# 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 (IR P) is based upon the best available information at the time of preparation. However, changes that may impact this plan can, and do, occur w ithout 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, particul arly in light of the current economic conditions, access to capita l, the movement towards increasing use of renewable generation a nd end-use efficiency, as well as legislative proposals to control “greenhouse gases.”

The implementation action items as descri bed 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 aff iliated 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 confid ential 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.comAEP-SPP 2009 Integrated Resource PlanAEP-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 SWEPC O 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........................................................................................................ 3 5 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 Defici ent 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 gridSMART SM ............................................................................................................................67 9.2 Demand Response/Energy Effi ciency 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............................................................................ 77AEP-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 R esource Options/Characteristics ..................................... 84 11.5 PSO Plan Development ...................................................................................................... ..... 85 11.6 SWEPCO Plan Development .................................................................................................. 9 7 

### 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...................................................................................... 1 11 12.5 Conclusion From Risk Modeling........................................................................................... 11 4 

### 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 ........................................................................................................... 1 27 14.1 Current Commitments ....................................................................................................... .... 127AEP-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-Electr icity Emissions, by Fuel Type ................................................................ ...........7 Exhibit 2-2: CO 2 Price Forecast ................................................................................................................ .............8 Exhibit 2-3: Renewable Standards by State ...................................................................................... .....................9 Exhibit 2-4: CO 2 Capture and Seques tration Process...........................................................................................11 Exhibit 2-5: Powe r Price Layers................................................................................................ ...........................12 Exhibit 2-6: SPP On -Peak Price Index........................................................................................... ......................13 Exhibit 2-7: Natura l Gas Price Index ........................................................................................... ........................13 Exhibit 2-8: PRB Co al Price Index .............................................................................................. ........................14 Exhibit 2-9: SO 2 Emission Price Index .......................................................................................................... ......17 Exhibit 2-10: CO 2 Emission Pr ice Index.......................................................................................................... ....17 Exhibit 2-11: 2H08 vs. 1H09 Commod ities Comparison............................................................................. ........20 Exhibit 3-1: Renewable En ergy Plan Th rough 2030................................................................................ ............22 Exhibit 4-1: Existing PSO and SWEPCO Genera ting Resources ...................................................................... ..25 Exhibit 4-2: PSO and SWEPCO Cap acity Change Af ter June 2009.................................................................... 26 Exhibit 5-1: Load and Demand Fo recast Process—Se quential Steps ................................................................. .35 Exhibit 5-2: AEP-SPP Peak De mand and Energy Projection......................................................................... ......37 Exhibit 5-3: AEP-SPP Current DR /EE Programs full- year impacts .................................................................. ..40 Exhibit 6-1: Capacity vs. SP P Minimum Requi red Rese rves........................................................................ .......41 Exhibit 6-2: Summary of Cap acity Deficien cy Position ........................................................................... ...........42 Exhibit 6-3: AEP-SPP, Hist orical Capac ity Pos ition ............................................................................. ..............43 Exhibit 8-1: Projected SPP Capacity Margin .................................................................................... ..................47 Exhibit 8-2: Recent Mercha nt 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 Biom ass Fac ility.................................................................... ........58 Exhibit 8-6: Biomass Resour ces in the Un ited St ates............................................................................ ...............59 Exhibit 8-7: Renewable Sources Included in AEP-SPP and East 2009 IRP ........................................................60 Exhibit 8-8: Typical DR/EE Meas ure Conservation Load Factor.................................................................... ....65 Exhibit 9-1: Impact of Legisl ation on Energy Consumption....................................................................... .........67 Exhibit 9-2: Achievable Versus Technical Potentia l (Illust rative) .............................................................. .........68 Exhibit 9-3: AEP-SPP Zone Cost Ef fectiveness of Re lative Programs.............................................................. ..70 Exhibit 9-4: AEP-SPP Zo ne DR/EE Pr oxy Blocks ................................................................................... ...........71 Exhibit 9-5: AEP-SPP Zone DR/EE Modeling Constraints ........................................................................... ......72 Exhibit 9-6: AEP-SPP Zone DR/EE Blocks Se lected in Resource Mo deling (AEP-SPP)...................................73 Exhibit 9-7: AEP-SPP Intern al EE Target versus IRP ............................................................................. ............74 Exhibit 9-8: AEP-SPP Zone DR/EE Assump tion Summary............................................................................. ...75 Exhibit 10-1: Long-term Forecast Pro cess Flow.................................................................................. ................78 Exhibit 10-2: Input Scen arios and Se nsitivitie s................................................................................ ....................79 Exhibit 11-1: AEP Spon sored DSM Programs....................................................................................... ..............85 Exhibit 11-2: Comparison of PS O Optimal and Su boptimal Plans................................................................... ...86 Exhibit 11-3: PSO Optimal Plan Comparison for Power and CO 2 Price Scenarios .............................................87 Exhibit 11-4: PSO Full Study Pe riod Revenue Requirem ents ....................................................................... ......88 Exhibit 11-5: PSO Full Study Peri od Cost over Optimal Plan..................................................................... ........88 Exhibit 11-6: PSO Pl an 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 Co mparison ..................................................................................... ...............93 Exhibit 11-9: PSO Reserve Margin............................................................................................... .......................94 Exhibit 11-10: PSO Hybrid Plan ................................................................................................. .........................95AEP-SPP 2009 Integrated Resource Plan

Exhibit 11-11: Comparison of SWEP CO Optimal and Su boptimal Plans ...........................................................98 Exhibit 11-12: SWEPCO Optimal Plan Comparison for Power and CO 2 Price Scenarios ..................................99 Exhibit 11-13: SWEPCO Full Stud y Period Revenue Requirements.................................................................10 0 Exhibit 11-14: SWEPCO Full Study Period Cost over Optimal Plan ................................................................1 00 Exhibit 11-15: SWEPCO Plan Comparisons......................................................................................... .............101 Exhibit 11-15: SWEPCO Pl an Comparisons (Cont’d) ................................................................................ .......102 Exhibit 11-16: SWEP CO Hybrid Plan .............................................................................................. .................103 Exhibit 11-17: SWEPCO Lo ad Forecast Comparisons ................................................................................ ......104 Exhibit 11-18 SWEPCO Reserve Margin With and Without Turk an d Stall Pl ants ..........................................105 Exhibit 12-1A: Key Risk Factors–Weig hted Means for 2009 -2035 (PSO)........................................................107 Exhibit 12-1B: Key Risk Factors–Weight ed Means for 2009-2035 (SWEPCO) ...............................................108 Exhibit 12-2A: Cumulative Proba bility Distribution of AEP-SPP Re venue Requirement (PSO)......................109 Exhibit 12-2B: Cumulative Probab ility Distribution of AEP-SPP Reve nue Requirement (SWEPCO).............109 Exhibit 12-3A: Probability Di stribution of AEP-SPP Revenu e Requirement (PSO) .........................................110 Exhibit 12-3B: Probability Di stribution of AEP-SPP Revenu e Requirement (SWEPCO).................................110 Exhibit 12-4: Basis of Ca pital Cost Di stributions .............................................................................. ................111 Exhibit 12-5A: Capital Cost Risk -Adjusted CPW 2009-2035 Revenue Requi rement ($ Millions) (PSO) ....... 111 Exhibit 12-5B: Capital Cost Risk-Adjusted CPW 2009-2035 Revenue Requirement ($ Millions) (SWEPCO)111 Exhibit 12-6A: Distribution Func tion for All Port folios (PSO) .................................................................. .......112 Exhibit 12-6B: Distribution Func tion for All Port folios (SWEPCO)............................................................... ..113 Exhibit 12-7A: Distribution F unction for All Portfolios at > 95% Probability (PSO) .......................................113 Exhibit 12-7B: Distribution F unction for All Portfolios at > 95% Probability (SWEPCO)...............................114 Exhibit 13-1: AEP-SPP Generation Capacity...................................................................................... ...............116 Exhibit 13-2: AEP-SPP Cu rrent Capac ity Mix ..................................................................................... .............117 Exhibit 13-3: AEP-SPP 2019 Capac ity Mix........................................................................................ ...............117 Exhibit 13-4: 2008 AEP-S PP 2030 Cap acity Mix................................................................................... ...........118 Exhibit 13-5: Change in Energy Mix With Hy brid Plan - Current vs. 2019 and 2030.......................................119 Exhibit 13-6: 2009 AEP-SPP IRP ................................................................................................. .....................121 Exhibit 13-7: CO 2 Emission Profile .............................................................................................................. .....122 Exhibit 13-8: CO 2 Emission Profile With Caps..................................................................................................12 3 Exhibit 13-9: CO 2 Emission Profile vs. Estimated Waxman-Markey Allocation ..............................................124AEP-SPP 2009 Integrated Resource Plan



### Appendices

Appendix A, Figure 1 Existing Ge neration Capacity, AEP-SPP Zone ..............................................................13 1 Appendix B, Figure 1 Economically Sc reened Renewable Alternatives ...........................................................132 Appendix C, Figure 1 Key Suppl y Side Resource Assumptions...................................................................... ..133 Appendix C, Figure 2 Ener gy Storage Screening.................................................................................. .............134 Appendix D, Figure 1 AEP-SPP Capac ity, Demand, Reserv e Forecast.............................................................135 Appendix D, Figure 2 AEP-SPP Capacity, Demand, Reserve Forecast (High Demand Scenario)....................136 Appendix D, Figure 3 PSO Capac ity, Demand, Rese rve Forecast ................................................................... .137 Appendix D, Figure 4 SWEPCO Capac ity, Demand, Reserv e 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........................................................................................ ................141AEP-SPP 2009 Integrated Resource Plan



## Acknowledgements

The Resource Planning group appreciates the s upport 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 opera ting 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 e fficiency requirements – that it is mandated to meet. Planning for future resource requirement s 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 Integr ated 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% pe r year, or roughly 140 MW annually. This growth can be considered as occurring in two phases. Th e 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 Tu rk for SWEPCO, Exelon-Green Country PPA for PSO) but excluding uncommitted planned capacity a dditions. 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 s till make resource additions to satisfy reserve requirements. With the supply side additions and de mand 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 m eet their margin require ments 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
YearMW- 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
YearMW- 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 PlanningAEP-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
YearMW- 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 ultr a-supercritical pulverized coal (USC-PC) plant and a 509 MW Stall Natural Gas Combined Cycl e 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 constr uction 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 begi nning 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 c onsistent with the AEP 2009 Corporate Sustainability Report with regard to the assumption of potential legisl ation related to greenhouse gas (GHG)/carbon dioxide (CO 2 ) emissions, renewable portfolio standards (RPS) , and energy efficiency. The driving planning assumptions include:

 CO 2 mitigation in the form of substantive CO 2 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) co sts, AEP initiatives to improve grid efficiency and install advanced metering, and a national gr oundswell 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 CO 2 legislation, the possible introduction of a Federal (or “en masse” state) RPS, helped justify the pla nned 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 econom ically-screened wind and biomass co-firing opportunities beyond the 10-year IRP period, th ese 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, fu el cells, solar panels, and “smart” grid enabling meters. These “distributed” technologies, while cu rrently expensive relative to traditional demand

1 Note: Firm “capacity” attributable to wind would be limited to roughl y 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 in to 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/interm ediate 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:
S 

### ummary 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%

C umu l

. (Capacity) Contribution 3% 24% 8% 2% 11% 42%

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

Planned Resource Reductions Planned Resource Reductions SWEPCO PSO

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 Forecas ting 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 ava ilable by 2011, but firm transmission delayed until 2013 (C) "New" DSM represents incremental activity projected based on estimated contribution & program cost (vs. avoided cost) param eters, from recent Market Potential Studies, and were generally limited to an EPRI Jan. '09 study i dentifying a "Realistically Achievable Potential". This 'New' (i ncrem) 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 loss es) 512

65% 83%

Source: AEP Resource PlanningAEP-SPP 2009 Integrated Resource Plan



### vi 

## Plan Impact on Carbon Mitigation ( “Prism” Analysis ) Global Climate Change and the prospect for comprehensive CO 2 legislation has had a direct bearing on the outcome of the 2009 AEP-SPP Plan. To gauge the respective CO 2 mitigation impacts incorporated into this resource planning, an assess ment 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 anticip ated 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)

CO 2 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 2034CO2 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 A llowance 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 CO 2 emission profile over time, it could still fall short of prospectiv e legislation that would attempt to further limitAEP-SPP 2009 Integrated Resource Plan



### vii CO 2 . 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 CO 2 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) CO 2 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 2034CO2 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-trad e mechanism could emerge from any set of carbon legislation, it is reasonable to assume that such CO 2 mitigation efforts, inclusive of offset acquisitions, may not provide for an adequate CO 2 position within that mechanism. Specifically, if the legislation provides for the allocation of an insufficient level of (free) CO 2 allowances to the utility, any such remaining CO 2 position “shortfall” must subsequently be borne by the utilities’ customers through additional, potentially more costly, CO 2 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) CO 2 Position vs. Est. W-M LDC Allo cations & 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 2034CO2 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% b y '20... 42% b y '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 mean ingful pathway to the attainment of potential Climate Change/CO 2 legislation, however, additional contributions–over-and-above the acquisition of CO 2 allowances—may be required in future pla nning cycles to protect AEP’s customers from significant cost exposures.



## Plan Impact on Capital Requirements This Plan includes new capacity additions, as we ll 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 sp ecific 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 th is 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 spe nd level reflected on the Summary Exhibit 7 is “incremental” in that it does not include “base”/bus iness-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) 362 306 321 110 175 281 306 302 177 634 2,974 25%

IRP (Response to Carbon / RPS Legislation)

- - - 44 147 381 349 548 848 623 2,941 24%

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

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

TOTAL INCREMENTAL "G" CAPEX 420 548 840 948 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) A ssuming 1,300 MW CCS (MT only ) by 2020

... (w/ 1,740 MW by 202 5 ... 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 res ources, increased DR/EE initiatives, completion of Stall and Turk plants, and the execution of the Ex elon PPA, will allow AEP-SPP to meet its resource requirements through 2018 at wh ich 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 ava ilable 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 towa rds 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 generati ng 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 e fficiency advancements all of which necessitate flexibility in any ongoing plan. The ability to invest in capital-inte nsive infrastructure is increasingly challenged in light of current economic conditi ons, 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 th e 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 tran smission 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 assumpti ons that are used to develop the plan such as planning objectives (Section 7), resource options (S ection 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 Pl an” 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 20 09-2019, with additional planning modeling and analyses conducted through the year 2030. The info rmation presented with this IRP (“Plan”) includes descriptions of assumptions, study parameters, methodol ogies, 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 th e 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-ter m 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 Co mpany’s current and anticipated environmental compliance, transmission planning, and othe r corporate planning initiatives such as gridSMART sm

. 1.2 Introduction to AEP AEP, with more than five million American cust omers 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 ge nerating stations in the United States, with a capacity of approximately 37,000 megawatts. AEP’s customer s 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 tw o 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 Southw estern 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 SO 2 , 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/CO 2 )... 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 AuroraFundamental Pricing ModelingCP&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 

## Q3 Q4

Document / Filing

Corporate (E & W) and OperatingCo./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, resp ectively. 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 essentia lly “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%, resp ectively, of AEP-SPP's total internal energy requirements of 42,868 GWh, including energy loss es. 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 th e 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 ultr a-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 SW EPCO 2006 Long-term Baseload Resource Request For Proposal (RFP) process. The 2008 PS O 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 IRPAEP-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 demons trated 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, respectivel y, still find these facilitie s 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 s how 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/fr om 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 W ith 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 PlanningAEP-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 mo st 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-approve d 1997 Restated and Amended CSW Operating Agreement for its western (former CSW) opera ting companies and the FERC-approved 1951 AEP Interconnection Agreement for its eastern operating co mpanies. 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 transf er capacity and energy between the AEP-SPP zone and under certain conditions the AEP-East zone. Si nce the inception of the SIA, AEP has continued to reserve annually, the transmission rights associat ed 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 app licable operating companies–PSO and SWEPCO–so as to leverage any opportunities such joint planni ng may offer as per the Operating Agreement. Specifically, Section 9.2 of that 1997 Restat ed and Amended SPP (CSW) Operating Agreement establishes that “...ownership share in each Joint Un it 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 notbe 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 fi rm transmission constraints between PSO and SWEPCO that will be discussed in this 2009 report, as well as specific regulatory (needs determination/cost recovery a nd 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



### 6AEP-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 exp ected 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 in to 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 virtua lly 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 natu rally, others are exclusively man-made. While Carbon Dioxide (CO 2) is the most prevalent and significant greenhouse gas in terms of its global warming potential, there are other major greenhouse gases including methane (CH 4 ), nitrous oxide (N 2 O) and chlorofluorocarbons (CFCs). Gases are typically quoted in terms of either CO 2 , carbon dioxide equivalents (CO 2 e) or carbon equivalents (Ce). CO 2 has an atomic weight of 44 while carbon has an atomic weight of 12. Thus, CO 2 equivalents are 3.67 times the mass of carbon equi valents, but the two m easures have the same relative purpose and can be used interchangeably if consistently applied. Anthropomorphic CO 2 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 CO 2 e) result from the conver sion 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 CO 2 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 RateTons 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 Ca p ture Units without Carbon Ca p ture

Natural Gas Coal

Source: AEP Resource PlanningAEP-SPP 2009 Integrated Resource Plan



### 8 2.2.1 Environmental Legislation The electric utility industry, as a major producer of CO 2 , will be significantly affected by any GHG legislation. During the 109th Congress (2005- 2006), 106 bills, resolutions, and amendments specifically addressing global climate change a nd 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-Warn er, 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 111 th 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 Representativ es 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 CO 2 caps over time.

2.2.2 Impact of Environmental Legislation on Industry Any binding legislation is likely to be “econo my-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 genera tor emissions are limited, similar to the EPA’s current programs that limit utility SO 2 and NO x emissions.

2.2.2.1 AEP’s Assumption on CO 2 Policy/Price For the 2009 IRP cycle, the impact of CO 2 /GHG legislation on AEP’s long-term planning is essentially modeled as a simple CO 2 price beginning in 2015, as shown in Exhibit 2-2, that would impact fossil unit dispatch cost.
Exhibit 2-2: CO2 Price Forecast

Emissions CO 2 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 2 027 2028 2 029 2030

CO2 2H08

Source: AEP Fundamental AnalysisAEP-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 amo unt 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 cu stomers 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 deliv er significant GHG reductions. For instance, Texas is expected to avoid 3.3 million tons of CO 2 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 stan dard (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 2020AEP-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 Clim ate Exchange (CCX), AEP committed to cumulatively reduce or offset 48 million metric tons of CO 2 emissions from 2003 to 2010. Through 2008, AEP reduced or offset 51 million metric tons of CO 2 — 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 u se of renewable power, reducing SF 6 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 fu el portfolio. This plan contains a minimal 10 percent renewable energy target by 2020. AEP al ready plans to go beyond its initial commitment. AEP has made significant progress in reducing a potent GHG — SF 6 — which is found in some electrical equipment. When AEP joined the Environmental Protection Agency’s (EPA) SF 6 Emission Reduction Partnership in 1999, our SF 6 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 fro m 1996 levels. This was done by employing a combination of technologies such as replacing SF 6 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 CO 2 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 pl ants make them more efficient than the national average for coal plants. Between 2001 and 2007, th ese improvements helped us to avoid burning 16.2 million tons of coal, preventing the release of 39 million tons of CO 2 . 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 legi slation, 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 furt her 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 an ticipated 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 technol ogy providers for carbonAEP-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 CO 2 at a lower cost than other technologies that coul d be retrofitted at pulverized coal power plants. A vendor-sponsored project demonstrating the t echnology was successfully completed on a 1.7 MW (electric) slipstream at Pleasant Prairie a Wiscons in plant in 2008. This projected operated around the clock for over 4,600 hours capturing 88 – 90 percent of CO 2 emissions, and achieved purity levels exceeding 99 percent. Exhibit 2-4: CO 2 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 vali dation in the second half of 2009. It is designed to capture approximately 100,000 metric tons of CO 2 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 CO 2 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 g as stream. The expectation is for the commercial scale technology to have a 90% capture rate of approximately 1.5 million tons of CO 2 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 co mbustion 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 CO 2 that is ready for storage. At commercial scale, the CO 2 likely would be stored in deep geologic formations.AEP-SPP 2009 Integrated Resource Plan



### 12 AEP’s vendor B&W completed a pilot demonstr ation and retrofit feasibility study in 2nd Quarter 2008. Unfortunately, this tech nology proved to be cost prohi bitive 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 in cluded in the Confidential Supplement.

The internal process utilized by AEP-SEA fo r 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 SO 2 , NO X , 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 rema in extremely volatile due to the uncertainty in the economy, environmental policy, and commodity mark ets. As such, the short term Reference price does not fully capture the most recent market signa ls – 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 th e forecast resides less in the ab ility to precisely predict the power price and more in the ability to accurately capture th e trends in the power market. Starting in the midterm, the Reference Case begins to deviate from th e 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 AnalysisAEP-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% co mpared 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 200 9, while still reflective of Hurrican e Ike-related supply loss, will decline through 2012 as domestic natural gas pr oduction reverses its traditional decline due to heretofore unconventional exploitation plays (see Exhibit 2-7 ). Beyond 2014, unconventional natural gas produc tion, buoyed by technology advancements, provide adequate supply to meet demand when given long-term price si gnals 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 dema nd will be the growth of gas consumption for electricity generation. Additionally, the Alaskan Pipelin e, 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 AnalysisAEP-SPP 2009 Integrated Resource Plan



### 14 2.3.2.2 CoalCoal is a unique commodity that comes with many different specifications. Coal is traded overthe-counter at relatively thin volumes. The major ity of coal transactions are done through contracts between sellers and buyers, which sometimes resu lts in significant differences between coal spot prices and contract prices. Because of the high pe rcentage of transportation cost relative to total delivered coal cost and the significant capital invest ment required for a boiler to switch from one type of coal to another, Btu and/or SO 2 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. Hi gh coal prices in intern ational 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 meta llurgical coal has reversed due to the global economic downturn. Demand for steel has been reduced dramatically, and the international metallurgical coal benchmark at Ne wcastle 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 tren ds. Capital costs have increased significantly from rising materials, equipment, and labor. However, co sts have declined recently due to the credit crisis and economic concerns. Demand h as 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 ga s price projections, the cost of a gas plant will be driven more on the physical s upply chain constraints of constructing the plant versus the variable cost of the plants as seen in th e 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 e nvironmental 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 additi onal 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 th e 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 negativ e 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 SO 2 , NO X, 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 th e Business-As-Usual Case (government policy isAEP-SPP 2009 Integrated Resource Plan



### 16 very unlikely to become less regulated) to an ex tremely 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 ar e 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 wh en a command-and-control policy could require all coal units to install either a mercury-specific c ontrol technology such as Activated Carbon Injection (ACI) or Flue Gas Desulphurization/Selective Catalytic Reduction (FGD/SCR) emissions control equipment. For development of market scen arios, the 2H08 forecast limits the FGD/SCR installations to projects currently under constr uction 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 al ternatives 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 Environmen tal Group has postulated a scenario in which SO 2 and NO x 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 NO x emissions require a $1,000/ton price signal to remain in compliance, while SO 2 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 replac ement 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 typica lly include an allowance bank to meet emission targets.AEP-SPP 2009 Integrated Resource Plan



### 17 Exhibit 2-9: SO 2 Emission Price Index

Emissions SO 2 Index 2H08 2009 $/ton = 1.0

0 5 10 15 20 25

2009 2 01

0 2 0 11 2012 2 01

3 2 0 14 2015 2 01

6 2 0 17 2018 2 01

9 2 0 20 2021 202 2 2 0 23 2024 202 5 2 02

6 2 0 27 202 8 2 02

9 2 0 30

SO2 2H08
Source: AEP Fundamental Analysis

2.3.5.2 CO 2 The forecasting of future CO 2 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 CO 2 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: CO 2 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 2 012 2013 2014 2015 2016 2017 2018 2 019 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; th e “Low Carbon Economy Act of 2007” introduced by Senators Bingaman and Sp ecter and the “Climate Security Act of 2008”AEP-SPP 2009 Integrated Resource Plan



### 18 introduced by Senators Lieberman and Warner. Th e Bingaman-Specter bill was widely supported by industry for its moderate emission reduction timelin e, while the Lieberman- Warner was praised by environmentalists for its more aggressive emission reduction time line. Thus, these bills represent relative “bookends” for likely climate policy outcomes.

*******************End of 2H 08 Fundamental Analysis ex cerpt***********************

2.4 Issues Summary The increasing number of variables and their un certainty 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 b een stable fuel prices and growth in demand over time. Highly volatile fuel prices, and uncerta inty surrounding the economy and environmental legislation require that the process used to dete rmine a resource plan is sufficiently flexible to incorporate more subjective criteria. The intro duction of a cap-and-trade system and high capital construction costs weigh unfavorably on solid-fuel op tions, 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 co mpany ahead of the game if one does come to pass. In this way, the company is trading fu ture uncertainty for a known cost. Lastly, adding diversity to the generating portfolio reduces the risk of the overall port folio. 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 r esource 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 CO 2 capture and sequestration technologies which, in the east where higher-quality bitumi nous coals are prevalent, could ultimately favor current Integrated Gasification Comb ined 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 CO 2 emissions.

 Potential for volatile natural gas pricing mark ed 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 affecti ng the economic viability of uncontrolled coal generation. Finally, the IRP process was complicated furth er 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. Ho wever, after comparing the long-term commodities forecasts used in this IRP (the 2H08 Forecast) to th e 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 AnalysisAEP-SPP 2009 Integrated Resource Plan



### 21 

## 3.0 Implications of Industr y Issues in this IRP Cycle

3.1 Demand Response/Energy Efficiency (DR/EE) The AEP System (East and West/SPP zones) h as 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 ma ndated levels of efficien cy and demand reduction. There also exists the possibility of federally mandate d 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 u ltimately 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 la rge-scale renewable tec hnologies (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 th eir 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 fu rther legislative clarity in the AEP states. In early 2007, AEP committed to the acquisiti on 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 SWEPC O 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 th e 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

A EP 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 applic able to LSEs only. o Conventional (run-of-river) hydro energy as a renewable source as it has been excluded from certain state and prop osed federal RPS criteria... Should hydro be ultimately included, it would contribute roughly 1% to the AEP System target by 20 20.

(b) 2012/2013 represent the initial years for F ederal RPS/RES mandates as currently propos ed by several draft bills before Congres s. Further, 2013 would represent the initial year after the likely expiration of Production Tax Credits (PTC) fo r, particularly, wind resources. The notion being that establishment of a Federal renewables standard would likely eliminate further ext ension 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. Ho wever, given the focus on the advancement and associated cost reduction of such technologies, it is likely to become both av ailable 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 legislati on that is passed and the degree to which there is financial support for CCS technology in such le gislation. 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 in fluence on the consideration of supply-side resources for inclusion in the IRP because of thei r potential significant effects on both capital and operational costs. The AEP System’s strategy fo r 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 SO 2 , NO

x , and mercury (Hg) emissions. Specifically, in 2005, the U.S. Environmen tal Protection Agency (USEPA) established new emission regulations for these pollutants as part of the CAIR (which the D.C. Circuit CourtAEP-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 CO 2 /GHG emissions, particulate matter (PM), and regional haze, as well as the previ ously mentioned potential enactment of additional state and/or Federal RPS will likewise influe nce 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 SO 2 and NO X . PSO will be equipping its units with NO X combustion technology to meet BART limits for NO X and is expected to install flue gas desulfurization technology (FGD) at the No rtheastern 3 & 4 coal units to meet BART limits for SO 2 and PM. The specific timing of these installati ons 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



### 24AEP-SPP 2009 Integrated Resource Plan



### 25 

## 4.0 Current Resources The initial step in the IRP process is the demonstr ation 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 efficien cy 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 reliab ility 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 w ith 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 fi ndings of previous studies, recommending no unit disposition planned for the IRP peri od. In general, the capacity value provided by the older units far outweigh the fixed costs associated with their c ontinued 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 provi de 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 utilitiesAEP-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 identi fies transmission reliability improvements to accommodate approved transmission service and a pproved 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 inte rconnection requests in separate studies. Going forward, the SPP RTO will be using an Integrated Trans mission Planning (ITP) process that is being developed. The limited capacity of interconnections between SPP and neighboring systems, as well as theelectrical 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 signi ficantly 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 th an originally designed, in order to meet SPP RTO requirements, which can stress the system. In add ition, factors such as outages, extreme weather, and power transfers also stresses the system. This h as resulted in a transmission system in the AEP-SPP zone that is constrained when ge neration 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 develo p the models AEP provides to SPP to develop and plan the system. SPP uses models provided by a ll 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 transmissi on 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 lo ad flow models, plus models which include power transfers biased in the various transfer directions. The 2008 STEP summarizes 2008 activities, includi ng expansion planning and long-term SPP Open Access Transmission Tariff studies (Tariff Stud ies) 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 suffi cient scope and configuration to maintain electric reliability, effectively perform its functions, a nd 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 sche dules. It also has opera tional authority for all transmission facilities under its control. The 10-y ear 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 associ ated 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 billi on 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 Tari ff with a FERC-filed Service Agreement; and generation interconnections with a FE RC-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 f unded 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 ha ve been demonstrated by model analysis to outweigh the costs (benefits greater than costs), t hus 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. Th e balanced portfolio includes five new 345 kV transmission lines, a 345 kV transformer, and a ne w 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 restructur ing the organization's regional planning processes to focus on the construction of a robust tran smission system, large enough in both scale and geography to provide flexibility to meet SPP's futu re needs. The new Integrated TransmissionAEP-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 assessment s 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 transmis sion 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 previous ly 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 respec tive PSO and SWEPCO expansion plans are adjusted to take advantage of any surplus of one company th at 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 ap pears that either company would ever have more than 200 MW of surplus capacity in any year th at could be transferred to the other company.

4.4.2.3 AEP-SPP Import CapabilityCurrently the transmission system cannot accommodate incremental firm imports to the AEPSPP area, based on preliminary AEP studies. Genera lly, 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 ne ighboring 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 iden tified 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 cost s 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, th e 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 Okla homa. 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 northwar d toward the Kansas City area; the other to Wichita, Kansas and eastward toward the Kansas C ity area. The 765 kV system would also extend eastward with two 765 kV lines, one to the sout heast to Entergy and one to the northeast to Associated Electric Cooperative, Inc. (AECI). Th e 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 perform ed 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 ye t 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. Th e SPP Board of Directors has yet to approve an overlay plan but is now looking at a new synerg istic 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 provid es guidance for future reinforcements to the transmission system in this area. The r ecommendations 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 ar ound the Fayetteville / Springdale area of northwestern Arkansas as well as 345 kV expansion east ward to SWPA’s Table Rock Station located in southwestern Missouri. From Table Rock Stati on, 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 ar ound the south side of th e Fayetteville / Springdale area as a complex priority project.

4.4.3 Recent AEP-SPP Bulk Transmission Improvements Over the past several years, th ere have been several major transmission enhancements initiated to reinforce the AEP-SPP transmission sy stem. 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 s upplied 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 Clarks ville-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 a nd 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 Cr eek-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 an d 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 a nd the new distribution station site near Caplis; correct contingency low voltage and th ermal overloads in Bossier City, Louisiana and the vicinity; and supply a second feed to B ean, 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 approximate ly 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. Integr ation of additional generation capacity within the AEP-SPP zone will likely require significant tran smission 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 transmissionAEP-SPP 2009 Integrated Resource Plan



### 32 enhancements, including EHV line and station c onstruction, 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 tr ansmission 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 gene ration 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 requi re significant enhancements in the EHV and sub-transmission system to address therma l, 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 east ern interface would likely require significant transmission enhancements, including EHV line a nd station construction, to address thermal and stability constraints should such genera tion additions adversely impact existing transactions along the interface. SPP has address ed 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 replac ements 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 approxi mately $500 million based on SPP ́s Extra-High Voltage Overlay Study, but final costs will de pend 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 fo r the necessary state and federal regulatory approvals for the project in the coming months. ETA also has formed a joint venture with West ar 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 Electri c 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 integr ating Generation and Tr ansmission planning is still developing. AEP continues to stand ready to e ngage in that process. At this time, though, PSO and SWEPCO can do very little to import capacity fro m 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



### 34AEP-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 pro cess involves three specific forecast model processes, as identified in Exhibit 5-1

. Exhibit 5-1: Load and Demand Fo recast 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 seasona l 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 Munici pal and Cooperative customer classes, as well as Statistically-Adjusted End-use (SAE) models fo r the modeling of Resi dential 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 StepsAEP-SPP 2009 Integrated Resource Plan



### 36 The long-term process starts with an economic fo recast 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 de mographic 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 projec tions and other inputs to produce a forecast of kilowatt-hour (kWh) sales. Other inputs include regional and national ec onomic and demographic conditions, energy prices, weather data, and customer-specific information. The AEP Economic Forecasting department uses St atistically 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 en ergy efficiency which has served to slightly lower the forecast of Residentia l 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 re lative 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 struct ural trends in electricity consumption that are important for longer-term planning. The long-te rm 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 reasona ble 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 (C AGR). 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 th e existing recession depresses peak demand in 2009 andAEP-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 2018Net Energy Requirement (GWh)

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000Peak 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, muni cipalities and cooperatives who currently have or have had a relationship w ith 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 appr oximately 15% of the zone’s (predominantly SWEPCO) overall load obligation.
2. Additionally, as described below, this for ecast 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 su ch as the Energy Independence and SecurityAEP-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 build ing efficiency standards and codes. The efficiency of lighting is set to increase by 20-30% by 2012-24. St andards 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 en ergy 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 Reinv estment 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 forecast ed 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 “o wn-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 industria l customers and, in PSO, the tariff-based “Value Choice” program which provides large users of electri city 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 househol ds 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 r esidential 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 Transforma tion Program. This program seeks to decrease the number of inefficient refrigerators and freezer s in general use, and by doing so, deliver long-term electric energy savi ngs and peak demand reduction.

 Home$avers low-income weatherization

 Load Management. The Load Management st andard 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 DistributionAEP-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 Transf ormation 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 pa rt 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 th rough 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 Transformati on Program. This targets commercial and industrial customers.

 Residential Solutions Market Transformation Program. This targets residential customers and provides incentives to homeowners for elig ible energy efficient improvements. A network of qualified energy efficiency servi ce providers will become partnering contractors and can both offer and accept incentives fo r 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 progr ams 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 th e Quick Start programs based on the results of the first year of implementation.

The peak demand and annual energy conservation th at 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 PlanningAEP-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” assess ment 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 peri od. 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 2019Load 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 2019Load 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 wholes ale 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 400Position, 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 400Position, 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 re lative 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 de cade, 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 cap acity. During this period AEP-SPP has relied on limited-term (market) capacity purchases to achie ve 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 2007MW

6,500 7,000 7,500 8,000 8,500 9,000 9,500Summer 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 PlanningAEP-SPP 2009 Integrated Resource Plan



### 44AEP-SPP 2009 Integrated Resource Plan



### 45 

## 7.0 Planning Objectives

In addition to the determination of a funda mental 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, ulti mately, from the perspective of affordability. In addition, given its unique impact on generation, th e 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 De ficient 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 Southwest ern (PSO) gas generation assets, the AEP-SPP zone is faced with a capacity deficiency through 20 11 that will need to be met through short-term capacity purchases. Power market opportunities in the form of lim ited-term bilateral capacity purchases from nonaffiliated sources and asset purchases at significant di scounts 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 w ill drive recommended regional long-term resource plans must maintain sufficient implementation flex ibility to consider such market or “purchase or buy” opportunities in the future.

7.2 Planning Horizon Recognizing the significant time period typical ly encompassed by the capacity planning process–both from the perspective of the ultimate co st exposure of these long-lived assets as well as considering the typical in-service lead-time requi rement–the evaluations were performed over a 22 year (2009-2030) detailed capacity r esource planning period. In orde r 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 c onsider 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 te rms of their ability to be funded corporately.

7.4 Other Operational Factors In addition to focusing on the creation of a capac ity resource plan that would be considered the lowest reasonable life-cycle costs fo r those customers for whom it is being established, such planning must likewise consider the practicality of the Pl an from the perspective of it addressing the on-going operational needs of the system. Given that, the Strategist modeling (to be discussed) currentlyAEP-SPP 2009 Integrated Resource Plan



### 46 considers in its costing-profile traditional co mmodities 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 a ffordability. 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 fo r such a major investment can be onerous to the utility. While earnings are typically not affect ed by investment program through the accounting of “Allowance for Funds Used During Construction” (A FUDC) (which allows utilities to defer to the balance sheet book recognition of project financing e xpenses that are associated with spending capital until the project is complete), cash flow will be ne gatively 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 & Budge ting and Corporate Finance, among others, continually assess plans generated through the IR P 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 P ool. These pressures may become more pronounced as the impact of potential CO 2 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 2017Capacity Margin, percent

Existing Capacity Committed Capacity Requirement Existing and Planned Capacity

Source: AEP Resource Planning
Due to various factors discussed here and elsewhe re in this document, firm capacity supply as well as the firm power mobility of existing me rchantable 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 re quirements 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 zo ne is to take advantage of market opportunities when they

are available and economic, either in the form oflimited-term bilateral capacity purchases from nonaffiliated sources or by way of available, disc ounted, merchant generation asset purchases. Such market opportunities could be utilized to hedge cap acity planning exposures should they emerge and create (energy) option value to the company. However, such opportun ities must be tempered with theAEP-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 pl anning 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 lik ely approach the fixed cost of new-build generation;

 the purchase of merchant generation assets re lative 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 a pproaches 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 2009Purchase Price, $/kW

McClain Energy CC Dogwood CC
Acadia CC Redbud CC

Spring Creek CT Range of current greenfield CT/CC costs

Source: AEP Resource PlanningAEP-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 para meters for a wide array of generation technology alternatives. Utilizing access to industry collabo ratives such as EPRI and Edison Electric Institute (EEI), AEP’s association with architects and engi neering 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 curre nt 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 Namepl ate) 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, especi ally 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 in to 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 elect ricity. Major by-products of combustion include SO 2 , NO X , CO 2 , and ash, as well as various forms of elements in the coal ash including Mercury (Hg). The steam cycle for the pulverized coal-fired un its – 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 temper atures. 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 operati ng 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 lo wer than those of a comparable supercritical unit by about 4 to 6 percent, but the overall effici ency of the supercritical design is higher than the subcritical design by approximately 3 percent. Du e 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 superc ritical unit. While the overall efficiency remainsAEP-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 pl anning exercises, IRP processes must be able to consider new technologies with uncertain co sts, such as IGCC. Th e assessment of such technologies is based on cost and performance estimates from commonly cited public sources, consortiums where AEP is actively engaged, vendo r relationship, as well as AEP’s own experience and expertise. IGCC technology has the potential to achieve the en vironmental benefits closer to those of a natural gas-fired plant, and therma l 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 a ny 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 ow ners, 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, lign ite, 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 inhe rent 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 te mperatures than pulverized coal-fired boilers. Theenergy 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 characteristi cs of fluidization to control the combustion process, minimize NO X formation, and capture SO 2 in-situ. Specifically, SO 2 is captured during the combustion process by limestone being fed into the be d 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 SO 2 . The chemical process does disadvantage CFB by contributing to relative Hg emission exposure.

8.2.2.4 Nuclear Although new reactor designs a nd ongoing improvements in safety systems make nuclear power a potentially viable option as a new-build alternativ e due to it being an emission-free power source,AEP-SPP 2009 Integrated Resource Plan



### 51 concerns about public acceptance/permitting, spent nucl ear fuel storage, lead-time, and capital costs continue to temper its consideration. Because of th e 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 e xpected 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 co mbustion 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, pr oduce 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 “pla tform,” 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 effici ency due to inability to maintain optimum air-tofuel pressure and turbine exhaust and steam te mperatures. 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 stea m 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 g as turbine is cutback. This approach would reduce efficiency at full load, but would likew ise greatly reduce efficiency degradation in lower-load ranges.

 Use of a multiple gas turbine coupled with a wast e 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, peak ing capacity such as combustion turbines can provide backup and some have the ability to provide em ergency (black-start) capability to the grid.AEP-SPP 2009 Integrated Resource Plan



### 52 8.2.4.1 Simple Cycle Combustion Turbines (NGCT) In “industrial” or “frame-type” combustion turb ine systems, air compressed by an axial compressor (front section) is mixed with fuel a nd burned in a combustion ch amber (middle section). The resulting hot gasses then expand and cool wh ile passing through a turbine (rear section). The rotating rear turbine not only runs the axial compr essor in the front section but also powers an electric generator. The exhaust from a combustion turbin e can range in temperature between 800 and 1,150 degrees Fahrenheit and contains substantial ther mal energy. A simple cycle combustion turbine system is one in which the exhaust from the gas turb ine 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 e ngines 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 da y. The cycling capabilities provide aeroderivatives the ability to backup intermittent renewables such as solar and wind. Aeroderivatives weigh less than their industria l counterparts allowing for skid or modular installations. Efficiency is also a considera tion in choosing an aeroderivative over an industrial turbine. Aeroderivatives in the below 50 MW range ar e 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 valle ys.” 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 wa ter 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



### 53 The investment requirements for pumped hydro st orage are significant. Further, site-selection and attainment of FERC licensing represent huge challenges. NaS Batteries are the leading technology under consideration for st orage-related utility planning. Appendix C, page 2 describes an energy stor age technology screening curve which could be used to indicate whether a particular te chnology warrants further investigation.

8.2.5.1 Sodium Sulfur Batteries (NaS): Storage technologies have begun to receive greate r consideration due partly to the improved battery-storage technologies; efficiencies now are a pproaching 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) th e market arbitrage, 2) line loss reduction, 3) deferral of selected distribution infrastructure th rough 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 fo r distributed storage. The use of distributed storage technology, which will involve the placemen t of small energy storage batteries throughout residential areas, will look similar to the sm all transformer boxes currently seen throughout neighborhoods. Each box should be able to power fo ur to six houses. AEP is testing this potential game-changing technology, which should also provi de 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 a nd reliability and follows closely on contracts Beacon has entered with independent system opera tors (ISO) in New England and New York to deploy its system, which stores kinetic energy on spi nning 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 deliv er, 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 pow er lines. However, given the existing limitations associated with the energy storag e capabilities, flywheel technology is not a practical alternative for AEP-SPP capacity planning.AEP-SPP 2009 Integrated Resource Plan



### 54 8.3 Renewable Alternatives Renewable generation alternatives represent tho se in which nontraditional (e.g., non-fossil) fuel sources that are either naturally occurring (wind, so lar, hydro or geothermal), or are sourced from a by-product or waste-product of another process (b iomass 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, th e 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 CO 2 benefits in a potentially carbon-constrained policy environment. AEP’s New Technology Development group evaluate d 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. Technologi es were evaluated on cost, location, feasibility, applicability to AEP’s service territo ry, 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 co st. Costs and benefits considered in the screening included project capital and O&M costs; avoi ded capacity and energy co sts; 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 technologi es 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 notAEP-SPP 2009 Integrated Resource Plan



### 55 necessarily the least expensive options screened, but rather those that provide suitable economics and practicality. A complete list of screened renewable tec hnologies and their incremental levelized life cycle costs is included in Appendix B

.

8.3.1 Wind Wind is currently the fastest growing form of el ectricity 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 applicati ons 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 spor adic 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 necessitati ng 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 StatesAEP-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 othe r 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 (CO 2 ). 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 atmos pheric 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 pul p 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 f eeding mechanisms. In a typical biomass co-firing application, 1.5% to 6% of the generating unit’s h eat input is provided by biomass, depending on the boiler’s method of firing coal. A more capital-inte nsive option is separate injection, which involves separate handling facilities and separate injection por ts 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 met hod 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 re latively less auxiliary power than a dedicated biomass plant, and thus generates more power from the same quantity of biomass. Some possible drawbacks associated with biom ass co-firing or separate injection include reduced plant efficiencies due to lower energy conten t 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 feedst ock 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 lo w 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 be nefits and holds some promise for the AEP generating fleet, but the high fuel/transportation co sts 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 ge neration. Because it simply substitutes “carbonneutral” fuel for fossil fuels, it does not elimin ate 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 CO 2 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 combinedAEP-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 o f Operating Company First A nnual A nnual Projected Size (Existing or Awarded No. of Full Energy Energ y 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 PlanningAEP-SPP 2009 Integrated Resource Plan



### 61 8.4 Carbon Capture
CO 2 capture is the separation of CO 2 from emissions sources or the atmosphere and the recovery of a concentrated stream of CO 2 that is suitable for sequestration or conversion. Efforts are focused on systems for capturing CO 2 from coal-fired power plants, a lthough the technologies developed will also be applicable to natural-g as-fired power plants, industrial CO 2 sources, and other applications. In PC plants, which are 99% of all coal-fired power plants in the United States, CO 2 is exhausted in the flue gas at atmospheric pressure at a concentrati on of 10-15% of volume. This is a challenging application for CO 2 capture because:

 The low pressure and dilute CO 2 concentration dictate a high volume of gas to be treated.

 Trace impurities in the flue gas tend to reduce the effectiveness of the CO 2 absorption
processes.

 Compressing captured CO 2 from atmospheric pressure to pi peline pressure (1,200 to 2,000 pounds per square inch) requir es a large parasitic load. Aqueous amines are the current state-of-the-art technology for CO 2 capture for PC power plants. The 2020 Department of Energy aspirational goal for advanced CO 2 capture systems is that CO 2 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 CO 2 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 CO 2 is relatively concentrated (50% of volume) a nd at higher pressure. These conditions offer the opportunity for lower-cost CO 2 capture. The state-of-the-art technology for CO 2 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 CO 2 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 CO 2 capture are more favorable in an IGCC plant.

8.4.1 Carbon Storage/Sequestration Storage is the placement of CO 2 into a repository in such a wa y that it will remain sequestered for hundreds of thousands of years. Geologic formations considered for CO 2 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 in jecting pressurized (“spongy” liquid) CO 2 into it. The CO 2 is buoyant and flows upward until it encounters the laye r of nonporous rock and becomes trapped. There are other mechanisms for CO 2 trapping as well. CO 2 molecules dissolve in brine and react with minerals to form solid carbonates, or be absorb ed by porous rock. The degree to which a specific underground formation is suitable for CO 2 storage can be difficult to discern. Research is aimed at developing the ability to characterize a formation before CO 2 injection to be able to predict its CO 2 storage capacity. Another area of research is the development of CO 2 injection techniques that achieve broad dispersion of CO 2 throughout the formation, overcom e low diffusion rates, and avoid fracturing the cap rock. These two areas, site characterization and injection techniques, areAEP-SPP 2009 Integrated Resource Plan



### 62 interrelated because improved formation characteri zation will help determine the best injection procedure.

8.4.2 Carbon Capture Technology and Alternatives While not yet considered as an economically viab le supply-side option, the costs to remove CO 2 from the effluent stream and sequester it in geologi cal formations will have increasing efficacy as the cost of CO 2 increases over time. Reducing CO 2 emissions from a fossil-fuel technology can be accomplished in three ways: increased generating efficiency, removing the CO 2 from the flue gas, or reducing the carbon content of the fuel. While effective, increasing the generatin g efficiency of a coal-based plant has its practical limitations from a design and performance perspective. Removing the CO 2 from the flue gas of a PC plant is a very expensive process. Currently, th e only demonstrated technology used to “scrub” the CO 2 from the flue gas is by using a monoethanol amine (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% CO 2 capture at a lower cost than othe r retrofit technologies. Based on that Mountaineer (20 MW) slip-stream test, a subseque nt 235 MW commercial installation of this chilled ammonia technology has been proposed for Mountaineer. Reducing the carbon content of the fuel can be ac complished 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 CO 2 removal in an IGCC system.

8.5 Demand Side Alternatives

8.5.1 Background “Demand Side Management” (DSM) refers to, fo r the purposes of this IRP, utility programs, including tariffs, which encourage reduced energy c onsumption, 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 en ergy efficiency is important, as the solutions for accomplishing each objective are typically differe nt, 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-We st 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 ma jority of customers, as well as the normal useAEP-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, th e amount of power consumed at the peak must be reduced. This can be addressed several wa ys via both “active” and “passive” measures:

 Interruptible loads . This refers to a contractual ag reement with the utility and a heavy consumer of power, typically an industrial cu stomer. In return for reduced rates, an industrial customer allows the utility to “int errupt” 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, a llow the utility to (remotely) deactivate discrete appliances, typically air conditioners, hot wate r 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” mete r 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 p eak 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 t ask, 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 excepti on 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 inv estment in an appliance/equipment modification, upgrade, or new technology. If the consumer feels th at 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 th e 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 l ess 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 th e 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. Measure s with larger energy efficiency components–with little corresponding peak demand reduction–are to the ri ght. The y-axis is merely a ratio of energy conservation (kWh) to demand reduction (kW). Notably, the air conditioning measures (“Resi dential AC” and “Commercial HVAC”) show distinct differences by region. Because air conditi oners are likely to be on during the peak (high coincidence), there is a significant peak dema nd 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 10,000Demand ResponseResidential Windows(Film)Residential A/CCommercial Windows(Film)Residential InsulationCommercial HVACWeatherizationResidential Heat PumpCommercial InsulationPool PumpCommercial SystemsCommercial MotorsCommercial RefrigerationCommercial LightingAppliance RecyclingResidetial Water HeaterResidential CFLConservation 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, co nservation 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



### 66AEP-SPP 2009 Integrated Resource Plan



### 67 

## 9.0 Evaluating DR/EE Impacts for the 2009 IRP

9.1 gridSMART SM AEP continues to evaluate distribution technologies that operate off the gridSMART SM platform. These include “smart meters” that allow the consumer of electricity to receive pricing signals, or variable rates, encouraging the migra tion of consumption from times of peak demand, to times when power is more readily available. Pilot programs employing smart meters are curren tly 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 pr ograms, including tariff offerings.

9.2 Demand Response/Energy Efficiency Mandates and Goals In November of 2007, the Energy Independen ce 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 st andards 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 th an 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 2019AEP-SPP Annual Energy Consumption (GWh)

Embedded EE programs
Baseline Forecast BAU (excludes EISA 2007) Resultant Energy Consumption

Source: AEP Resource Plannin gAEP-SPP 2009 Integrated Resource Plan



### 68 As identified in this document, AEP has inte rnally committed to (system-wide) peak demand reductions of 1,000 MW by year-end 2012 and ener gy 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 efficien cy 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 typi cally described in three buckets: technical potential, economic potential, and achievable potential ( Exhibit 9-2 ).
Exhibit 9-2: Achievable versus T echnical 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-effectiv eness. 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 achieva ble, 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 a nd lack of information are addr essed with utility-based energyAEP-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 commi ssioned for 10 of AEP’s 11 jurisdictions. In the SPP zone, at the time the analysis for this IR P was performed, only the Oklahoma MPS study was complete. Additionally, one national study of ener gy 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 o ccur through the natural adoption of efficiency by consumers, either through preferences or cod es and standards. The EPRI study provides a useful basis for assigning realistic levels of energy effi ciency and demand response in lieu of jurisdictionspecific studies as well as a basis for assessing jurisd iction-specific study results which are typically stated as a range of possible outcomes. The economic potential for Energy Efficiency li es 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 re gulatory 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 program s as recommended by the Oklahoma MPS, the blocks should be economically co st 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 prog rams 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 ProgramCost of Effiiciency $/MWh levelized RC

CL CM RTE RES

Cost Effective Not Cost Effective

A voided 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 Residentia l Cooling and Residential Energy Star TM (All). As modeled, these program blocks consist of many measures and even pr ograms, some cost effective, others not. As the green blocks show, there are both Energy Star and resi dential 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 th e ability of C&I customers to “opt out” of utility programs, influencing the ultimate portfolio mix. Some states have a collabor ative process that can greatly influence the tenor and composition of a progr am portfolio. That said, these blocks provide a reasonable proxy for demand-side resources with in the context of an optimization model. A list of the programs and impacts used to de velop the proxy resources is included in the Technical Addendum.AEP-SPP 2009 Integrated Resource Plan



### 71 9.5 Optimizing the Incremental DR/EE Resource 

### s Using the red and yellow program characteristics, DR/EE “blocks” were constructed of equal energy impacts, corresponding demand impacts a nd 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 provi ded 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 acronymsAEP-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 wi th 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 co st effective and should not be part of any future portfolios in any jurisdiction. It does show, how ever, that certain characteristics of programs are more desirable than others in the context of a dy namic, constrained optimization. As a practical matter, actual DR/EE programs are likely to cont ain elements of many of these programs but not match the blocks exactly. However, for the purpo ses 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 2018Total Retail Sales (GWh)

@meter SPP forecast (no em bedded 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 genera tor. 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 si gnificantly higher than past IRP plans have included. There are a few reasons why this is valid:

 Mandates at the state and potentially at the fe deral 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 r esponse 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 pro cesses 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 th at include the latest, most environmentally friendly technologies and protocols. Adoption of these measures is predicated on securing adequateAEP-SPP 2009 Integrated Resource Plan



### 75 cost recovery. For this planning cycle, it is assu med 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 ma tches 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 ad equate reserves. As more experience is gained implementing DR/EE programs, and results are observe d, 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 PlanningAEP-SPP 2009 Integrated Resource Plan



### 76AEP-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 continua lly 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 pa rameters; regulatory constructs; capacity supply; energy adequacy and operational reliability; and en vironmental mandate requirements are constantly reassessed to ensure optimal capacity resource planning. Further impacting this process are growing number s of federal and state initiatives that address many issues relating to industry restructuring, cu stomer 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 cons idered 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 pe rformed 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 a ddress 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, capacit y costs, energy costs, effluent prices including CO 2 , 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-co sting tool that is driven by inputs into the model, not necessarily past performance. AEP-SEA models the eastern synchr onous interconnect and ERCOT using Aurora. Fuel and emission forecasts established by AEP Fuel, Emissions and Logistics, are fed into Aurora. Capital costs fo r new-build generating assets by duty type are vetted through AEP Engineering Services. The CO 2 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 itera tive 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 de veloped: 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 SO 2 Reference Case Same Same Same NO X Reference Case Same Same Same CO 2 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 economic s, 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 Constr ained 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 vi a weather or political issues. The “Reference Case” sits inside the Abundance and Constrained Case. The “BAU” case is essentia lly a case where there is

no carbon policy, and no attendant cost of CO 2 . Though the commodities are changing in each case, the key driver is the CO 2 price used. The CO 2 price in this report is elevated versus last year’s outlook. The mid-range CO 2 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 cha nge applied to the other key inputs. In the Reference Case, AEP-Hub power pric es 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-i n. 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 mark ets, 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, unconventiona l 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 ampl e amount of coal in the world, particularly when the demand is being constraine d 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 rema in high due to local supply issues. However, very similar to gas there is another coal supply source – Powder Ri ver Basin (PRB). Unlike unconventional gas, theAEP-SPP 2009 Integrated Resource Plan



### 80 ultimate end product of this supply will take modificati on 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 contro l equipment should go down. However much of our industrial load will likely be damage d if prices continue to stay low.

10.3.1 CO 2 Forecast The forecasting of future CO 2 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 organizati on has developed three potential CO 2 price forecasts to match potential prospective legislated outcomes. The Abundance (“High CO 2 ”) and Constrained (“Low CO 2 ”) 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-Specte r bill was widely supported by industry for its moderate emission reduction timeline, while the Lieb erman-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 CO 2 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 CO 2 price forecast is based on an average of four modeling scenarios of the Lieberman-Warner bill: two conducted by EIA an d 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 Bingama n-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 compro mise 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., capita l 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 SO 2 , NO X , and CO 2 emission allowances.

 Reliability constraints (in this study, minimum reserve margin targets).

 Transmission limitations

 Emission limits and enviro nmental compliance options.

 Alternative DR/EE program costs and impacts on peak load and energy requirements. These and other assumptions are considered in the de velopment 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 tho se generation-COS components that change from plan to plan. It does not consider embedded costs asso ciated with existing generating capacity that would remain constant under any scenario. Likewise, transm ission 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-s pecific) capacity resource modeling would not typically incorporate significant capital for transmission interconnection. Specifically, Strategist includes and recognizes in its re venue 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 sp lit-savings per West Operating Agreement.AEP-SPP 2009 Integrated Resource Plan



### 82  Variable costs associated with the entire fleet of new and exis ting 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 transacti ons (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 al ternative combinations created by the module’s dynamic programming algorithm. On an annual b asis, each capacity reso urce combination that satisfies various user-defined constraints (to be discu ssed below) is considered to be a “feasible state” and is saved by the program for consideration in fo llowing 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 requireme nt. 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 res ource alternatives being considered.

11.1.1 Modeling Constraints and Economic Scenarios Given that the model’s algorithm has the potentia l 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 r eserve 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; likewis e 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 suboptim al plans given the fundamental power and CO 2 pricing scenarios and sensitivity cases devel oped 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 “t he answer;” rather, it produces or suggests many portfolios that have different cost profiles under di fferent scenarios and sensitivities. Portfolios that fare well under all scenarios and sensitivities are cons idered 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 decisi ons 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 co mbined 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 dive rsified solution that is not significantly more expensive. The optimum or least expensive portfol io 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 u nderlying 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” commitmen t 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 CO 2 /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 a nd the optimum assets then were made available as options in Strategist . Such screening for typical supply-side alternatives was performed for each ofAEP-SPP 2009 Integrated Resource Plan



### 84 the major generating duty-cycle “families” (baseloa d, intermediate, and peaking) as discussed in Section 8.

The selected technology alternatives from th is screening process do not necessarily represent the optimum technology choice for that duty cycle fa mily. Rather, they refle ct proxies for modeling

purposes.

Other factors will be considered which will dete rmine 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, th e 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 m odeled as a 618 MW Supercritical PC unit considering availability beginning in 2017. Du e 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 join t 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 with in 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 pr ofiles were developed for each program for both PSO and SWEPCO. Depending on the program, blocks of one or two could beAEP-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

C apacity, energy and cost assumptions were made for a new 100 MW (nameplate) wind resource block in the AEP-SPP IRP analysis. The ener gy 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 pro cess 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 al so 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 reser ve 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 (O CC) final order in Cause number 200600030, the OCC found that PSO had a need for 450 MW of a dditional baseload generati on in or around 2012. In response to this order, PSO re-issued a Re quest for Proposals (RFP) in 2008 for supply-side capacity and energy resources. As a result of th e RFP, PSO has successfully negotiated a Power Purchase Agreement (PPA) with Exelon Generation Company for approximately 512 MW 4 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 capac ity additions would be available until 2013.

4 512 MW rating is based on SPP criteria. 520 MW ra ting is based on contra ctual 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 exhibi t 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 approxi mately $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 a nd suboptimal plans under the Reference case power and CO 2 pricing scenario along with the constraint s 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 CO 2 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 CO 2 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 S upply-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 CO 2 price scenarios and sensitivities produ ced essentially two choices. The optimization runs under the “Reference” and “B AU” price scenarios and sensitivities produced the same optimum plan adding eight 164 MW of generi c 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. Th e 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 respectiv ely, the optimum plan includes two combustion turbine units and 313 MW of DSM, as in the BAU an d 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 additi onal 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 underAEP-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 wh ich of the various developed plans appears to be most “robust” (i.e., least-cost while also represen ting a practical solution) under the various price scenarios being driven by, particularly, implicit CO 2 price loads. In order to make this comparison, the optimal plans for each price scenario are e ffectively “forced” into the other scenarios. Exhibit 11-4 summarizes the CPW of each PSO plan under ea ch 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 informati on for use in developing the Hybrid plan, Strategist was also used to identify optimal and suboptimal pl ans 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 contai ning a baseload coal supply-side resource. Separate plans were identified for PSO and SWEPCO.

 Best Contrary Baseload Nuclear Plan – Se parate 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 Stor age (CCS) Requirements on New Coal – the optimal plan without a requirement that new b aseload 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. Se parate plans were identified for PSO and SWEPCO.

 Demand Destruction – the optimal plans unde r the Reference and Constrained scenarios when the load forecast was re duced from year 2009 to 2010 a nd 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) be tween 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%.

 CO 2 Limited – In this scenario, CO 2 emission limits were assumed to be placed on the AEP’s East and SPP systems based on the continued prospect for comprehensive Climate Change/CO 2 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 CO 2 emission limit was based on a 15% reduction (W-M called for 17%) from 2005 actual CO 2 emissions. In 2030, the CO 2 emissions limit was based on a 40% reduction (W-M called for 42%) in 2005 CO 2 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 A EP 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 CO 2 emissions, with the East being allocated approximately 15.5 million tonnes and the West receiving 4.5 million tonnes. In recognition of a CO 2 constrained environment, this scenario includes options to meet system CO 2 emission limits in 2020 and 2030, in cluding 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 Wind a 5 500 $/MWh 52.29 44.95 57.23 76.94

Total 1,296

DR b 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 Wind a 5 500 $/MWh 52.49 45.13 57.4 5 77.24

Total 1,296

DR b 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 Wind a 5 500 $/MWh 52.29 44.95 57.23 76.94

Total 1,296

DR b 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 Wind a 5 500 $/MWh 47.57 39.93 50.16 66.50

Total 1,264

DR b 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 Wind a 5 500 $/MWh 50.58 43.15 54.69 73.14

Total 1,437

DR b 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

Wind a 5 500 $/MWh 50.43 43.13 54.60 73.05

Total 1,382

DR b 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 CO 2 ) 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 Wind a 5 500 $/MWh 52.29 45.1 3 57.23 Total 1,296

DR b 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 Wind a 7 700 $/MWh 45.76 57.51 67.13 Total 1,312

DR b 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

Wind a 7 700 $/MWh 55.25 69.29 Total 1,398

DR b 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 Wind a 5 500 $/MWh 56.13 69.16 Total 1,296

DR b 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 Wind a 5 500 $/MWh 44.24 55.77 Total 1,610

DR b 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 Wind a 5 500 $/MWh 67.06 Total 1,264

DR b 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 Wind a 7 700 $/MWh 57.35 67.09 Total 1,312

DR b 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 PlanningAEP-SPP 2009 Integrated Resource Plan



### 92 Finally, in late-April 2009, prior to the developm ent 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 highe r or lower, depending on changes in economics or customer behavior both locally (for PSO) and nationa lly. However, the trend is generally consistent with compound annual growth rates between 0.93 per cent 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

199

5 19 96 1997 199 8 19 99 2000 200 1 2

002 2003 20 04 2 005 2006 20 07 20 08 2 009 2010 20 11 2 012 2013 20 14 2 015 201 6 20 17 2018 201 9Peak 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 prep ared to ensure that PSO would not find itself in a capacity deficit position should the econo my turn around quicker than expected. Exhibit 11-8 compares the current April 2009 for ecast 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 2019Peak 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 cap acity 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 r eact 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 optim al plans developed under the price scenarios and other modeling constraints and scenarios, and taki ng 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% 2009-201 9 747 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 loss es) (B) "Embedded" DSM represents 'known & measurable', commission-approved program activity now projected by AEP-Economic Forecas ting in the most recent load forecast (C) "New" DSM represents incremental activity projected based on estimated contribution & program cost (vs. avoided cost) para meters, from recent Market Potential Studies, and were generally limited to an EPRI Jan. '09 study identifying a "Realistically Achievable P otential"... 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 PlanningAEP-SPP 2009 Integrated Resource Plan



### 96 11.5.5 Observations: PSO Hybrid Plan Composition Several factors were considered in the devel opment 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 a ddition was generally peaking capacity and energy. It was also determined that the co mbustion 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 resour ce portfolio included both wind and solar resources required to achieve the renewable en ergy sales targets established for 2013, 2020, and 2030. Wind resources are being adde d throughout the planning period.

 DSM – The four DR/EE programs that were f ound to be cost eff ective 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 po tential requirement for significant CO 2 emission reductions in the future, that may not be achievable via other means, a CCS technology retrofit is included in the plan at the Nort heastern 3 unit in the 2030 out-year. This technology’s potentially significant relative CO 2 reduction contribution was viewed as being critical to the prospect of achieving substantive CO 2 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 r obust 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 requir ed to meet additional capacity needs over the 10 year planning horizon. The plan includes substa ntial clean energy renewable resources, including wind and, over the long term, solar, to meet aggres sive 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 CO 2 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 develo ped 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 plan s to the optimal SWEPCO plan for the Reference price scenario. This exhibit shows the di versity 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 incl udes a coal unit, shows that SWEPCO’s costs would increase by approximately $212 million. Stall Turk A rkansas 06-120-U 06-154-U
Louisiana U-29702/U-27866 B U-23327 B
Texas 33048 33891AEP-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 CO 2 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 CO 2 Price Scenarios SWEPCO Optimal Pl an 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 ve ry similar. The optimum runs under the BAU and Reference price scenarios and sensitivities produ ced 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 reducti on 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 cumulativ e CPW savings under three of the four discrete price scenarios and sensitivities. This would in dicate 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 wh ich 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 pl ans for each price scen ario 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 Opti mal 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 pl ans 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 describe d 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 Wind a 13 1,300 $/MWh 38.33 32.81 40.16 47.52

Total 1,046

DR b 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 Wind a 13 1,300 $/MWh 38.4 5 32.90 40.28 47.69

Total 1,046

DR b 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 Wind a 13 1,300 $/MWh 38.33 32.81 40.16 47.52

Total 1,046

DR b 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 Wind a 13 1,300 $/MWh 38.41 32.94 40.34 47.52

Total 1,046

DR b 402 B es t C on t rary C oa l Pl an 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 Wind a 13 1,300 $ /MWh 37.59 31.98 39.01 45.81 Total 1,187

DR b 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

Wind a 13 1,300

Total 1,132

DR b 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 CO 2 ) 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 Wind a 13 1,300 $/MWh 38.33 32.90 40.16 Total 1,046 DR b 313 Enhanced Renewables CT 6 942 Total NPV-$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 Wind a 19 1,900 $/MWh 34.2 5 40.76 47.88 Total 1,094 DR b 313 "Green" Plan CT 4 628 Total NPV-$B 19.54 25.49 CC 0 0 $/MWh 75.37 95.89 Nuclear 1 400 Fuel NPV-$B 11.60 13.36

Wind a 19 1,900 $/MWh 39.54 45.6 5 Total 1,180 DR b 313 Demand Destruction CT 6 942 Total NPV-$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 Wind a 13 1,300 $/MWh 38.2 5 44.6 2 Total 1,046 DR b 152 Demand Destruction + Unit Retirements CT 10 1,570 Total NPV-$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 Wind a 13 1,300 $/MWh 31.30 37.74 Total 1,674 DR b 313 High DR/EE Bandwidth CT 6 942 Total NPV-$B 25.30 CC 0 0 $/MWh 96.09 PC w/CCS 0 0 Fuel NPV-$B 13.77 Wind a 13 1,300 $/MWh 47.46 Total 1,046 DR b 603 CO2 Limited CT 8 1,256 Total NPV-$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 Wind a 19 1,900 $/MWh 40.88 47.60 Total 1,408 DR b 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 PlanningAEP-SPP 2009 Integrated Resource Plan



### 103 The load forecast issued by AEP’s Economic Fo recast group in late-Apr il 2009 to reflect the results of the downturn in the economy was take n 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 loss es) (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 "Realistic ally 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 PlanningAEP-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 tre nds 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 2019Peak 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 St all CC and Turk PC units within the next five years, the most cost effective ther mal resource additions in the long-term was determined to be peaking capacity and ener gy. 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 ove r the balance of the longer-term planning horizon.

 Renewable Resources – The renewable resour ce portfolio included both wind and solar resources required to achieve the renewabl e 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 pe riod, 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 th e cumulative demand reduction was reduced from 313 MW to 144 MW to reflect the “Realisti cally Achievable Potential” identified in a recent EPRI study. In addition, cu mulative 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 CO 2 emission limits in the future, CCS technology retrofits are included in the plan at the Turk plant in 2025 and atAEP-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 CO 2 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 r esource to meet future cap acity needs. The plan includes substantial clean energy renewable resour ces, including wind, solar, and biomass to meet aggressive renewable energy targets set by the Co mpany. 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 CO 2 emission limits through retrofitting a limited number of exis ting 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 Ov ersight, the Utility Risk Simulation Analysis (URSA) model uses Monte Carlo simulation of th e 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,

 SO 2 , CO 2 , and NO X 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 le vel of required revenue su fficiently 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 “Hybri d 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 woul d 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 OversightAEP-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 CO 2 and SO 2 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%+ an d 40%+, which is significantly greater than the relative difference of other risk factors. On the ot her extreme, the possible fu tures associated with the RRaR-exceeding outcomes are characterized by on ly slightly higher levels for load and NO X 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 NO X allowance prices and some of the other risk factors that determine the tail cases, so that in these tail cases, the average NO X 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 exam ined 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; variab le 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 Distribu tion of AEP-SPP Revenue Requirement (SWEPCO)

Source: AEP Market Risk OversightAEP-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 OversightAEP-SPP 2009 Integrated Resource Plan



### 111 12.3 Capital Cost Risk Assessment In order to further scrutinize the seven plan s under the 1399 possible futures, the impacts of Capital Cost Risk on the URSA results were examin ed. A six-point capital cost distribution for each of the seven plans was created. (See Exhibit 12-4 for its basis.) In crea ting the distribution for each plan, the capital costs of all types of capacity were as sumed to be perfectly corre lated 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 fu el/generation diversity of the capacity resourceAEP-SPP 2009 Integrated Resource Plan



### 112 options introduced into the analysis, the rela tive economic exposure would appear to be small irrespective of the plan selected. The three lowest-cost plans at the 50 th percentile are the CO 2 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 95 th percentile is the CO 2 limited plan, followed by the Hybrid plan. RRaR measures the risk relative to the 50th percen tile, or expected, result of a plan. The plan with the least RRaR is not necessarily preferred fo r risk avoidance. Instead, low values of required revenue at extreme percentiles, such as the 95 th , are preferred. The estimated distributions of revenue require d under the seven plans are rather similar. Exhibits 12-6A, 12-6B, 12-7A, and 12-7B show the superimposed gra phs 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 PlanningAEP-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 PlanningAEP-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 CO 2 Limited Plan had the lowest cost at the 95% probability level. Their RRaR was also among the lowest of all plans. As the CO 2 Limited Plan includes assumptions regarding potential legislati on 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-approv ed Turk baseload facility and Stall combined cycle facility, and the Exelon PPA reflects manage ment’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 comp ared 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 re duce demand, energy usage and, with that, our attendant carbon footprint.

 Keeping coal as a viable fuel in a carbon-c onstrained world requires that commercial USCPC technology be championed and built. AEP’ s steeped history and core competency surrounding coal-based generation would also natu rally 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 intr oducing 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, th e 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 PlanningAEP-SPP Generation Capacity02,0004,0006,0008,00010,00012,00014,0002009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

MW of Summer CapabilityNew CTTurk PC(Limited) ICAPPurchasesExisting CCExisting CTStall CCExisting Coal w/Environmental Retrofits(includes FGD and ACIESP)Gas-SteamExisting Coal, no RetrofitsExisting WindNew WindLong-term PPADSMAEP-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 PlanningAEP-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 WindAEP-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 additi ons 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%

C umul. (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 loss es) 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) param eters, from recent Market Potential Studies, and were generally limited to an EPRI Jan. '09 study identifying a "Realistically Achievable Potential". This 'New' (i ncrem) 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-a pproved program activity now projected by AEP-Economic Forecas ting 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 Reso urce Plan (Hybrid Plan)

THERMAL Planned Resource Reductions Planned Resource Reductions SWEPCO PSO

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 re newable 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 CO 2 legislation has had a direct bearing on the outcome of the 2009 AEP-SPP Plan. To gauge the respective CO 2 mitigation impacts incorporated into this resource planning, an assessment was perfo rmed that emulates an approach undertaken by the Electric Power Research Institute (EPRI). This pr ofiling seeks to measure the contributions of various “portfolio” components that could, when taken t ogether, effectively achieve such carbon mitigation:

 Energy Efficiency

 Renewable Generation

 Fossil Plant Efficiency, including coal-unit retirements

 Nuclear GenerationAEP-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: CO 2 Emission Profile

AEP-SYSTEM (East & West)

CO 2 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 2034CO2 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 A llowance 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 CO 2 emission profile over time, it could still fall short of prospectiv e legislation that would attempt to further limit CO 2 . Specifically, using H.R. 2454 (the Waxman-Markey B ill) that passed the U.S. House in June, 2009 as a proxy, this profile would require reduction in CO 2 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 reducti on 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: CO 2 Emission Profile With Caps

AEP-SYSTEM (East & West) CO 2 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 2034CO2 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 CO 2 mitigation efforts, inclusive of offset acquisitions, may not provide for an adequate CO 2 position within that mechanism. Specifically, if the legislation provides for the allocation of an insufficient level of (free) CO 2 allowances to the utility, any such remaining CO 2 position “shortfall” must subsequently be borne by the utilities’ customers through additional, potentially more costly, CO 2 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: CO 2 Emission Profile vs. Estimated Waxman-Markey Allocation

AEP-SYSTEM (East & West) CO 2 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 2034CO2 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% b y '20... 42% b y '30 )

Est. increm. allowance/cost recovery from Wholesale Customers

Source: AEP Resource Planning In summary, this prism analysis would s uggest that the carbon mitigation requirements in the AEP System (East and SPP) 2009 IRPs offer a meaningf ul pathway to the attainment of potential Climate Change/CO 2 legislation, however, additional contributions–over-and-above the acquisition of CO 2 allowances—may be required in future planning cycl es 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 i ssued 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 throug h 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 th e SPP required levels. These projects were selected through a competitive bidding process which assures ratepa yers 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 concernsAEP-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 forwar d to working with them again for future IRP filings.

13.5 Conclusion The recommended plan provides the “least, reasona ble cost” solution through a combination of traditional supply, renewable and de mand side investments. The temper ed load growth combined with additional renewable resources, increased DR/EE initiativ es, 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 rene wable portfolio standards and energy efficiency requirements, and sets in place the framework to meet potential CO 2 reduction targets at the intended least reasonable cost to its customers.AEP-SPP 2009 Integrated Resource Plan



### 126AEP-SPP 2009 Integrated Resource Plan



### 127 

## 14.0 Implementation

14.1 Current Commitments While the resource plan described in this re port covers an extende d 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 c onstruction timetables–and whether certain elements (e.g. land or permitting) are already in-p lace–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 A EP-SPP zones to be opera tional 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) - Cu rrently have 10.5 MW subscribed for summer 2009.

 Energy Star New Homes program - Complete d 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 200 9. This results in an energy savings of approximately 160,500 kWh and 28.6 kW.

 ES Res/Comm appliance reba te program - Began implem entation of air conditioner replacement rebate program in April 2009 in partnership with Sears and Kmart.

 C&I SOP - Have projects completed that resu lted in a reduction of 150 kW and 965,800 kWh with projects pending that will provi de another 1,100 kW and 6 million kWh in energy savings by December 2009.

 Model Cities LED Traffic signal change out pr ogram - 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 a dditional 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 th e 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 cont rol 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 collabora tive that was initiated by th e 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 kilowa tts 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 Ge neration Company LLC, a subsidiary of Exelon Corporation, have executed a long- term PPA and filed an application seeking its approval with the Oklahoma Corporation Commi ssion (OCC). The PPA is for the purchase of up to 520 megawatts (MW) of electric generati on 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 cons truction, 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 Confid ential 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 

# APPENDICESAEP-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-BH Super 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 AlternativesUnit or Series Renewable Type $/MWh Unit or Series Renewable Type $/MWhHydro, Existing Dam, PTC Hydro -$16.08 Mountaineer Biomass Separate Injection $25.32Wind Project, SPP with PTC Wind -$10.50 Big Sandy 1 Biomass Separate Injection $25.49Amos 3 Biomass Cofire -$3.60 Conesville 5 Biomass Separate Injection $25.51Big Sandy 2 Biomass Cofire -$1.32 Conesville 6 Biomass Separate Injection $26.06Amos 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 $26.15Rockport 1 Biomass Cofire $2.98 Flint Creek 1 Biomass Separate Injection $26.30Stoker 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 $30.51Muskingum River 5 Biomass Separate Injection $9.04 (a) Tanners Creek 3 Biomass Separate Injection $32.49Glen Lyn 6 Biomass Separate Injection $11.53 Tanners Creek 1 Biomass Separate Injection $32.70Big Sandy 2 Biomass Separate Injection $12.09 (a) Northeastern 3 Biomass Cofire $32.79Mountaineer Biomass Cofire $12.69 Clinch River 1 Biomass Cofire $37.48Amos 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 $45.04Welsh 1 Biomass Cofire $14.51 Sporn 1 Biomass Separate Injection $47.21Mitchell 1 Biomass Cofire $15.09 Landfill Gas0.8Recip Engine Gas $57.00Wind Project, SPP w/o PTC Wind $16.62 Muskingum River 3 Biomass Separate Injection $75.23Rockport 1 Biomass Separate Injection $16.79 (a) Glen Lyn 5 Biomass Separate Injection $86.09Wind Project, PJM with PTC Wind $17.94 Muskingum River 1 Biomass Cofire $104.54Welsh 1 Biomass Separate Injection $18.51 (a) Sporn 5 Biomass Cofire $130.46Oklaunion 1 Biomass Separate Injection $20.45 (a) Muskingum River 1 Biomass Separate Injection $135.04Pirkey 1 Biomass Cofire $20.80 Picway 5 Biomass Separate Injection $141.28Cardinal 1 Biomass Cofire $21.01 Conesville 3 Biomass Cofire $316.90Zimmer Biomass Separate Injection $22.04 Residential Wind, PJM w/o PTC Wind $394.03Kammer 1 Biomass Separate Injection $22.34 Central Station Solar Solar $445.00Conesville 4 Biomass Separate Injection $22.82Gavin 1 Biomass Separate Injection $24.28Beckjord 6 Biomass Separate Injection $24.32Note: (a) The cost of a second technology at a unit is incremental, that is, additional renewable energy divided by additionalcost.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 A ero-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 A ero-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 Perf ormance Estimates," 12/03/08, Corporate Technology Development (CTD). Emission RatesAEP-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 we re 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 C ycle 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 CycleCapital 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 1 5.9 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 1 2.0 18.0 17.1 18.2 17.3 16.2 15.0 16.1
c h ec k 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 469AEP-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
c h ec k 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 120AEP-SPP 2009 Integrated Resource Plan



### 137 Appendix D, Figure 3 PSO Capaci ty, 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 DIVERSIT Y 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 IRPAEP-SPP 2009 Integrated Resource Plan



### 138 Appendix D, Figure 4 SWPCO Capa city, 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 O ther 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 IRPAEP-SPP 2009 Integrated Resource Plan



### 139 Appendix E, Figure 1 AEP Plan to Meet 10% of Renewable Energy Target by 2020AEP System - East ZoneRenewables to Achieve a 7% System Target by 2013 and 10% by 2020(a)Together with Known or Emerging State-Specific Mandates2009 IRPSolar WindBiomassRnwblSolar WindBiomassRnwblSolar WindBiomassRnwblSolar WindBiomassRnwblSolar WindBiomassRnwblSolar WindBiomassRnwblSolar WindBiomassRnwblNmpltNmpltEquivPercent NmpltNmpltEquivPercent NmpltNmpltEquivPercent NmpltNmpltEquivPercent NmpltNmpltEquivPercent NmpltNmpltEquivPercent NmpltNmpltEquivPercent(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 Sales2009 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% 10525-1.5%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% 131,226103.2%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% 151,9261095.5%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% 282,4262357.0%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% 422,4262357.0%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% 562,4263857.8%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% 702,5263858.0%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% 832,5263858.0%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% 1002,5265128.6%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% 1172,5266419.2%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% 1332,7266419.7%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% 1682,87676810.6%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% 2202,97676810.9%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% 2203,07689611.6%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% 2713,27689612.1%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% 2713,37689612.2%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% 3063,47689612.4%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% 3063,5761,02313.1%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% 3403,7761,02313.5%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% 3403,7761,02313.4%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 SYSTEMSolar WindBiomassRnwblSolar WindBiomassRnwblSolar WindBiomassRnwblSolar WindBiomassRnwblNmpltNmpltEquivPercent NmpltNmpltEquivPercent NmpltNmpltEquivPercent NmpltNmpltEquivPercent(MW) (MW)(MW)of Sales(MW) (MW)(MW)of Sales(MW) (MW)(MW)of Sales(MW) (MW)(MW)of Sales2009 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% 101,029-2.5%2011 0 591 0 13.3% 0 211 0 4.3% 0 801 0 8.6% 132,027104.5%2012 0 591 0 12.8% 0 311 0 6.3% 0 901 0 9.5% 152,8271096.4%2013 (b) 0 591 0 12.7% 0 461 0 9.3% 0 1,051 0 10.9% 293,4772358.0%2014 0 591 0 12.6% 0 461 0 9.2% 0 1,051 0 10.9% 423,4772358.0%2015 0 658 0 14.0% 0 494 0 9.8% 0 1,151 0 11.8% 563,5773858.8%2016 0 658 0 13.9% 0 594 0 11.6% 0 1,251 0 12.7% 703,7773859.1%2017 0 858 0 18.0% 0 594 9 11.7% 0 1,451 9 14.7% 833,9773949.6%2018 0 858 0 17.9% 0 594 9 11.6% 0 1,451 9 14.6% 1003,97752110.1%2019 0 858 0 17.8% 0 594 9 11.4% 0 1,451 9 14.5% 1183,97765010.5%2020 0 1,058 0 21.8% 0 594 9 11.3% 0 1,651 9 16.3% 1334,37765011.3%2021 0 1,058 0 21.6% 0 694 9 12.9% 0 1,751 9 17.0% 1684,62777712.2%2022 0 1,058 0 21.4% 0 794 9 14.6% 0 1,851 9 17.9% 2204,82777712.6%2023 0 1,158 0 23.3% 0 794 9 14.4% 0 1,951 9 18.6% 2205,02790413.3%2024 0 1,158 0 23.1% 0 894 9 16.0% 0 2,051 9 19.4% 2715,32790413.9%2025 0 1,158 0 22.9% 0 994 9 17.4% 0 2,151 9 20.0% 2715,52790414.1%2026 17 1,258 0 24.8% 17 994 9 17.3% 35 2,251 9 20.8% 3405,72790414.5%2027 17 1,258 0 24.6% 17 1,094 9 18.8% 35 2,351 9 21.5% 3405,9271,03215.2%2028 35 1,258 0 24.5% 35 1,094 9 18.7% 69 2,351 9 21.4% 4096,1271,03215.5%2029 35 1,358 0 26.2% 35 1,194 9 20.0% 69 2,551 9 22.8% 4096,3271,03215.7%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, 2013would represent the initial year afterthe likely expiration of Production Tax Credits (PTC) for, particularly, wind resources. The notion being thatestablishment of a Federal renewables standard would likely eliminate further extension of such PTC opportunities.AEP-EastPSO SWEPCO AEP-SPPAEP Sytem - SPP ZonePotential Renewables Profile to Achieve a7% System Target by 2013, 10% by 2020, and 15% by 2030(a)...as well asKnown or Emerging State-Specific Mandates2009 IRPOPCo AEP-Ohio I&M KPCoAPCo CSPAEP-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 Prior itization of Issues IV. Independent Power Producers 17

V. Renewable Energy Group 18

VI. Wholesale, Retail & Comme rcial 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 Stak eholder 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 da y of the meeting consisted of presentations by AEP on the objectives and goals of the Integrat ed Stakeholder Committee Meeting consisting of Resource Planning Guidelines, AEP Integrated Resource Planning Process, Transmission Overview, and Incorporating Renewabl e Energy into the AEP IRP Process.

Prior to the beginning of the meeting, stake holders were asked to complete worksheets addressing Key Issues to be addr essed in the IRP process. We then broke into three randomly selected groups in which stakeholders develope d 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), Renewabl e 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 AE P/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 a ny prioritization by the stakeholders. 

## Issue #1 DSM, Energy E fficiency, & 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, Ge n, 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 c onservation and demand response goals

 Ownership of environmental attr ibutes: 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 lo ad 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 & Po wer (CHP) & Distributed Gen Description of the Issue: CHP and some distributed generation is cost effective to implement given the right signals from the mark et and government. It has clear additional benefits for reduced CO 2 

### 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 cap ture 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 (cus tomer buying green po wer 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/ut ility 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 in ternal objective of carbon neutral

 Allow utility to directly a ssign renewable energy costs. Cons of Addressing this Issue:  May not meet need if renewabl e energy credits not included.

 Administrative burden.



## Issue #4 Jointly procure larger base load with other utilities The Issue: Consideration of partne rships with surr ounding utilities where economy of scale makes sense



## . Description of the Issue: Economy of scale can exist with ne w 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 fa ilures – wires breaking, capacitors blowing, etc. which is extremely cost ly 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 relia bility 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 biom ass, and therefore a renewable carbon neutral energy, and besides GHG credit benefits, it provides benefits to the poultry industry a nd the water system. Why is this issue important? The poultry industry is extremely la rge 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 pr ojects 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 s lide #12, planned ca pacity 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/sustai nable resources into SWEPCO generation resource mix Description of the Issue: Historical lack of renewabl e energy goals; goals too low. Customer owned renewable energy vs. utilities owned renewable energy. Ownership of environmental attributes.

Renewable resources provide sustai nable energy and further diversify traditional fossil fuel generation resources. Many renewable resources also have the benefit of elim inating greenhouse gas and other emissions (SO 2 

### , NO x 

### , particulates)

Properly sited wind generation is competitive with other forms of generation on a delivered to busba r basis (new plant to new plant comparison basis.) Why is this issue important? Need “balance” of supply alternatives Need to leverage with customer s; not compete with customers. Bad outcome: renewable ener gy not being fully utilized.

Renewable resources (e.g. wind, so lar) eliminate fuel costs and provide a hedge re: generation that require fuel inputs and have the potential for cost increases over ti me. Historically, the societal impacts of emissions from conventiona l 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 so me 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. Cost s 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 cu stomers 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 3 rd 

### party Purchased power Agreements Lack of financial Incentives Reluctance to utilize customer resources Risks to REC ownership

Cost of renewable energy is often c ited as an impediment. Integrating the most cost effective resources initially (e.g. wind) and phasing in promising but not yet low cost al ternatives (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 hi gh capacity transmission lines. Pros of Addressing this Issue A mix of generation assets/resources is important to hedge future costs/need for rate increases. Fu rther, a reduction of emissions is important to promote a healthy enviro nment particularly in the face of growth in energy consumption. Pla nning for additions of a variety of generation sources will allow for th e introduction of next generation of power sources at the lowest possi ble 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 (a nd Daily Peaking) of Pump Hydro

Description of the Issue: Meet peak demand

Why is this issue important? Allows use of lower cost/more-effici ent 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/othe r renewables (wind) Cons of Addressing this Issue  Initial high capacity cost.

 Environmental elements – physical, CO 2 

### , etc.



## Issue #10 Incentivize Utiliti es to consider PPA’s. The Issue: Utility owning assets (gen eration) 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 incu rred 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 u tility 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 Co sts (Env. Societal Costs) in Cost Model The Issue: Distinguish methodology for determining low cost – This traditional driver and historical methods will le ad to same answers – fossil plants.

Value all externalities of supply optio ns – that includes environmental, health, economic, societal

Description of the Issue: Conventional power vs. Renewables vs. DSM All “costs” including externalities mu st be incorporated in a more dynamic way and alter past low co st determination approaches.

Traditional cost analysis is usua lly 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 sl ightly more in the near term. Solution integrate renewables ove r 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 ut ility 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 e nvironmental attribute waiver.



## Issue #12 Economic development benefits related to renewable project development in side 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 sp ending, 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 co uld be the better solution.

Pros of Addressing this Issue  This issue should be part of th e “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 reason able costs to customers Description of the Issue: Increasing costs of power are passe d 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 in creasing beyond reasonable.

Possible Obstacles: Fuel sour ces 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 Ga s Mitigation Options Description of the Issue: GHG emissions are a concern for our facility (Domtar) as well because when we market our produc ts, 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 th at is required to have impact.

Possible Obstacles: Cost of alternative fuel s could compete with ou t 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 decisi on to expand operations, increasing the demand for power, how will that be a ddressed 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 insu res 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 CO 2 

## Mitigation Description of the Issue: SWEPCO’s portfolio cons ists of significant amounts of coal/lignite based resources. Displacing coal/lig nite resources with efficient natural gas resources is an effective CO 2 

### mitigation strategy. Why is this issue important? Natural gas resources existing on the SPP/Entergy systems are under utilized. The resources emit significantly lower CO 2 

### emissions per MWh that coal/lignite resources and can be a low cost alternative (as compared to wind resources) to meet future CO 2 

### regulations

### 15 (anticipated)

Risks of failing to address: Higher costs to ratepayers.

Possible Obstacles: Transmission congestion acr oss the SPP/Entergy Seam. See previous sheet 1 for implementation strategy. Pros of Addressing this Issue: Low cost alternative to mitigate CO 2 

### output for SWEPCO Use existing gas resource Reduces CO 2 

### 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 lim iting other supply options

 Transmission expansion in conjunction with purchase power alternatives to meet in cremental 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 genera tion 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 si gnificant 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) ex ists within the SPP but can’t be delivered to SWEPCO.

 Natural gas fired generation is clea n, efficient alternative to meet base, intermediate and peak ing 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 fr om 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 congest ion 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 / Legisl ators to adopt, pressure, and accelerate transmission solutions

 Lower all end costs to rate payers Cons of Addressing this Issue:  Without addressing cost constraint s, 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 transmissi on constraint-free options – if there were no constraints what options would be available

 When considering new build opt ions, 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 pr oduct 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 pro cess 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 assumpti ons 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 conso lidated 18 issues compiled by the general stakeholders group for evaluation and prioritizat ion 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: 1 st



### – Created 3 buckets of prio rities (A=highest, C=lowest) 2 nd 

### – 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 conso lidated 18 issues compiled by the general stakeholders group for evaluation and prioritizat ion with respect to the specific concerns, operational issues, and priorities of this cu stomer 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 do minated by a mix of fossil fuel generation resources, with approximatel y 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 need s, and these resources should include renewable energy in order to provide greater diversity a nd reliability, along with many environmental and societal benefits, including the use of “home gr own” 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 territori es is strongly urged through a process that recognizes and quantifies the exte rnal costs associated with e nvironmental degradation, health and other impacts, including future carbon regulat ion, to the highest extent possible when evaluating the addition of new generation. Relian ce upon cost of service a pproaches that only consider low cost via employment of traditional Integrated Resource Plan, rate making and other embedded planning paradigms that do not incor porate costs to address broader and more complex environmental and extern alities, will lead to continued relia nce upon fossil fuel generation that may not be in the best long term interest of the broader constituents living within and adjacent to the utilit y’s service territories.

SWEPCO stakeholders strongly urge utility mana gement, state regulators, and elected officials which oversee SWEPCO’s operations to adopt policies, procedur es and potentially legislation which will: 1. Establish targets for incorporating and dive rsifying 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 ex tent 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 c onstraints within the SPP, and Entergy RTO regions adjacent to SWEPCO, may limit SWEP CO’s ability to locate or purchase generation from facilities in otherwise cost effective locations 3. Consider expansion of the cl assic definition of renewabl es to include demand side management resources. For example, the St ate of Pennsylvania treats demand response as a tier 2 renewable and allows part of a utility's alternativ e energy goal to be achieved through demand reduction.

New resource additions should al so encourage non-utility owned options which can demonstrate their ability to deliver reliable and competitivel y 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 environmenta l and societal benefits to the people of Arkansas, Louisiana, Texas and the surrounding states.

What follows is how the Renewable Energy St akeholder subgroup priori tized the individual issues developed at the session. A, B, and C is sues 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, Su stainability, 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 – E nvironment / 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 conso lidated 18 issues compiled by the general stakeholders group for evaluation and prioritizat ion with respect to the specific concerns, operational issues, and priorities of this cu stomer 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, so me were combined as they a shared common basis, while one was deleted, as it was not an issue but a question abou t the presentation. After consolidation, this left 13 key issues for th e working group to prioritize. The issues were discussed by the group and through a process of c onsensus 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 Ra nking and Priorities

RELIABILITY 

### Priority Ranking #1: “ensuring a high level of reliabi lity of supply to the customer” (issue #5) The first priority of the Whol esale/Retail/Municipal (WRM) work ing group is the reliability of the supply and delivery systems, as this is fu ndamental to meeting the needs of the working group’s direct customers. While it is understood th at “reliability” is imp licit 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 safe ty as well as modern conveniences, and outages are costly for comm ercial, retail and manufacturing. Baseload, intermediate, and peaking resources must remain adequate to reliably meet present and future demand for power, including rese rves 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 WR M group is the ability of the utility to provide adequate power supply at a reasonable market competitiv e cost. The group felt this was fundamental to sustained economic development. Consumers living on a fixed income suffer economic distress from rising power costs. Ma nufacturing facilities that are energy intensive may no longer be viable if power costs incr ease beyond certain economic thresholds. Economic development and job growth depend on long-ter m stability of power costs with minimal escalation. Demand-side management, greenhouse gas mitigation, and renewable energy are all issues advocated by the WRM gr oup (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 is sues can only be addressed through integrated partnerships between the va rious state agencies, suppliers, and regional transmission entities. Specific examples are rede velopment of nuclear generation capabilities and the expansion of regional and national transm ission capacity. Nuclear, although costly to develop, may, in the long-term, address both th e drive for low-cost reliable power and sustainability initiatives. Nucl ear 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 m itigating greenhouse gases. Another area where partnership and cooperation can benefit the end user is thr ough the economy of scale when looking at new generation capacity. Co-ownership ma y allow for a larger pl ant and overall lower cost of energy. Potential oppor tunities 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 IR P issue, transmission constrai nts continue to plague our industry, to wit:

 The “seams” issue needs to be addressed be tween Entergy and the SPP. The separation of Entergy from the SPP as a whole frustrat es 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 righ t to develop and ex tend 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 SE P/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 mu ch risk or exceed jurisdictional authority for any singular partner to overcome. In fact, it was the consensus of the group that resolu tion of these issues will likely require leadership at the fede ral 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 th rough a more broadly implemented and aggressive DSM program. Below are two examples of speci fic areas of recomme ndation though there are certainly others.

 Expansion of traditional DSM programs us ing 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 technologi es. 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 aggres sive 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 ge neration facilities. Conservation lowers cost and lowers greenhous e gas production. SWEPCO should continue the investment at the current level, and consider ad ditional 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. SW EPCO is encouraged to look to other of its operating units, the Arkansas PSC an d the Arkansas Energy Office for best in class DSM programs.

GREENHOUSE GAS MITIGATI ON & RENEWABLE ENERGY Priority Ranking #6: “greenhouse gas mitigation” (issue #14) and “CO 2 

### mitigation” (issue #16); “customer options for rene wable supply purchasing” (issue #3); “poultry litter biomass power plant” (option #6); and “renewables (wind; solar)” (option #8) The final grouping of issues a ssigned a specific priority by the WRM sub-group concerned Green House Gas (GHG) issues and Renewabl e Energy technologies. The discussion centered around how these emerging group of issues w ill factor into the IR P 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 advoc ate unilateral GHG reduction acti ons on the part of SWEPCO in Arkansas, as this could likely have majo r cost of service and economic development implications. The WRM sub-group’s recomme nded approach for implementation of GHG controls or reduction targets was that these shoul d come from the federal level so as to not disadvantage any one specific service terr itory, group of consumers, or State. At the stakeholder meeting, several retail cust omers 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 op tions that have a lowe r carbon footprint, for example:

 Displacing coal/lignite res ources with natural gas.

 Displacing coal/lignite/g as with nuclear power. SWEPCO should continue to pursue a “cap and trad e” program, and should continue to explore cost effective means of CO 2 

### 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 fo r purchasing power from renewable energy sources. What the WRM sub-group would advocat e 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 br oader 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 te rm cost stability. SWEPCO s hould continue pursuing cost effective renewable wind and solar power. Alt hough the cost of renewable power is currently high, increments of renewable energy allow for a reasonable blende d 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 si gnificant with respect to t hose 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 Reliabi lity, 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 Divers ity, 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 at tend 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 wi th respect to their issues and priorities, to make comments on the process, or otherwise provide i nput to the final report appropriate to their perspective. They are incl uded 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 Arka nsas relative to th e 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 pr ovide an “informational report” that can be used for “planning” by the Commission. 5



### Among the objectives of an IRP is “comp arable consideration of demand and supply resources.” 6 

### Such consideration includes “devel opment of a range of outcomes that complement the long-term forecasts of elect ricity demand (MW) and energy consumption (kWh). 7 

### The range of demand response activities, such as efficiency, conservation, demand-side management, interruptible loa d, 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 cr iteria. 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 probi ng analysis of efficiency and demand response scenarios is an essential objective, Audubon Arkansas sugg ests that more complete information about demand, energy consumption, and the potential for demand response and efficiency efforts to meet varying levels of potential demand s hould 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 SWEP CO 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 a nd energy consumption to be served through efficiency and demand response? Smart mete ring alone has been estimated at several percentage points of capacity in some juri sdictions. The overall po tential for demand and energy consumption reductions should be e xplored under a reasonable range of carbon cost, fuel cost, and cost recovery scenarios.

 As SWEPCO is aware, FERC and some state PS C’s are considering the use of efficiency and demand response to provide transmission be nefits. What is the potential for such efforts to benefit Arkansas?

 What would be the emissions benefits of th ese potential efficiency and demand response scenarios?

The information needed to answer these que stions would help to meet the objectives identified in the IRP guidelines. This info rmation would allow stakeholders to understand how overall demand might be affected by mark et 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 furthe r discussion, analysis a nd 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 c ohesive Stakeholder Report, the consensus decision of the group was to look at the issues from three broad interest perspectives. The stakeholders decided to divi de 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 in formation provided by AEP/SWEPCO, and with respect to the perspec tives and priorities of the other representatives at the meeting. On behalf of the attendees at the IRP Stake holders Meeting, we a ppreciate the efforts of AEP/SWEPCO, and of the Arkansas Public Service Commission for the opportunity to participate in the process. This conc ludes the report of the stakeholders.

Respectfully Submitted,

Lawrence Scott Turley, PE Director, Utility Operations The University of Arkansas Acting Secretary for the Stakeholder Group