

SWEPCO’s existing generation capacity is dominated by a mix of fossil fuel generation 

resources, with approximately 90 percent of system energy production/ consumption derived 

from these company-owned generating resources. SWEPCO will need to add generation 

resources to meet future demand and energy needs, and these resources should include renewable 

energy in order to provide greater diversity and reliability, along with many environmental and 

societal benefits, including the use of “home grown” fuels for greater energy independence and 

security. 

Attaining reduced environmental impacts upon its service territory constituents and the broader 

regions surrounding the company’s service territories is strongly urged through a process that 

recognizes and quantifies the external costs associated with environmental degradation, health 

and other impacts, including future carbon regulation, to the highest extent possible when 

evaluating the addition of new generation. Reliance upon cost of service approaches that only 

consider low cost via employment of traditional Integrated Resource Plan, rate making and other 

embedded planning paradigms that do not incorporate costs to address broader and more 

complex environmental and externalities, will lead to continued reliance upon fossil fuel 

generation that may not be in the best long term interest of the broader constituents living within 

and adjacent to the utility’s service territories. 

SWEPCO stakeholders strongly urge utility management, state regulators, and elected officials 

which oversee SWEPCO’s operations to adopt policies, procedures and potentially legislation 

which will: 

1. Establish targets for incorporating and diversifying SWEPO’s current generation mix to 

include renewable/alternative energy resources, that: 

a. reduce environmental and external impacts 

b. provide some level of fuel hedging and related risk mitigation 

c. provide for and promote to the largest extent possible the addition of resources 

within SWEPCO’s service territory in Arkansas to promote further in- state 

economic development 
 20 

2. Promote and incorporate the addition of new electric transmission infrastructure, as the 

current high voltage transmission system constraints within the SPP, and Entergy RTO 

regions adjacent to SWEPCO, may limit SWEPCO’s ability to locate or purchase 

generation from facilities in otherwise cost effective locations 

3. Consider expansion of the classic definition of renewables to include demand side 

management resources. For example, the State of Pennsylvania treats demand response 

as a tier 2 renewable and allows part of a utility's alternative energy goal to be achieved 

through demand reduction. 

New resource additions should also encourage non-utility owned options which can demonstrate 

their ability to deliver reliable and competitively priced renewable energy when compared to 

other renewable resources that would otherwise be developed and owned by the utility company. 

Processes to add any new generation resources should be managed through transparent sourcing 

processes run by non-biased third parties. 

Increases in cost of electric service to customers is likely as the need to construct and / or 

purchase additional generation continues to grow in order to meet growing customer needs. 

Adding renewable energy to the mix will help to provide the desired energy security, diversity, 

and reliability, along with the many environmental and societal benefits to the people of 

Arkansas, Louisiana, Texas and the surrounding states. 

What follows is how the Renewable Energy Stakeholder subgroup prioritized the individual 

issues developed at the session. A, B, and C issues represent prioritization, but the individual 

items within the A, B, and C groups are not in any particular order. 

A Issues 3,6,8 Renewable Resources, Sustainability, Diversity, Cost, 

Environmental 

A Issues 13 Reasonable cost – Affordability to end users 

A Issues 11 Externalities considered – Environment / Societal benefits 

/ Recreation / Health 

A Issues 14, 16 Emissions – Environment / Cost / Health 

A Issues 1 DSM – Diversity / Cost / Emissions / Timing / 

Environmental 

B Issues 12 Economic Development Renewables 

B Issues 17 Transmission – Cost / Environment / Diversity 

B Issues 18 Transparency modeling – Cost 

B Issues 10 IOU vs. IPP ownership - Cost 

B Issues 4 Partnerships with other utilities – Cost / Environmental / 

Diversity / Timing 

C Issues 5 Reliability - Given 

C Issues 2 CHP 

C Issues 9 Pumped Hydro 

C Issues 15 Expansion – Cost Effectiveness 
 21 

VI. Prioritization of Issues by Wholesale / Retail / Municipal 

Stakeholder Group 

Discussion of Approach 

The above working group evaluated the consolidated 18 issues compiled by the general 

stakeholders group for evaluation and prioritization with respect to the specific concerns, 

operational issues, and priorities of this customer group of AEP / SWEPCO. Members of the 

Wholesale/Retail/Municipal (WRM) working group were: 

Kelly Crouch Domtar, Inc. kelley.crouch@domtar.com

David Fincher Hope Water and Light dfincher@hope-wl.com

Mike Hughes City of Bentonville mhughes@bentonvillear.com

Forrest Kessinger AECC FKessinger@aecc.com

Andrew Lachowsky AECC ALachowsky@aecc.com

Scott Turley University of Arkansas lturley@uark.edu

As the working group evaluated the 18 issues, some were combined as they a shared common 

basis, while one was deleted, as it was not an issue but a question about the presentation. After 

consolidation, this left 13 key issues for the working group to prioritize. The issues were 

discussed by the group and through a process of consensus prioritization; the sub-group arrived 

at an overall ranking of the issues. The overall ranking of the issues is presented at the end of this 

section. 

Discussion of the Ranking and Priorities 

RELIABILITY

Priority Ranking #1: “ensuring a high level of reliability of supply to the customer” (issue #5) 

The first priority of the Wholesale/Retail/Municipal (WRM) working group is the reliability of 

the supply and delivery systems, as this is fundamental to meeting the needs of the working 

group’s direct customers. While it is understood that “reliability” is implicit in every aspect of 

planning, the Retail group wanted to re-state the importance of reliability by making it their 

number one priority ranking. The consumer relies on electricity for life safety as well as modern 

conveniences, and outages are costly for commercial, retail and manufacturing. Baseload, 

intermediate, and peaking resources must remain adequate to reliably meet present and future 

demand for power, including reserves and contingency planning. 

COSTS; ECONOMIC DEVELOPMENT

Priority Ranking #2: “maintaining reasonable costs to customers” (issue #13) and “long term 

pricing constraints” (issue #15) 
 22 

Not surprisingly the second highest priority of the WRM group is the ability of the utility to 

provide adequate power supply at a reasonable market competitive cost. The group felt this was 

fundamental to sustained economic development. Consumers living on a fixed income suffer 

economic distress from rising power costs. Manufacturing facilities that are energy intensive 

may no longer be viable if power costs increase beyond certain economic thresholds. Economic 

development and job growth depend on long-term stability of power costs with minimal 

escalation. Demand-side management, greenhouse gas mitigation, and renewable energy are all 

issues advocated by the WRM group (see priority rankings 5, 6 & 7 respectively), but with a 

strong emphasis on reasonable low cost. 

PARTNERSHIPS

Priority Ranking #3: “jointly procure larger base load with other utilities” (issue #4). 

The working group recognized that certain future power supply issues can only be addressed 

through integrated partnerships between the various state agencies, suppliers, and regional 

transmission entities. Specific examples are redevelopment of nuclear generation capabilities and 

the expansion of regional and national transmission capacity. Nuclear, although costly to 

develop, may, in the long-term, address both the drive for low-cost reliable power and

sustainability initiatives. Nuclear power avoids greenhouse gases, and avoids the cost of 

mitigating greenhouse gases. Nuclear, although costly to develop, may, in the long-term, address 

both the drive for low-cost reliable power and sustainability initiatives. Nuclear power avoids 

greenhouse gases, and avoids the cost of mitigating greenhouse gases. Another area where 

partnership and cooperation can benefit the end user is through the economy of scale when 

looking at new generation capacity. Co-ownership may allow for a larger plant and overall lower 

cost of energy. Potential opportunities may be missed if joint development of large baseload 

plants is not explored with other utilities. 

TRANSMISSION

Priority Ranking #4: “transmission constraints” (issue #17) 

Although perhaps not a direct IRP issue, transmission constraints continue to plague our 

industry, to wit: 

 The “seams” issue needs to be addressed between Entergy and the SPP. The separation 

of Entergy from the SPP as a whole frustrates the ability to move power economically 

through the system. 

 Lack of adequate transmission frustrates the ability of IPP’s to sell into the market. 

Further, IPP’s are not granted the right to develop and extend transmission. 

 Additional national transmission infrastructure is needed to move renewable power from 

areas of renewable generation to the load centers. 

Mandates from FERC and the PSC are needed to address transmission constraints. 

Though these issues extend beyond the scope of the specific IRP for SEP/SWEPCO, they do 

affect the power supply options and choices available to the company for the IRP. 

Issues such as these are too costly, entail too much risk or exceed jurisdictional authority for any 

singular partner to overcome. In fact, it was the consensus of the group that resolution of these 

issues will likely require leadership at the federal level. Resolution of transmission issues was 

considered the top priority with respect to more global issues. 
 23 

DEMAND-SIDE MANAGEMENT

Priority Ranking #5: “DSM; Energy Efficiency; & Conservation” (issue #1) 

The fifth highest priority as ranked by the WRM sub-group concerned SWEPCO’s Demand Side 

Management (DSM) programs. As major end users of energy and power, the group felt that they 

could have a much larger impact on the IRP through a more broadly implemented and aggressive 

DSM program. Below are two examples of specific areas of recommendation though there are 

certainly others. 

 Expansion of traditional DSM programs using financial incentives to encourage 

conservation and demand reduction. 

 Encourage the use of tariffs, rate options, and other regulatory options to facilitate more 

private capital investment in DSM technologies. Instruments must be fixed over a long 

enough term to justify capital investment, and that send more timely and accurate price 

signals will encourage more aggressive large scale DSM investment. 

Energy efficiency may be the least cost energy resource available to a utility. Demand Side 

Management may offset the need to build additional expensive generation facilities. 

Conservation lowers cost and lowers greenhouse gas production. SWEPCO should continue the 

investment at the current level, and consider additional investment and additional rate incentives. 

The WRM stakeholder sub-group does recognize and appreciate SWEPCO’s recent DSM efforts 

and expects this to be a precursor of greater things to come. SWEPCO is encouraged to look to 

other of its operating units, the Arkansas PSC and the Arkansas Energy Office for best in class 

DSM programs. 

GREENHOUSE GAS MITIGATION & RENEWABLE ENERGY

Priority Ranking #6: “greenhouse gas mitigation” (issue #14) and “CO2 mitigation” (issue 

#16); “customer options for renewable supply purchasing” (issue #3); “poultry litter biomass 

power plant” (option #6); and “renewables (wind; solar)” (option #8) 

The final grouping of issues assigned a specific priority by the WRM sub-group concerned 

Green House Gas (GHG) issues and Renewable Energy technologies. The discussion centered 

around how these emerging group of issues will factor into the IRP from a long term 

environmental stewardship standpoint as well as the near term cost of service impact to the rate 

base. 

The WRM sub-group did not advocate unilateral GHG reduction actions on the part of SWEPCO 

in Arkansas, as this could likely have major cost of service and economic development 

implications. The WRM sub-group’s recommended approach for implementation of GHG 

controls or reduction targets was that these should come from the federal level so as to not 

disadvantage any one specific service territory, group of consumers, or State. 

At the stakeholder meeting, several retail customers expressed interest in greenhouse gas (GHG) 

mitigation, including: 

 Dotmar Mill; Ashdown, Arkansas 

 University of Arkansas, Fayetteville 

 Wal-Mart 
 24 

Options for limiting GHG may include generation options that have a lower carbon footprint, for 

example: 

 Displacing coal/lignite resources with natural gas. 

 Displacing coal/lignite/gas with nuclear power. 

SWEPCO should continue to pursue a “cap and trade” program, and should continue to explore 

cost effective means of CO2 sequestration, in the context of the above priorities. 

As different customers have different objectives as relates to approaching or achieving “carbon 

neutrality”, customers’ desire additional options for purchasing power from renewable energy 

sources. What the WRM sub-group would advocate is the implementation of special tariffs, 

green power purchasing rates, or other regulatory tools that will allow consumers to make green 

power purchasing choices. This will encourage development of renewable sources of energy 

supply without disadvantaging the broader rate base, while federal regulatory efforts concerning 

green house gas emissions are worked out. 

Renewable energy resources were viewed by the group as a positive addition to the IRP in terms 

of supply diversity and long term cost stability. SWEPCO should continue pursuing cost 

effective renewable wind and solar power. Although the cost of renewable power is currently 

high, increments of renewable energy allow for a reasonable blended cost approach. 

The remaining six issues were placed in rank order ( #9,10,2,18,12,11), but the consensus of the 

group was that they were less significant with respect to those listed above, and should be 

weighted accordingly by AEP/SWECPO as it prepares its Integrated Resource Plan. 

Ranking of the Issues 

Priority Issue & ID Number Criteria 

1 #5 Reliability Reliability, economic development 

2 #13, 15 Costs to Customers Economic development 

3 #4 Partnerships Costs-nuclear 

4 #17 Transmission Cost & reliability 

5 #1 Demand side mgmt Cost, environmental, energy efficiency 

6 #14,16 Green House Gas Issues Cost, environmental 

7 #3,6,8 Renewable Energy Diversity, environmental, cost 

8 #9 Pump Hydro Diversity, cost 

9 #10 Generation vs. supply contracts 

10 #2 Combined Heat & Power 

11 #18 Transparency of model 

12 #12 Economic development inside Arkansas/Renewables 

13 #11 Externalities 
 25 

VI. Comments from Other Invited Parties 

Several other constituent groups were invited to participate in the IRP Stakeholder process. 

However several members either were unable to attend the meeting or chose not to take an active 

role in the three representative working groups. This section is provided as a means for those 

stakeholders to provide input to the final IRP Stakeholder Report with respect to their issues and 

priorities, to make comments on the process, or otherwise provide input to the final report 

appropriate to their perspective. They are included as-received with only minimal formatting to 

fit the overall report format. 

Audubon Arkansas 

1423B South Main St. 

Little Rock, AR 72201 

December 23, 2008 

SWEPCO IRP Process 

Dear SWEPCO IRP Stakeholders: 

 Please find below comments from Audubon Arkansas relative to the ongoing Integrated 

Resource Planning process. While we regret being unable to attend the first IRP meeting, 

we hope that these comments can be taken into consideration. 

 The fundamental purpose of an IRP is to provide an “informational report” that can be 

used for “planning” by the Commission.5 

Among the objectives of an IRP is “comparable consideration of demand and 

supply resources.”6

 Such consideration includes “development of a range of outcomes that 

complement the long-term forecasts of electricity demand (MW) and energy consumption 

(kWh).7

 The range of demand response activities, such as efficiency, conservation, 

demand-side management, interruptible load, and price-responsive demand “should be 

identified” and should be “investigated” to determine costs, effectiveness, and other 

attributes such as future emission control or allowance costs to the extend they are 

monitizable.”8

 The APSC Guidelines contemplate development of “multiple” IRP’s, each 

of which meets reliability criteria. The multiple IRP’s demonstrate, among other things, 

 

5

 APSC Resource Planning Guidelines, § 1. 

6 Id., § 4.1. 

7 Id. § 4.2. 

8 Id. § 4.3. 
 26 

different ways to respond to potential different levels of load growth, first fuel cost 

forecasts, and other parameters.9

 

Because the fundamental purpose of the IRP is to provide information useful to the 

Commission, and because a probing analysis of efficiency and demand response scenarios 

is an essential objective, Audubon Arkansas suggests that more complete information about 

demand, energy consumption, and the potential for demand response and efficiency efforts 

to meet varying levels of potential demand should be included from the earliest stages of 

the public involvement process. 

 For instance, what is the sensitivity of overall demand and energy consumption in 

Arkansas and in the SWEPCO territory to economic downturn, federal efficiency and 

carbon legislation, and fuel cost? 

 Graphs in the initial SWEPCO handouts do not isolate or distinguish the impact of 

efficiency and demand response from the overall demand curve. We suggest that such 

impacts should be graphically represented, in combination with supply resources over the 

period studied, in such a way that their comparative impact can assessed by public 

stakeholders. 

 More importantly, what is the potential, if favorable cost recovery and incentives were 

available to SWEPCO, for future demand and energy consumption to be served through 

efficiency and demand response? Smart metering alone has been estimated at several 

percentage points of capacity in some jurisdictions. The overall potential for demand and 

energy consumption reductions should be explored under a reasonable range of carbon 

cost, fuel cost, and cost recovery scenarios. 

 As SWEPCO is aware, FERC and some state PSC’s are considering the use of efficiency 

and demand response to provide transmission benefits. What is the potential for such 

efforts to benefit Arkansas? 

 What would be the emissions benefits of these potential efficiency and demand response 

scenarios? 

The information needed to answer these questions would help to meet the objectives 

identified in the IRP guidelines. This information would allow stakeholders to understand 

how overall demand might be affected by market and regulatory signals, and what the 

potential is for SWEPCO to respond with programs that reduce or manage demand and 

energy consumption. 

Audubon Arkansas appreciates this opportunity to provide initial comments in the 

SWEPCO IRP process. 

Thank you. 

Sincerely, 

 

9 Id. § 4.4.
 27 

Ken Smith Eddy Moore 

Executive Director Audubon Arkansas 

Audubon Arkansas 

 VII. Conclusion

All stakeholders were allowed the opportunity to provide key issues both prior to and during the 

session. These issues became the basis for further discussion, analysis and prioritization, with 

the objective of communicating to AEP/SWEPCO the importance of these issues with respect to 

development of their Integrated Resource Plan. 

In order to come to conclusions that could be captured in a cohesive Stakeholder Report, the 

consensus decision of the group was to look at the issues from three broad interest perspectives. 

The stakeholders decided to divide into three groups to discuss and ultimately rank the issues as 

to their relevance and importance to that constituency group. The three groups were: 

- Retail / Wholesale / Municipal Customers 

- Renewable Interests 

- Independent Power Producers 

The consensus of the attendees at this first IRP Stakeholder’s Meeting was: 

 The experience was overall a positive one, and offered the opportunity to provide 

meaningful input with respect each constituent’s priorities and issues. 

 That it was educational, both from the information provided by AEP/SWEPCO, and with 

respect to the perspectives and priorities of the other representatives at the meeting. 

On behalf of the attendees at the IRP Stakeholders Meeting, we appreciate the efforts of 

AEP/SWEPCO, and of the Arkansas Public Service Commission for the opportunity to 

participate in the process. This concludes the report of the stakeholders. 

Respectfully Submitted, 

Lawrence Scott Turley, PE 

 Director, Utility Operations 

 The University of Arkansas 

 Acting Secretary for the Stakeholder Group