# INTEGRATED RESOURCE PLAN

The Integrated Resource Plan (IRP) is ba sed upon the best available information at

the time of preparation. However, change s that may impact this plan can, and do, occur without notice. Therefore this plan is not a commitment to a specific course of action, since the future, now more than ever before, is highly uncertain, particularly in light of the current economic conditions , access to capital, the movement towards increasing use of renewable generation and e nd-use efficiency, as well as legislative proposals to control greenhouse gases.

The implementation action items as describe d herein are subject to change as new information becomes available or as circumstances warrant.

.



# 2012-2021 Date Issued: October 1, 2012

### PSO 2012 Integrated Resource Plan

TABLE OF CONTENTS

1.0 INTRODUCTION .............................................................................................................. ...................................... 1

1.1 O VERVIEW



### ............................................................................................................................... .................................. 1 1.2 IRP P ROCESS



### ............................................................................................................................... ............................... 1 1.3 I NTRODUCTION TO 

### PSO............................................................................................................................

.................... 2 1.4 E NVIRONMENTAL 

### R EGULATIONS



### ............................................................................................................................... ...... 5 1.5 EPA S ETTLEMENT 

### (N ORTHEASTERN 

### 3 & 4 S ETTLEMENT 

### )

.................................................................................................... 6

2.0 LOAD FORECAST AND FORECASTING METHODOLOGY ...................................................................... 11

2.1 L OAD AND 

### D EMAND 

### F ORECAST



### ‐ P ROCESS 

### O VERVIEW



### ...................................................................................................... 11 2.2 P EAK 

### D EMAND 

### F ORECAST



### ............................................................................................................................... ............ 13 2.3 L OAD 

### U NCERTAINTY



### ............................................................................................................................... .................... 14 2.4 PSO C URRENT 

### D EMAND



### ‐ S IDE 

### R ESOURCES



### ..................................................................................................................... 15 2.4.1 Energy Efficiency

............................................................................................................................... ............ 15 2.4.2 Demand Response

............................................................................................................................... ......... 17 2.4.3 Smart Grid

............................................................................................................................... ...................... 17

2.4.3.1 gridSMART ® Smart Meter Pilots

............................................................................................................................... 17 2.4.3.2 Voltage /VaR Optimization (VVO)

............................................................................................................................ 17 2.4.3.3 Distributed Generation

............................................................................................................................... ............. 19 

### 2.4.4 Demand

‐ Side Resource Summary

................................................................................................................. 19

3.0 EXISTING RESOURCES AND TRANSACTIONS ....................................................................................... .... 21

3.1 C URRENT 

### R ESOURCES



### ............................................................................................................................... .................. 21 3.2 E XISTING 

### PSO G ENERATING 

### R ESOURCES



### ....................................................................................................................... 21 3.3 C APACITY 

### N EEDS 

### A SSESSMENT



### ............................................................................................................................... ...... 24 3.4 I MPACTS OF 

### E NVIRONMENTAL 

### C OMPLIANCE 

### P LAN



### ........................................................................................................... 25 3.5 D EMAND 

### S IDE 

### A LTERNATIVES



### ............................................................................................................................... ....... 25 3.5.1 Background

............................................................................................................................... .................... 25 3.5.2 Energy Efficiency

............................................................................................................................... ............ 26 3.5.3 Demand Response

............................................................................................................................... ......... 26 3.5.4 Smart Grid

............................................................................................................................... ...................... 26 3.5.5 Distributed Generation

............................................................................................................................... .. 26 3.6 AEP

‐ SPP T RANSMISSION



### ............................................................................................................................... ............ 27 3.6.1 Transmission System Overview

..................................................................................................................... 27 3.6.2 Current AEP

‐ SPP Transmission System Issues

............................................................................................... 27

3.6.2.1 The SPP Transmission Planning Process

.................................................................................................................. 27 3.6.2.2 PSO

‐ SWEPCO Interchange Capability

...................................................................................................................... 29 3.6.2.3 AEP

‐ SPP Import Capability

............................................................................................................................... ........ 30 3.6.2.4 SPP Studies that may Provide Import Capability

..................................................................................................... 30 

### 3.6.3 Recent AEP

‐ SPP Bulk Transmission Improvements

....................................................................................... 31 3.6.4 Impacts of New Generation

.......................................................................................................................... 32 3.6.5 Summary of Transmission Overview

............................................................................................................. 34

4.0 HEDGING: RISK MANAGEMENT .................................................................................................. .................. 35

4.1 I NTRODUCTION



### ............................................................................................................................... .......................... 35 4.2 H EDGING 

### N OW AND FOR THE 

### S HORT



### ‐ T ERM



### ................................................................................................................... 35

### PSO 2012 Integrated Resource Plan

4.3 PSO’ S 

### F UEL 

### S UPPLY 

### M IX 

### & R EGIONAL 

### M ARKET 

### S TRUCTURES 

### A RE 

### C HANGING



### ...................................................................... 37 4.4 H EDGING FOR THE 

### L ONGER



### ‐ T ERM



### ............................................................................................................................... . 38

5.0 MODELING PARAMETERS........................................................................................................ ....................... 42

5.1 M ODELING AND 

### P LANNING 

### P ROCESS



### – A N 

### O VERVIEW



### ..................................................................................................... 42 5.2 M ETHODOLOGY



### ........................................................................................................................................................ 42 5.3 F UNDAMENTAL 

### M ODELING 

### I NPUT 

### P ARAMETERS



### ............................................................................................................. 43 5.3.1 CO 2 

### Forecast

.................................................................................................................................................. 46

6.0 RESOURCE PORTFOLIO MODELING ............................................................................................... ............ 47

6.1 T HE 

### S TRATEGIST 

### ® M ODEL



### ‐ A N 

### O VERVIEW



### .................................................................................................................... 47 6.1.1 Key Input Parameters

................................................................................................................................... 49 6.2 S TRATEGIST 

### ® O PTIMIZATION



### ....................................................................................................................................... 49 6.2.1 Purpose

......................................................................................................................................................... 49 6.2.2 Strategic Portfolios

....................................................................................................................................... 50 6.3 PSO P LAN 

### D EVELOPMENT



### .......................................................................................................................................... 51 6.4 M ODELING 

### R ESULTS



### .................................................................................................................................................. 54

7.0 CONCLUSIONS AND RECOMMENDATIONS............................................................................................ .... 56

7.1 C APACITY AND 

### E NERGY 

### P LAN



### ....................................................................................................................................... 56 7.2 P LAN 

### S UMMARY



### ....................................................................................................................................................... 57 7.3 F IVE 

### Y EAR 

### A CTION 

### P LAN



### ............................................................................................................................................. 57 7.4 C ONCLUSION



### ............................................................................................................................................................ 58

APPENDIX ...................................................................................................................... ............................................. 60

E XHIBIT 

### A: D EMAND



### ‐ S IDE 

### R ESOURCES



### .................................................................................................................................. 1 E XHIBIT 

### B: F UEL 

### S UPPLY 

### P LAN



### ........................................................................................................................................... 27 E XHIBIT 

### C: T ECHNICAL 

### A DDENDUM



### .................................................................................................................................... 63 E XHIBIT 

### D: T ECHNICAL 

### C ONFERENCE 

### T RANSCRIPT



### ................................................................................................................ 104

### PSO 2012 Integrated Resource Plan



## Cross Reference Table Requirement from OAC 165:35-37-4(c) Location of PSO’s Response (1) Schedule A: An electric de mand and energy forecast IRP pp. 11-15 (2) Schedule B: A forecast of capacity and energy contributions from existing and committed supply- and demand-side resources IRP pp. 15-27

(3) Schedule C: A description of transmission capabilities and needs covering the forecast period IRP pp. 27-34

(4) Schedule D: An assessment of need for additional resources IRP pp. 21-25 (5) Schedule E: A description of the supply, demand-side and transmission options avai lable to the utility to address the identified needs IRP pp. 21-34

(6) Schedule F: A fuel procuremen t plan, purchased-power procurement plan, and risk management plan Appendix, Exhibit B pp. 27-62

(7) Schedule G: An action plan id entifying the near-term (i.e., across the first five [5] years) actions th at the utility proposes to take to implement its proposed resource plan IRP pp. 56

(8) Schedule H: Any proposed RFP( s), supporting documentation, and bid evaluation procedures by which th e utility intends to solicit and evaluate new resources Appendix, Exhibit B pp. 43-57

(9) Schedule I: A technical append ix for the data, assumptions and descriptions of models needed to understand the derivation of the resource plan IRP pp. 42-54

(10) Schedule J: A description a nd analysis of the adequacy of its existing transmission system to determine its capability to serve load over the next ten (10) years, includi ng any planned proposed changes to existing transmission facilities IRP pp. 27-34

(11) Schedule K: An assessment of the need for additional resources to meet reliability, cost and price, environmental or other criteria established by the Commission, the State of Oklahoma, the Southwest Power Pool, North American Electric Reliability Council, or the Federal Energy Regulatory Commission. This assessment should address both base line forecast condition and impo rtant uncertainties, including but not limited to load growth, fuel pr ices, and availability of planned supplies IRP pp. 21-26

(12) Schedule L: An analysis of th e utility’s proposed resource plan and any alternative scenarios necessary to demonstrate how the preferred plan best meets the planning criteri a. Technical appendices should be included to document the planning an alysis and assumptions used in preparing this analysis IRP pp. 47-58

(13) Schedule M: A descripti on and analysis of the Utility’s consideration of physical and fi nancial hedging to determine the Utility’s ability to mitigate price vol atility for the term covered by the IRP IRP pp. 35-41

### PSO 2012 Integrated Resource Plan

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## 1.0 Introduction

1.1 Overview This report presents the Integrated Resource Plan (“IRP” or “Plan”) for Public Service Company of Oklahoma (PSO or Company) including descrip tions of assumptions, study parameters, and methodologies. The results incorporate the integra tion of supply-side resources and demand-side management (DSM) programs.

The goal of the IRP process is to demonstrate the amount, timing and type of resources required to ensure a reliable supply of power and ener gy to customers at th e least reasonable cost. In addition to developing a l ong-term strategy for achieving reliability/reserve margin requirements as set forth by the Southwest Powe r Pool (SPP), capacity resource planning is critical to PSO due to its impact on:

 Determining Capital Expenditure Requirements —which represents one of the basic elements of the Company’s long-term business plan.

 Regulatory Filings —this planning process is a cr itical component of recovery filings that will reflect input base d on a prudent planning process.

 Integration with other Strategic Business Initiatives —generation/capacity resource planning is naturally integrated with the Company’s current and anticipated environmental compliance, transmission planning, and other corporate planning initiatives such as gridSMART ®



## .

1.2 IRP Process This IRP covers the processes and assumptions required to develop the Plan for PSO. The IRP process consists of the following steps:

 Description of the Company, the resource planning process in general, and the implications of current issues as they relate to re source planning.

 Provide projected growth in demand and energy which serves as the underpinning of the plan.

 Identify and discuss demand-side options.

 Identify current supply resources, includi ng projected changes to those resources ( e.g., de-rates or retirements), and tran smission system integration issues.

### PSO 2012 Integrated Resource Plan

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##  Identify and describe supply-side resource options.

 Describe the analysis and assumptions that w ill be used to develop the plan such as Regional Transmission Organization (R TO) reserve margin criteria, and fundamental modeling parameters.

 Perform resource modeling and use the resu lts to develop portfolios, including the selection of the ultimate plan.

 Present the findings and recommendati ons, Action Plan and, finally, Plan implications on PSO.

1.3 Introduction to PSO PSO is an affiliate company of American El ectric Power (AEP). With more than five million customers and serving parts of 11 states, AEP is one of the country’s largest investorowned utilities. The service territory covers 197,500 square miles in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklaho ma, Tennessee, Texas, Virginia and West Virginia. AEP owns and/or operates 58 generating stations in the United States, with a capacity of approximately 37,000 megawatts (MW). AEP’s cust omers are served by one of the world’s largest transmission and distribution systems. System-wide there are mo re than 39,000 circuit

miles of transmission lines and more than 213,000 miles of distribution lines. 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 m ile area in parts of Arkans as, Louisiana, Oklahoma, and Texas (see Figure 1-1 ). PSO serves approximately 532,000 retail cu stomers in Oklahoma and one wholesale customer. The peak load requirement of PSO’s tota l retail and wholesale cu stomers is seasonal in nature, with distinctive peaks occurring in the summer and winter seasons. The 2011 weather normalized summer and winter peaks we re 4,099 MW and 2,682 MW respectively. PSO’s historical (ten-year average, endi ng 2011) annual peak demand growth rate was 0.27% on a weather-normalized basis. PSO estimates that its 10- and 20-year peak demand average annual prospective growth rates will be 0.03 and 0.29 percent, respectively. This projection assumes the acceleration of energy efficiency initiatives.

### PSO 2012 Integrated Resource Plan

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## PSO’s 10-year ending 2011 growth in annual energy requirements was 0.36 percent, also

on a weather-normalized basis. PSO forecasts its 10- and 20- year average annual energy growth rates to be 0.22 and 0.48 percent, respectively. These estimated growth figures account for current and emerging energy efficiency programs.

On a weather-normalized basis, PSO’s 2011 ener gy sales, plus losses, to its retail and firm-requirement wholesale customer (i.e., inte rnal load) were 18,486 Gi gawatt-hours (GWh).

The weather-normalized 2011 load factor from those total company sa les (weather normalized GWh sales / [MW peak demand x 8,760 hrs. / 1000]) was 51.5% 1 

## , or a level that largely parallels

both historical and projected levels. Figure 1-1: AEP System

Table 1-1 below provides PSO’s long-term (2012-2031) projection of summer peak demand, internal energy, and load f actors. This exhibit also offe rs a comparative view of those projections versus the recent 10-year PSO load history (2002-2011).

1 

### 18,486 GWh / (4,099 MW [weather-normalized] peak demand x 8,760 hrs. / 1,000) = 0.515 load factor.

### PSO 2012 Integrated Resource Plan

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## Table 1-1: PSO Peak De mand and Internal Load

Load Fa ctor

(A) (B) (B)/ [(A)x8760/1000] Total Company Total Company Total Company

Year Yea r 2002 3,786 3,999 2002 17,922 17,906 51.1% 2003 3,879 4,029 2003 17,993 18,061 51.2% 2004 3,773 4,079 2004 18,056 18,427 51.6% 2005 4,043 4,154 2005 18,822 18,722 51.4% 2006 4,169 4,154 2006 18,993 18,845 51.8% 2007 4,175 4,200 2007 19,032 18,966 51.6% 2008 4,200 4,194 2008 18,963 19,056 51.9% 2009 3,994 4,122 2009 18,072 18,379 50.9% 2010 4,168 4,213 2010 19,057 18,646 50.5% 2011 4,407 4,099 2011 19,347 18,486 51.5% (A) (B) 2012 4,424 4,233 2012 18,824 50.8% 2013 4,265 2013 18,899 50.6% 2014 4,283 2014 18,994 50.6% 2015 4,282 2015 19,067 50.8% 2016 4,285 2016 19,155 51.0% 2017 4,292 2017 19,241 51.2% 2018 4,303 2018 19,343 51.3% 2019 4,318 2019 19,458 51.4% 2020 4,326 2020 19,558 51.6% 2021 4,350 2021 19,670 51.6% 2022 4,366 2022 19,781 51.7% 2023 4,379 2023 19,895 51.9% 2024 4,392 2024 20,020 52.0% 2025 4,419 2025 20,148 52.0% 2026 4,442 2026 20,284 52.1% 2027 4,466 2027 20,426 52.2% 2028 4,488 2028 20,582 52.4% 2029 4,515 2029 20,740 52.4% 2030 4,546 2030 20,913 52.5% 2031 4,580 2031 21,098 52.6% 10-Year Historical (2002-2011): 10-Year Historical (2002-2011):

Total Growth 100 Total Growth 581 Compound Annual Growth Rate 0.27% Compound Annual Growth Rate 0.36%

10-Year Forecast (2012-2021): 10-Year Forecast (2012-2021):

Total Growth 117 Total Growth 845 Compound Annual Growth Rate 0.30% Compound Annual Growth Rate 0.49% Compound Annual Growth Rate 0.03% Compound Annual Growth Rate 0.22%

20-Year Forecast (2012-2031): 20-Year Forecast (2012-2031):

Total Growth 347 Total Growth 2,274 Compound Annual Growth Rate 0.42% Compound Annual Growth Rate 0.60% Compound Annual Growth Rate 0.29% Compound Annual Growth Rate 0.48% AFTER EE

AFTER EE BEFORE EE

BEFORE EE

AFTER EE BEFORE EE AFTER EE BEFORE EE Actual Reported Actua l and Proje cte d (Summer) Peak Demand a nd Inte rna l Load PSO (Aug/ Sep-2011 Fcst: SPP Region)

Peak Demand (MW) (Forecasted values are BEFORE Passive DSM)

Total Company Inte rnal Load (GW h) (Forecasted values are BEFORE Passive DSM)

Total Company ActualWeatherNormalized ActualWeatherNormalized Actual Reported

### PSO 2012 Integrated Resource Plan

5 

## 1.4 Environmental Regulations The two major final U.S. EPA rulemakings th at will necessitate the installation of air emissions control equipment are:

 The Regional Haze Rule (RHR) and

 The Mercury and Air Toxics Standards Rule (MATS)

On February 18, 2010, the state of Oklahoma submitted to the U.S. EPA Regional Haze revisions to the Oklahoma State Implementatio n Plan (SIP). On March 22, 2011, the U.S. EPA published its proposed partial approval and disa pproval of the Oklahoma Regional Haze SIP and Federal Implementation Plan (FIP) in the Fede ral Register. The Regional Haze FIP requires 0.06

lbs SO 2 

## /MMBtu on SO 2 

## which is considerably lower than the presumptive limits of 0.15 lbs

SO 2 

## /MMBtu in the RHR. This would require that Northeastern Units 3 and 4 be retrofitted with a DFGD to meet the prescribed SO 2 

## limits within 5 years.

Table 1-2 Drivers for Environmental Controls

Rule Compliance Timeline Northeastern Units 3&4 Environmental Controls

Regional Haze Rule Became effective on January 27, 2012, 5 year compliance deadline Dry Flue Gas Desulfurization (DFGD) Low NO x 

## Burners/Over fire Air (LNB/OFA)

MATS Rule Required by April 16, 2015; likely 1 year extension for major retrofits to April 16, 2016 Dry Sorbent Injection (DSI) Activated Carbon Injection System (ACI) Fabric Filter Baghouse (FF)

The following proposed and emerging federal and state rulemaking requirements may have future impacts on Northeastern Statio n’s environmental c ontrol requirements:

 Cross State Air Pollution Rule 2

2 

### U.S. EPA issued the final CSAPR in July, 2011. The rule wa s to go into effect in January, 2012. The D.C. Circuit Court of Appeals issued a stay of the rule in late December, 2011 pending the outcome of the appeals. On August

### PSO 2012 Integrated Resource Plan

6 

##  Coal Combustion Residuals (CCR) Rule

 Clean Water Act “316(b)” Rule

 Carbon and Greenhouse Ga s (GHG) Regulation

 Revisions to the 1 hour SO 2 

## Primary National Ambien t Air Quality Standard (NAAQS)

 Second planning period under RHR

1.5 EPA Settlement (Northeastern 3 & 4 Settlement) In April 2012, in parallel to the announcement of the negotiated sett lement in principle around the Northeastern coal units, AEPSC, as ag ent for PSO, issued an RFP for 260 MW of base-load capacity and energy and ancillary servi ces for a desired term of 15 years, beginning June 1, 2016. This capacity and energy would serv e to effectively replace Northeastern Unit 4. Specifically, the agreement addresses PSO’s future obligations under the EPA’s Regional Haze rule (RHR) and effectivel y allows PSO to comply with the Mercury and Air Toxics Standard (MATS). Under the agr eement, PSO would meet specif ied emissions rates at both Northeastern coal units, install certain emissions control equipment on one of the Northeastern coal units in 2016, and re tire the other unit in 2016. The coal unit with the emissions controls

would be retired in th e 2025-26 timeframe. The agreement also will result in PSO withdrawing its lawsuit against the EPA regarding the Regional Haze rule. The core terms of the term sheet

include:

1. PSO will submit to Oklahoma Department of Environmental Qual ity (ODEQ), and ODEQ will develop and adopt after public notice and he aring, and the Secretary of Environment for the State of Oklahoma will submit to the EPA, a revised Best Achievable Retrofit Technology (BART) determination with supporting administrative and technical information and visibility modeling for PSO's Northeastern Units 3 and 4 that includes the following

elements: a) ODEQ's SIP revision will include a Regiona l Haze Agreement (RHA) entered into by ODEQ and PSO to effectuate the BART determination.

21, 2012, the D.C. Circuit issued an opinion vacating and remanding CSAPR and ordering that EPA continue to administer CAIR until it promulgates a replacement rule. The court issued an order withholding the mandate in this case until 7 days after the court takes action on any petition fo r rehearing that is timely filed. Until the mandate is issued, the stay previously ordered by the court will remain in effect.

### PSO 2012 Integrated Resource Plan

7 

## b) The RHA will require that by no later than December 31, 2013, PSO will complete

installation of low NOx com bustion technologies and achieve a nitrogen oxide ("NOx")

emission rate of 0.23 lbs/MMBtu on a 30-day rolling average at each of the two coalfired generating units at PSO's Northeastern St ation (Units 3 and 4).

c) The RHA will require that beginning on January 31, 2014, PSO will comply with a new sulfur dioxide ("SO2") emission rate at No rtheastern Units 3 and 4 of 0.65 lbs/MMBtu on a 30-day rolling average, and beginning on December 31, 2014, PSO w ill comply with a

new SO 2 

## emission rate of 0.60 Ib/MMBtu on a 12-month rolling average at Northeastern

Units 3 and 4. PSO will maintain those emission rates until controls are installed at one unit as provided in subparagraph e), and the other unit is reti red as provided in subparagraph d). The RHA will include an alte rnative operating scenario that addresses potential disruption of coal supplies duri ng the time period between January 31, 2014, through April 16, 2016.

d) The RHA will require that PSO retire one of the coal-fired generating units at Northeastern Station by April 16, 2016.

e) 

## The RHA will require that PSO install and operate a dry-sorbent injection system, activated carbon injection system, and a fabr ic filter baghouse, and secure further NOx emission reductions by April 16, 2016, on the coal -fired generating unit at Northeastern Station that will continue to operate. On and after May 16, 2016, PSO will achieve a 0.15

lbs/MMBtu emission rate for NOx on a 30-day rolling average basis, and a 0.40

lbs/MMBtu emission rate for SO 2 

## on a 30-day rolling average basis.

f) 

## The RHA will require that during the first year of operation of the c ontrols requ ired under the RHA, PSO will develop and propose a monitoring program to test various operating profiles and other measures, to determine whether increased SO 2 

## removal efficiencies can be achieved during normal operations. Pursuant to the terms of the RHA, PSO will submit the monitoring program to EPA and ODEQ for review a nd will implement the monitoring program during the second and thir d years of operation of the DSI system. PSO will evaluate and report the results of the monitoring program to EPA and ODEQ,

and if that evaluation demonstrates that the technology is capable of sustainably

### PSO 2012 Integrated Resource Plan

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## achieving an emission rate of less than 0.37 Ibs/MMBtu on a 30-day rolling average basis without (i) altering the unit's fuel supply, (ii) incurring additional capital costs, (iii) increasing operating expenses by more than a negligible amount, and/or (iv) adversely impacting overall unit operations, ODEQ will propose to revise the emission rate in the RHA by 60 percent of the difference between 0.40 and the demonstrated emission rate. ODEQ will work with PSO to maximize the emission reductions resulting from the implementation of this agreement and the enforceable mechanism outlined in paragraph 3 below will only be implemented by ODEQ in the event that an emission rate of 0.30 Ibs/MMbtu is determined to be unachievable under the criteria described above. Upon adoption after notice and opportunity for h earing, the ODEQ will submit the revised RH SIP revision to EPA for approva l. If the demonstrated emissi on rate is 0.37 Ibs/MMbtu or greater, no adjustment will be made to th e RHA, and the emission rate limitation for SO 2 

## at the operating Northeastern coal-fired generating unit in th e RHA will remain 0.40

Ibs/MMBtu.

g) 

## The RHA will require that beginning in cal endar year 2021, the Annual Capacity Factor (calculated for each calendar year as a per centage of MWH based on a rated capacity of 470 MW X 8760 hours) for the operating coal-f ired generating unit at Northeastern

Station will be reduced as follows:

1. 

## to no more than 70% in calendar years 2021 and 2022;

11. 

## to no more than 60% in calendar years 2023 and 2024; and

111. 

## to no more than 50% in calendar years 2025 and 2026. h) 

## The RHA will require that no later than December 31, 2026, PSO will retire the remaining operating coal-fired generating un it at Northeastern Station. However, in calendar year 2021, the RHA w ill require PSO to evaluate whether the projected generation from that unit can be replaced at lower or equal total projected costs from natural gas or renewable resources. Pursuant to the RHA, PSO will provide a copy of the evaluation to EPA and ODEQ. If power is av ailable from such resources at a lower projected total cost (including considerati on of PSO's need to recover its remaining investment in the units), then the operati ng unit will retire no later than December 31,

2025.

### PSO 2012 Integrated Resource Plan

9 

## 2. Nothing in the RHA relieves PSO from its obligati ons to comply with all applicable federal, state, and local laws and regulations, includ ing laws, regulations, and compliance deadlines that become applicable after the date of entry of the RHA. Such laws and regulations include, but are not limited to, the Cross-State Air Poll ution Rule and the Mercury and Air Toxics Standards (MATS). Nothing in the revised BA RT determination for PSO's Northeastern Units 3 and 4 will be construed to provide any relief from the emissions limits or deadlines specified in such regulations, including, but not limited to, deadlines for the installation of pollution controls required by any such regulations.

3. ODEQ also will develop and propose as part of the revised BART determination for PSO, a revision to the Visibility Interstate Transport SIP. This proposed SIP revision will provide an

enforceable mechanism that addresses SO 2 

## reductions from sources ot her than those operated by PSO, to the extent necessary to achieve the anticipated visi bility benefits from the 2018 regional modeling. This proposed SIP revision will be implemented if the SO 2 

## emission rate

for the controlled unit at Northeastern is not reduced to 0.30 Ibs/MMBtu or less as a result of the subparagraph f) provision in paragraph 1.

4. Separately from the RH SIP process, EPA an d PSO will enter into an agreement under which PSO will report biannually to EPA (beginni ng in 2017 for the period 2015-2016, and every second year thereafter through the end of 2025 or 2026, whenever the last Northeastern unit is retired) on the energy produced by PSO's units and the sources of energy secured under PSO's long-term purchased power contracts. The initial report will include similar information for calendar years 2013-2014. Re quests for proposals (RFPs) for long-term purchase power contracts issued between 2013 and the date the reporting obligation ends will specifically seek bids for energy supplied by natural gas and renewable resources. The biannual reports will include copi es of any RFPs issued duri ng the reporting period, and a summary of the capacity or energy secured through any long-term power purchase agreements executed during the reporting pe riod, including the unites) providing the purchased power, the amount of capacity or energy secured under the agreement, and the term of each agreement.

5. An EPA letter to ODEQ and PSO dated July 18, 2012, expresses EPA's support of PSO's comprehensive strategy, and notes that the use of the technologies de scribed in the RHA,

### PSO 2012 Integrated Resource Plan

10 

## when properly designed and operated, would be e xpected to achieve the emission limitations prescribed by the MATS rule issued Februa ry 16, 2012 ("MATS letter" ). If approved by the appropriate EPA and DOJ officials, the parties will enter into a Settlement Agreement in the matter referenced above, which will refer to the MATS letter in a "whereas" or "recital"

clause and the MATS letter will be att ached to the Settlement Agreement.

### PSO 2012 Integrated Resource Plan

11 

## 2.0 Load Forecast and Fo recasting Methodology

2.1 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 PSO internal long-term load and peak demand forecasts were developed by the AEP Economic Forecasting group in August 2011. The electric energy and demand forecast pro cess involves three specific forecast model processes, as identified in Figure 2-1

.

Figure 2-1: Load and Demand Forecast Process

The first process models the consumption of el ectricity at the aggregated customer level: Residential, Commercial, I ndustrial, Other Ultimate customers, and Municipals and Cooperatives. It involves modeli ng both the short- and long-ter m sales. The second process contains models that derive hourly load estima tes from blended short- and long-term sales, estimates of energy losses for distribution and tr ansmission, and class and end-use load shapes. The aggregate revenue class sales and energy lo sses are generally called “net internal energy 

## 1. Monthly Sales Forecast (by FERC Revenue Classes) Short & Long Term

2. Hourly Demand Models

(Load Shapes / Losses)

3. Net Internal Energy Requirements & Demand Forecast Load & Demand Forecast Process – Sequential Steps

### PSO 2012 Integrated Resource Plan

12 

## requirements.” The third proce ss reconciles historical net in ternal energy requirements and seasonal peak demands through a load factor anal ysis which results in the load forecast. The long-term forecasts are developed usi ng a combination of econometric models to project load for the Industrial, Other Ultimate and Municipal and Cooperative customer classes, as well as using Itron Inc. Statistically-Adjus ted End-use (SAE) models for the modeling of

Residential and Commer cial classes. The long-term process starts with an economic forecast provided, under proprietary license, by Moody’s Analytics for the United States as a whole, each state, and regions within each state. These forecasts include projec tions of employment, population, and other demographic and financial variables for both the U.S. as a whole and for specific AEP service territories. The long-term forecasting process inco rporates these economic projections and other inputs to produce a forecast of kilowatt-hour (kWh ) sales. Other inputs include regional and national economic and demographic conditions, energy prices, weather data, and customerspecific information. The AEP Economic Forecasting department empl oys Itron’s Statistically Adjusted Enduse (SAE) models for forecasting long-term Resi dential and Commercial kWh energy sales.

 SAE models are econometric models with end-use features in cluded to account for energy efficiency impacts, such as those included in the Energy Policy Act of 2005 (EPAct 2005) and the Energy I ndependence and Security Act of 2007 (EISA).

 SAE models start with the construction of structured end-use variables that embody end-use trends, including equipmen t saturation levels and efficiency.

Factors are also included to account for changes in energy prices (retail rates), household size, home size, income, and weather conditions.

 Regression models are used to estimat e the relationship between observed customer usage and the structured end-use variables. The result is a model that has implicit end-use structure, but is ec onometric in its model-fitting technique.

 The SAE approach explicitly accounts fo r naturally occurring energy efficiency which has served to slightly lower the forecast of Residential and Commercial

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## class demand and energy in the forecast horizon particularly when federal energy standards such as EPAct 2005 and EISA impacts begin to manifest. AEP uses processes that take advantage of the relative strengths of each method. The regression models typically used in the shorter-term modeling em ploy the latest available sales and weather information to represent the variat ion in sales on a monthly basis for short-term applications. While these models generally prod uce accurate for ecasts in the short run, without specific ties to economic factors they are less capable of capturing the structural trends in electricity consumption that are important fo r longer-term planning. The long-term modeling process, with its explicit ties to economic and demographic fact ors, is appropriate for longerterm decisions and the establishment of the most likely, or base case, load and demand over the forecast period. By overlaying these respectiv e output profiles, AEP Economic Forecasting can then effectively apply the st rengths of both load-modeling a pproaches, thereby achieving a

reasonable validation of such forecasted results.

2.2 Peak Demand Forecast Figure 2-2 identifies the PSO internal demand a nd energy profile as having -0.03% and 0.22%, respectively, compound annua l growth rates (CAGR) in the forecast period. Figure 2-2: PSO Peak De mand and Energy Projection

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## Figure 2-3 reflects PSO’s actual and weather normalized historical and forecast of annual peak demand. PSO’s weather normalized hist orical peak demand has increased 0.18% on a compound annual basis over the last 10 years. Figure 2-3: PSO Historical and Forecast Peak Demand

3,400 3,600 3,800 4,000 4,200 4,400 4,600



## 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022PeakDemandinMW



## Actual Weather Normalized Forecast



## 2.3 Load Uncertainty Two factors of load uncertainty is weather in the short-term and the ga in or loss of large

customer loads. PSO has experienced two successive years of extreme weather with the winters of 2010

and 2011 and summers of 2011 and 2012. These tw o years have produced all-time record seasonal peaks. Prior to 2011, PSO’s historical all-time highest recorded peak demand was 4,200 MW, which occurred in August 2008; and the highest recorded winter peak was 2,903 MW, which occurred in January 2010. The 2011 actual PSO summer a nd winter peak demands were significant at 4,411 MW and 2,8 29 MW, occurring on August 3rd and February 10th, respectively. This all-time PSO summer peak de mand exceeded the previous all-time summer peak demand by 207 MW, or nearly 5 percent. The forecasted 2011 PSO summer peak demand was 4,191 MW, suggesting that summer’s actual p eak demand created an increase versus the forecast of 216 MW, or a 5.1 percent increase.

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## The preliminary 2012 summer peak demand ha s again exceeded the previous all-time summer peak. The preliminary 2012 peak demand is 4,424 MW which is 0.4% above the 2011 peak. It was set on August 1, 2012. The last tw o summers loads have been driven by record setting summer weather. PSO is currently learning about increases in po tential new load as a re sult of increased oil and natural gas production and natural gas pr ocessing and compression that is beyond that reflected in the current peak dema nd forecast. If this new load ma terializes over the next two – three years PSO will need to secu re additional supply- or demand-si de resources to reliably serve

this new load.

2.4 PSO Current Demand-Side Resources

2.4.1 Energy Efficiency PSO has had energy efficiency progra ms in place since 2009. Since 2009, PSO has residential and commercial prog rams that resulted in an a nnual reduction of 53 GWh through year-end 2011. Current and proposed programs are expected to improve th is number to over 300 GWh by year-end 2015. The programs expected to be in place beginning in 2013 are:

 High Performance Business

 Home Weatherization

 High Performance Homes

 Energy Saving Products and Services

 Educational Program They are detailed in the Appendix (see Exhibit A).

The impacts of the current and proposed progr ams, as well as a continuation of programs through 2025 are shown, where the difference betw een installed and fore cast illustrates the measure degradation that results over time. Programs amounting to the installation of approximately 800 GWh of annual reductions are fact ored into the load forecast. These programs place PSO on a pace to exceed the plan pres ented in the 2009 Market Potential Study. Currently, energy efficiency programs are lim ited to the residential and commercial sectors; industrial customers ha ve the ability, and have in most part chosen, to opt out.

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## Additionally, residential programs are limited by a spending cap, which is proving to limit the size of consumer programs. It is assumed that these limitations will persist.

Figure 2-4: Energy Efficiency Energy Savings

0 100 200 300 400 500 600 700

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021AnnualEnergySavingsfromEnergyEfficiency(GWh)

Installed but "degraded" Forecast EE impacts Market Potential Study Mid Case



## Figure 2-5: Annual Energy Consumption

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## The energy efficiency programs result in a 35 % reduction in the growth rate of energy consumption, and represent installation of 0.5% to 0.65% of previous years’ applicable retail

sales.

2.4.2 Demand Response PSO currently has 77 MW of demand respons e capability. It is constituted of the Business Demand Response Program (56MW), and in terruptible tariffs (22MW). Residential

direct load control has been discontinued. PSO expects to grow demand response capability to 150 MW by 2025, primarily in the comme rcial and industr ial sectors.

2.4.3 Smart Grid

2.4.3.1 gridSMART ® 

## Smart Meter Pilots PSO’s gridSMART ® 

## project includes up to 16,000 smar t meters, distribution automation and Volt/VaR Optimization equipment, and cons umer energy management devices. The total cost of the project is estimat ed at $17.88 million. PSO was awar ded an $8.7 million low-interest loan from the Oklahoma Department of Commer ce’s federal stimulus fund, and $2 million is collected annually through base rates to support the project. The initial phase replaced approximately 14,000 analog meters with digital smart meters and established a network for two-way comm unication in Owasso, Ok lahoma. Another 1,000 meters on the University of Tulsa campus were replaced this year. A website is available for customers to learn how their smart meters work, access their usage information, and better understand the benefits they provide. Future phases of the project will measure the response by cu stomers to time-of-use rates in conjunction with technologies such as in-home displays, programmable two-way communicating thermostats, and a home energy ma nager with remote access and control via the web. Because this program is still in the piloti ng and testing phase, expected impacts are not yet incorporated into the load forecast.

2.4.3.2 Voltage /VaR Optimization (VVO) PSO will employ VVO to achieve energy and demand savings, and distribution automation technology will help to reduce customer outages. VVO provi des all of the benefits of power factor correction, voltage optimization, and condition-based maintenance in a single, optimized package. In addition, VVO enable s conservation voltage reduction (CVR) on a

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## utility’s system. CVR is a process by which the ut ility systematically re duces voltages in its distribution network, resulting in a proportional reduction of load on the network. A 1 percent reduction in voltage typically results in a 0.5% to 0.7% reduction in load.

As the electric infrastructure was built out in the last century, distribution systems were designed to assure end-users received voltages ranging from 114 to 126 volts in accordance with national standards. Most utility systems were de signed so that customers close to the substation received voltages close to 126 vo lts and customers farther from the substation received lower voltages. This design kept line construction cost s low because voltage regulating equipment was only applied when necessary to assure the requ ired minimum voltages were provided. However, since most devices operated by electricity, esp ecially motors, are designed to operate most efficiently at 115 volts, any excess voltage is t ypically wasted, usually in the form of heat. Tighter voltage regulation, enabled by smart-grid infrastructure, allows end-use devices to operate more efficiently without any action on the part of consumers (see Figure 2-6). Consumers will simply use less ener gy to accomplish the same tasks. Not all circuits are good economic candida tes for VVO. Currently, PSO anticipates fitting distribution circuits serving 62% of its load with the new technology.

Figure 2-6: Integrated Vo ltage/VaR Optimization

PSO anticipates accelerating and increasing the roll-out of VVO technology relative to what was in the August 2011 forecast. This accel eration and increase in the VVO plan amounts to a decreased requirement of 20MW by 2021 relativ e to the forecast used in the IRP modeling (see Table 2-1). This variation would not materially affect the modeling results.

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## Table 2-1 VVO Technology-Energy Demand Reductions

Aug 2011 Forecast 

## 2014 2015 2016 2017 2018 2019 2020 2021 Peak Demand (MW)

- - - 10 20 28 37 45 Energy (GWh) - - - 42 84 118 156 189 Revised Plan 

## Peak Demand (MW)

‐ 7 13 22 32 43 55 65 Energy (GWh) - 28 56 91 133 182 232 275



## 2.4.3.3 Distributed Generation PSO has a net-metering tariff in place which allows the integration of customer-sited generation into the distribution system. The program is currently nominal with aggregate generation less than 1 MW across the system.

2.4.4 Demand-Side Resource Summary PSO has a demand-side program that employs consumer energy e fficiency programs, demand response, and the newest smart grid technol ogies to meet its resource needs. Under the current plan, demand-side resource reduces cap acity requirements by 166 MW (see Table 2-2) from the current capability by 2021.

Table 2-2 Demand-Side Resource Summary 3



### 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Energy Efficiency 26 38 48 56 64 70 75 79 83 85 Demand Response 77 80 86 93 99 129 132 134 136 139 Grid Smart (VVO) - - 

## ‐ ‐ 10 20 28 37 45 Distributed Generation 0 0 0 0 0 0 0 0 0 0 Total Demand-Side 103 118 134 149 163 209 227 241 257 269



## Table 2-3 offers a summary of the latest long-t erm projection of PSO’s DSM activity.

3 

### Table 2-3 reflects DR consistent with the 2013-2015 Demand Portfoli (PUD 201200128) and varies only from the modeling assumptions in those years.

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## Table 2-3: Projected DR and EE

Projected Demand Reduction and Energy Efficiency PSO (Aug/Sep-2011 Fcst)

+

Year Interruptibl

e DLM/ELM/ RTP Tariff New PSO DR

Goals TOTAL PSO Consumer Programs V V O TOTAL PSO 2012 13 64 0 77 26 0 26 2013 13 64 0 77 38 0 38 2014 13 64 0 77 48 0 48 2015 13 64 0 77 56 0 56 2016 13 64 23 99 64 0 64 2017 13 64 53 129 70 10 80 2018 13 64 55 132 75 20 95 2019 13 64 57 134 79 28 108 2020 13 64 60 136 83 37 119 2021 13 64 62 139 85 45 130 2022 13 64 65 142 87 45 132 2023 13 64 68 144 88 45 133 2024 13 64 70 147 89 45 133 2025 13 64 73 150 89 45 134 2026 13 64 73 150 89 45 134 2027 13 64 73 150 89 45 134 2028 13 64 73 150 89 45 134 2029 13 64 73 150 89 45 134 2030 13 64 73 150 89 45 134 2031 13 64 73 150 89 45 134 10-Year Forecast (2012-2021): Total Growth Compound Annual Growth Rate 20-Year Forecast (2012-2031): Total Growth Compound Annual Growth Rate + = "PASSIVE" ENERGY EFFICIENCY (EE) PROGRAMS

* T OT AL DEMAND REDUCTION Peak Reduction (MW)

133 "ACT IVE" DEMAND RESPONSE (DR)

103 Peak Reduction (MW) Peak Reduction (MW)

166 11.3%

180 283 274 277 280

283 283 283 115 124 TOTAL

PSO

283 283 283

5.5% 163 209 227 242 256 269

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## 3.0 Existing Resources and Transactions

3.1 Current Resources The initial step in the IRP process is th e demonstration of the capacity resource requirements. This needs assessmen t must consider projections of:

 

## Existing capacity resources—current levels and anticipated changes

 

## Anticipated changes in capability due to efficiency and/or environmental retrofit projects

 

## Changes resulting from decisions su rrounding unit disposition evaluations

 

## Regional and sub-regional capacity and transmission constraints/limitations

 

## Load and (peak) demand

 

## Current DSM

 

## SPP capacity reserve margin and reliability criteria

3.2 Existing PSO Generating Resources The underlying minimum reserve margin criterion to be utilized in the determination of PSO’s capacity needs is based on the current Southwest Power Pool (SPP) minimum capacity margin of 12 percent. 4 

## As a function of peak demand this converts to an equivalent “reserve margin” of 13.6 percent. 5



## Table 3-1 provides the Company’s detailed Cap acity, Demand and Reserves (CDR) report for the 15-year period through the year 2025 assuming no new cap acity additions. In addition to identifying current projected peak de mand requirements of its internal customers, it also identifies the MW capability of resources that are projected to be required to meet the minimum SPP reserve margin criterion. For instance, at the beginning of the first forecasted (2012) SPP planning year, 6 

## it indicates PSO is expected to rely on 4,268 MW of owned generating capability (sea sonal ratings) to achieve this threshold.

4 

### Per Section 2.1.9 of the “Southwest Power Po ol Criteria” (Latest Revision: April 25, 2011). 5 

### 0.12 / (1 – 0.12) = 0.136. 6 

### For capacity planning/reporting purposes, SPP operates on a June (Year X) -through- May (Year X+1) fiscal year basis.

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## Table 3-1: Capacity, Demand a nd Reserve (CDR) “Going In”

CAPABILITY (MW)

11 ACT 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Plant Capabilities 4,346 4,268 4,268 4,268 4,268 4,268 4,268 4,268 4,268 4,268 4,268 Adjustments to Plant Capability 0 0 0 0 0 -5 -10 -10 -10 -10 -10 Net Plant Capability 4,346 4,268 4,268 4,268 4,268 4,263 4,258 4,258 4,258 4,258 4,258 S ales W it hout Res erves 0 0 0 0 0 99 106 130 157 176 200 Purchases Without Reserves 215 556 556 554 554 554 552 552 555 554 554

Total Capability 4,561 4,824 4,824 4,822 4,822 4,718 4,704 4,680 4,656 4,636 4,612

DEMAND (MW) 11 ACT 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Peak Demand before passive DSM 4,407 4,233 4,265 4,283 4,282 4,285 4,292 4,303 4,318 4,326 4,350 Passive DSM 0 26 38 48 56 64 80 95 108 119 130 Peak Demand 4,407 4,207 4,227 4,235 4,226 4,222 4,212 4,208 4,210 4,207 4,220 Active DSM 31 77 77 77 77 99 129 132 134 136 139 Firm Demand 4,376 4,130 4,150 4,158 4,149 4,123 4,083 4,076 4,076 4,071 4,081 Other Demand Adjustments 3 32 32 33 37 37 37 38 38 39 39 Native Load Responsibility 4,373 4,098 4,118 4,125 4,112 4,086 4,046 4,038 4,038 4,032 4,042 S ales wit h Res erves 0 0 0 0 0 0 0 0 0 0 0 Purchases with Reserves 39 39 39 39 39 39 39 39 39 39 39 Load Responsib ility 4,334 4,059 4,079 4,086 4,073 4,047 4,007 3,999 3,999 3,993 4,003

PSO RESERVES 11 ACT 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Reserve Capacity 227 765 745 736 749 671 697 681 657 643 609 % Reserve Margin 5.2% 18.8% 18.3% 18.0% 18.4% 16.6% 17.4% 17.0% 16.4% 16.1% 15.2% %Capacity Margin 5.0% 15.9% 15.5% 15.3% 15.5% 14.2% 14.8% 14.6% 14.1% 13.9% 13.2% Reserve Above 12% Capacity Margin (364) 212 189 179 193 119 151 136 112 98 64



## TABLE 3-2 below identifies the generating res ources identified in the CDR Section. PSO currently utilizes several other capacity entitlements to meet the minimum SPP reserve margin requirement. As set forth in Figure 3-1 beginning in 2012, PSO began to receive approximately 512 MW of generating capacity unde r a 10-year power purchase agreement (PPA) with Exelon Generating Company LLC, from the Green Country Generating Station located in Jenks, OK.

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## TABLE 3-2

Coal Units:

 Northeastern Unit 3 (460 MW) located in Oologah, OK. In-service 1979

 

## Northeastern Unit 4 (470 MW) located in Oologah, OK. In-service 1980

 

## Oklaunion Unit 1 (101 MW*) located in Vernon, TX. In-service 1986



## Gas-Steam Units:

 

## Northeastern Unit 2 (430 MW) located in Oologah, OK. In-service 1970 

###  

## Riverside Units 1&2 (909 MW) located in Jenks, OK. In-service 1974 & 76 

###  

## Southwestern Units 1&2 (155 MW) located in Anadarko, OK . In-svc 1952 & 54

 

## Southwestern Unit 3 (311 MW) located in Anadarko, OK. In-service 1967

 

## Tulsa Units 2&4** (309 MW) located in Tulsa, OK. In-service 1963 & 64 

## Gas-Combined Cycle Units:

 Comanche Unit 1 (235 MW) located in Lawton, OK. In-service 1974

 

## Northeastern Unit 1 (422 MW) located in Oologah, OK. In-service 2001 

## ***

Gas-Combustion Turbine Units:

 

## Weleetka Units 4-6 (156 MW) located in Weleetka, OK. In-service 1975 & 76

 

## Riverside Units 3&4 (143 MW) located in Jenks, OK. In-service 2008

 

## Southwestern Units 4&5 (142 MW) located in Anadardo , OK. In-service 2008



## Diesel Units : 

##  Eight (8) Diesel units at Six PSO Plant Locations (Sum: 25 MW)

2012 Total Generating Plant Capa bility (CDR, Section 1) 4,268 MW * reflects PSO’s 15.62% ownership share 

### ** Tulsa Unit 3(65 MW) was recently removed from service 

### *** NE1 was converted from a gas-steam unit that was originally placed in-service in 1970



## Additionally, PSO currently has a total of 691 MW (nameplate rating) of wind capacity from five wind facilities in which the Compan y is receiving energy, capacity, and renewable energy credit attributes under separate renewa ble energy purchase agreements. For capacity resource planning purposes, however , an important distinction is that SPP criteria also dictates that intermittent resources such as wind may only recognize a small portion of such nameplate

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## capacity rating. Specifically, the latest SPP Cr iteria (January 30, 2012 Revision), Section 12.1.5.3, describes the approach for establishing such seasonal ratings for wind (and solar) resources. Using those guidelines, as shown on th e Figure 3-1 CDR, PSO is only able to count 44 MW of these wind resources for capacity planning purposes.

3.3 Capacity Needs Assessment

Based on the assessment of the AEP-SPP cu rrent resources and its peak demand projections (Section 2); a capacity needs assessmen t can be established that will determine the amount and timing of capacity resour ces for this 2012 PSO IRP cycle. Figure 3-1 summarizes the going-in capacity position through the 10-year 2012 IRP window. No new capacity additions are needed during this period. Figure 3-2 compares the demand (line) and capacity (b ar) trends over the period. Figure 3-2 reflects the culmination of the separate impacts.

Figure 3-1 Capacity vs. SPP Minimum Required Reserves

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## Figure 3-2 Summary of Capacity Deficiency Position

3.4 Impacts of Environmental Compliance Plan As a result of the environmental rules, th ere are significant exposures surrounding the future operations of PSO’s coal units. Based on the prospects of an Oklahoma Regional Haze Rule (RHR) State Implementation Plan (SIP) an d the established requirements of the Mercury Air Toxic Standard (MATS) rulemaking, it would s uggest that Northeastern Units 3 and 4 will ultimately require nitrogen oxide (NO X 

## ), sulfur dioxide (SO 2 

## ), hazardous air pollutant (HAP) and acid gas emission reductions und er the RHR and MATS as well as mercury emission reduction requirements also under the MATS. In essence, the Northeastern coal units are likely to either require controls (DSI, ACI, and FF Baghous e) by 2016 assuming the one year compliance deadline extension is granted by ODEQ or ceas e operations as early as the MATS rule implementation date of April 2015.

3.5 Demand Side Alternatives

3.5.1 Background Demand side management in this IRP refers to investments made by the utility, typically behind the meter, to reduce customer demand at va rious times. Generally, these investments fall

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## into four categories: 1. Energy Efficienc y, 2. Demand Response, 3. Smart Grid, and 4.

Distributed Generation

3.5.2 Energy Efficiency Energy efficiency programs offer consumers in centives to replace or otherwise purchase end-use devices (light bulbs, air conditioners, refrig erators, e.g.) that are more efficient than the current code or standard requires. Similarly, it applies to measures such as insulation that improve the thermal efficiency relative to the cu rrent state or a code or standard, whichever is applicable. Efficiency measures tend to have a greater impact of energy consumption than on peak demand.

3.5.3 Demand Response Demand response refers to the immediate reduc tion in load at times of peak demand on the system. For a monetary incentive, customers ag ree to reduce load within an allocated time of receiving a signal from the utility. The demand re sponse mechanism can be as simple as a direct

load control device that turns o ff an air conditioner oras sophisticated as a programmed suite of controls that selectively reduces load on several systems, minimi zing the impact to occupants or businesses. The ability to reduce load in these peak times defers the need to build additional generation as well as limits the time that less-e fficient utility generators are called upon to run.

3.5.4 Smart Grid Smart Grid investments are improvements to th e distribution grid, up to and including the meter. In a general sense, it is the replacemen t of dumb analog devices with smart digital ones that are capable of communicating in both directions. The ability to provide immediate feedback to the consumer and the utility enables the utilit y to charge time-differentiated rates which, in theory, would reduce consumption in the most expensive hours of the day, reducing over-all system costs. Other grid improvements can save energy through reduced voltage requirements in a way that is transparent to the end-user.

3.5.5 Distributed Generation Distributed generation resources refer to sma ll, dispersed generati on that partially or completely satisfies the load requirements of the customer with surplus/(deficit) generation being sold/(purchased) from the utility. Distributed generation typically includes customer-sited

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## solar, wind, and combined heat and power (CHP ). Back-up (emergency) generators are not counted here, but may be consider ed as demand-response resources.

3.6 AEP-SPP Transmission

3.6.1 Transmission System Overview The portion of the AEP Transmission System operating in SPP (AEP-SPP zone) consists of approximately 1,290 miles of 345 kV, approxi mately 3,490 miles of 138 kV, and 2,320 miles of 69 kV. The AEP-SPP zone is also integrated with and directly c onnected to ten other companies at 89 interconnection points, of whic h 71 are at or above 69 kV and to ERCOT via two high voltage direct current (HVDC) ties. These interconnections provide an electric pathway to provide access to off-system res ources, as well as a delivery mechanism to neighboring systems

.



## 3.6.2 Current AEP-SPP Transmission System Issues The limited capacity of interconnections be tween SPP and neighboring systems, as well as the electrical topolo gy of the SPP footprint transmission system, influences the ability to deliver non-affiliate 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 signifi cantly slowed down the process of developing new interconnections. Despite the robust nature of the AEP-SPP transmission system as originally designed, its curre nt use is in a different manner than originally designed, in order to meet SPP RTO requirements, which can stress the system. In addition, factors such as outages, extreme weather, and powe r transfers also stress the system. This has resulted in a transmission system in the AEP-SPP zone that is constrai ned when generation is dispatched in a manner inconsistent with the orig inal design of utilizing local generation to serve local load. The resulting use of the AEP-SPP system is inconsistent with the assumptions used to develop the modeling data AEP provides to SPP to develop and plan the system. SPP uses models developed from data provid ed by all load serving entities to study the reliability needs of the SPP footprint.

3.6.2.1 The SPP Transmission Planning Process Currently, SPP produces an annual SPP transm ission expansion plan (STEP). The STEP is developed through an open stakeholder proce ss with AEP participation. SPP studies the

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## transmission system, checking for base case and contingency overload and voltage violations in all of the SPP base case load flow models, plus models which include powe r transfers biased in

the various transfer directions.

The 2012 STEP summarizes 2011 activities, in cluding expansion planning and long-term SPP Open Access Transmission Tariff studies (Tariff Studies) that impact future development of the SPP transmission grid. Seven key t opics are included in the STEP: 1) Integrated Transmission Planning 2) Tariff Studies, 3) Sub-regional and local area planning, 4) Transmission Conges tion and top Flowgates 5) Interregiona l coordination, 6) Project tracking; and 7) Public Policy Impacts These topics are critical to meeting mandates of either the SPP strate gic plan or the nine planning principles in FERC Order 890. As a RTO under the dom ain of the Federal Energy Regulatory Commission (FERC), SPP must meet FERC requireme nts and the SPP Open Access Transmission Tariff (OATT or Ta riff). The SPP RTO acts indepe ndently of any single market participant or class of participants. It has sufficient scope and configuration to maintain electric reliability, effectively perform its functions, an d support efficient and non-discriminatory power markets. Regarding short-term reliabilit y, the SPP RTO has the capability and exclusive authority to receive, confirm, and implement a ll interchange schedules. It also has operational authority for all transmission fac ilities under its control. The 10- year RTO regional reliability assessment continues to be a primary focus. STEP projects are categorized by the following designations:

 Balanced Portfolio – Projects identified through the Balanced Portfolio Process;

 Generation Interconnect – Projects associ ated with a FERC-f iled Interconnection Agreement;

 Interregional- Projects developed wi th neighboring Transmission Providers;

 ITP - Projects needed to meet regional re liability, economic, or policy needs in the ITP study process;

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##  ITP – Non-OATT – Projects to maintain reliability for SPP members not participating under the SPP OATT

 Transmission service – Projects associat ed with a FERC-filed Service Agreement;

 Zonal Reliability - Projects identified to meet more stringent local Transmission Owner criteria; and

 Zonal-Sponsored – Projects sponsored by facility owner with no Project Sponsor Agreement

The 2012 STEP identified 492 transmission ne twork upgrades with a total cost of approximately $7.1 billion. These include Networ k Upgrades required for NERC Reliability Standards or SPP Criteria; Zonal Reliability Upgrades (compliance to Transmission Owner company-specific planning criter ia); requests for transmission service under the Tariff with a FERC-filed Service Agreement; and genera tion interconnections with a FERC-filed interconnection agreement. At the heart of SPP’s STEP process is its Integrated Transmission Planning (ITP) process. The ITP process was designed to mainta in reliability and provide economic benefits to the SPP region in both the near and long-term. Th e ITP process was conducted in three phases. The first phase recommended a long-term transmi ssion plan for a 20-year horizon, incorporating a proposed extra-high voltage supply system. The second phase of the ITP process resulted in a recommended portfolio of transmission project s for comprehensive re gional solutions, local reliability upgrades, and the expected reliabil ity and economic needs of a 10-year horizon. Finally, the third phase of the IT P process studied the reliability of the SPP transmission system in the near-term, identifying upgrades based on a 6-year planning horizon.

3.6.2.2 PSO-SWEPCO Interchange Capability Operational experience and internal assessm ents of company transmission capabilities indicate that, when consideri ng a single contingency outage even t, 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 econo mical energy transfers when no transmission facilities are out of service. However, the intra-company available transmission capability between the two companies is available to all transmission users under the provisions established by FERC Order 888 and subsequent orders. Thus, there is some

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## question as to whether, in the future, as SPP grants further tr ansmission rights, any transfer capability will in fact be av ailable without further upgrades to the transmission system. As previously indicated, each company’s capa city additions are planned so that each meets its own reserve requirement over the long-te rm. Any capacity tran sfers (i.e. “reserve sharing”) should be considered for short time frames only. Speci fically, the practice has been that, as the last step of the planning process, the respective PSO and SWEPCO expansion plans are adjusted to take advantage of any surplus of one company th at might match a potential deficit of the other, and thereby delay some of the id entified new capacity. Because of the sizes, demand growth rates, and peak coincidence of the two companies, it rarely appears that either company would ever have more than 200 MW of surplus capacity in any year that could be transferred to the other company.

3.6.2.3 AEP-SPP Import Capability Currently the transmission system cannot accommodate large incremental firm imports to the AEP-SPP area. Generally, the transfers are limited by the facilities of neighboring systems rather than by transmission lines or equipment owned by AEP. Increasing the import capabilities with AEP- SPP’s neighboring companies could require a large capital investment for new transmissi on facilities by the neighbor ing systems or through sponsored upgrades by SPP transmission owners. An analysis of the cost of the upgrades cannot be performed until the capacity resources are determined. For identified resources, the cost of any transmission upgrades necessary on AEP’s transmission system can be estimated by AEP once SPP has identified the upgrade. AEP’s We st Transmission Planning group can identify constraints on third-party systems through ad hoc power flow modeli ng studies, but West Transmission Planning does not have information to provide estimates of the costs to alleviate those third-party constraints.

3.6.2.4 SPP Studies that may Provide Import Capability Besides the annual STEP process, SPP also perf orms other special studies or area studies on an as needed basis. One recent SPP study that re sulted in approved proj ects that may lead to improve transfer capability between AEP-SPP a nd neighboring companies and regions is the Priority Projects study. Among the projects approved as a result of this study are:

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##  Double circuit 345 kV line in southwestern Kansas from Spearville to Comanche County to Medicine Lodge to Wichita

 Double circuit 345 kV line from southw estern Kansas (Medicine Lodge) to northwestern Oklahoma (Woodward)

 Double circuit 345 kV line in northwester n Oklahoma from Woodward to Hitchland

 A 345 kV line from Valliant, in southeas tern Oklahoma to Nort hwest Texarkana in

northeastern Texas

3.6.3 Recent AEP-SPP Bulk Tr ansmission Improvements Over the past several years, there have b een several major transmission enhancements

initiated to reinforce the AEP-SPP transmi ssion system. These enhancements include:

 Northwest Arkansas — Northwest Arkansas is one of the fastest growing areas on the AEP-SPP Transmission System. The approximat e 1,300 MW of load in this area, about49% of which is AECC load, is supplied primarily by the SWEPCO and AECC jointlyowned Flint Creek generating plant, the SWEPCO Mattison generating plant, the GRDA-Flint Creek 345 kV line, and the Clar ksville-Chamber Springs 345 kV line. WalMart’s international headqua rters and its supplying businesses’ offices and Tyson’s headquarters are all located in this area. A new 345 kV lin e is now under construction from Flint Creek to the new Shipe Road 345/161 kV substation, with a 161 kV line connecting Shipe Road substation to East Ce nterton substation. This 345 kV line will also extend from Shipe Road substation to a new substation in the Osage Creek area east of Eureka Springs where it wi ll tie into the 161 kV system.

 Port of Shreveport (Port), Louisiana — A 138 kV loop was completed in 2012 around the Port to increase system reliability and to serve the increasing area load. This loop extends approximately 33 miles from Wallace La ke Station to the Port to Bean Station to Caplis Station to McDade Station to Haughton Station to Red Point Station. Together, these improvements supply power to the Port, Bean Station and the new Caplis distribution station; correct conti ngency low voltage and thermal overloads in Bossier City, Louisiana and the vicinity; a nd supply a second feed to the Port, Bean, Caplis, McDade, and Haughton stations.

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##  Turk Generation Interconnection – In order to connect the 600 MW coal-fired Turk Power Plant in southwestern Arkansas, ne ar McNab, to the transmission system, the

Turk 345/138/115 kV substation was built and se veral new transmission lines were built or upgraded. A 138 kV line approximately 22 miles from Turk to Sugar Hill substation and a 138 kV line approximately 27 miles from Turk to Southeast Texarkana substation have been completed as well as a 138 kV line section and a 115 kV line section approximately 2 miles each from Turk to the Okay-Hope 115 kV line, which was opened and routed into Turk. The Patterson to Okay and Okay to Hope 115 kV lines were rebuilt to 138 kV standards, though the portion between Hope and Turk will continue to be operated at 115 kV. A 345 kV line approximately 33 miles from

Northwest Texarkana to Turk is to be co mpleted in the second half of 2012. This expansion provides the interconne ction of the Turk Power Pl ant, transmission service, improved reliability for the City of Hope and southwestern Arkansas, and improved reliability to Texarkana by comple ting a 138 kV loop around the city.

 McAlester, Oklahoma area – The Canadian River 345-138 kV substation is being built northwest of McAlester, along OG&E’s Pittsburg-Muskogee 345 kV line. A 69 kV line is being converted to 138 kV line for appr oximately 17 miles from the Canadian River substation to the McAlester City substation. This will relieve 138 kV line loadings in the area and provide voltage support.

3.6.4 Impacts of New Generation Integration of additional gene ration capacity within the AE P-SPP zone will likely require significant transmission upgrades. At most loca tions, any additional ge neration resources will aggravate existing transmission constraints. Specifically:

 Western Oklahoma/Texas Panhandle —there are very few E HV transmission lines in this area. In fact, transmission facilities above 69 kV are limited. However, the area is one of the highest wind dens ity areas within th e 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

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## transmission enhancements, including EHV line and station construction, to address thermal, voltage, and stability constraints.

 PSO/SWEPCO Interface - There is one 345 kV EHV line linking PSO’s service area with the majority of SWEPCO’s generation re sources in its service area. The Danville to North Magazine 161 kV line rebuild increa sed the transfer capability from SWEPCO to PSO to approximately 900 MW. Also, the Broken Bow to Cr aig Junction 138 kV line rebuild increased the transfer capability from PSO to SWEPCO to approximately 200 MW. An SPP approved project, men tioned above, to build a 345 kV line approximately 76 miles from Valliant substation to Northwest Texarkana substation will improve transfer capability by formi ng a second 345 kV path between PSO and SWEPCO’s transmission system in northeaste rn Texas. Significant generation additions to the AEP-SPP transmission facilities (or connection to neighbor’s facilities) may require significant transmission enhancemen ts, 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 pl ants. Additionally, Oklahoma Gas & Electric Company has large ge neration plants located to the southeast and southwest of Tulsa, and there are large merc hant plants just east and south of Tulsa. The Grand River Dam Authority has a large plant located to the east of Tulsa.

Generation additions in the Tulsa area would likely require significant enhancements in the EHV and sub-transmission system to address thermal, voltage and stability

constraints.

 SPP Eastern Interface —there are only five east-wes t 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 impor ts and exports along th e eastern interface of SPP with neighboring regions. It also c onstrains the amount of transfers from the capacity rich western SPP region to the ma rket hubs east and north of the SPP RTO region. Significant generation additions ne ar or along the SPP eastern interface would likely require significant transmission e nhancements, including EHV line and station construction, to address thermal and stab ility constraints should such generation additions adversely impact existing transactions along the interface.

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## Integration of generation reso urces at any location within the AEP-SPP zone will require significant analysis by SPP to identify potential th ermal, short circuit, and stability constraints resulting from the addition of generation. Depending on the specific location, EHV line and station construction, in addition to connection facilities, could be necessary. Other station enhancements, including transformer additions and breaker replacements may be necessary. Some of the required transmission upgrades could be reduced or increased in scope if existing generating capacity is retired concurre nt with the addition of new capacity.

3.6.5 Summary of Transmission Overview In the SPP region, the process of truly integr ating Generation and Transmission planning is still developing. AEP continues to stand ready to engage in that process. At this time, though, PSO and SWEPCO can do very littl e to import capacity from outsi de of its control area. Both companies have been open to such imports as evidenced by the issuing of recent RFP’s for nonsite specific generation types. These RFP’s a llow bidding entities to offer generation coupled with transmission solutions, which would be subject to SPP approvals.

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## 4.0 Hedging: Risk Management

4.1 Introduction The primary objective of PSO's fuel hedging strategy is to reduce fuel and purchased power cost volatility experienced by customers. Notably, PSO' s hedging strategy is not intended to predict the market or to engage in speculati ve trading. In many re spects, a fuel hedging strategy is similar to insurance. A successful hedging program can effectively mitigate the risk to fuel cost increases, but it can also limit potential fuel cost decreases if prices fall or remain unchanged. If this happens, the total cost of th e hedges increases the cost of the fuel. PSO continually evaluates its hedging strategy options in such a way to most appropriately balance the many, sometimes conflicting, goals it faces. Traditionally, PSO’s diversified generation fleet has been the f oundation of its risk management plan. By investing in and using generating plants th at use different fuel sources, PSO has created a flexible portfolio of coal, natural gas, fuel oil, and purchased power resources, including wind, which manages overall variable cost s due to the potential pr ice volatility of any one particular fuel source. PSO’s ability to mitigat e the price volatility of its overall fuel cost has been primarily attributable to effective manage ment of its fuel mix through maximum use of its coal generation, provisions in its fuel supply and transportation contracts that provide additional flexibility, and the use of purchased power when it econom ically displaces PSO’s own generation. Additionally, through the use of an annual fixed fuel factor, PSO’s customers experience stable fuel costs during the annual fu el factor period and are effectively insulated from short term price volatility in the fuel mark ets. To date, PSO’s successful hedging and risk management program has not utilized instrume nts such as Financial Swaps, Call and Put Options, or Collars. However, as PSO transitions to the SPP Integrated Marketplace (or SPP IM) in 2014, as coal plants are reti red, and as natural gas Purchase d Power Agreements (PPAs) are added to the portfolio, PSO’s efforts to mitigate th e price volatility of its fuel supply will be faced with additional challenges and opportun ities that will broaden the scope of hedging strategies to be considered.

4.2 Hedging Now and for the Short-Term In the short term, PSO anticipates that its current hedging strategy will not change significantly. Typically, PSO meets its generation requirements by first using its lower–cost coal

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## units (and generation from SWEPCO’s coal and lignite units when available to PSO) to achieve

the overall lowest reasonable fuel cost. PSO he lps to ensure the provision of reliable electric service to its customers by maintaining a coal in ventory to be both proactive and responsive to known, anticipated, and potential changes in op erating, coal supply, a nd rail transportation conditions. In addition, PSO’s co al inventory mitigates risk and allows the Company to take advantage of favorable market c onditions. PSO’s coal inventories also serve as a physical hedge against price volatility for that volume of coal already secured, on hand, and available for consumption. PSO also hedges the price volat ility of coal, through a variet y of methods. The majority of the coal used as boiler fuel on PSO’s system is procured through compet itive solicitations for staggered terms of a year or more, primarily at a fixed price. PSO includes a variety of contract provisions in its solicitations which provide add itional flexibility. The final key component of PSO’s coal procurement strategy includes the use of index pricing in some of its coal contracts as well as spot market purchases. The resulting portf olio of coal contracts has sufficiently provided an effective price hedge for PSO’s coal costs. PS O’s hedging strategy for co al was driven in part by (1) coal’s position as a base lo ad fuel, (2) the fairly predicta ble nature of the required volume needed, and (3) the ability to stockpile on site any variances between purchases and consumption

which can be used at a late r time at PSO’s discretion. The marginal supply source in PSO ’s generation portfolio is t ypically a natural gas unit. The natural gas plants’ ultimate usage is determined in large part in coordination with purchased power opportunities. In the short-term and dur ing real-time market operations, PSO’s natural gas units are compared to purchased power o pportunities (based on ea ch unit’s efficiency, economics, and other relevant factors) to meet peak load demands, to replace coal capacity during scheduled maintenance and forced outages , to follow daily and hour ly load swings, and for voltage support. In the intra-day market (real-time), American Electric Power Service Corporation’s (AEPSC’s) hourly marketers, produ ction coordinators, natural ga s coordinators, and generation dispatchers work closely to optimize the PSO sy stem by taking into cons ideration opportunities to purchase energy in the market. If AEPSC has an offer in the intra-day market (real-time) for a reliable source of energy capable of being delivered to PSO’s system at a price that is below the

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## forecasted marginal generation (dispatch) co st, AEPSC purchases this economic energy whenever possible on behalf of PSO. PSO procures all of its natural gas supplies competitively. To optimize its natural gas supply, PSO will continue to evaluate its natura l gas supply requirements and use a combination of long-term, annual, seasonal, monthly, and daily incremental purchases as needed. Many natural gas suppliers are unwilling to offer fixed prices to PSO, and those that do, typically include a price premium. Historically, for th e summer peak period of June through August, PSO has entered into some seasonal firm supply contra cts to ensure deliveries of natural gas as a physical hedge against a shortage of supply rather than against a change in prices. PSO may secure daily call gas to ensure supply availability on projected high volume days. Daily call gas is gas service provided on demand with a prio r day nomination. Daily call gas is typically provided by a producer or marke ting company with supply on the in terconnecting pipeline. It is priced at a daily index-based pr ice and often requires a minimum reservation fee for the demand

service. While PSO could purchase natural gas storage, if available, to meet its natural gas peaking supply needs for reliability purposes, PS O’s existing natural gas transportation contracts

include services that alre ady provide the reliability that storag e services would offer. Unlike coal stockpiling, where stockpiles can be created for use at a later tim e at PSO’s discretion, ratable flow restrictions are required when pulling natural gas from st orage. PSO’s analysis has indicated that, due to the difficu lty in anticipating peak hourly and daily supply needs, it would be difficult for PSO to nominate its natural gas withdrawals in advance. Storage injections and withdrawals must be accomplished at a steady fl ow rate and are not re sponsive to the peaking demands of natural gas el ectric generators. Also, the normal injection and withdrawal seasons for storage (injection – summer, withdrawal - winter) are opposite from PSO’s needs. PSO would need to inject gas in the winter months when gas prices are typi cally higher and withdraw gas in the summer to meet the summer peak dema nds. As a result, natural gas storage has not evolved to be a viable operationa l or economic alternative for PSO.

4.3 PSO’s Fuel Supply Mix & Regional Market Structures Are Changing PSO’s fuel supply portfolio wi ll experience signifi cant changes in the years ahead. By recent agreement, PSO will be required to meet specified emission rates at both Northeastern coal units, install certain emissi ons control equipment on one of th e Northeastern coal units and

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## retire the other unit in 2016. The unit with the emission controls will be retired in the 2025-26 timeframe. In 2012, PSO began receiving 520 MW s of capacity and en ergy through its longterm PPA with Exelon Genera tion Company LLC, a subsidiary of Exelon Corporation. The agreement is the result of PSO’s 2008 Request fo r Proposals (RFPs) for supply-side capacity and energy resources, which followed a December, 2007 Oklahoma Corporation Commission (OCC)

order that found that PSO had a need for new ba se load generation by 2012. As coal generation is retired, additional natural gas PPAs, with some additional wind PPAs will likely be added which will place a greater weight on natural gas in PSO’s fuel mix. The company is in final negotiations for a 260 MW PPA will fill the capaci ty and energy shortage resulting from the retirement of Northeastern Unit 4 in 2016 as a pa rt of PSO’s settlement with the Environmental Protection Agency (EPA). Between these afor ementioned PPA’s, PSO will have the contractual rights to over 750 MWs of highly effici ent natural gas-fi red generation. Although PSO’s generation portfo lio is shifting over time to have a greater dependence on natural gas, the changes underway in the SPP markets add increased uncertainty to the ultimate volume of natural gas th at PSO will need to procure. SPP is currently pursuing the implementation of its SPP IM, with an expected st art date in the first half of 2014. The SPP IM requirement for centralized unit commitment could re sult in material changes to the dispatch of PSO’s generation fleet. Until the SPP IM begins ope ration, it is difficult to determine the level

of PSO’s base load natu ral gas hedging needs. The implementation of the SPP IM will also provide PSO with additional tools to optimize its purchased power activities. A centr alized day-ahead power market is likely to increase the number of market participants, pr ovide additional clarity on medium-term power prices, and spur the introduction of additional trad ing instruments. PSO will continue to monitor the development and implementation of the SPP IM.

4.4 Hedging for the Longer-Term As previously explained, PSO’s flexible portf olio of coal, natural gas, and fuel oil and purchased power resources will be transitioning to a fuel mix that has a greater dependence on natural gas. PSO’s transition to a more domi nant reliance on natural gas introduces both challenges and opportunities that will be incorporated into PS O’s ongoing analysis of its fuel and purchased power hedging strategy. In particular, there are markedly different hedging opportunities, hedging instruments, pricing dynami cs, and the relative willingness of producers

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## and end users that are different between coal and natural gas. For example, coal hedging opportunities have been traditio nally clustered around long-term physical contracts executed with the coal producers themselves. Such an environment made the staggering of terms of physical purchases, together with certain contract provisions to provide flexibility, as the most efficient ways to mitigate the price volatility of coal. PSO’s coal base load units have previously had relative certainty th at the plants would

run if available to run. As a result of that re lative certainty, it was quite reasonable to lock-in some long-term and mid-term agreements and pur sue spot purchases to address variations in generation burn from the forecasted burn. Howeve r, the broad changes underway to PSO’s fuel supply requirements creates less certainty and w ill drive the pursuit of more mid-term coal agreements. For example, Northeastern 3 & 4 likely remains base loaded. However, Oklaunion is expected to more likely be utilized during the high-peak periods, i.e. , summer and winter, so short-term, seasonal, and spot agreements would likely be mo re appropriate. The target inventory of a plant with greater certainty would benefit from a larger inventory to manage for any delivery disruptions. While the target invent ory of a plant with less certainty of burn would require less coal in its inventory as it could manage through short to me dium delivery disruptions

with more ease. Circumstan ces will still warrant maintaini ng a diversity of suppliers and staggering terms. The increasing uncertainty regarding PSO’s physical na tural gas needs will add additional complexity to hedging PSO’s natural ga s price risk through a staggered portfolio of physical contract purchases. A lthough PSO anticipates a decline over its current level, some mid- to long-term procurement of physical natura l gas may continue to be utilized to ensure reliable supply and to hedge pr ice risk. In part, PSO’s natura l gas supply portf olio will be influenced by projections for the overall supply of natural gas. Mid- to long-term physical contracts would become more likely should natura l gas supplies, which ar e currently plentiful, become more difficult to obtain and the Compa ny must ensure that natural gas supplies are available to support the reliabilit y of electric supply to customers. In light of the uncertainty surrounding PSO’s expected natural gas burn, natu ral gas storage may provi de a useful tool in PSO’s future fuel price hedging strategy. For example, the implementation of the SPP IM increases the uncertainty of which PSO plan ts will be called on to run on any given day, potentially increasing the value of the flexibility provided by natural gas storage. In addition,

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## certain hedging strategies, using the financial hedging tools discusse d in greater detail below, can be used in combination with physical hedges wh ich can be executed thr ough the use of natural gas storage. As a result, storage may b ecome a more viable operational and economic

alternative. As mentioned above, mitigating the price vo latility of natural ga s introduces a much broader range of considerations and instruments. For example, natural gas has moved from a long-term physical contracting ba sis that existed prior to the deregulation of the natural gas market, to a much shorter-term contract basi s as competition increased. Another significant factor impacting the successful hedging strategy su rrounding natural gas pr ocurement has been the unprecedented price volatility over the last decade and a half. An d finally, until recently, there has been a great deal of concern over the l ong-term supply of U.S. natural gas resources. More recently, PSO has seen an increased desire among natural gas producers to enter into longterm contracts. However, these long-term contract offers contain a significant price premium to lock in a fixed price. The natural gas markets have evolved a liq uid, robust number of financial trading instruments that could be used to hedge some of PSO’s natural gas pr ice risk. PSO’s fuel hedging program is not intended to reduce overall fuel costs, but rather to level prices over time by mitigating the impact of price volatility. It is important to note that hedging positions are distinctly different from speculative positions even though the tools used for hedging, for the most part, can also be used for speculation. Fina ncial derivatives are hedging instruments in the form of contractual agreements between two part ies to buy or sell assets (e.g., commodities) at a pre-determined price at a future date. The most common type of hedging instruments are (1) physical hedges, (2) financial swap s, (3) call and put options, and (4 ) collars. These instruments are briefly defined as follows: Physical Hedge – a contract between two parties to buy or sell a commodity at a pre- agreed future point in time. The purpose of a physical hedge is to lock-in a fixed purchase price for physical delivery of the commodity. Financial Swaps – a contractual agreement wh ereby a floating (market or spot) price is exchanged for a fixed price on a future, spec ified date. A financial swap is a futures transaction where no commodity changes hands. Instead, the proceeds from a financial swap transaction are intended to offset a separate transaction for the physical fuel.

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## Call and Put Options – a financia l contract, similar to swaps, that is intended to offset a physical fuel purchase. There are two types of options: calls and puts. In the case of either a call or put, the option buyer (opti on holder) must pay th e option seller (option writer) a premium to enter the contract. Regardless of how the market swings, the most an option buyer can lo se is the option premium. Collars – are a two-part option strategy that involves the combination of a put and call option. A collar position is made by selli ng a put option at one strike price while simultaneously purchasing a call option at a lower price. This trade gets its name because the position is essentially “collared” between two prices. PSO will continue to evaluate the appropriateness of using additional tools, such as financial derivatives, to hedge its natural gas price risk.

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## 5.0 Modeling Parameters

5.1 Modeling and Planning Process – An Overview The objective of a resource planning effort is to determine a system expansion plan that balances least-cost objectives with planning flex ibility, asset mix considerations, adaptability to risk, conformance with applicable North American Electric Relia bility Corporation (NERC) and RTO criteria, and customer affo rdability. In addition, given the unique impact of generation on the environment, the planning effort must ultimat ely be in concert with anticipated long-term requirements as established by the EPA-driven environmental compliance planning process. The information presented with this IRP includes descriptions of assumptions, study parameters, methodologies, and results including the integration of supp ly-side resources and demand-side management (DSM) programs. In general, assumptions and plans are c ontinually 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; technica l parameters; regulatory constructs; capacity supply; energy adequacy and operational reliability; and environmental mandate requirements are constantly reassessed to ensure optimal capacity resource planning. Further impacting this process are a growing number of federa l and state initiatives that address many issues relating to industry restructur ing, customer choice, a nd reliability planning. Currently, fulfilling a regulatory obl igation to serve native load customers represents one of the cornerstones of the PSO IRP process. Therefore, as a result, the “obj ective 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. Other factors–some more difficult to monetize

than others–were considered in the determination of the plan. To challe nge the robustness of the Plan, sensitivity analyses were pe rformed to address these factors.

5.2 Methodology The IRP process aims to address the long-te rm gap between resource needs and current

resources. Given the various assets and resource s that can satisfy this expected long-term gap, a

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## tool is needed to sort through the myriad of potential combinations and return an optimum solution–or portfolio–subj ect to constraints. Strategist ® 7 

## is the primary modeling application, used by AEP for identifying and ranking portfolio s that address the gap between needs and

current available resources. Given the set of proxy resources–both supply and demand side–and

a scenario of economic conditions that include fuel prices, capacity costs, energy costs, effluent prices including CO 2 

## , and demand, Strategist ® 

## will return all combinations of the proxy resources (portfolios) that meet the resource nee d. The portfolios are ranked on the basis of cost, or cumulative present worth (CPW), of the result ing stream of revenue requirements. The least cost option was considered the initial “optimu m” portfolio for that unique input parameter

scenario.

5.3 Fundamental Modeling Input Parameters The long-term power sector suite of commod ity forecasts are derived from a proprietary

model known as AURORA xmp 

## . AURORA xmp 

## is a long-term fundame ntal production-costing tool developed by EPIS, Inc. that is driven by co mprehensive user-defined input parameters. For example, unit-specific fuel delivery and emission allowance price forecasts which are established by AEP Fuel, Emissions and Logistics (FEL) and Commercial Operations, are fed into

AURORA xmp 

## . Similarly, capital costs and perform ance parameters for various new-build generating options, by duty-type are vetted through AEP Engineering Servi ces and incorporated into the tool. Other information specific to th e thousands of generating units being modeled is researched from “Velocity Suite,” an on-line information database maintained by Ventyx, an ABB Company. This includes data such as un it capacity, heat rates, retirement dates and

emission controls stat us. AEP uses AURORA xmp 

## to model the eastern synchronous interconnect

as well as ERCOT. The CO 2 

## forecast is based on assumpti ons developed by AEP Strategic Policy Analysis as detailed in section 5.3.1.

7 

### A Ventyx Co., long-term resource optimization tool utilized extensively in the utility industry for over two decades.

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## Figure 5-1: 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



## Figure 5-1 shows the Fundamentals process flow for solution of the long-term (power) commodity forecast. The input assumptions are init ially used to generate the output report. The output is used as feedback to change the base input assumptions. This it erative process is repeated until the outp ut 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). Commodity pricing forecasts as well as modeled CO 2 

## pricing that were used in the IRP economic modeling are shown in Table 5-1.

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## Table 5-1: Long-Term Commodity Price Forecast

'BASE' Alt. Scenario 'BASE' Alt. Scenario Alt. Scenario Fleet FT

‐ CSAPR: Fleet FT

‐ CSAPR: Fleet FT

‐ CSAPR: Transition:

CSAPR LOWER Band Transition: CSAPR LOWER Band Transition: CSAPR LOWER Band

Carbon in 2022 Carbon in 2022 Carbon in 2022 Carbon in 2022 Carbon in 2022 Carbon in 2022

2012 4.22 3.71 4.48 3.94 15.75 14.49 2013 4.57 4.02 4.94 4.35 16.95 15.26 2014 4.84 4.26 5.38 4.73 17.50 15.75 2015 4.86 4.27 5.52 4.86 17.50 15.40 2016 5.18 4.56 5.99 5.27 17.40 15.31 2017 5.22 4.60 6.13 5.39 17.30 15.22 2018 5.30 4.67 6.32 5.56 17.72 15.59 2019 5.34 4.70 6.46 5.68 18.14 15.96 2020 5.31 4.67 6.52 5.73 18.57 16.34 2021 5.42 4.77 6.75 5.94 19.00 16.72 2022 5.59 4.92 7.07 6.22 19.07 16.78 2023 5.66 4.98 7.26 6.39 19.51 17.17 2024 5.76 5.07 7.51 6.61 19.96 17.57 2025 5.86 5.15 7.75 6.82 20.42 17.97 2026 5.85 5.15 7.85 6.91 20.89 18.38 2027 5.90 5.19 8.04 7.08 21.36 18.80 2028 5.94 5.23 8.22 7.23 21.84 19.22 2029 5.99 5.27 8.41 7.40 22.34 19.66 2030 5.99 5.27 8.52 7.50 22.84 20.10

'BASE' Alt. Scenario Alt. Scenario 'BASE' Alt. Scenario Fleet FT

‐ CSAPR: Fleet FT

‐ CSAPR: Fleet FT

‐ CSAPR: Transition:

CSAPR LOWER Band Transition: CSAPR LOWER Band Transition: CSAPR LOWER Band

Carbon in 2022 Carbon in 2022 Carbon in 2022 Carbon in 2022 Carbon in 2022 Carbon in 2022

2012 0.00 0.00 47.39 44.20 32.63 30.57 2013 0.00 0.00 50.77 45.32 34.86 31.98 2014 0.00 0.00 55.73 47.48 39.00 33.74 2015 0.00 0.00 59.20 52.72 41.78 36.92 2016 0.00 0.00 64.97 57.34 46.15 40.69 2017 0.00 0.00 65.75 58.54 47.70 42.41 2018 0.00 0.00 66.64 59.56 48.97 42.86 2019 0.00 0.00 67.85 61.41 49.75 44.68 2020 0.00 0.00 66.87 62.52 48.80 45.35 2021 0.00 0.00 68.52 64.48 50.78 47.58 2022 15.08 15.48 75.69 73.29 59.13 56.07 2023 15.28 15.67 76.53 74.03 60.17 56.36 2024 15.48 15.88 78.76 75.36 62.40 58.28 2025 15.67 16.08 80.50 76.45 63.83 59.71 2026 15.88 16.29 81.13 77.12 64.33 60.67 2027 16.08 16.50 83.15 78.22 66.12 61.68 2028 16.29 16.72 84.15 79.06 67.56 63.01 2029 16.50 16.94 85.57 80.45 69.56 64.32 2030 16.72 17.16 86.60 81.44 70.45 64.81 

### Summary of Long

‐ Term Commodity Price Forecast Scenarios Annual Average (Nominal Dollars unless otherwise noted) (Source: AEP Fundamental Analysis)

($/Metric Tonne) ON

‐ Peak Energy (SPP) ($/Mwh) ($/Mwh) CO 2 PRB (0.8#) ($/Ton

‐ FOB Mine)

OFF

‐ Peak Energy (SPP) NATURAL GAS (Henry Hub) ($/MMBtu) REAL 2010$ ($/MMBtu) NOMINAL

### PSO 2012 Integrated Resource Plan

46 

## 5.3.1 CO 2 

## Forecast Each of the pricing forecasts also assume a CO 2 

## /carbon impact as a result of the implementation of any prospectiv e carbon-reduction legislation; however, that pe rspective is reflected assuming three unique sets of implem entation timing. The Base view assumed such legislation would be effective by 2022. The relative timing for the Ba se view (2022) is largely in recognition of the potential con tinued aversion in the U.S. Congress to passing comprehensive

CO 2 

## legislation that would establish either a ca rbon-based, cap-and-trade mechanism or, as an alternative, a carbon tax on emissions. So, under the notion that it potentially could be five years before such action is taken by Congress, pl us the assumption based on prior proposed CO 2 

## legislation—such as Waxman-Markey and Kerry -Lieberman—that another 5 years would be afforded for the ultimate implementation of any such legislation, an effective date for such

CO 2 

## /carbon pricing impacts of 2022 was deemed by Company management as a plausible

outcome.

### PSO 2012 Integrated Resource Plan

47 

## 6.0 Resource Portfolio Modeling

6.1 The Strategist ® Model - An Overview

The Strategist ® 

## optimization model served as the ca lculation tool from which the PSO capacity requirements were examined and resour ce addition recommendations were made as part of the IRP process. In this process, Strategist ® 

## offers unique “portfolios” of capacity resource options for PSO that can be assessed from a discrete, revenue requirement perspective. As its objective function, Strategist ® 

## determines the lowest revenue requirement resource mix for PSO. The solution is bounded by user-defin ed sets of resource technologies, commodity pricing, and prescribed sets of constraints. Strategist ® 

## develops a least-cost resource mix by consideri ng a variety of expansion planning assumptions including:

 Resource alternative characteristics ( e.g., capital cost, construction period, project life).

 Operating parameters ( e.g., capacity ratings, heat rates, outage rates, emission effluent rates, must-run status, etc.) of existi ng 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 st udy, minimum reserve margin targets).

 Transmission limitations.

 Emission limits and environmental compliance options.

 Alternative distribution system solutio n (including DR/EE program) costs and impacts on peak load and energy requirements. These and other assumptions are considered in the development of an integrated plan that best fits the utility system being analyzed. Strategist ® 

## is a holistic model in that existing units may operate differently under different scenario s. The model determines and reflects such impacts on overall system va riable operating costs. Strategist ® 

## does not develop a full regulatory cost-of-service (COS ) profile. Rather, it typical ly considers only those COS components that change from plan to plan. It does not consider embedded costs associated with

### PSO 2012 Integrated Resource Plan

48 

## existing generating and T&D capacity that w ould remain constant under any scenario. Transmission costs are included only to the extent that they are associated with new generating capacity, or are linked to specific supply alternatives. In other wo rds, generic (nondescript or non-site specific) capacity resource modeling woul d not typically incorpor ate significant capital

for transmission interconnection. Specifically, Strategist ® 

## includes and recognizes in its revenue requirement

calculation:

 Fixed costs of capacity additions, i.e., carrying charges on capacity and associated transmission (based on PSO’s weighted aver age cost of capital), and fixed O&M.

 Fixed costs of any capacity purchases.

 Installation and administrative costs of DR/EE alternatives.

 Affiliate energy purchases and sales based on split-savings per West Operating Agreement.

 Variable costs associated with the entire fleet of new and existing generating units (using its probabilistic unit dispatch optim ization engine). This includes fuel, purchased energy, market replacement cost of emission allowances, and variable

O&M costs.

 Market revenues from external energy transactions ( i.e., off-system sales). These are netted against costs.

In the PROVIEW module of Strategist ® 

## , the least-cost expansion plan is formulated from potentially tens of thousands of resource a lternative combinations created by the module’s dynamic programming algorithm. On an annual basi s, each capacity resour ce combination that satisfies various user-defined constraints (to be di scussed below) is considered to be a “feasible state” and is saved by the program for considerati on in following years. As the years progress, the previous years’ feasible states are used as starting points for the addition of more resources that can be used to meet the current year’s minimum reserve requirement. As the need for additional capacity on the system increases, the number of possible combinations and the number

of feasible states increases exponentially with the number of resource alternatives being

considered.

### PSO 2012 Integrated Resource Plan

49 

## 6.1.1 Key Input Parameters Two of the major underpinnings in this proces s are long-term forecasts of PSO’s energy requirements and peak demand, as well as the pr ice of various generation-related commodities, including energy, capacity, coal, natural gas, and CO 2 

## /carbon. Both views were created internally within AEP. The load forecast, including the PSO load and demand summary was created by the AEP Economic Forecasting organi zation, while the long-term commodity pricing forecast was created by the AEP Fundamental Analysis group. Moreover, the Fundamental Analysis group constantly performs peer revi ew by way of compari ng and contrasting its commodity pricing projections versus consensu s pricing on the part of outside forecasting entities such as IHS Cambridge Energy Research Associate (IHS CERA), PIRA and the U.S. Department of Energy-Energy Info rmation Administration (EIA). Other critical input parameters include the in stalled cost of both e nvironmental retrofits required and replacement capacity alternative opti ons, as well as the attendant operating costs associated with those options; data which wa s sourced from the AEP E ngineering Projects & Field Services (EP&FS) organization.

6.2 Strategist ® Optimization

6.2.1 Purpose Strategist ® 

## should be thought of as a tool used in the development of viable resource portfolios. It does not produce th e answer; rather, it produces or suggests many portfolios that have different cost profiles under different scenar ios and sensitivities. Portfolios that fare well

under all scenarios and sensitivitie s are considered for further ev aluation. The optimum, or leastcost, portfolio under one scenario ma y not be the least-cost portfolio in other scenarios. Portfolio selection may reflect strate gic decisions embraced by PSO Management, including a commitment to DR/EE, renewable re sources, or other considerations. 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 scenario the Strategist ® 

## model consistently adds peaking capacity in large quantities, a portfolio that subs titutes a combined cycle plant for an equivalent amount of CTs might be constructed and tested to determine whether the revenue requirements are significantly different. Constraining the model to insert some additional practical constraints

### PSO 2012 Integrated Resource Plan

50 

## or conform to a company’s stra tegy often can yield a more dive rsified solution that is not significantly more expensive. The optimum or least expensive portfolio under a scenario may have practical limitations that Strategist ® 

## does not take into full account or may result in a plan that is very expensive u nder a different scenario.

6.2.2 Strategic Portfolios Strategist ® 

## was used to develop the PSO plan deve lopment alternatives below. Portfolios with various options concerning Northeastern 3 & 4 were evaluated under different pricing scenarios. As indicated below in TABLE 6-1, th ree unique, long-term commodity pricing views were used in the disposition economic analysis, consisting of a base view as well as two alternative pricing scenario views.

TABLE 6-1 8 

## (BASE) Fleet Transition-CSAPR : 

###  

## Recognizes relatively lower fuel price trending, increasing natural gas price

elasticity and captures a likely implementation profile of environmental regulation including CSAPR, MATS, CCR and potential carbon mitigation via a carbon tax beginning in 2022

. 

## Commodity Price Banding Scenario

2. Fleet Transition-CSAPR: Lower Band : same as the BASE case except:  

## Bounds a lower-end of the BASE case with plausible fuel, emissions and

energy pricing varying by approximately a -1.0 standard deviation.

Carbon Tax Timing Scenario 3. Fleet Transition-CSAPR: Early Carbon : same as the BASE case except:  

## Reflects an accelerated –versus BASE case view-2017 timeframe for the

implementation of a carbon tax and attendant correlated impacts.

8 

### Relative impact of commodity pricing due to vacating of CSAPR is mi nimal. The overriding driver of such pricing projections is more directly influenced by other emerging EPA rulemaking including MATS and RHR which, to a greater degree than CSAPR, tend to force either fossil unit retrofit or re tirement decisions and hence ultimate attendant impacts on commodity pricing. Given that the op tion-specific economic analyses around the Northeastern coal units were not distinguishable un til at least the 2015 forecast year, by de fault, the elimination of the CSAPR rule would have had little to no impact. In sum, the issue is one of nomenclature, not substance.

### PSO 2012 Integrated Resource Plan

51 

## 6.3 PSO Plan Development As represented on TABLE 6-2, five modeli ng options—and two additional sensitivity views—surrounding the disposition of Northeastern Units 3 and 4 for purposes of determining

the relative economics were evaluated.

TABLE 6-2 EPA Settlement Option (1 Northeastern Coal Unit Retrofit): Retrofit Northeastern Unit 3 with Dry Sorben t Injection (DSI) technology, Fabric Filter (FF) bag house and Activated Carbon Injection (ACI) technology— for mercury removal—and Retire and Replace Unit 4 with a PPA by April 2016. Option #1 (2 Northeastern Coal Unit Retrofit): Retrofit both Northeastern Units 3&4 with DFGD technology—for SO 2 

## , particulate matter (PM), FF bag house and ACI technology—for mercury removal—by April 2016, operating each unit for 15 years, th en retiring and optimally replacing both units with either/both new-bui ld natural gas CC or combustion turbine (CT) capacity. Option #2 (1 Northeastern Coal Unit Retrofit) : Retire Northeastern Unit 4 and Retrofit Unit 3 with DFGD and ACI technology by April 2016, effectively filling the ca pacity need created by a Unit 4 retirement with an assumed contemporaneous market capacity purchase; operating Unit 3 for 15 years, then retiring and repl acing the unit with either/both newbuild natural gas CC or CT capacity. Option #3 (1 Northeastern Coal Unit Retrofit) : Retrofit Unit 4 with ACI as well as—in lieu of DFGD— DSI technol ogy and a fabric filter baghouse system, by the end-of 2017. Retire Unit 3 by end of 2018 (This was an initial option that was not evaluated in the final analysis). Option #4 (No Northeastern Coal Unit Retrofit): Retire both Northeastern Units 3&4 by April 2016, replacing contemporaneously with a combination of an assumed market capacity purchase and new-build natural gas CC capacity.

### PSO 2012 Integrated Resource Plan

52 

## As represented in TABLE 6-3, the following two sensitivity cases were assessed to examine the relative impact of the operating life-cycle and cost recovery period for the DFGD retrofit options:

TABLE 6-3 Sensitivity #1A : same as Option 1 above, except

... operate (and cost-recover) both ACI and DFGD-retrofitted units fo r 25 years, or through the full modeling study period (that is, thru 2040). Sensitivity #2A : same as Option 2 above, except

... operate (and cost-recover) the NE4, ACI and DFGD-retrofitted un it for 25 years, or through the full study period (2040).

### PSO 2012 Integrated Resource Plan

53 (a) (b) (c) (d) (e) (f) (g)

(1) PSO Production Capital Overhead Alloc

@ 11.2%

Unit Capacity Millions $/kW Ins talled Millions Millions $/kW Ins talled MW (Nominal $) (2011 $) (Nominal $) (Nominal $) (2011 $)

EPA SETTLEMENT Option : Northeastern Unit 3 (only) DSI/FF Baghouse & ACI RETROFIT Option @ 6/2015 (NE Unit 4 Retired & Replaced in 2016 with PPA) (4) Dry Sorbent Injection (DSI), Fabric Filter(FF) & ACI 210 $415 24 234 $462 (5) Separated Over

‐ Fired Air (SOFA) 6 $13 1 7 $14

(6) TOTAL DSI/FF, ACI, SOFA 46 0 216 $428 24 240 $476

PLUS: Add'l Environmental Project Costs included in Modeling : CEMS and CCR

‐ Related (by 12/2017) 40 $75 4 4 4 $84 (8) TOTAL All Projects Modeled 460 256 $503 29 28 5 $560

(9) Option #1 : Northeastern Units 3 an d 4 DFGD & ACI RETROFIT Option @ 4/2016

(10) Dry (NIDTM) FGD (DFGD) 670 $679 75 746 $755 (11) FGD Landfill & Rail Improvements 58 $56 6 64 $62 (12) Activiate Carbon Injection (ACI) 21 $20 2 23 $23 (13) SOFA 13 $14 1 14 $15 (B) (14) TOTAL DFGD, ACI, SOFA 915 762 $768 85 847 $854

PLUS: Add'l Environmental Project Costs included in Modeling : CEMS and CCR

‐ Related (by 12/2017) 80 $76 9 89 $84

(16) TOTAL All Projects Modeled 915 842 $844 94 936 $939

Option #2 : Northeastern Unit 3 (only) DFGD & ACI RETROFIT Option @ 4/2016 (NE Unit 4 Retired & Replaced in 2016 with PPA) (18) DFGD 335 $671 38 373 $747 (19) FGD Landfill & Rail Improvements 29 $55 3 32 $61 (20) ACI 10 $20 1 12 $22 (21) SOFA 7 $14 1 7 $15 (B) (22) TOTAL DFGD, ACI, SOFA 462 381 $760 43 424 $846

PLUS: Add'l Environmental Project Costs included in Modeling : CEMS and CCR

‐ Related (by 12/2017) 40 $75 4 4 4 $83

(24) TOTAL All Projects Modeled 462 421 $835 47 468 $929

(25) Option #3 : (Original Modeling not Revised)

(26) Option #4 : No NE Unit Retrofits (BOTH Units Retired)... with (partial) Combined Cycle Replacement Build in 2016 ( i.e. , combined with PPA)

(C) (D) (E) (27) TOTAL (Greenfield) CC w/o Duct

‐ Firing 390 555 $1,287

‐ 555 $1,287 (28) " " " with Duct

‐ Firing 465 $1,088 $1,088

ALL Options... Combustion Turbine

(Used in Subsequent Year's [post

‐ 2016] Resource Optimization) (D) (E) (30) TOTAL (Greenfield) CT 236 $833

‐ $833

(A) Represents PSO and AEP

‐ EP&FS capital cost estimates utilized for revised Strategist® modeling purposes in August 2012... (B) Reflects an assumed ~1.6% unit derate to compensate for assumed NID

‐ FGD parasitic load (C) Represents an absolute cost and MW capacity based on roughly two

‐ thirds (64%) of a (~610

‐ MW, nominal ISO

‐ rated @ 1150' ) 2x1 GE F

‐ Series CC... (~726

‐ MW wit h Duct

‐ Firing) (D) Note: "2011 $" CC/CT installed cost would be utilized by the model in subsequent years' (post

‐ 2016) PSO resource optimizations (E) Assumes a "generic" CC

‐ build w/ no overhead adder based on possibility of being built under contract with a 3rd

‐ party (29) (2)

(7)

(15) (3)

(17)

(23) Direct (EPC) & Indirect Costs (A) TOTAL COST (Excluding AFUDC) Estimated Capital Expenditures Used in Strategist® Modeling

( Excluding AFUDC) Reflecting UPDATED Installed Cost Estimates for (Follow

‐ up) Analysis, August 2012 

## TABLE 6-4 offers a summary of the in stalled costs of these alternatives.

TABLE 6-4

### PSO 2012 Integrated Resource Plan

54 

## 6.4 Modeling Results

Table 6-5 offers a tabulation of the comparative modeling results for the Northeastern 3 and 4 disposition options, all un der the various commodity pricing scenarios identified in

TABLE 6-1 above. This tabula tion represents a re lative cost analysis, meaning each are compared to a base profile for purposes of dete rmining the least-cost alternative outcome. Given that, Table 6-5 reflects the costs of alternative Options 2, 4 and EPA Settlement compared to a Base or reference alternative (Option 1 - Re trofit both Northeastern Units 3&4 with DFGD technology). The analysis indicates that the EPA Settl ement Option offers a $201 million, or 1.5% CPW savings, versus Option 1, under the BASE commodity pricing scen ario. Likewise, under the Lower Band scenario pricing, the EPA Se ttlement Option offers a $297million, or 2.3%, CPW savings versus Option 1. Furthermore, the EPA Settlement Option also offers a reasonable result when viewed from an annual, year-to-ye ar CPW perspective over th e course of the longterm study period.

Further, the relative costs of the EPA Settleme nt Option also continued to be on par with the results of either Option 2 or Option 4, with su ch relative costs being slightly lower for the EPA Settlement Option view under either the BASE or Lower Band commodity pricing scenario. The analysis estimates that the CPW costs of Option 2 (Retire/Replace Northeastern 4 and

Retrofit Northeastern 3 with DFGD + ACI in 2016) are $100 million less expensive, or representing a 0.7% savings over Option 1 under the BASE commodity pricing scenario. The analysis also shows that Option 4 (Retire/Repl ace both Northeastern 3 and 4 in 2016) is $50 million less expensive than Option 1 (Retrofit both Northeastern 3 and 4 in 2016), a 0.4%

difference.

### PSO 2012 Integrated Resource Plan

55 Public Service Company of Oklahoma Environmental Compliance Plan Northeastern Units 3 and 4 Disposition Economic Analysis 30-Year Study Period (2011-2040) Economics

Option #2 (1 NE Coal Unit) Option #4 (No NE Coal Units) EPA SETTLEMENT Option (1 NE Coal Unit)

RETIRE NE U4 (4/2016) ; RETROFIT U3 (4/2016 w/ DFGD & ACI...Operate 15 yrs) RETIRE BOTH Northeastern Units 3&4 (4/2016) RETIRE NE U4 (4/2016); RETROFIT U3 (w/ DSI, FF Baghouse & ACI @ 4/2016... Operate ~11 yrs w/ Reduced Capacity Factors eff: 2021) Replacing U4 @ 4/2016 w/ Capacity Purchases; Replacing U3 in 2031 w/ NG New

‐ Build Replacing U3&4 @ 4/2016 with Capacity Purchases and New

‐ Build Natural Gas units Replacing U3 @ 4/2016 w/ Capacity Purchases; Replacing U4 in 2026 w/ NG New

‐ Build

L/T Commodity Pricing Scenarios

%

‐ 0.7%

‐ 0.4%

‐ 1.5%

'Commodity Pricing' Scenario... $MM (174) (189) (297)

% ‐ 1.4%

‐ 1.5%

‐ 2.3%

n/a = not analyzed

Option #2A (1 NE Coal Unit) Option #4 (no change fr above) (No NE Coal Units) EPA SETTLEMENT Option (no change from above)

same as Option #2

... except:

U4 Operate & Recover Costs

over 25 Yr. Period RETIRE BOTH Northeastern Units 3&4 (4/2016) RETIRE NE U4 (4/2016); RETROFIT U3 (w/ DSI, FF Baghouse & ACI @ 4/2016

L/T Commodity Pricing Scenarios

% 1.2% 3.4% 2.2%

'Commodity Pricing' Scenario... $MM 61 260 153

% 0.5% 2.1% 1.2%

$MM 199

% 1.5%

n/a = not analyzed

Note:

‐‐ A "POSITIVE" value above would favor the NE3 and 4 RETROFIT alternative (Option #1)... a " <NEGATIVE> " value would favor the alternative option

‐‐ Every $100 Million change in CPW is equivalent to a $4.94 per Mwh (0.494 cents/kWh) impact on levelized annual PSO G

‐ rev req (2011$), 2016

‐ 204 0

For example: Based on the <$201 million> incremental cost/<benefit> associated with the "EPA Settlement Option" (above), the

average increm. cost (vs. Retrofit BOTH: "Option #1") to a typical residential customer using 1,000 kWh per month would be... (

‐ 201 / 100 x $0.000494/kWh x 1,000 kwh = < $0.99>/month for EACH month through the study period (2011 $)

Additional Notes:

o 'BASE' ("Fleet Tra nsi ti on

‐ CSAPR") pricing scena rio ‐‐ as well a s "LOWER Band" pricing scena rios ‐‐ assumes ca rbon/CO2 pricing i s e ffective in 2022

o Option #2 assumes a 15

‐ yea r recove ry ca pa ci ty purcha se term (to 2030) followed by new

‐ build NG replacement capa ci t y

o Option #3 was not included in this 'Follow

‐ up' Analysi s a s i t had similar ‐‐ but delayed ‐‐ cha ra cte ris ti cs a s the EPA Settlement Opti on

o Option #4 (Re ti re Both Northea s tern coal uni ts, repla ci ng w / capa ci ty purcha ses and new

‐ build NG plants ) assumes a 30

‐ yea r recove ry period for the CC

‐ build

o U3 and / or U4 "Re ti rement" Opti ons #2 & #4 and 'EPA Settlement' conse rva tively excludes cos ts a s socia ted w / s ocio

‐ economic impacts to the regi on as well as any reti reme n

(asset wri te

‐ down and / or decommi s sioning) cos ts; i.e., res ul ti ng in no rela tive impact on these Northeas te rn dis posi tion analyses

o PSO "G" Revenue Requi rements a re re flective of a 'cos t

‐ optimized' resource plan neces sa ry to achieve SPP minimum reserve ma rgin cri te ri on... Such cos ts inclusive of: 1) All PSO (compa ny

‐ di spa tched) Fuel, VOM and Emi ssion Cos ts (incl. CO2); 2) on

‐ going plant FOM; and 3) FOM and Ca pi tal (ca rryi ng cos ts )

on incrementa l inves tments (e.g. envi ronmental re trofi ts on coal unit and / or new

‐ build / conve rted NG

‐ CC ca paci ty) ( COST / <SAVINGS> )

versus... Option #1 (2 NE Coal Units): RETROFIT BOTH Northeastern Units 3&4 with: DFGD & ACI (4/2016), Operation & Cost Recovery over 15 yrs (thru 2030) (then Retiring/Replacing with New

‐ Build NG)

434

2. "Fleet Transition

‐ CSAPR: LOWER Band " Option #1A : same as Option #1

... except: Units 3&4 Operate (and Recover Costs) over 25 Yr. Period (thru 2040) FOLLOW-UP ANALYSIS (AUGUST-2012)

COMPARATIVE Cumulative Present Worth (CPW) of Relative PSO "G" Revenue Requirements (2011 $)

BASE: Fleet

‐ Transition: CSAPR $MM (100) (50) (201)

2. "Fleet Transition

‐ CSAPR: LOWER Band "

283 SENSITIVITY : DFGD RETROFIT LIFE-CYCLE PERIOD OF 25 YRS . (vs. 15 YRS.)

3. "Fleet Transition

‐ CSAPR: Early Carbon " versus...

n/a n/a BASE: Fleet

‐ Transition: CSAPR 146 $MM 

## Table 6-5: Modeling Results

### PSO 2012 Integrated Resource Plan

56 

## 7.0 Conclusions and Recommendations

7.1 Capacity and Energy Plan Based on the previous summarizations of the major contributors used in the determination of PSO’s capacity resource “need”, the following TABLE 7-1 illustrates the forecasted 2012 SPP planning year:

TABLE 7-1

(Projected) Peak Demand 4,233 MW (CDR Section 7A; Exhibit SCW-1) 

## Less: DSM-DR 103 MW (CDR Sections 7B & 7D; Ex SCW-2) 

## Less: AEP-West Load Diversity 32 MW (CDR Sections 7F) 

## Plus: Sales With Reserves 0 MW (CDR Section 8) 

## Less: Purchases With Reserves 39 MW (CDR Section 9) 

## (A) = LOAD RESPONSIBILITY 4,059 MW (CDR Section 10)



## Owned Generating Capability 4,268 MW (CDR Sections 1 & 2; TABLE 1) 

## Less: Sales Without Reserves 0 MW (CDR Section 4) 

## Plus: Purchases Without Reserves 556 MW (CDR Section 5) 

## (B) = TOTAL CAPABILITY 4,824 MW (CDR Section 6)



## (C)=(B)-(A) = RESERVE CAPACITY 765 MW (CDR Section 11 ) 

## (D)=(B)/(A)-1 = ‘R ESERVE’ MARGIN 18.8% (CDR Section 12) 

## (E)=(C)/(B) = ‘CAPACITY’ MARG IN 15.9% (CDR Section 13) 

## (F)=(B)-[(A)/(1-12%)] =

RESERVES ABOVE/<BELOW> MINIMUM SPP CAPACITY MARGIN 

## (12.0%) 212 MW (CDR Section 14)



## These single-year (2012) results excerpted from Figure 3-1 above indicate that PSO is currently expected to have a small (212 MW) capacity margin above the minimum SPP criterion by virtue of its Total Capability exceeding its Lo ad Responsibility by 15.9 percent, or slightly above that 12 percent SPP-required minimum.

### PSO 2012 Integrated Resource Plan

57 

## 7.2 Plan Summary Based on the modeling results that were pr edicated on a more gas-friendly earlier

CO 2 

## /carbon (Fleet Transition-CSAPR: Early Carbon) and lower natu ral gas and attendant energy pricing (Fleet Transition-CSAPR: Lower Band) scenarios, the analysis indicates that three of the compliance alternatives were reas onably similar in overall cost over the study period. That is, the study period CPW cost of retrofitt ing both units in 2016 (Option 1) or retrofitting in some form one unit in 2016, and retiring the ot her unit in 2016 and replacing (a t least in part) that capacity with a market purchase contract (Options 2 and 3), were similar. More precisely, the 30-year study period CPW values for Options 1, 2, and 3 were within nearly one percent of each other. The most costly alternative was clearly the retirement and immediate replacement (with newbuild gas generation and market purchases) of both units (Opti on 4), with this option being within approximately two to three percent of the other options. In short, while there was some

difference in the estimated CPW costs for th e unique compliance plan alternatives, those differences are not materially significant, particul arly in light of all of the necessary assumptions, forecasts, and underlying estimates. Put differe ntly, PSO had several re asonable alternative compliance plans or strategies around the North eastern coal units to choose from. A follow-up analysis performed more recently in August of 2 012 tended to support the earlier results. That is, the subsequent analysis continue d to indicate that the complianc e alternatives were reasonably

similar in overall CPW co st over the study period. In addition, PSO plans to meet the terms of the Northeastern Settlement by specifically retiring Northeastern 4 in April 2016 and re placing with approximately 260MW of base-load capacity (PPA) beginning June 1, 2016

.



## 7.3 Five Year Action Plan Steps to be taken by PSO over the next five years with respect to its generating assets

include:

 Retire Northeastern Unit 4 by end of April 2016

 Retrofit Northeastern Unit 3 with DSI tec hnology, ACI and fabric filter baghouse by April 16, 2016

 Replace with approximately 260MW of lo ad capacity (PPA) beginning June 1, 2016

### PSO 2012 Integrated Resource Plan

58 

##  Implement 2013-2015 Demand Portfolio currently pending before the Commission in

PUD 201200128

7.4 Conclusion PSO has put forth an IRP that meets the requirements of its customers in a least

reasonable cost fashion as refl ected in Table 7-1. The optimal option has significant economic advantages, particularly after co nsidering the relative impacts asso ciated with three of the more critical driving economic risk para meters: the potential future cost of natural gas, the timing of

CO 2 

## /carbon pricing, and the future costs to construct either of the available options. In addition, the Company continues to operate demand-side programs in its Oklahoma jurisdictions. PSO will continue to evaluate supply and demand-side options to meet the long-term needs of its

customers in a cost-effective and reliable manner.

The future PSO capacity resource plan set forth in this final CDR summary represents a reasonable proxy at this time. Additional options and analyses will continue to be evaluated and performed that could offer some modification of, particularly, the type (and timing) of resources that would ultimately be relied upon by the Company.

### PSO 2012 Integrated Resource Plan

59 

## Figure 7-1: Capability, Demand and Reserve (CDR)

### PSO 2012 Integrated Resource Plan

60 

## APPENDIX

## Exhibit A: Demand-Side Resources



# Table of Contents

I. Home Weatherization

................................................................................. 2

II. High Performance Homes

............................................................................. 7

III. Energy Saving Products and Services

............................................................ 11

IV. Educational Program

................................................................................ 17

V. High Performance Businesses

....................................................................... 18

VI. Business Demand Response

........................................................................ 23

### PSO 2012 Integrated Resource Plan - Exhibit A

2 

## I. Home Weatherization

PSO’s proposed Home Weatheri zation Program seeks to generate energy and demand savings for limited income residential customers th rough the installation of a wide range of cost

effective weatherization and othe r measures in eligible dwellings. The purpose of the Home Weatherization Program is to provide PSO’s limite d income residential customers the financial assistance they need to make their homes more energy efficient, increase comfort levels, and reduce their utility bills.

PSO’s program budget includes funds for the inst allation of measures, PSO or third-party implementer costs, measurement and verificat ion, online program mana gement and tracking systems, and other administrative functions. PSO may choose to use a third party implementer to process payments to various weatherization agen cies, provide contractor training, customer outreach, and other program processes.

The objective of the Home Weatherization prog ram is to focus on residential customers

or communities with customers with total annual household incomes at or below 200% of federal poverty guidelines, and househol ds with annual incomes less than $35,000. Goals of the program

are to:

 Achieve customer energy and cost savings

 Educate customers on the benefits of con tinued or expanded energy efficiency and conservation efforts including, but not limited to, a change in customer usage habits through energy education

 Supplement the resources of existing state, fe deral, nonprofit, and trib al housing authority weatherization programs to allow more eligib le dwellings to be treated on an annual basis. This may include the replacement of non-energy specific elements that without replacement prevent eligible homes from r eceiving state, federal, nonprofit, and tribal housing funds, under the condition that spec ific energy efficiency and conservation measures, as deemed cost effective by PSO , are also installed at the residence.

The program is designed to facilitate the in stallation of a wide ra nge of cost-effective

weatherization measures such as:

 Ceiling Insulation

### PSO 2012 Integrated Resource Plan - Exhibit A

3 

##  Infiltration Control

 AC and Heat Pump Tune-ups

 Exterior Door Replacement

 Carbon Dioxide Detectors

 Blower Door Tests

 Duct Efficiency The following measures are excluded from consideration in the program:

 Measures that receive an inducement th rough any other energy efficiency program offered by PSO.

 Measures that involve self-generation or cogeneration, except for renewable DSM technologies.

 Measures that rely only on changes in customer behavior and require no capital investment.

 Measures that result in negative e nvironmental or health effects. As a general rule, measures involving “plug loads” (equipment or appliances that are plugged into standard electrical outlets) are not permitted. However, this restriction may be waived by PSO if it can determine with reasonable assurance that the energy and/or demand savings associated with such measures are likely to persist over a 10-year period of time and that quantifiable energy and/or demand reduction can indeed be achieved through the proposed measure(s).

PSO will utilize the expertise of the existing state, federal, nonprofit, and tribal housing authority weatherization agency programs personnel to install the weatherization measures. These weatherization agencies will be responsible for all necessary data collection, utilizing PSO documentation, providing a detailed breakdown of m easures installed, invoi ces, customer release forms, and other information deemed necessary by PSO.

Participating customers must be homeowners who purchase retail electricity from PSO on a residential tariff. PSO’s eligibility may eith er focus on entire low income communities with a substantial percentage living at or below 200% of the Federal Poverty level, as indicated by U.S. Census data, or for specific customers livin g at 200% of the Federal Poverty Guideline, as published each year in the Federal Register. Table A1 displays the 2012 income (Federal Poverty) guidelines. Households with annual in comes less than $35,000 are also eligible for the

program.

### PSO 2012 Integrated Resource Plan - Exhibit A

4 

## Table A1 % Gross Yearly Income Family Size 100% 200% 300% 1 $11,170 $22,340 $33,510 2 15,130 $30,260 $45,390 3 19,090 $38,180 $57,270 4 23,050 $46,100 $69,150 5 27,010 $54,020 $81,030 6 30,970 $61,940 $92,910 7 34,930 $69,860 $104,790 8 38,890 $77,780 $116,670

Eligible customers include:

 Low Income Energy Assistance Program (LIEAP)

 Total annual household income at or be low 200% of federal poverty guidelines

 Low income communities with a substantial population living at or below 200% of the federal poverty level, as indi cated by U.S. Census data

 Households earning less than $35,000 per year

 Elderly and handicapped

 Single-family homes qualify for this program as long as it is a primary residence receiving electric service from Public Service Company of Oklahoma (PSO) Baselines for all program measures except CFLs can be found in the Oklahoma Deemed Savings 2010 document, Exhibit WLB-08(a). The deemed savings values presented represent best estimates of the average impact of a m easure at the customer’s meter if installation standards are properly applied. Because savings estimates represent av erages, they are not appropriate for making measure sa vings representations to custom ers. It is the installer’s responsibility to evaluate premise and equipmen t conditions and customer usage patterns to properly estimate actual savings. No warranty of savings or th e suitability of any measure contained in these documents is implied. Integral CFLs replacing general service la mps used a new baseline set by the Energy Independence and Security Act (EISA) of 2007. EISA mandates a new level of efficacy for general service lamps, phasing out the 100W, 75W, 60W, and 40W incandescents beginning in 2012. Savings were calculated us ing the new baseline set by EISA for general service lamps. In each case the customers are living at or ne ar poverty level. They have little or no available funds to make energy improvements to their homes.

### PSO 2012 Integrated Resource Plan - Exhibit A

5 

##  Lack of information - many customers do not know enough about home energy use to identify opportunities for savings an d make the necessary repairs.

 Financing - limited income customers are not likely to have the necessary funds to pay

for the installation of measures that w ill improve space-conditioning efficiency.

To overcome these barriers, PSO will take the following steps as part of the program:

 Provide funding for the weatherization of ho mes owned or rented by limited income customers. Customers will be approached by agencies or contractors who will inform them of improvement opportunities. By re moving any investment requirement, PSO hopes to motivate a significant number of limited income customers to adopt proposed

measures. Title 165, Chapter 35 of the Oklahoma Corpor ation Commission rules requires that PSO offer a low income weatherization program. Ad ditionally, PSO recognizes that this program,

when combined with other federal and state w eatherization programs, could provide low income and limited income customers with significant upgr ades in the efficiency and comfort of their

homes.

Cost Effectiveness

The analysis demonstrates that this program passes all cost effectiveness tests except the Ratepayer Impact Measure, as shown in Table A2.

Table A2

Participa

nt Test Program Administra

tor Cost

Test Ratepayer Impact Measure Total Resource Cost Test Societal Test Benefit/Cost Ratio 18.83 1.15 0.10 1.46 1.82 Net Benefits ($000s) 77,263 1,346 -95,031 4,057 7,373 Total Benefits ($000s) 81,596 10,140 10,140 12,852 16,354 Total Costs ($000s) 4,333 8,794 105,171 8,794 8,981

Upon implementation, PSO will m onitor the program to evaluate how effectively it reaches its target market, and make modifications to improve market penetration if it is not

### PSO 2012 Integrated Resource Plan - Exhibit A

6 

## meeting expectations. PSO may need to cons ider extending their fu nds to other nonprofit agencies in order to make sure that their f unds are spent each year, and their customers are reached. Additionally, in order to increase the market potential, PSO may extend eligibility to

additional tiers of the Federal P overty Guidelines where customers may need financial assistance to improve the efficiency of their homes.

Program Costs The total annual budget is reflected in th e table below, broken down by annual cash inducements, non-cash inducements, and administrative costs.

Table A3

Year Annual Cash Inducement Cost ($) Annual Non-Cash Inducement Costs ($) Annual Administrative Costs ($) Total Annual Program Costs ($)

2013 1,570,412 1,256,330 314,082 3,140,824

2014 1,570,412 1,256,330 314,082 3,140,824

2015 1,570,412 1,256,330 314,082 3,140,824

Annual administrative costs incl ude internal labor, tracking and advertising expenses, and EM&V activities. The table below provides a brea kdown of the EM&V costs included within the

total administrative costs.

Table A4

Year Non-EM&V Admin EM&V Admin Total Admin

2013 188,449 125,633 314,082 2014 188,449 125,633 314,082 2015 188,449 125,633 314,082

### PSO 2012 Integrated Resource Plan - Exhibit A

7 

## Demand Impacts The following table details the annual program capacity and energy savings estimates for

PSO’s Home Weatherization Pr ogram. PSO expects the savings provided by its energy efficiency program to be evenly distri buted throughout the Company’s system.

Table A5

Year Annual kWh Energy Savings Annual kW Demand Reduction Annual Therms Gas Savings

2013 2,119,479 1,301 167,266 2014 2,119,479 1,301 167,266 2015 2,103,910 1,292 167,266

II. High Performance Homes

PSO’s proposed High Performance Homes Pr ogram seeks to generate energy and demand savings for residential customers throu gh the promotion of comprehensive efficiency upgrades to building envelope measures and HVAC equipment for both ENERGY STAR ® 

## new homes and retrofits. The purpose of the High Performance Homes Program is to provide PSO

residential customers with inducements for in creasing building envelope efficiencies and installing items such as high efficien cy appliances and HVAC equipment.

PSO’s program budget includes funds for cu stomer rebates, PSO or third-party implementer costs, measurement and verificat ion, online program mana gement and tracking systems, and other administrative functions. The estimated customer rebates in the analysis performed coincided with roughly 75% of increm ental cost; however, PS O may adjust rebate amounts when programs are implemented to ensure cost effectiveness, and to incentivize customer participation.

PSO may choose to use a third party implemente r to process rebates, provide contractor training, customer outreach, a nd other program processes.

The objective of the High Performance Homes Program is to promote comprehensive efficiency upgrades to building envelope meas ures and HVAC equipment for retrofits and new homes. The High Performance Homes Program will help customers recognize improved comfort levels as a result of upgrading their thermal envelope and/or heating and cooling

### PSO 2012 Integrated Resource Plan - Exhibit A

8 

## equipment. Offering PSO customers direct indu cements for higher efficiency measures offsets the first cost obstacle, encouraging customers to choose the upgraded products. PSO intends to provide audits to their reside ntial customers to help them identify what energy efficiency measures could improve their comfor t while reducing th eir energy costs.

The main goals of the program are:

 Long-term and permanent changes in behavior , attitude, awareness, and knowledge about energy savings and use of energy efficient technologies in orde r to achieve energy savings;

 Permanent peak electric demand reduction;

 Energy cost savings and cost-effectiveness;

 Reliability enhancements;

 Energy security benefits;

 Environmental benefits;

 Economic development/competitive benefits

The program is designed to facilitate the insta llation of a wide range of cost-effective measures including, but not limited to:

 Ceiling insulation

 Duct sealing and insulation

 Infiltration control

 E NERGY 

## S TAR 

## air conditioners

 E NERGY 

## S TAR 

## heat pumps

 E NERGY 

## S TAR 

## windows

 CFLs

Participants in the program must be single-family homeowners who purchase retail electricity from PSO on a residential tariff.

Baselines for all program measures were es timated by the program implementor, ICF, based on deemed savings values. The deemed savi ngs values presented represent best estimates of the average impact of a measure on the gas or el ectric utility’s system at the customer’s meter if installation standards are pr operly applied, assuming a baseli ne adherent to national and regional standards. Because these represent av erages, they are not appropriate for making measure savings representations to customers. It is the installer’s res ponsibility to evaluate

### PSO 2012 Integrated Resource Plan - Exhibit A

9 

## premise and equipment conditions and customer usage patterns to properly estimate actual savings. No warranty of savings or the suitability of any measure contained in these documents is implied. The High Performance Homes Program may invol ve measures such as ceiling insulation, wall insulation, duct sealing and insulation, CFLs, ENERGY STAR refrigerated air conditioners, Energy Star heat pumps, and infiltration control. Existing single family homes are eligible to participate in this program.

The barriers likely to impede residential customers from participating in the High Performance Homes Program include:

 Lack of information -where the consumer does not know enough about the technology and payback to determine whether to participate

 Financing- even with inducements, customers may not have the necessary funds to pay for the efficiency measures. To overcome those barriers, PSO will:

 Cover a large part of the cost for an audit, and offer rebates on other qualifying items.

 Offer audits by PSO certi fied representatives.

 Offer outreach to various types of contractor s who can perform the measures proposed in this program, especially licensed HVAC contractors. The measures evaluated for this program we re based on previous program experience. Past program implementation showed the areas fo r the potential expansio n or contraction of certain efficiency measures.

Cost Effectiveness

Analysis demonstrates that the High Perfor mance Homes Program passes all of the cost effectiveness analysis except the Ratepayer Impact Measure.

Table A6

Participant Test Program Administrator Cost Test Ratepayer Impact Measure Total Resource Cost Test Societal Test Benefit/Cost Ratio 4.96 1.14 0.25 1.17 1.34 Net Benefits ($000s) 50,474 2,017 -48,430 2,897 6,116 Total Benefits ($000s) 63,231 16,253 16,253 20,400 24,049 Total Costs ($000s) 12,757 14,236 64,683 17,503 17,933

### PSO 2012 Integrated Resource Plan - Exhibit A

10 

## PSO has modeled its High Performance Homes Pr ogram to reflect its expectation that the program will experience moderate growth betw een years one and three; however, participation may not reach or may exceed anticipated levels in any given year. Upon implementation, PSO will monitor the program to evaluate how effectively it reaches its target market, and make modifications to improve market pe netration if it is not meeting expectations, or to reduce freeridership if the program is over-subscribed and fr ee-ridership is suspected. As the market for a given technology matures, PSO may need to in crease minimum efficiency levels for certain equipment.

This program design reflects the current state of the residentia l housing markets. Retrofit building practices, and high efficiency applia nces and equipment are subject to minimum efficiency standard changes as a re sult of federal, state or local c ode increases at any given time. PSO will its programs in conjunction with any effi ciency code changes that go into effect with regards to housing retrofit requi rements, appliances, and HVAC equipment rebated under this

program. Program Costs The total annual budget is reflected in Tabl e A7 below, broken down by annual cash inducements, non-cash inducements , and administrative costs.

Table A7

Year Annual Cash Inducement Cost ($) Annual NonCash Inducement Costs ($) Annual Administrative Costs ($) Total Annual Program Costs ($)

2013 2,411,422 1,205,711 401,904 4,019,037

2014 3,042,058 1,521,029 507,010 5,070,097

2015 3,795,503 1,897,752 632,584 6,325,839

Annual administrative costs incl ude internal labor, tracking and advertising expenses, and EM&V activities. Table A8 below provides a brea kdown of the EM&V costs included within the

total administrative costs.

### PSO 2012 Integrated Resource Plan - Exhibit A

11 

## Table A8

Year Non-EM&V Admin EM&V Admin Total Admin

2013 241,142 160,761 401,904 2014 304,206 202,804 507,010 2015 379,550 253,034 632,584

Demand Savings The following Table A9 details the annua l demand reduction, energy savings, and gas savings (if applicable) estimated for this prog ram. PSO expects the savings produced by this program to be evenly distribute d throughout the Company’s system.

Table A9

Year Annual kWh Energy Savings Annual kW Demand Reduction Annual Therms Gas Savings

2013 3,973,279 2,549 384,539 2014 3,900,920 2,722 309,992 2015 4,882,576 3,402 388,504

The energy and peak demand savings provide d in the table above represent generation impacts, in that estimated transmission and di stribution line losses are incorporated into the savings estimates. However, the impacts of PSO ’s portfolio of energy efficiency and load management programs on generation capacity planni ng requirements will be analyzed outside of the efforts directly associated with the deve lopment of these programs. Delta load shapes developed from modeling the planned portfolio of programs will be incorporated into PSO’s integrated resource planning process.

III. Energy Saving Products and Services PSO’s proposed Energy Saving Products and Se rvices Program seeks to generate energy and demand savings for residential customers through the promotion of E NERGY 

## S TAR 

## cooling equipment, CFLs, window replacements, duct s ealing, advanced power strip offerings, LEDs, ceiling insulation, and AC Tune Ups. The purpose of this program is to provide PSO residential

### PSO 2012 Integrated Resource Plan - Exhibit A

12 

## customers inducements for purchasing appliances and cooling equipment that meet the high efficiency standards.

PSO’s program budget includes funds for cu stomer rebates, PSO or third-party implementer costs, measurement and verificat ion, online program mana gement and tracking systems, and other administrative functions. For c ooling equipment, rebates will only be offered on products with SEER ratings greater than 17. Th e rebate schedules used in the program design for this filing are shown in Table A10.

Table A10

Measure Rebate HP – 18 SEER, 3 Tons $600 HP – 17 SEER, 3 Tons $600 AC – 18 SEER, 3 Tons $350 AC – 17 SEER, 3 Tons $350 Energy Star Window AC $35 APS – Home Office $10 APS – Entertainment System $10

CFLs $20 Duct Sealing Gas/HP $400 Energy Star Window Replacement $500

AC Tune Up $50 LEDs $20 Ceiling Insulation $450 Geothermal Heat Pump $450

PSO may modify rebates, eligibility requir ements, or installation standards prior to program rollout. This program provides financial inducements for the purchase of cooling equipment with an E NERGY 

## S TAR 

## rating, CFLs, or advanced power strips that reduce customer energy costs, reduce peak demand and/or sa ve energy for residential customers. The primary goal of this program is to achieve cost-effective reduction in energy consumption, and to reduce peak demand duri ng the summer by encouraging customers to purchase high efficiency equipment, and to re duce phantom load by installation of advanced power strips. Additional objectiv es of the program may be to:

 Increase customer awareness of the E NERGY 

## S TAR 

## label

 Encourage private sector delivery of energy efficient products and services.

### PSO 2012 Integrated Resource Plan - Exhibit A

13 

##  Achieve customer energy and cost savings

The program is designed to facilitate the in stallation of a wide ra nge of cost-effective

measures such as:

 ENERGY STAR cooling systems 17 SEER and above

 ENERGY STAR heat pump systems 17 SEER and above

 Advanced power strips

 CFLs

 ENERGY STAR window units

 Duct sealing

 ENERGY STAR Windows

 AC Tune Ups

 LEDs

 Ceiling Insulation

 Geothermal Heat Pumps The target market is residential customers with aging appliances, air conditioning and heat pump equipment that have reached the end of their useful measur e life. Additionally, the targets for the advanced power strips are th ose customers with home offices or home entertainment systems. Participants in the program must be existing single-family homeowners who purchase retail electricity fr om PSO on a residential tariff.

Baselines for all program measures (with th e exception of the advanced power strip, CFLs, and LEDs) can be found in the Deemed Savings document, Exhibit WLB-08(a). The deemed savings values presented represent best estimates of the average impact of a measure on the gas or electric utility’s system at the custom er’s meter if installati on standards are properly applied, assuming a baseline adherent to national a nd regional standards. Because these represent averages, they are not appropriate for making measure savings repres entations to customers. It is the installer’s responsibility to evaluate premise and equipment conditions and customer usage patterns to properly estimate actual savings. No warranty of savings or the suitability of any measure contained in these documents is implied. Baseline information for the advanced power strip was derived both from the New York State Energy Research and Development Authority ’s “Advanced Power Strip Research Report,” August 2011, and from regional market research.

### PSO 2012 Integrated Resource Plan - Exhibit A

14 

## Integral CFLs replacing general service lamps used a new baseline set by the Energy Independence and Security Act (EISA) of 2007. EISA mandates a new le vel of efficacy for general service lamps, phasing out the 100W, 75W, 60W, and 40W incandescents beginning in 2012. Savings were calculated us ing the new baseline set by EISA for general service lamps. Assumptions for energy savings and incremen tal costs for replacing general service lamps with LED products came from two s ources: (1) 2011 EPA Repor t. “Next Generation Lighting Programs: Opportunities for Advance Effi cient Lighting for a Cleaner Environment.”; (2) U.S. Department of Energy. “2010 U. S. Lighting Market Characterization.”

There are a number of barriers likely to impede residential customers from participating in the High Performance Homes Program:

 Lack of information - where the consumer does not know enough about the technology and payback to determine whether to participate

 Financing – even with inducements, customers may not have the necessary funds to pay for the efficiency measures.

 Organizational practices or customs - where decisions may reside with the uninformed or an entity that does not pay the bills

 Misplaced inducements, especially for multifamily residences in which the landlord owns the housing structure but the tenant pays the electric bill. To overcome those barriers, PSO will:

 Educate and inform customers and landlords through its website and bill inserts

 Cover a large part of the cost for an audit, and offer rebates on other qualifying items.

 Offer audits by PSO certi fied representatives.

 Offer outreach to various types of contractor s who can perform the measures proposed in this program, especially licensed HVAC contractors.

Based on the 2006 Residential A ppliance Saturation Survey of Home Characteristics conducted by the Public Service Company of Oklahoma, existing cooling equipment was on average 10 years old, indicating that there is po tentially a large market for cooling equipment replacement. Likewise, the study showed that the majority of homes had several typical appliances indicative of high potential for cont inuous appliance replacements over the years that this program is offered. Additionally, the incr ease in ownership of a wide variety of home entertainment system technology and home offices justified an advanced power strip offering.

PSO also conducted the Residential Customer Study: Energy Efficiency, Demand Response Attitudes , which suggested that customers f ound it very important that PSO offer

### PSO 2012 Integrated Resource Plan - Exhibit A

15 

## inducements for high efficiency cooling and appl iances. Given various le vels of inducements, survey results showed that PSO can expect activ e participation in this residential program.

Cost Effectiveness Analysis demonstrates that the Energy Saving Products program passes all cost effectiveness tests except the Ratepayer Impact Meas ure, shown in Table A11.

Table A11

Participant Test Program Administrator Cost Test Ratepayer Impact Measure Total Resource Cost Test Societal Test Benefit/Cost Ratio 13.89 1.83 0.12 1.64 1.97 Net Benefits ($000s) 188,459 10,603 -178,628 10,921 16,832 Total Benefits ($000s) 203,085 23,382 23,382 27,919 34,215 Total Costs ($000s) 14,626 12,780 202,010 16,998 17,383

PSO has modeled this Program to reflect its expectation that the program will experience moderate growth between years one and three; however, partic ipation may not reach or may exceed anticipated levels in any given y ear. Upon implementation, PSO will monitor the program to evaluate how effectiv ely it reaches its target mark et, and make modifications to improve market penetration if it is not meeting expectations, or to reduce free-ridership if the program is over-subscribed and free-ridership is suspected. As the market for a given technology matures, PSO may need to increase minimu m efficiency levels for certain equipment. A key goal for this program is to promote mark et transformation to en courage adoption of all relevant equipment.

This program is designed based on the curren t state of the resident ial cooling markets. Appliances and cooling equipment are subject to minimum efficiency standard changes as a result of federal, state or local code increases at any given time. PSO will need to adjust its programs in conjunction with any efficiency code changes that go into effect with regards to the appliances and cooling equipm ent rebated under this program.

Cost Effectiveness The total annual budget is reflected in Ta ble A12 below, broken down by annual cash inducements, non-cash inducements , and administrative costs.

### PSO 2012 Integrated Resource Plan - Exhibit A

16 

## Table A12

Year Annual Cash Inducement Cost ($) Annual Non-Cash Inducement Costs ($) Annual Administrative Costs ($) Total Annual Program Costs ($)

2013 2,491,019 1,245,510 415,170 4,151,699 2014 2,742,117 1,371,059 457,020 4,570,196 2015 3,019,597 1,509,799 503,266 5,032,662

Annual administrative costs incl ude internal labor, tracking and advertising expenses, and EM&V activities. Table A13 below provides a br eakdown of the EM&V co sts included within the total administrative costs.

Table A13

Year Non-EM&V Admin EM&V Admin Total Admin

2013 249,102 166,068 415,170 2014 274,212 182,808 457,020 2015 301,960 201,306 503,266

Demand Impacts The following table details the annual dema nd reduction, energy savi ngs, and gas savings (if applicable) estimated for this program. PSO expects the savings provid ed by this program to be evenly distributed thr oughout the utility system.

Table A14

Year Annual kWh Energy Savings Annual kW Demand Reduction Annual Therms Gas Savings

2013 10,569,444 2,290 243,306 2014 11,629,317 2,520 267,445 2015 12,047,769 2,356 293,984

The energy and peak demand savings provide d in the table above represent generation impacts, in that estimated transmission and di stribution line losses are incorporated into the savings estimates. However, the impacts of PSO ’s portfolio of energy efficiency and load management programs on generation capacity planni ng requirements will be analyzed outside of the efforts directly associated with the deve lopment of these programs. Delta load shapes

### PSO 2012 Integrated Resource Plan - Exhibit A

17 

## developed from modeling the planned portfolio of programs will be incorporated into PSO’s integrated resource planning process.

IV. Educational Program PSO’s proposed Educational Program seeks to generate minimal energy and demand savings for residential customers by providing elementary school st udents with eas y self-install energy efficiency measures, such as CFLs an d Advanced Power Strips. The purpose of the Educational Program is to provide PSO residentia l customers with an educational experience on

how to make their homes more efficient.

The intent of the Educational Program is to provide an educational experience for home

owners to learn how to make their homes more energy efficient with easy-to-install measures.

 Provide a way for residential customers to more easily receive direct information to help make their home more energy efficient.

 Improve operating energy efficiency of ex isting homes for residential customers.

Because energy savings are minimal, PSO will not report any energy savings from this program. The program targets students and their classroom teachers. The program implementer will target schools within PSO’s service territory.

The savings for this program will be minima l because the objectives are education and the promotion of easy-to-install measures. PSO will not report any energy savings from this

program. The major barrier resolved by this program is the effect of lack of information on

customer initiatives to instal l energy efficiency measures on their own. Many customers do not know enough about home energy use to identif y opportunities for savings and make the necessary repairs or investments. To overcome this barrier, PSO will offer educational materials to inform its customers of the ways they can reduce energy consumption.

The 2006 Residential Appliance Saturation Surv ey of Home Charact eristics conducted by PSO found that the average existi ng home in the PSO service te rritory would be eligible to participate in energy efficiency program offe rings. The Educational Program is offered to

educate customers on how to make their homes more efficient, as well as to make them aware of

### PSO 2012 Integrated Resource Plan - Exhibit A

18 

## what programs offered by PSO may assist them in making energy efficiency upgrades to their

homes.

Cost Effectiveness Because PSO is not claiming any energy or demand savings for this program, the costeffectiveness tests (with the exception of the PT) all equal 0.0.

Table A15

Participant Test Program Administrator Cost Test Ratepayer Impact Measure Total Resource Cost Test Societal Test Benefit/Cost Ratio 1.00 0.00 0.00 0.00 0.00 Net Benefits ($000s) 0.00 -2,800 -2,800 -1,680 -1,716 Total Benefits ($000s) 2,759 0.00 0.00 0.00 0.00 Total Costs ($000s) 2,759 2,800 2,800 1,680 1,716

The program has a set budget over the three year period addressed by this demand portfolio. As a direct result of the Educational Program, it should act as a catalyst to get more customers to participate in the othe r PSO residential rebate programs.

Program Costs The total annual budget is reflected in th e table below, broken down by annual cash inducements, non-cash inducements , and administrative costs.

Table A16

Year Annual Cash Inducement Cost ($) Total Annual Program Costs ($)

2013 1,000,000 1,000,000 2014 1,000,000 1,000,000 2015 1,000,000 1,000,000

Demand Savings There are no measurable savings that can be determined for this program.

V. High Performance Businesses PSO’s proposed High Performance Businesses pr ogram seeks to generate energy savings for large and small commercial and industrial customers through promotion of high efficiency

### PSO 2012 Integrated Resource Plan - Exhibit A

19 

## electric end use products includi ng (but not limited to) lighting, HVAC, and motors. The program provides PSO’s C&I customers with flexibi lity in choosing how to participate, by either self-sponsoring or by working through a third party implementer to leverage technical expertise.

PSO’s budget for this program includes funds fo r customer rebates, PSO or third-party implementer costs, measurement and verificat ion, online program mana gement and tracking systems, and other administrative functions. The es timated customer rebates used in analysis of this program are for a range of equipment to be rebated in this program, and are intended to offset a sufficient part of the customers’ costs that, in concert with program outreach, customer education, and other promotional activities, will produce a cost-effective le vel of participation. Prescriptive rebate amounts by measure will be included in program information when the program begins; rebate amounts will be set to ensure cost effectiveness and to incentivize customer participation.

This program seeks to achieve cost-effective reduction of peak demand and energy use by assisting C&I customers in generating energy savings through promotion of high efficiency electric end use products. The program seeks to co mbine provision of financial inducements with access to technical expertise to maximize program penetration acro ss the range of potential large C&I customers. The program has additional goals:

 Increase customer awareness of applicable energy saving measures

 Achieve customer cost savings

 Increase the market share of commercial gr ade high efficiency technologies sold through market channels,

 Increase the installation rate of high efficiency technologies in C&I facilities by businesses that would not have done so absent the program

The target market is facilities where PSO e xpects saturation rates a nd awareness levels of efficient equipment to be lower. PSO’s pr oposed High Performance Businesses program incorporates two modes of cust omer participation: customers can choose to self-sponsor and participate directly with PSO, or they can wo rk through a third party project sponsor. Those customers choosing to self-sponsor also have the option to take advantage of technical expertise

that PSO will make available in the form of third party implementers.

The target market for the program incl udes both customers and project sponsors. Customers will be eligible to participate in this inducement program when they purchase

### PSO 2012 Integrated Resource Plan - Exhibit A

20 

## qualifying equipment or services. An y entity meeting the applicati on requirements that is capable of carrying out the program requirements is elig ible to be a project sponsor. PSO anticipates active participation from both the commercial and indus trial sectors.

The High Performance Businesses Program involv es a wide variety of equipment. This evaluation used past performance of PSO’s progr ams to generate energy and demand savings values. PSO anticipates that most of the C&I customers replacing lighting will be installing lighting control systems and sensors, replacing older high intensity discharge (“HID”) lighting products with light emitting diode (“LED”) lighti ng, premium fluorescent 4- or 6-lamp fixtures, or other efficient HID systems, or installing LED exit signs. With the EISA 2007 phase out of T12 fluorescent products, PSO will no l onger be rebating retrofits of T12s.

PSO anticipates that most of the C&I cust omers replacing HVAC equipment through this program will be doing so in a replace on burnout situation. For HVAC equipment that has

reached the end of its useful life, the baseline for a replacem ent unit is set by the relevant

standard. The federal standard that took effect on January 1, 2010 for unitary and split systems larger than 5.4 tons sets the baseline for such sy stems. For chiller equipment, relevant standards are the existing federal standards. For equipment being replaced befo re the end of its useful life, the baseline is determined by th e efficiency of the unit being re placed and the remainder of its

estimated useful life. Several commercial baseline assumptions can be found in Exhibit WLB08(b). The applicable baseline for motors th at are replaced on burnout is NEMA premium efficiency. For retrofit applica tions of motors that would ot herwise be rewound and kept in operation, the applicable ba seline is EPACT 1992.

The following barriers may impede C&I customer s’ decisions to install more efficient equipment or undertake efficiency-seeking ac tivities (e.g. building retro-commissioning):

 Lack of information- where the consumer does not know enough about the technology and payback

 Asymmetric information - which may lead vendors to price their more energy-efficient products at a price that is not designed for maxi mum market penetration

 Bounded rationality - where the customer acts against its own best eco nomic interest

 Organizational barriers or customs - where decisions may reside with the uninformed or the entity that does not pay the bills

### PSO 2012 Integrated Resource Plan - Exhibit A

21 

##  Financing - in the case where a customer may de sire to install more energy-efficient technology, but is unwilling to sp end or unable to obtain the re quired capital to obtain the long-term benefits

To overcome those barriers, PSO will promote the proposed program by (1) engaging market providers, (2) marketing directly to targeted customers, (3) offering customers the technical expertise of th ird party implementers, (4) providing complete website presence, (5) comarketing, when possible, and (6) conducting workshops.

PSO has consulted with the primary stakehol ders in its service territory, including traditional energy service companies and representatives of the program’s target market. The program is designed based on the current stat e of the markets for each equipment type. Furthermore, PSO contracted with experts in energy efficiency program development and design, Frontier Associates, for th e development of a portfolio of cost-effective programs, from which this proposed program was derived.

Cost Effectiveness

The benefit-cost test ratios fo r this program are favorable.

Table A17

Participant Test Program Administrator Cost Test Ratepayer Impact Measure Total Resource Cost Test Societal Test Benefit/Cost Ratio 11.14 3.04 0.30 2.45 2.84 Net Benefits ($000s) 362,639 66,684 -228,214 58,830 76,235 Total Benefits ($000s) 398,396 99,332 99,332 99,332 117,701 Total Costs ($000s) 35,757 32,648 327,547 40,502 41,465

PSO has modeled its High Performance Businesses program to reflect its expectation that the program will experience moderate growth between years one and three; however, participation may not reach or may exceed an ticipated levels in any given year. Upon implementation, PSO will monitor the program to ev aluate how effectively it reaches its target market, and make modifications to improve market penetration if it is no t meeting expectations, or to reduce free-ridership if the program is ove r-subscribed and free-ridership is suspected. As the market for a given technology matures, PSO ma y need to increase minimum efficiency levels

### PSO 2012 Integrated Resource Plan - Exhibit A

22 

## for certain equipment, or transition from a prescriptive inducement program to a market transformation program.

Programs are designed based on the current st ate of the markets for each equipment type. Lighting technology is rapidly e volving, as new technologies ente r the marketplace and replace traditional lighting retrofit tec hnologies. HVAC equipment is al so evolving, as are minimum efficiency standards set by local building codes, national standard-setti ng entities (e.g., ASHRAE or ICC), and the federal government. With the em ergence of new technologies and promulgation of higher standards, PSO will occasionally need to alter its rebate structure to incorporate these new technologies and regulator y changes, modifying program objectives to focus on maintenance and emphasizing market transformation.

Program Costs The total annual budget is reflected in th e table below, broken down by annual cash inducements, non-cash inducements , and administrative costs.

Table A18

Year Annual Cash Inducement Cost ($) Annual Non-Cash Inducement Costs ($) Annual Administrative Costs ($) Total Annual Program Costs ($)

2013 5,388,701 3,429,173 979,764 9,797,638

2014 6,374,808 4,056,696 1,159,056 11,590,560

2015 7,633,386 4,857,609 1,387,888 13,878,883

Annual administrative costs incl ude internal labor, tracking and advertising expenses, and EM&V activities. Table A18 below provides a br eakdown of the EM&V co sts included within

the total administrative costs.

Table A19

Year Non-EM&V Admin EM&V Admin Total Admin

2013 587,858 391,906 979,764 2014 695,434 463,622 1,159,056 2015 832,733 555,155 1,387,888

### PSO 2012 Integrated Resource Plan - Exhibit A

23 

## Demand Reductions The following Table A19 details the annual demand reduction, energy savings, and gas savings (if applicable) estimated for this progr am. PSO expects the savings provided by this program to be evenly distribute d throughout the utility system.

Table A20

Year Annual kWh Energy Savings Annual kW Demand Reduction Annual Therms Gas Savings

2013 37,919,306 8,219 0 2014 45,352,999 9,658 0 2015 54,463,513 11,577 0

The energy and peak demand savings provide d in the table above represent generation impacts, in that estimated transmission and di stribution line losses are incorporated into the savings estimates. However, the impacts of PSO ’s energy efficiency and load management programs on generation capacity planning requirements will be analyzed outside of the efforts directly associated with the development of th ese programs. Delta load shapes developed from modeling the planned portfolio of programs will be incorporated into PSO’s Integrated Resource Planning process.

VI. Business Demand Response The Business Demand Response program is a demand response program targeted to commercial and industrial customers served by Public Service Company of Oklahoma (PSO) capable of reducing demand on shor t notice. Typically, this capabil ity is predicated on having load-producing equipment that is operated by a c ontrol system capable of receiving a load shed signal and reducing equipment operation to produce demand savings. Such equipment may include programmable, communicating HVAC contro ls (thermostats), or commercial lighting equipped with dimmable ballasts linked to a central control syst em, among others.

PSO’s program budget includes an estimate d average of $32/kW-year for customer rebates, and PSO or third-part y implementer costs, as well as amounts for measurement and verification, online program management and tracking systems, and other administrative

### PSO 2012 Integrated Resource Plan - Exhibit A

24 

## functions. However, PSO may adjust rebate am ounts when programs are implemented to ensure cost effectiveness, and to incen tivize customer participation.

The primary goal of this program is to ach ieve cost-effective reduction in demand during critical summer peak capacity periods, and to maintain and improve overall system reliability. Additional goals of the program may be to achieve customer energy and cost savings and

educate customers on the benefits of continued or expanded energy effici ency and conservation efforts. The target market includes all co mmercial and industrial customers. Monetary inducements will be paid to customers willing to allow PSO to install devices capable of interrupting specific electrical end use load(s) w ithin a customer facility. PSO anticipates active participation from both the commercial and indu strial sectors, though this program may have broader appeal in the commercial sector.

The program attempts to provide customers an inducement to manage their energy usage on peak. Since this program relies on convincing customers to consume less energy at selected times, there is not a clear market that this progr am intends to address; rather, PSO must create a market for demand reduction by offering to pay for this service. PSO may c hoose to select one or more providers of demand response aggregation services to implement its Business Demand Response program through a competitive bidding process.

The following barriers may impede C&I cust omers’ participation in this program:

 Opportunity Cost - Customer concern that the tempor ary reduction in electricity usage would affect productivity.

 Organizational barriers or customs - Internal company policies prohibiting participation in curtailment programs.

 Bounded rationality - where the customer acts against its own best eco nomic interest

PSO provides a healthy inducement for partic ipation to overcome the opportunity cost barrier. To overcome the remaining barriers, PSO will (1) market this program directly to commercial and industrial customers, (2) will wo rk with DLC implementation service providers and/or load aggregators, and (3) wi ll provide complete website presence.

### PSO 2012 Integrated Resource Plan - Exhibit A

25 

## PSO has consulted with the primary stakehol ders in its service territory, including representatives of the program’s target market, and has consu lted with providers of demand response aggregation services.

Cost Effectiveness

Table A21

Participant Test Program Administrator Cost Test Ratepayer Impact Measure Total Resource Cost Test Societal Test Benefit/Cost Ratio 1.00 1.13 1.13 1.13 1.15 Net Benefits ($000s) 0 1,183 1,183 1,183 1,396 Total Benefits ($000s) 5,387 10,303 10,303 10,303 10,723 Total Costs ($000s) 5,387 9,120 9,120 9,120 9,326

As can be seen in the table above, the be nefit/cost test ratios for this program are favorable. The program also passes the RIM, whic h is typical of load management programs.

PSO expects the program to grow modestly over th e next three years, as customers become more aware of the program and more attuned to its benefits. Upon implementation, PSO will monitor the program to evaluate how eff ectively it reaches its target market. If participation increases more rapidly than expected, such that budget c onstraints limit the amount of peak demand for which PSO can contract through the program, PSO may need to transition from a first-come, first-served model for soliciting participation to a competitive bidding process.

Program Costs The total annual budget is reflected in the table A21 below, broken down by annual cash inducements, non-cash inducements , and administrative costs.

### PSO 2012 Integrated Resource Plan - Exhibit A

26 

## Table A22

Year Annual Cash Inducement Cost ($) Annual Non-Cash Inducement Costs ($) Annual Administrative Costs ($) Total Annual Program Costs ($)

2013 1,779,200 889,600 296,533 2,965,333

2014 1,957,120 978,560 326,187 3,261,867

2015 2,152,832 1,076,416 358,805 3,588,053

Annual administrative costs incl ude internal labor, tracking and advertising expenses, and EM&V activities. Table A22 below provides a br eakdown of the EM&V costs included within

the total administrative costs.

Table A23

Year Non-EM&V Admin EM&V Admin Total Admin

2013 177,920 118,613 296,533 2014 195,712 130,475 326,187 2015 215,283 143,522 358,805

Demand Impacts The following Table A23 details the annua l demand reduction, energy savings, and gas savings (if applicable) estimated for this prog ram. PSO expects the savings provided by this program to be evenly distribute d throughout the utility system.

Table A24

Year Annual kWh Energy Savings Annual kW Demand Reduction Annual Therms Gas Savings

2013 0 58,886 0 2014 0 64,774 0 2015 0 71,252 0

## Exhibit B: Fuel Supply Plan

Below is the 2012 PSO Fuel Supply Portfolio and Risk Management Plan which addresses the requirements of OAC 165:35-37-4( c) Schedule F: Fuel procur ement plan, purchased-power procurement plan, and risk management plan.

### PSO 2012 Integrated Resource Plan – Exhibit B



# Table of Contents

I. INTRODUCTION

.............................................................................................................................. 29

A. F UEL 

### P LANNING 

### O BJECTIVES



### ......................................................................................................................... 30 B. R ESOURCES 

### & C APABILITIES



### ......................................................................................................................... 30 1. Generation

............................................................................................................................... ..................... 30 2. Purchased Power

............................................................................................................................... .......... 32 C. P RIOR 

### P ERIOD 

### R ESULTS



### ............................................................................................................................... .. 33

II. ENERGY AND SUPPLY FORECAST

.............................................................................................. 40

A. D EMAND 

### F ORECAST



### ............................................................................................................................... ........ 40 B. F UEL 

### S UPPLY AND 

### E NERGY 

### F ORECAST



### .......................................................................................................... 40 1. Fuel

............................................................................................................................... ............................... 41 2. Energy

............................................................................................................................... ........................... 43

III. PROCUREMENT STRATEGY

......................................................................................................... 45

A. D ISCUSSION OF 

### A LTERNATIVES



### ..................................................................................................................... 45 1. Coal Procurement and Transportation

......................................................................................................... 48 2. Natural Gas Procurement and Transportation

............................................................................................. 49 3. Fuel Oil

............................................................................................................................... ........................... 51 4. Purchased Power

............................................................................................................................... ........... 51 B. S ELECTED 

### F UEL 

### P ROCUREMENT 

### P LAN



### ........................................................................................................... 53

IV. RISK MANAGEMENT

...................................................................................................................... 57

A. H EDGING



### ............................................................................................................................... ......................... 57 B. F UEL 

### D IVERSITY AND 

### O PTIMIZATION



### ............................................................................................................ 58 C. C ONTRACT 

### T ERMS



### ............................................................................................................................... .......... 59 D. C USTOMER 

### P ROGRAMS



### ............................................................................................................................... ... 60 V. C OST OF 

### E NERGY



### ............................................................................................................................... ............ 61

VI. SUMMARY

............................................................................................................................... ......... 62

### PSO 2012 Integrated Resource Plan – Exhibit B

29 

## I. Introduction

Public Service Company of Oklahoma (“PSO” or “the Company”) has served Oklahoma’s electric energy needs si nce the Company’s incorporation in 1913. PSO is headquartered in Tulsa, Oklahoma and serves approximately 532,000 customers in 232 cities and towns across 30,000 square miles of eastern and southwestern Oklahoma.

To meet the needs of its customers, PSO has approximately 4,268 Megawatts (MW) of nameplate generation capacity as well as access to the Southwest Powe r Pool (SPP) for the purchase of additional energy. PSO also engages in the purchase of renewable energy, such as wind, and capacity to further diversify its portf olio of resources. The map (Exhibit 1) below indicates the approximate boundaries of PSO’s serv ice territory (in green) and the location of its generation resources. The red squares repres ent PSO’s coal units and the purple diamonds

indicate the location of na tural gas generation units.

Exhibit 1: Map of PSO in Oklahoma

Under Order 454610 of the Oklahoma Corpor ate Commission made in Cause No. PUD 200100096, PSO provides this diversified fuel supply portfolio and risk management plan on an annual basis. This document serves to support PSO’s plans to provide reliable, adequate, and

### PSO 2012 Integrated Resource Plan – Exhibit B

30 

## flexible fuel supplies for its customers at the lowest reasonable cost. It al so explains the strategy for the purchase of energy and capacity for both economic and environmental reasons.

A. Fuel Planning Objectives As a public utility company, PSO has an obliga tion to serve its cust omers reliably at all times and at all load levels. Loads vary instantaneously and sometimes change in an unforeseen manner due to weather patterns th at are unpredictable or due to system conditions. PSO’s fuel procurement and risk mana gement plan is designed to meet concerns

for:

 Reliability - Ensure fuel w ill be available when needed

 Adequacy - Sufficient quantities are procured

 Flexibility - Ability to alter the portfolio to meet changing circumstances

 Price - Ensure the lowest reasonable deliver ed cost while consid ering other objectives

In other words, PSO’s fuel procurement activit ies are first and foremo st focused on ensuring that all the electric pow er that its customers want is availa ble when they want it and at the

lowest reasonable delivered cost.

B. Resources & Capabilities

1. Generation PSO’s generating fleet is composed of two coal power plants, six natural gas power plants and eight diesel units at six PSO plant locations. Th ese plants and their nameplate capacity are summarized in Table 1 below. Table 1: Plant Capacity

Power Plant Fuel Type Production Capacity (MW) Comanche Natural Gas 235 Riverside Natural Gas 1052 Southwestern Natural Gas 608 Tulsa Natural Gas 309 Weleetka Natural Gas 156 Northeastern 1 & 2 Natural Gas 852 Northeastern 3 & 4 Coal 930 Oklaunion* Diesel Units Coal Diesel 101 25 Total 4268

### PSO 2012 Integrated Resource Plan – Exhibit B

31 * Capacity at Oklaunion represents the PSO share.



## In addition, certain generating units at Rivers ide and Southwestern can also use fuel oil to generate electricity. PSO maintains a limite d quantity of fuel oil at these units as an emergency back-up fuel supply. PSO can also use natural gas to ru n Northeastern 3 and 4 at partial load in the even t of coal curtailments or coal-related equipment outages.

Comanche, Weleetka, Northeas tern Unit 1, Riverside Units 3 and 4, and Southwestern Units 4 and 5 are each connected to one pipeli ne system. Northeastern Units 2, 3, and 4, Southwestern Units 2 and 3, and Tulsa are each connected to two pipeline systems, and

Riverside Units 1 and 2 are connected to th ree pipelines. These multiple natural gas pipeline connections provide the Company with access to reliable, flexible, and competitively priced natural gas supplies. Th e natural gas pipeline interconnections to each of PSO’s natural gas plants are shown below in Exhibit 2.

Exhibit 2: Existing Natural Gas Pipeline Interconnections to PSO

Similarly, the Northeastern 3 and 4 coal units have access to two co mpeting rail carriers, Union Pacific (UP) and Burlington Northern Santa Fe (BNSF), for coal deliveries. Currently, UP provides coal de liveries to the Northeastern power plant with a shipping

### PSO 2012 Integrated Resource Plan – Exhibit B

32 

## distance of approximately 1,000 miles. The BN SF railroad provides de liveries of coal to the Oklaunion power plant with a shipping di stance of approximately 1,100 miles. The location of PSO’s coal generating plants relative to the coal supply region and rail transportation routes is provided in Exhibit 3.

Exhibit 3: Location of PS O Coal Plants relative to the PRB* coal supply region

*Powder River Basin



## 2. Purchased Power American Electric Power Service Corporatio n (AEPSC), as agent for PSO, forecasts hourly, daily, monthly, and annual loads to an ticipate purchased power requirements. Because of PSO’s diverse generation portf olio, long-term wind contracts and the numerous power purchase options available to PSO, the majority of the Company’s purchased power is procured through short and medium term (less than one year) trades. AEPSC uses the GenTrader algorithmic optimization model to combine the load forecast with heat rate curves, projected fuel cost s, projected operations and maintenance costs and emissions costs to predict dispatch co sts, unit loading, and fuel consumption.

### PSO 2012 Integrated Resource Plan – Exhibit B

33 

## AEPSC’s Commercial Operations’ employees leverage a broad cross-section of operations and market knowledge to optimize the PSO system and to identify opportunities in the purc hased power market.

Wind Energy PSO has made a significant commitmen t to wind generation through long-term purchased power agreements. PSO’s wind contracts, like PSO’s longer-term power purchases in general, were procured through competitive RFP solicitations.

C. Prior Period Results Summary PSO has a diversified fleet of generators and, when combined with purchased power, offers a variety of ways to provide power to its customers when needed. Table 2 below offers a comparison of the total generation resource mix in 2010 and 2011.

Table 2: Resource Percentage Comparison Generation Resource (MWh Basis) 2010 2011

Natural Gas 37.4 34.1

Coal 31.6 36.3

Fuel Oil <0.01 <0.01

Purchased Power 21.3 17.1

Wind Energy 9.7 12.5



## In 2011, the Company had a reasonable expecta tion that the fuel mix experienced in 2010 would continue through 2011. The most significant year-on-year change illustrated in Table

2 is the increase in coal offs et by a decrease in generation from natural gas and purchased power. Additionally, wind generation increa sed in 2011 compared to 2010. There are several factors that can contribute to changes in the fuel mix. Most notably in 2011, there were fewer long-term unplanned outages at Northeastern 3 & 4 and at Oklaunion. This resulted in an increase of coal generati on available during the y ear compared to 2010.

### PSO 2012 Integrated Resource Plan – Exhibit B

34 

## The impact to PSO’s fuel costs resulting from an increase in coal and wind generation as well as the implementation of the plan detaile d in the 2011 Fuel Suppl y Portfolio and Risk Management Plan are provided in Table 3.

Table 3: Fossil Fuel Consumed During 2011

Fossil Fuel Type MMBtu % MMBtu Fuel Expense $ $/MMBtu

Natural Gas 73,055,271 48.5% $327,223,427 4.48

Coal 77,396,955 51.4% $100,853,167 1.30

Fuel Oil * 27,393 0.02% $605,772 22.11

Total 150,479,619 100% $428,682,366 2.85

*Total fuel oil consumed for generation includes a monthly allocation of the annual pipeline lease payment for the fuel o il pipeline connected to Riverside.

### PSO 2012 Integrated Resource Plan – Exhibit B

35 

## The chart below (Exhibit 4) illustrates, on a mont hly basis, how fuel costs at PSO generation resources and purchased power contribut ed to overall costs on a $/MWh basis.

Exhibit 4: 2011 Average Monthly Cost of Selected Resources in $/MWh

PSO’s fossil fuel mix (based on MMBtus consum ed), as reflected above in Table 3, reduced the effect on PSO’s overall monthly fuel cost. During 2011, PSO’s average monthly delivered cost of natural gas varied between a low of $3.25 per MMBtu in December 2011 to a high of $4.69 per MMBtu in February 2011. As a result of PSO’s fuel mix, PSO’s average

delivered cost of fossil fuel varied within a lowe r and tighter range, between a low of $2.09 per MMBtu in November 2011 to a hi gh of $3.35 per MMBtu in July 2011.

2011 Coal Procurement Summary As PSO’s primary low-cost base load power source, coal units are generally dispatched when available before other sources of generati on. To illustrate the significance of baseload coal generation to PSO, the coal units at Northeastern and Oklaunion represent approximately 22.5 percent of PSO’s genera ting capacity, but supplied 51.5 percent of

### PSO 2012 Integrated Resource Plan – Exhibit B

36 

## PSO’s generation in 2011. Northeastern Units 3 & 4 consumed approximately 4.2 million

tons of coal in 2011 while Oklaunion consumed roughly 2.2 million tons (total plant basis) during the same period. The exhibit below (E xhibit 5) summarizes th e contracts used by PSO to acquire coal in 2011.

Exhibit 5: List of Coal Contracts in Effect in 2011

Vendor Agreement Number Tons Purchased Peabody COALSALES, LLC 04-40-05-500PeabdyCS 288,681 J. P. Morgan Ventures Energy Corporation 08-81-10-001 122 Peabody COALSALES, LLC 08-81-10-4M3 2,473,618 Cloud Peak Energy Resources LLC 08-81-10-4M4 987,776 Enserco Energy Inc. 08-81-11-001 30,677 Alliant Energy Corporate Services, Inc. 08-81-11-002 91,074 Exelon Generation Company LLC 08-81-11-003 45,820 Enserco Energy Inc. 08-81-11-004 15,433 Enserco Energy Inc. 08-81-11-005 91,934 Enserco Energy Inc. 08-81-11-006 45,998 Exelon Generation Company LLC 08-81-11-007 106,489 Peabody COALSALES, LLC 08-81-11-009 23,161 

## Northeastern Generation Station

Vendor Agreement Number Tons Purchased Peabody COALSALES, LLC 04-40-89-501PeabdyCS 246,052 Buckskin Mining Company 08-11-10-003 474,821 Enserco Energy Inc. 08-11-10-005 173,781 Enserco Energy Inc. 08-11-10-006 43,700 NRG Power Marketing LLC 08-11-10-008 43,011 Alpha Coal Sales Co., LLC 08-11-10-4M2 995,030 Alpha Coal Sales Co., LLC 08-11-10-4M4 144,304 Alpha Coal Sales Co., LLC 08-11-11-4M1 29,114 

## Oklaunion Generation Station (Total Plant Basis)

Shipments of coal from the Powder River Ba sin (PRB) to the Northeastern and Oklaunion plants during 2011 were made pursuant to tr ansportation arrangement s with UP and BNSF, respectively.

### PSO 2012 Integrated Resource Plan – Exhibit B

37 

## 2011 Natural Gas Procurement Summary PSO’s natural gas generating units were brou ght on-line and taken off-line on relatively short notice and the actual unit loading and resulting natural gas demand was highly variable. The chart (Exhibit 6) below illustrate s how PSO utilized multiple transaction types for purchasing gas to meet the varying dema nds for natural gas generation. The chart indicates a range of total pur chases per day from a low of 96,704 MMBtus in November 2011 to a high of 584,239 MMBtus in August 2011.

Exhibit 6: PSO 2011 Natural Gas Purchases by Transaction Type

PSO positioned itself to meet its natural gas needs using a variety of transaction types. Approximately 40 percent of purchases in 2011 were for a term of one year or longer, representing the largest category of purchases.

### PSO 2012 Integrated Resource Plan – Exhibit B

38 

## Exhibit 7 below provides a graphical representa tion of the mix of arrangements used during

in 2011.

Exhibit 7: 2011 Natural Gas Purchase Types

To take advantage of favorable conditions and further mitigate risk, PSO also used different pricing mechanisms in 2011. Approximately 81 pe rcent of purchases for the year were at an index price. Conversely, as shown below, almo st 19 percent were on a fixed price basis. Fixed price contracts mitigate price volatility; th ey are not intended to lower fuel cost. PSO used monthly index prices to effectively lo ck in prices on a monthly basis and provide greater price stability compared to daily indexe s. The figure below illustrates the correlation between price and percentage of each pricing me chanism used for all natural gas purchases.

Pricing Mechanism % of NG Purchases Wtd. Avg. Price Fixed 18.95 $5.01 Daily Index 32.27 $3.89 Monthly Index 48.78 $3.96

### PSO 2012 Integrated Resource Plan – Exhibit B

39 

## To transport natural gas supplies to PSO gas plants as necessary, tr ansportation contracts with Enogex and ONEOK Gas Transportation, LLC (ONEOK or OGT) were used. PSO uses a mix of firm and interruptible agreemen ts to provide reliable, flexible, natural gas transportation at the lowest reasonable cost. See Exhibit 2 for an illustration of the pipeline connections at each plant.

2011 Purchased Power Summary Purchased power accounted for 31 percent of PSO’s overall generation supply mix in 2010 and 29.5 percent in 2011. Congestion, unit outages, marginal fuel prices, third party bids and offers, and system native load levels are some of the many factors that can impact the total amount of PSO’s purchased power for the year. The average SPP market prices are also influenced by many of the same factors. SPP market pr ices for 2011 displayed a yearover-year decrease in both the off-peak and on-peak hours. The ch ange in 2011 SPP power prices relative to 2010 prices can be seen in Table 4 below.

Month Average OnPeak ($/MWh) Average OffPeak ($/MWh) Month A verage OnPeak ($/MWh) Average OffPeak ($/MWh) 

### Jan-10 

### 47.97 $ 37.80 Jan-11 

### 32.62 $ 27.64 Feb-10 

### 46.22 $ 35.42 Feb-11 

### 32.98 $ 23.09 Mar-10 

### 33.09 $ 23.40 Mar-11 

### 32.23 $ 25.34 Apr-10 

### 33.52 $ 20.89 Apr-11 

### 33.36 $ 23.46 May-10 

### 35.09 $ 21.50 May-11 

### 31.41 $ 23.42 Jun-10 

### 39.43 $ 26.94 Jun-11 

### 38.45 $ 26.39 Jul-10 

### 41.61 $ 29.10 Jul-11 

### 44.85 $ 34.62 Aug-10 

### 42.64 $ 29.89 Aug-11 

### 41.04 $ 30.68 Sep-10 

### 32.82 $ 21.57 Sep-11 

### 32.89 $ 23.27 Oct-10 

### 31.34 $ 21.40 Oct-11 

### 28.90 $ 22.34 Nov-10 

### 29.45 $ 20.41 Nov-11 

### 27.17 $ 21.82 Dec-10 

### 33.09 $ 27.14 Dec-11 

### 25.24 $ 21.61 2010 Average 

### 37.19 $ 26.29 2011 Average 

### 33.43 $ 25.31 

# Table 4: 2010 & 2011 Average SPP Prices

### PSO 2012 Integrated Resource Plan – Exhibit B

40 

## II. Energy and Supply Forecast

Any forecast that attempts to predict mark et conditions, weather patterns, unit outages, transmission outages, and purchas ed power opportunities will have limited precision. However, it is important for PSO to create such forecasts to anticipate both short-term and long-term fuel supply needs.

A. Demand Forecast PSO’s forecast for the percentage of its native load requirement to be supplied by purchased power for 2012 is substantially unchanged fr om the actual amount of purchased power

utilized in 2011. As a result of last year’s warmer than normal summer, PSO’s 2012 peak native load responsibilit y is expected to decrease as co mpared with PSO’s actual peak of 4,407 MW, realized on August 3, 2011.

B. Fuel Supply and Energy Forecast

PSO’s generation portfolio includes coal, natura l gas, and fuel oil generation, as well as wholesale economic energy purchases. Additi onally, PSO has entered into long-term wind energy purchases. PSO optimizes available ge neration resources by fi rst dispatching its lower cost coal units (and solid fuel units from Southwestern Electric Power Company (SWEPCO) when available to PSO) and wind res ources, in addition to its Reliability Must Run (RMR) units. PSO then uses natural gas generation, along with purchased power, to meet any base load requireme nts which exceed coal and wi nd generation capabilities, to meet peak electrical demands, to replace coal capability during scheduled maintenance and forced outages, and to meet load-following, vo ltage support and rese rve ancillary service requirements.

AEPSC, as agent for PSO, forecasts hourly, da ily, monthly, and annual loads to anticipate both its fuel and purchased power requirements. As previously mentioned, AEPSC uses the GenTrader algorithmic optimization model to co mbine the load forecast with heat rate curves, projected fuel costs, projected operati ons and maintenance costs and emissions costs to predict dispatch costs, unit loading, and fu el consumption. The output from this model,

### PSO 2012 Integrated Resource Plan – Exhibit B

41 

## along with market price projectio ns, is then used to optimize the PSO system and to identify opportunities in the purc hased power market.

To meet its constantly changing load obligat ions, PSO uses all avai lable resources while taking into account fuel markets, environmenta l constraints, and regulatory requirements. PSO routinely displaces its own generation wi th economic purchases from the competitive market (through both bilateral transactions and the SPP En ergy Imbalance Service (EIS) market) and has well-established natural gas, coal, fuel oil, and transportation procurement processes that use competitive bidding and market offers that are econom ic and beneficial to

PSO customers.

1. Fuel PSO’s fuel planning, and the foundation of PSO’s fuel costs for 2012, are generally based on existing fuel and fuel-related contra cts and anticipated market prices for noncommitted fuel.

The fuel cost for each of PSO’s generating plan ts is different and is based on the cost of fuel and related transportation costs to deliver the fuel to the plant. Coal prices are based upon the contractual pricing provisions contai ned in the coal supply and transportation contracts, with replacement and supplemen tal coal costs based on projected market prices for coal.

Coal

Northeastern 3 & 4 and Oklaunion use sub-bi tuminous coal from the PRB of Wyoming that typically has a heat content of 8,200 to 8,800 Btu pe r pound. Projections of coal supply needs must consider ra ilroad delivery constraints and cycle time performance. Currently, PSO has arrangements with UP and BNSF to deliver coal to Northeastern and Oklaunion, respectively.

As the demand for coal in the power s ector decreases overall in 2012, many PRB consumers are negotiating with suppliers to de fer shipments on existing contracts to later periods. This will cause a decrease in production at some of the PRB mines in 2012

### PSO 2012 Integrated Resource Plan – Exhibit B

42 

## compared to 2011. Demand for PRB coal is e xpected to remain somewhat depressed as

the effects of the economic downturn and an unstable regulatory environment persist.

PSO currently has contracted commitments to purchase 96 percent of the anticipated coal

needs at Northeastern and Oklaunion in 2012. Approximately 55 percent of those commitments are under a contract term longer than one year.

Due to the high percentage of coal co mmitted under contracts in 2012, PSO does not anticipate any coal supply i ssues at PSO plants in 2012.

Natural Gas

Natural gas prices can vary based on suppl y and demand realities in the natural gas market. Recently, shale gas has been a “gam e changer” and is contributing significantly to increased natural gas supplies and lower, less volatile natural ga s prices. However, PSO’s utilization of natural gas has declined over the last few years due to increased wind generation. In addition, PSO has execute d a long-term Purchase Power Agreement (PPA) for up to 520 megawatts of electric generation which starts in June 2012. The PPA is expected to further impact PSO’s u tilization of natural gas during 2012. As such, PSO currently plans to reduce its long-te rm and annual firm natural gas supply commitment from approximately 97,500 MMBtu per day in 2011 to approximately 75,000 MMBtu per day in 2012, or approximately 37 percent of its annual natural gas supply requirements (based on 2011 generation). As a result of the Southwest Power Pool planning to go to a “Day 2” market in 2014 and the uncertainty it creates with PSO’s natural gas utilization, PSO will evaluate whether or not the terms of any natural gas supply or transportation agreement should extend beyond 2014.

Natural gas projections are based upon the contractual pr icing provisions contained in the varied term supply and transportation cont racts and the trading pr ices of natural gas

futures contracts from the New York Mercan tile Exchange (NYMEX) for delivery at the Henry Hub, and then they are adjusted for tran sportation basis different ials applicable to PSO’s geographic region and delivery points. PSO analyzes the fundamental drivers of the fuel markets daily and c onsiders industry standard fo recasts publishe d by analysts

### PSO 2012 Integrated Resource Plan – Exhibit B

43 

## such as Cambridge Energy Research Associat es, Inc. and the United States Energy Information Administration (EIA).

Actual weather, generating unit availability and economic purchase power opportunities will impact the annual natural gas purchases for 2012. PSO’s diversity in the types of natural gas purchases it make s (long-term, annual, seasonal, monthly and daily) reduces its exposure to potential price volatility and s ecures a reliable supply of natural gas. PSO is active in the daily natural gas markets a nd stays abreast of current market changes, including any new potential natural ga s suppliers that can be solicited.

Fuel Oil Fuel oil is generally used during natural gas supply disruptions and emergencies. While natural gas supply issues have arisen in the past due to extreme cold weather in Oklahoma, those conditions are difficult to anticipate. According to the EIA’s ShortTerm Energy and Summer Fuels Outlook released April 10, 2012, the average price for diesel fuel (fuel oil) is expected to in crease eight percent in 2012 over 2011. As a very small part of the PSO generation portfolio, fuel oil costs will not have a significant impact on PSO’s overall cost of fuel in 2012.

2. Energy

Purchased Power PSO’s purchased power activit ies include affiliate purcha ses with AEP West and AEP East companies, bilateral transactions, and purchases from the SPP EIS market. As of June 2012, PSO will begin taking power under th e terms of the Exelon PPA. The Exelon

contract is a 520 MW Power Purchase and Sa le Agreement from an existing natural-gasfired combined-cycle plant located near Tulsa, Oklahoma. The net impact of this contract is expected to be an overall incr ease in PSO’s purchased power. While the total amount of purchased power in 2012 is expect ed to increase as a result of the Exelon PPA, the relative contribution of PSO’s i ndividual purchased power activities and the overall amount of purchased power will depend on the specific market conditions that unfold over the course of 2012. For example, if the price of natural gas continues to remain depressed throughout 2012, purchased power from the Exelon PPA is likely to

### PSO 2012 Integrated Resource Plan – Exhibit B

44 

## displace a portion of PSO’s affiliate purchases from SWEPCO. The amount of purchased power will ultimately be influenced by market conditions, weather patterns, unit outages and tr ansmission outages.

Wind Energy PSO’s commitment to a diversified generatio n portfolio combined with its support of developing environmentally beneficial forms of energy production is borne out by PSO’s portfolio of wind energy contracts. PSO’s first wind energy purchase entered commercial operation in December of 2005 a nd its most recently completed wind purchase went into commercial operation in January of 2011. The following (Table 5)

shows PSO’s 2012 wind resources.

Table 5: Wind Contracts

### PSO 2012 Integrated Resource Plan – Exhibit B

45 

## Table 6 below shows the amount of wind energy purchased by PSO in 2011 in MWhs and as a percentage of PSO’s total resources in 2011.

Table 6: Wind Energy and Purchased Power

MO/YR of

Service Wind Energy Purchased Power MWh Total Resources MWh Wind as a % of Total Resources Jan-11 168,159 1,745,615.5 9.6% Feb-11 217,227 1,484,315.5 14.6% Mar-11 266,083 1,474,661.5 18.0% Apr-11 260,681 1,407,029.5 18.5% May-11 284,830 1,680,003.3 17.0% Jun-11 282,243 2,227,232.2 12.7% Jul-11 151,357 2,458,941.8 6.2% Aug-11 155,467 2,380,576.2 6.5% Sep-11 150,450 1,653,343.5 9.1% Oct-11 219,339 1,563,121.7 14.0% Nov-11 275,949 1,440,867.3 19.2% Dec-11 208,133 1,526,140.9 13.6% TOTAL 2,639,918 21,041,848.8 12.5% PSO 2011 Wind Energy Purchases and Total Resources



## III. Procurement Strategy

A. Discussion of Alternatives PSO’s overall fuel strategy is to assure reliab le, adequate, flexible, and competitively priced fossil fuel supplies and transportation to meet the generation requirements of the PSO system

at the lowest reasonable delivered cost. To accomplish this objective, PSO maintains a portfolio of supply contracts with varying cont ract terms for fuel suitable for use in its generating units.

The flexibility in PSO’s fuel supply plan and the diversity of its ge nerating fleet allow the Company to optimize its generation resources to take advantage of lower priced spot market fuel and purchased power opportunities, while maintaining reliability of service to its customers. PSO’s diversified generation and ba lanced fuel supply portfolio is the foundation

### PSO 2012 Integrated Resource Plan – Exhibit B

46 

## of its risk management plan and provides an effective physical hedge to mitigate the impact of fuel cost volatility of any particular fuel cost component. By investing in and using generating plants that use different fuel sources , PSO has created a flexib le portfolio of coal, natural gas, fuel oil, and purchased power resources, including wind, which manages overall variable costs due to the potential price volatili ty of any one particular fuel source. PSO’s ability to mitigate the potential impact of pric e volatility of its overall fuel cost has been primarily attributable to effective management of its fuel mix through maximum use of its coal generation, increased flexibility in fuel s upply and transportation c ontracts, periodic use of fuel oil, and the use of purchased pow er when it economically displaces PSO’s own generation.

Typically, PSO meets its generation requirement s by first using its lower–cost coal units (and generation from SWEPCO’s coal and lignite units when available to PSO) to achieve

the overall lowest reasonable fuel cost and by running its RMR units for system reliability purposes. PSO maintains a coal inventory to be both proac tive and responsive to known, anticipated, and potential changes in opera ting, coal supply, and rail transportation conditions. In addition, PSO’s co al inventory mitigates risk and allows the Company to take advantage of favorable market conditions.

Next, PSO’s natural gas units are compared to purchased power opportunities (based on each unit’s efficiency, economics, and other relevant factors) to meet peak load demands, to replace coal capacity during scheduled maintena nce and forced outages, to follow daily and hourly load swings, and for voltage support. Fu el oil is also used in PSO’s power plants when appropriate. Exhibit 8 provides a graphi cal depiction of the hourly economic dispatch of available resources for a typical day.

### PSO 2012 Integrated Resource Plan – Exhibit B

47 

## Exhibit 8: Typical Day Re source Economic Dispatch

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 

## Hour EndingMWH



### Coal/Lignite Generation RMR Units Gas Generation Long Term Econ Purchases IPP Pre-Sched Purchases Purchases from AEP East Hourly Purchases Non-RMR Gas Generation

### PSO 2012 Integrated Resource Plan – Exhibit B

48 

## Table 7: Typical Dispatch Charact eristics of PSO’s Generation Fleet

Typical Dispatch Order Unit Dispatch Type Northeastern 3 Baseload Northeastern 4 Baseload Oklaunion Baseload Comanche 1 Intermediate Northeastern 1 Intermediate Northeastern 2 Load Following

Riverside 2 Load Following Southwestern 3 Load Following Riverside 3 Peaking Riverside 1 Load Following Riverside 4 Peaking Southwestern 4 Peaking Southwestern 5 Peaking Weleetka 5 Peaking Tulsa 4 Peaking Tulsa 2 Peaking Southwestern 2 Peaking Southwestern 1 Peaking Weleetka 4 Peaking



## As previously discussed, PSO’s fuel procur ement and risk management plan must have concerns for reliability, adequacy, flexibility, an d price as its primary focus. All of these

concerns are at the forefront of PSO’s fuel procurement decisions when reviewing the various supply options potentially available to it. The options below are intended to be comprehensive, yet it is not exhaustive.

1. Coal Procurement and Transportation Coal Procurement Option 1 All coal could be procured by PSO through short-term contracts and spot market purchases. This would allow for maximum fl exibility and allow PSO to purchase based

on shorter-term and more reliable forecasts. This option also introduces the greatest risk of supply disruptions and exposes the Co mpany to potential price instability.

### PSO 2012 Integrated Resource Plan – Exhibit B

49 

## Coal Procurement Option 2 PSO could procure all forecasted coal needs us ing long-term contracts to ensure supplies

will be available. Use of contracts with longer terms would reduce the risk of supply disruptions and allow for a more reliable estimat e of fuel costs. As discussed previously,

forecasts have inherent flaw s and their accuracy reduces with increases in time. Therefore, purchasing all co al based on long-term forecasts could lead to overcommitments, inventory issues, and possibly force majeure penaltie s. It would also prohibit PSO from taking advantage of favorab le coal spot market opportunities while, at the same time, potentially paying an economic premium to tie up supplier capacity for the long term.

Coal Transportation

Northeastern 3 & 4 will continue to rece ive coal deliveries under a transportation agreement with UP through th e end of 2012. Oklaunion is captive to BNSF as the only carrier with physical access to the plant. Co al was received under a rail tariff established by the Surface Transportation Board (STB) th rough 2011 and then under a long-term rail transportation agreement beginning in January of 2012.

PSO will continue to evaluate economically favorable coal transportation contracts when possible to provide greater flexibility and competitive transportation rates.

2. Natural Gas Procurement and Transportation Natural Gas Procurement Option 1 PSO could purchase all of its natural ga s supply needs through fixed-price supply

contracts for terms of one year or greater if there we re suppliers willing to sell all volumes at a fixed price and assu me all of the price risk. Th is could result in suppliers demanding an economic premium to ensure a fixed price over a long period due to uncertainty in the market and result in hi gher prices for PSO’s customers. Use of contracts with longer terms w ould reduce the risk of supply disruptions and allow for a

more reliable estimate of fuel costs.

### PSO 2012 Integrated Resource Plan – Exhibit B

50 

## Natural Gas Procurement Option 2 PSO could purchase all of its natural gas supply on the daily spot market if ample supplies were available. This option would give the Company greater flexibility and the ability to take advantage of favorable mark et opportunities as they arise. Though these prices could be lower than purchases made on a longer-term basi s, PSO would, however, face the uncertainty of not knowing whether su fficient natural gas would be available to provide generation when needed.

Natural Gas Procurement Option 3 PSO could purchase all of its natural gas under index-priced supply c ontracts if suppliers were willing to commit to sales of natural ga s. During periods of declining prices, this option could lower natural gas generation costs. Purchasing all natural gas supply needs under index-priced supply cont racts also increases risk th rough the Company’s exposure to gas price volatility. Howeve r, some index-priced supply contracts, such as monthly base load gas purchases, are priced based on monthly indices and mitigate the risk of daily price volatility to PSO customers.

Natural Gas Transportation Option 1 PSO could negotiate to have all its natu ral gas transportation requirements provided through firm service, which would assure that all of its requirements would be met at all times, if sufficient firm transportation capacity were available. The price for such firm service would be prohibitive and the Company could often leave portions of this firm service unused due to the lower price of coal generation, purchased power, and wind

energy.

Natural Gas Transportation Option 2 PSO could secure interruptible service to meet its entire transportation needs if sufficient interruptible transportation capaci ty were available. This w ould be less expensive than utilizing firm service. However, service reliability could be severely impacted, as the transporter would be able to curtail gas delivery to PSO at its sole discretion.

### PSO 2012 Integrated Resource Plan – Exhibit B

51 

## Natural Gas Storage PSO could purchase natural gas storage, if available, to meet its natural gas peaking supply needs for reliability purposes. Historic ally, natural gas storage has been used by both natural gas and electric u tilities primarily fo r supply reliability and to meet peak energy demands, not for price arbitrage purposes. Pipelines and local natural gas distribution companies also require physic al storage for operational balancing and system supply. If the storage facility is directly connected to a pipe line system owned by the utility or its affiliate, storage can be us ed to meet instantaneous unforeseen natural gas use (real-time load follo wing service). However, physi cal storage agreements with third-party providers require wi thdrawals to be nominated in advance and withdrawn at a steady flow rate. Because PSO, like other el ectric utilities, cannot precisely predict hourly loads, they cannot nominate hourly stor age requirements for third-party storage

service.

3. Fuel Oil

PSO could use fuel oil on a limited basis as an al ternative to natural gas in selected units. However, fuel oil is generally a higher-pri ced alternative to na tural gas and could decrease the flexibility and e fficiency of plant operations , including decreased generation capacity. There are also environm ental issues that need to be considered when fuel oil is consumed for an extended period.

4. Purchased Power PSO has adequate generating resources, incl uding capacity purchases, to meet its load obligation and does not rely on economy energy purchases to serve its load. However, because there are opportunities for PSO to purchase energy at a price lower than generating the energy from its own units opera ting on the margin, AEPSC, as agent for PSO, makes the necessary arrangements to purchase economy energy and "back down" higher cost PSO generation.

Purchased Power Option 1 PSO could follow a traditional purchased power strategy. Such a strategy would rely primarily on affiliate economy energy purch ases, supplemented by much less frequent

### PSO 2012 Integrated Resource Plan – Exhibit B

52 

## economic energy purchases from PSO’s neighbori ng utilities. Such third party purchases were most typically short-term in durati on. While adopting such a purchased power strategy would be more reflective of a utilities traditional role in regards to purchased power, it would represent a reduction from PSO’s current level of purchased power activity and is not the alternative that PSO recommends.

Purchased Power Option 2 PSO could modify the traditional purchased power strategy through its participation in

the SPP EIS market. Under this alternative, PSO would c ontinue to participate in affiliate economy energy purchases under the West Operating Agreement and the System Integration Agreement. However, third party economic purchases would be placed solely in the hands of the SPP Regional Tr ansmission Organization (RTO), with PSO raising or lowering its generation output base d on the SPP dispatch signals and using EIS purchases to make up any difference between PSO’s load and PSO’s generation over any given five minute interval. While such a simplified approach may sound appealing on the surface, it overlooks the fact that SPP’s economic dispatch procedures are designed to optimize cost for the entire SPP footprint. Stated anothe r way, the least cost solution for the SPP footprint does not mean it is the least cost solution for PSO and its customers. This approach would place PSO in the passive role of a price taker and ignores additional value added activities pe rformed by AEPSC on PSO’s behalf that can increase the savings resulting from purchased power activities. Under this approach, there is no certainty of the availability of en ergy as the sellers in the SPP EIS market are making only a five minute commitment to sell power.

Purchased Power Option 3 PSO could continue to optimize its purchas ed power activity usi ng the full range of resources available to it today. Resources that are available to it based on the skill set and expertise of AEPSC and based on the gr owth and development of wholesale power markets. AEPSC, on behalf of PSO, enga ges in short and medium term energy purchases, takes full advantage of PSO’s many AEP affiliate relationships in both the west and the east, procures energy through thir d party bilateral trad ing in SPP and PJM,

### PSO 2012 Integrated Resource Plan – Exhibit B

53 

## and actively manages PSO’s participation in the SPP RTO markets. This approach

continues to offer the best value to customers.

B. Selected Fuel Procurement Plan PSO must consider environmental and regulator y requirements while procuring fuel to meet the load requirements of PSO’s customers at the lowest reasonable cost. To accomplish this, the selected fuel procurement plan must incorp orate the use of a variet y of alternatives to provide adequate, reliable, and flexible fuel supplies.

PSO’s generation portfolio includes coal, natura l gas, and fuel oil generation, as well as wholesale economic energy purchases. Additi onally, PSO has entered into long-term wind energy purchases. PSO optimizes available ge neration resources by fi rst dispatching its lower cost coal units (and solid fuel units from SWEPCO when avai lable to PSO) and wind resources, in addition to its RMR units. PSO then uses natural gas generation, along with purchased power, to meet any base load requirements which exceed coal and wind generation capabilities, to meet peak electrical demands, to replace coal capability during scheduled maintenance and forced outages, a nd to meet load-following, voltage support and reserve ancillary service requirements. And finally, PSO participates in a variety of purchased power markets to optimize PSO’s system through the purchase of economic

power.

Coal Procurement Plan PSO has an established coal and transportation procurement process that uses competitive bidding and market offers. The ma jority of the coal used as boiler fuel on PSO’s system is obtained at fixed prices through supply and tr ansportation contracts having a term of oneyear or greater, with the remaining portion of PSO’s coal requirements purchased in the spot market. Currently, PSO has agreements in place for 96 percent of the Company’s anticipated coal needs in 2012. As it has done in the past, PSO will continue to evaluate its contracts and negotiate reasonable terms.

PSO maintains a coal inventory to be both proactive and responsive to known and anticipated changes in operating, coal supply and rail transpor tation conditions. In addition,

### PSO 2012 Integrated Resource Plan – Exhibit B

54 

## PSO’s coal inventory mitigates risk and allows the Company to take advantage of favorable

market conditions. PSO’s coal inventories al so serve as a physical hedge against price volatility for that volume of coal already s ecured, on hand, and available for consumption.

PSO has been able to secure its coal position as (1) coal is a base load fuel, (2) the volume to be used is fairly predictable, and (3) any variances between purchas es and consumption can be stockpiled on site for use at a later time at PSO’s disc retion–unlike the ratable flow restrictions required when pulli ng natural gas from storage. Also, unlike the natural gas markets, coal suppliers have historically been willing to competitively bid against each other to offer fixed prices which provides PSO with fu el cost certainty for its coal portfolio. In contrast, many natural gas supplie rs are unwilling to offer fixed prices to PSO, and those that do, typically include a price premium.

To further reduce delivered coal costs, PSO will also continue to pursue efforts to minimize its coal transportation costs through its rail c ontract negotiations. The contract with UP to deliver coal to Northeastern will expire at the end of 2012. An RFP was sent in October 2011 to obtain rail transportation to both No rtheastern and Oklaunion beyond 2012. The negotiation process is ongoing. As previously mentioned, coal was received under a rail tariff established by the Surface Transportati on Board (STB) through 2011 and then under a long-term rail transportation agreement be ginning in January of 2012. PSO may also consider financial hedging instruments to reduce price volatility and strategic sales of coal inventory to reduce overall net fuel costs.

Natural Gas Procurement Plan PSO procures all of its natural gas supplies competitively. To optimize its natural gas supply, PSO will continue to evaluate its natural gas supply requirements and use a combination of long-term, annual, seasonal, monthly, and daily incremental purchases as needed. As discussed earlier, PSO’s natural ga s usage is expected to decline further in 2012 as a result of a 520 MW long-term PPA which starts in June 2012.

Historically, for the summer peak period of J une through August, PSO has entered into some seasonal firm supply contracts to ensure deliveries of natu ral gas as a hedge against a

### PSO 2012 Integrated Resource Plan – Exhibit B

55 

## shortage of supply rather than against a ch ange in prices. For the summer of 2012, in addition to its long-term and annual firm natural gas supply of approximately 75,000 MMBtu/day, PSO may obtain seasonal firm s upply for the months of July, August, and September. Much of this decision will depend on the impacts of the PPA starting in June

2012.

In addition to the long-term, annual, and seas onal firm supply contracts, PSO may secure daily call gas on Enogex and OGT for the 2012 summer to ensure s upply availability on projected high volume days. Daily call gas is gas service provided on demand with a prior day nomination. Daily call gas is typically provided by a producer or marketing company with supply on the interconnecting pipeline. It is priced at a daily index-based price and often requires a minimum reservatio n fee for the demand service.

PSO’s plan for 2012 is to start each mont h with approximately 75,000 MMBtu/day of longterm and annual firm natural gas and supplemen t the natural gas supply as needed with competitively-bid monthly and seasonal firm natural gas purchases to meet forecasted minimum monthly supply requirements. PSO t ypically uses pricing based on the following natural gas price indices:

Monthly: Inside FERC PEPL Daily: Gas Daily PEPL

Inside FERC OGT Gas Daily OGT

Inside FERC NGPL – Mid Continent Gas Daily NGPL – Mid Continent

Inside FERC ANR Gas Daily ANR Inside FERC CEGT - East Gas Daily CEGT - East



## The index price plus or minus the current ma rket adder represents the market price for natural gas. PSO has seen a decrease in market adders si nce 2009. Production from the shale gas reserves (Haynesville, Fayette ville, Woodford, Granite Wash, Barnett, Marcellus, etc.) has impacted the natural gas market in Oklahoma. Since 2009, the natural gas market has also become more national versus regional, which has narrowed basis

differentials.

### PSO 2012 Integrated Resource Plan – Exhibit B

56 

## PSO uses competitive bidding and competitive market offers for natural gas transportation services. PSO negotiates transportation arrang ements with connecting pipelines for swing service beyond its daily nomina tions to meet its peak hour ly and daily demands. PSO currently has a firm transpor tation agreement with Enogex a nd interruptible transportation agreements with Enogex and OGT. As a result of the Enogex firm transportation agreement expiring at the end of 2012, PSO issued a re quest for proposals on May 4, 2012 for firm transportation. Bid responses are due back on June 8, 2012 and PSO anticipates execution of a firm transportation agreemen t by July 27, 2012. PSO also ha s a direct connection with Scissortail Energy at the Riverside Power Station that can supply Units 1 and 2. A schematic that reflects the various pipelines interconnected to each of PSO’s power plants was provided in Exhibit 2.

PSO could purchase natural gas st orage, if available, to meet its natural gas peaking supply needs for reliability purposes. However, PSO ’s analysis has indica ted that, due to the difficulty in anticipating peak hourly and daily supply needs, it would be difficult for PSO to nominate its natural gas withdrawals in advanc e. Storage injections and withdrawals must be accomplished at a steady flow rate and ar e not responsive to the peaking demands of natural gas electric generators . Also, the normal injectio n and withdrawal seasons for storage (injection – summer, w ithdrawal - winter) are opposite from PSO’s needs. PSO would need to inject gas in the winter months when ga s prices are typically higher and withdraw gas in the summer to m eet the summer peak demands.

PSO’s existing natural gas transportation contra cts include services which already provide the reliability that storage services would offer. The most recent estimates indicate that firm natural gas storage arrangements (including tr ansportation) would co st approximately $1.61- $1.63 per MMBtu above the commodity costs of th e related natural gas. Thus, natural gas storage has not evolved as a viable oper ational or economic alternative for PSO.

Fuel Oil Plan Since fuel oil is not used as a primary fuel supply for PSO’s power plants, PSO will continue to purchase its fuel oil requirements by competit ive bid. In late 2011, PSO issued a fuel oil

RFP and awarded the low-cost bidder PSO’s fuel oil requirements for 2012.

### PSO 2012 Integrated Resource Plan – Exhibit B

57 

## PSO maintains fuel oil inventories at Riversid e and Southwestern for reliability purposes. At the end of 2011, PSO had 72,897 barrels of fu el oil at Riverside for units 1 & 2 and 46,312 barrels at Southw estern for unit 3.

Purchased Power Plan The purchased power plan for 2012 relies on a mixt ure of transactions that take advantage of many of the alternative appro aches discussed above, without favoring one approach to the exclusion of all other options. For example, the Exelon PPA demonstrates PSO’s utilization of cost-effective, long-term purchased power opportunities. And PSO’s active participation

in the SPP EIS market demonstrat es PSO’s use of short-term purchased power markets, for

the benefit of its customers. The selection of PSO’s purchased power plan is also heavily influenced by PSO’s position within the overa ll AEP system and is designed to take full advantage of those benefits. First, the West Operating Agreement, and the System Integration Agreement provide PSO with a br oad and diversified generation fleet that provide access to a range of economic purchas ed power options derive d from a wide range of fuel types. Additionally, AEPSC, on be half of PSO and all of the AEP operating companies, is actively engaged in trading with a variety of counter parties that buy and sell over-the-counter electricity in the Southwest Power Pool. AEPSC ’s activities, on behalf of PSO, have enabled it to develop strong relati onships within the SPP and across the Eastern Interconnect, including PJM and MISO (Midwest Independent System Operator). AEPSC’s production optimization group and tr ading group are able to use this network of contacts and expertise to provide PSO with numerous oppor tunities to make economic power purchases from a wide range of third-party market participants.

IV. Risk Management

A. Hedging Financial hedging is aimed at reducing volatility, but could pot entially increase the overall fuel cost based on transaction costs and prem iums required to lock in pricing. While financial hedging will continue to be consid ered, PSO, under normal circumstances, does not believe it meets the objective of providing the lowest reason able cost energy to Oklahoma customers. PSO is more likely to use physical hedging to mitigate fuel cost volatility. For

### PSO 2012 Integrated Resource Plan – Exhibit B

58 Obligations - load and reserves

Unit Assessment



## - cost, RMR, availability, liabilities

Purchases / Sales



## - long-term



## - short-term



## - transmission availability Next Day Resource Commitment

Decisions Day-ahead Plan

Gas Forecast

Day-ahead Gas Purchases 

## natural gas, factors such as shale gas ava ilability, new pipeline construction, and market changes have significantly reduc ed price volatility and minimized the potential advantages of financial hedging.

B. Fuel Diversity and Optimization AEPSC’s purchased power and optimization activ ities are key ways that PSO manages fuel

risks and minimizes costs for its customers. As part of the day-ahead resource process used by PSO, items such as the forecasted load, fuel prices, market prices for energy, scheduled and unscheduled generating unit out ages are used to develop proj ections of fuel consumption and power purchases for PSO. These projecti ons are part of the day-ahead resource commitment process PSO uses, which is pr esented in Exhibit 9 on the next page. While the day-ahead process must plan to meet peak demand for the day, PSO also uses that process to purchase and schedule energy to displace its ow n generation when it is economical to do so.

Exhibit 9: Day-Ahead Resource Commitment Process

AEPSC’s optimization activities continue into th e real-time operation of the PSO system. In the intra-day market (real-tim e), AEPSC hourly marketers, pr oduction coordinators, natural gas coordinators, and generation dispatchers wo rk closely to optimize the PSO system by

### PSO 2012 Integrated Resource Plan – Exhibit B

59 Market Bids and Offers

SPP Energy Imbalance Market Signals Day-ahead Plan

Gas Availability and Cost

Update - Unit Assessment

Update - Obligations Gas Requirements

Real-time Economic Dispatch

Transmission Constraints - TLR/Redispatch Balance of Day / Hourly Dispatch Decisions 

## taking into consideration opportunities to purchase energy in the market. AEPSC’s optimization activities continue into the real -time operation of the PSO system. If AEPSC has an offer in the intra-day market (real-time) for a reliable source of energy capable of being delivered to PSO’s system at a price that is below the forecasted marginal generation (dispatch) cost, AEPSC purchases this economic energy whenever possible. Such purchases are part of the hourly an d balance of day resource dispatch process outlined in Exhibit 10 on the next page.

The Company’s generating units are economica lly dispatched in real time with other

resources in SPP. The SPP EI S market participation allows , on a five-minute dispatch basis, for PSO to buy economic energy from othe r resources in the SPP or to sell surplus online generation into the market.

Exhibit 10: Hourly and Balance of Day Resource Dispatch Process

C. Contract Provisions As mentioned previously, PSO proc ures fuel with a variety of contract provisions that serve as a hedge against fuel price volatility. Fuel contracts can utilize either fixed or indexed prices. The contract lengths also vary and are staggered to increase flexibility.

### PSO 2012 Integrated Resource Plan – Exhibit B

60 

## D. Customer Programs PSO offers a wide variety of programs to assi st customers in managing their total energy usage and cost. For example, PSO offers the Average Monthly Payment Plan (AMP), to help customers manage volatile monthly fuel costs. PSO also offers a wide range of Demand Side Management (DSM) programs that c over all customer classes in an effort to maximize the potential for participation for all customers. A complete listing of PSO’s DSM programs can be found in Table 8 below.

Table 8: PSO Demand Side Management Programs

Residential Commercial Industrial · Low Income Weatherization · Large C&I Solutions · Industrial Solutions · Energy Star New Homes · Commercial Lighting · Load Management

· Residential Solutions · Small C&I Solutions · Energy Star Appliances · Commercial AC Tune-Up · Residential AC Tune-Up · Model Cities · Energy Audits · Smart Schools · C&I Demand Response

· Industrial Solutions · Load Management

### PSO 2012 Integrated Resource Plan – Exhibit B

61 

## Cost of Energy Table 9 below provides monthl y bill projections for summer 2012 and winter 2011 and 2012, as well as the previous year’s information.

Table 9: Monthly Bill Projections

Winter Bill

Customer

Class and

Usage Bill*

2011/2012 Price– ¢/kWh

2011/2012 Projected

Bill*

2012/2013 Projected

Price– ¢/kWh

2012/2013 Projected % Change

Per kWh

Residential1070 kWh $83.90 7.84 $86.52 8.09 3.12%

Small

Commercial1760 kWh $137.49 7.81 $141.84 8.06 3.16%

Summer Bill

Customer

Class and

Usage Bill*

2011 Price– ¢/kWh

2011 Projected

Bill*2012 Projected

Price– ¢/kWh

2012 Projected % Change

Per kWh

Residential1450 kWh $127.03 8.76 $111.50 7.69 (12.23%)

Small

Commercial2300 kWh $202.97 8.82 $176.52 7.67 (13.03%)

* Actual and projected bill amounts include the Base Se rvice Charge, Energy Charge, Fuel Cost Adjustment

(FCA), and all applicable riders. ** Actual and projected bill amounts do not include franchise fees or taxes.

***Class kWh levels are based on prior FSP Table levels.

### PSO 2012 Integrated Resource Plan – Exhibit B

62 

## V. Summary As stated previously, any fuel procurement a nd risk management plan must contemplate and address reliability, adequacy, flex ibility, and price. The founda tion of PSO’s risk management plan has been to have a diversified genera tion and supply portfolio, which includes coal generation, natural gas genera tion, fuel-oil generati on, wholesale energy purchases, and renewable energy. Each of these commodities is procured under a competitive bidding or competitive market offer process. This include s energy purchases in lieu of PSO’s generation when it can be arranged both economically and reli ably. PSO’s fuel supply plan and portfolio are balanced, yet flexible, which allows PSO to appropriately respond to changes in load obligations, generation availability, fuel supply markets, and purchased power markets, thereby ensuring a reliable fuel supply at the lowest reasonable delivere d cost. Recognizing the dynamic nature of the markets, PSO will continue to revi ew its fuel procurement activities, and modify them as appropriate, to ensure th at any fuel procurement and risk management plan continues to meet the standards of reliability, adequacy, flexib ility, and lowest reasonab le delivered cost.

Contact Information

For questions or additional information, please contact:

Alan W. Decker Regulatory Services-Oklahoma 1601 Northwest Expressway Suite 1400 Oklahoma City, OK 73118 (405) 841-1338 (405) 841-1345 (Facsimile)

## Exhibit C: Technical Addendum

FORECASTING/MODELING DESCRIPTION & PROCESSES

A. Capacity Resource Modeling (Strategis t) and Levelized Busbar Costs.....................64

INPUT PARAMETERS

B. Energy and Demand Forecast......................................................................72

RESOURCE PLANNING MODEL RESULTS

C. Strategist Model Output Reports..................................................................76

## PSO 2012 Integrated Resource Plan – Exhibit C

64 

# FORECASTING/MODELING DE SCRIPTION & PROCESSES

A. Capacity Resource Modeling (Strateg ist) and Levelized Busbar Costs

The overriding objective of the modeling effo rt was to recommend an optimum system expansion plan, not only from a least-cost perspective but also from the perspectives of risk profile, achievability, and afford ability. The analytical model served as the foundation from which all of the perspectives were examined and recommendations made. The process will be continually refined as experien ce is gained to take into acc ount emerging issues identified by supporting work groups and management. The Strategist Model

The Strategist resource-planning model, devel oped by New Energy Associates, LLC (NEA), allows a user to determine the least-cost resource mix for its system (in this case, AEP’s East and West zones) from a user -defined set of resource technol ogies, under prescribed sets of constraints and assumptions. Strategist defines the “least-cost resource mix” as the combination

of resource additions that produces the lowest overall system pre-tax cost (revenue requirement) inclusive of:

 New resource capital carryi ng cost and fixed O&M

 Environmental retrofits

o New-build capacity

o Capacity (market) purchase costs

o Total system-wide fuel costs (new-build and existing capacity)

o Cost of system-wide (replacement) em ission allowances (SO2, NOx, CO2)

o Net (market) “system transaction” cost or revenue (i.e. third-party energy purchases and/or sales). Strategist allows all aspects of an integrated resource planning st udy to be considered with the depth and accuracy required for informed decision-making. Hourly chronological load patterns are recognized, detailed production costing logic is util ized, and the system employs a dynamic programming algorithm to develop the “ optimal” and large suites of “sub-optimal” portfolios of capacity add ition alternatives over a us er-defined study period.

## PSO 2012 Integrated Resource Plan – Exhibit C

65 

## the operation of the generating system, including new resource additions that may be needed to meet future demand growth. These modules calcu late the costs of serving a utility system’s capacity and energy needs over the defined study period. The Load Forecast Adjustment module (LFA) is used to represent the utility’s hourly demand and energy fore cast. The Generation and Fuel module (GAF) works with the LFA to simulate the operation of a u tility’s generating units and any interaction with extern al markets. The PROVIEW module pulls information from the LFA and GAF modules as well as other generation alternative data to determine the least-cost resource plan for the utility system under pres cribed sets of constraints and assumptions. Strategist develops an initial “macro” (zone-sp ecific)* least-cost resource mix for a system by incorporating a wide variety of expa nsion planning assump tions including:

 Characteristics (e.g. capital cost, construction period, operating life) of resource addition

alternatives that are available to meet future capacity needs

 Operating parameters (e.g. capacity ratings, h eat rates, forced outage rates, etc) of existing and new units

 Fuel prices

 Prices of external market energy, capacity, and emission allowances

 Reliability constraints (e.g. minimum reserve ma rgin targets, loss of load hours, unserved energy)

 Emission limits and environmental compliance options * Note: As discussed in the IRP report, for the AEP-West (SPP) zone, the model was set up to independently optimize least cost view s for PSO and SWEPCo, recognizing that the ultimate IRP could consider some limited reserve sharing among those operating companies. All of these assumptions, and others, are cons idered in order to de velop an integrated plan that best suits the utility system being analyzed.

To reiterate, Strategist does not develop a full “cost of service” (COS) profile. It considers only costs that change from plan to pl an, not costs that are fixed, such as embedded costs of existing generating capacity or distribu tion costs. Transmission costs are included only to the extent that they are associated with new generating capacity. Specifically, Strategist

## PSO 2012 Integrated Resource Plan – Exhibit C

66 

## to the extent that they are associated with new generating capacity. Specifically, Strategist includes and ultimately recognizes in its “incre mental revenue requirement” output profile:

 Fixed costs of capacity additions, i.e. carrying charges on capacity and associated transmission based on a weighted average co st of capital (WACC) and fixed O&M

 Fixed costs of any capacity purchases

 Variable costs of the entire fleet of existi ng and any added units. This includes fuel, purchased energy, the market replacement cost of emission allowa nces (SO2 and NOX, and CO2 in appropriate cases), and variable O&M costs. In addition, revenue from external energy transactions (Off-System Sales) is netted against these costs Due to the netting of Off-System Sales revenues against variable costs, depending on the market spreads for energy, Strategist outcomes can represent relative "longer" or "shorter" market energy positions that can have significant bearing on the resulting net system cost and determination of a least-cost plan. In summary, Strategist models the approach AEP uses to determine jurisdictional generation revenue requirements at an integrat ed, system level. For the purpose of comparing plans, these costs are expressed on a Cumulative Present Worth (CPW) basis for each plan, using

standard calculation methods and a 9.0% WACC.

Overview of Need for Modeling Constraints

In the PROVIEW module of Strategist , the least-cost expansion plan is empirically

formulated from hundreds of thousands of possible resource alterna tive combinations created by the module’s chronological “dynamic programmi ng” algorithm. On an annual basis, each capacity resource alternative combination that satis fies its least-cost objective function through user-defined constraints (in this case, a “minimum” on-going capacity reserve margin) is

considered to be a feasible state and is save d by the program for consideration in following years. As the years progress, the previous years’ feasible states ar e used as starting points for the

addition of more resources that can be used to meet the current year’s minimum reserve requirement. As the need for additional capacity on the system increases, the number of possible

combinations as well as the number of feasible states increases approximately exponentially with

the number of resource alternat ives being considered.

## PSO 2012 Integrated Resource Plan – Exhibit C

67 

## Exhibit A-1 offers a very simplistic exampl e of this algorithm. The model has the choice of two capacity types (CT and CC) and must achieve its reserve requirement constraint through some economic combination of the capacity type s over a three- year period. Six unique plans result after the elimination of one of the more expensive paths.

Exhibit A-1 Strategist chronol ogical “dynamic programming” algorithm

As can be seen in this example, the poten tial for creating hundreds of thousands of

alternative combinations and feasible states can become an extremely large computational and data storage problem, if not constrained in some manner. The Strategist model includes a number of input variables sp ecifically designed to allow the user to further limit or constrain the size of the problem the model is attempting to solve. Several of these variables focus on limiting the number of a particular resource alternativ e that can be considered by the model during the Planning Period. In addi tion, other variables li mit the years that a particular alternative is availa ble for selection by the model.

## PSO 2012 Integrated Resource Plan – Exhibit C

68 

## PSO and SWEPCO RFP Evaluation Methodology 

## (As approved by the Independent Monitor)

Introduction

This documentation is intended to describe the price evaluation processe s used to evaluate Proposals received in response to PSO and SWEP CO RFPs. Two types of price evaluation processes are described in this document. One process used for evalua ting a significant number of Proposals where Proposal clus tering is necessary and a second process for evaluating a limited number of Proposals where Proposa l clustering isn’t necessary. In cluded is a description of the input assumptions used by the Strategist resource planning software to evaluate the Proposals, the Price and Non-Price Scoring mechanism for developing the S hort-list of Proposals, the Portfolio Evaluation of Proposals an d selection of the Award Group.

Price Evaluation Assumptions:

 Gas and Market Prices - Prior to the rece ipt of the Proposals, Fundamental Analysis and Economic Forecasting will provide Resource Planning with long-run gas and SPP market energy price forecasts (Low, Base and High Bands) to be used in the Price Evaluations. Gas price forecasts will be provided for the PSO and SWEPCO systems and Gas Daily daily midpoint indices that the bidders could potentially propose as a basis for determining their energy pricing.

 Load Forecast - The PSO and SWEPCO peak and energy forecasts will be revised by Economic Forecasting in November and agai n in February each year. The use of

these load forecasts will allow PSO and SWEPCO to make their RFP resource

decisions based on the most current load information available at that time.

 Generic Unit Assumptions - Generic unit operating and cost information developed by the New Generation Development group will be the basis for modeling the resources added when a Proposal’s capacity is insufficient to meet reserve margin targets. In early December, the Ne w Generation Development group updates the generic unit information to be used in subsequent PSO and SWEPCO Proposal

evaluations.

## PSO 2012 Integrated Resource Plan – Exhibit C

69 

## Initial Price and Non-Price Evalua tion and Short-list Determination

 Baseline Comparison Plan - A Baseline Plan will be developed for both PSO and SWEPCO for Proposal comparison purposes ba sed on the input assumptions mentioned above. The Baseline Plan will be composed of generic units additions through 2035 (i.e. end of the Strategist database) to mi nimize PSO and SWEPCO reliance on the SPP capacity and energy markets to meet their ongoi ng capacity and energy requirements.

 Proposals will replace the generic resources id entified in the IRP Plan on a MW for MW basis. For example, if the IRP Plan has 500 MW of generic combustion turbine (CT) capacity added in 20xx, a 100 MW Peaking Pro posal with a 20xx in-service date would replace 100 MW of the IRP Plan’s generi c CT capacity and the remaining 400 MW would have the operating and cost characterist ics of the IRP Plan’s generic CT capacity. Additional capacity added in the years fo llowing 2011, will be based on an optimization of generic units.

 If a significant number of Proposals are received, the Proposals’ Contract Term will be

one of the characteristics used to assign it to a Proposal clus ter. Each Proposal will be placed in a cluster that has othe r Proposals with similar Contra ct Terms. A Strategist run will be conducted for each Proposal for the peri od of the longest Contract Term possible. For example, in the case of 2008 Peaking Proposals, if the long est Contract Term possible is 30 years, a Strategist run will be conducted through 2037 for all of the Proposals within all of the Proposal clusters . In addition, if a 2008 Peaking Proposals has less than a 30 year Contract Te rm, Strategist will replace th e Proposal capacity at the end of the Contract Term with generic units of similar size and type. For example, assume that the longest Contract Term proposed in 30 years, and a 100 MW Peaking Proposal with a 20 year Contract term is being eval uated. At the end of th e Proposal’s 20 year Contract Term, the Proposal w ould be replaced with 100 MW of generic CT capacity for the remaining 10 years of the evaluation.

 If a limited number of Proposal s are received, it will not be necessary to cluster Proposals by like characteristics (e.g. Contract Term, PPA, APP, etc) in or der to create a short-list. All Proposals may be evaluated against each othe r in order to determine the short-list.

## PSO 2012 Integrated Resource Plan – Exhibit C

70 

##  The Cumulative Present Worth (CPW) of PSO and SWEPCO revenue requirement will be calculated for each Proposal and will be used, in part, as the basis for comparing Proposals within a cluster. In evaluating PSO RFP Proposals, the PSO CPW will be used, and the SWEPCO CPW will be used to comp are SWEPCO RFP Proposals. In addition to the CPW costs developed in Strategist , transmission impact costs will also be calculated for each Proposal and added to the Proposal's Strategist CPW. In the case of PPA Proposals, a debt equivale nce adder will be developed and added to the Strategist CPW and transmission impact costs to calculate a total Proposal CPW. The Proposal's total CPW will be used in assigning price points during the initial price evaluation.

 Price Point Calculation - Each Proposal's tota l CPW will be compared to the CPW of the

Baseline Plan and that CPW difference will be used as a basis for determining the allocation of price points for Proposals within a cluster. The range of CPW differences of all Proposals versus the Baseline Comparis on Plan will be divi ded into deciles and Proposals will be awarded price points based on which decile they fall into.

 Non-Price Point Calculation - In addition to the Price Evaluation, each Proposal will be evaluated on non-price factor s and non-price points will be assigned to each Proposal

within a cluster.

 Short-list Selection for a signi ficant number of Pr oposals - Within each Proposal cluster, a short-list of Proposals will be developed ba sed on the comparison of the Proposals' total points (price + non-price points) to that of a comparable self-build alternative's total points. Proposals will be placed on the short-list if they have a total point score that is greater than, or comparable to, that of the self-build alternative's total point score.

 Short-list Selection for a limited number of Proposals – A short-list of Proposals will be developed based on the comparison of th e Proposals' total points (price + non-price points). Proposals whose ranking is clearly lower than other proposals may be excluded

from the short-list and further evaluation.

## PSO 2012 Integrated Resource Plan – Exhibit C

71 

## Exhibit A-2: Levelized Busbar Cost for various technology options

0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400

0 10 20 30 40 50 60 70 80 90 100$/kW/Year



## Capacity Factor - % AEP System- West Zone Lowest Cost Base, Intermediate and Peaking Options (Single and Multiple Unit) Levelized 40-Year Busbar Costs (2013-2052)

CC- 762 MW (2X1 M501GAC) PC Sup(Ultra)-618 MW PRB CT-164 MW (2X1 GE7EA)

## PSO 2012 Integrated Resource Plan – Exhibit C

72 

# INPUT PARAMETERS: B. Energy and Demand Forecast

The following tables provide an annual and monthly summary of the long-term, energy (GWh) and demand forecast used in this IRP. This data was provided by the AEP Economic Forecasting Group from the August, 2011 AEP Energy and Demand Forecast.PSO 2012 Integrated Resource Plan – Exhibit C73Table 1JAN.FEB.MAR.APR.MAYJUN.JUL.AUG.SEP.OCT.NOV.DEC.2011 2647 2803 2323 2662 3309 3678 4192 4179 3227 2702 2239 26662012 2478 2735 2192 2439 2929 3820 4207 4192 3331 2723 2235 26572013 2498 2760 2207 2448 2943 3838 4227 4212 3348 2746 2228 26542014 2508 2769 2216 2453 2949 3846 4235 4220 3357 2764 2236 26532015 2516 2777 2223 2452 2946 3840 4226 4212 3355 2774 2245 26552016 2516 2774 2224 2451 2943 3837 4222 4208 3355 2797 2245 26512017 2535 2797 2244 2460 2949 3834 4212 4197 3349 2736 2257 26632018 2541 2801 2250 2462 2948 3831 4208 4193 3350 2739 2265 26652019 2550 2810 2259 2467 2962 3834 4210 4196 3356 2756 2276 26722020 2548 2804 2260 2466 2951 3832 4207 4193 3356 2780 2277 26682021 2567 2824 2276 2478 2962 3845 4220 4205 3371 2805 2296 26882022 2582 2838 2290 2489 2974 3859 4234 4220 3386 2830 2309 27032023 2602 2860 2314 2508 2993 3874 4246 4230 3395 2780 2324 27162024 2608 2863 2321 2517 3017 3886 4259 4243 3408 2802 2332 27222025 2635 2891 2346 2537 3028 3912 4285 4271 3434 2837 2359 27502026 2653 2908 2362 2554 3042 3934 4308 4294 3456 2868 2378 27682027 2671 2925 2379 2570 3061 3957 4333 4319 3479 2899 2396 27862028 2681 2933 2391 2584 3076 3977 4354 4340 3498 2941 2402 27952029 2717 2973 2428 2614 3107 4007 4382 4366 3522 2888 2433 28252030 2740 2994 2448 2635 3151 4036 4413 4397 3550 2924 2457 28482031 2763 3017 2471 2658 3164 4068 4447 4432 3580 2963 2480 28722032 2776 3028 2484 2675 3176 4095 4477 4461 3605 3010 2496 28832033 2811 3065 2517 2705 3209 4135 4519 4504 3644 3057 2526 29202034 2845 3100 2552 2740 3246 4173 4556 4539 3674 3018 2553 29472035 2874 3129 2580 2769 3279 4214 4600 4584 3713 3051 2582 29752036 2897 3151 2602 2794 3318 4251 4640 4623 3747 3106 2606 29982037 2938 3192 2640 2831 3349 4302 4694 4678 3795 3161 2646 30392038 2968 3222 2668 2860 3383 4344 4740 4724 3835 3209 2676 30692039 2999 3252 2697 2889 3416 4387 4786 4770 3875 3257 2703 31012040 3025 3281 2728 2922 3451 4423 4820 4802 3901 3212 2723 3119PSO MONTHLY PEAK NATIVE DEMAND (MW)PSO 2012 Integrated Resource Plan – Exhibit C74Table 2JAN.FEB.MAR.APR.MAYJUN.JUL.AUG.SEP.OCT.NOV.DEC.2011 1,5541,3761,3621,3061,5181,7332,0612,0211,5791,3351,2971,5012012 1,5151,3821,3591,2771,4521,7652,1302,0781,6001,3481,2931,4892013 1,5231,3351,3601,2841,4561,7682,1422,0811,6091,3521,2931,5002014 1,5261,3391,3661,2881,4551,7762,1462,0811,6171,3551,2931,5082015 1,5271,3431,3741,2911,4551,7822,1432,0811,6181,3551,2991,5122016 1,5231,3961,3751,2891,4611,7822,1332,0871,6181,3531,3071,5112017 1,5391,3511,3831,2921,4701,7852,1342,0891,6181,3631,3131,5122018 1,5441,3541,3841,2991,4731,7822,1372,0881,6181,3711,3161,5162019 1,5501,3601,3871,3081,4781,7832,1452,0881,6261,3771,3171,5272020 1,5481,4081,3931,3101,4721,7922,1422,0831,6301,3731,3161,5292021 1,5511,3691,4021,3181,4831,8022,1472,0961,6401,3801,3341,5422022 1,5641,3771,4121,3231,4951,8112,1512,1091,6481,3891,3421,5472023 1,5781,3861,4221,3291,5091,8202,1612,1201,6531,4031,3511,5492024 1,5831,4451,4211,3431,5151,8192,1762,1211,6601,4131,3491,5582025 1,6001,4051,4381,3571,5251,8392,1922,1331,6801,4271,3601,5792026 1,6061,4151,4531,3681,5331,8562,2042,1461,6921,4341,3731,5892027 1,6131,4251,4631,3781,5461,8692,2132,1641,7041,4421,3931,6032028 1,6251,4881,4731,3801,5641,8792,2202,1801,7081,4551,3981,5982029 1,6491,4491,4871,3991,5811,8932,2432,1981,7231,4761,4131,6172030 1,6631,4611,4971,4171,5951,9042,2652,2101,7421,4901,4211,6352031 1,6771,4751,5121,4301,6051,9262,2832,2241,7631,5051,4301,6542032 1,6811,5361,5261,4401,6151,9452,2922,2441,7751,5071,4521,6652033 1,7041,5031,5471,4551,6391,9682,3122,2731,7951,5281,4701,6822034 1,7261,5181,5651,4681,6621,9872,3352,2961,8101,5501,4861,6912035 1,7451,5351,5791,4891,6812,0042,3632,3191,8271,5721,5011,7092036 1,7601,6001,5921,5091,6922,0232,3892,3291,8531,5861,5041,7332037 1,7791,5711,6211,5321,7122,0572,4182,3601,8791,6061,5301,7572038 1,7931,5871,6371,5481,7332,0792,4372,3891,9001,6211,5581,7792039 1,8171,6041,6561,5611,7572,1012,4562,4181,9201,6411,5741,7932040 1,8361,6801,6671,5771,7782,1132,4822,4371,9271,6641,5841,796MONTHLY INTERNAL ENERGY REQUIREMENTS (GWH)PSO 2012 Integrated Resource Plan – Exhibit C75Table 3AEP System-West ZoneNew Generation TechnologiesKey Supply-Side Resource Option Assumptions (a)(b)(c)Installed Trans. Full Load Fuel Variable Fixed Capacity OverallCapability (MW) Cost (d) Cost (e) Heat Rate Cost (f) O&M O&M SO2 NOx CO2 Factor AvailabilityTypeStd. ISO Winter Summer ($/kW) ($/kW) (HHV,Btu/kWh) ($/MBtu) ($/MWh) ($/kW-yr) (Lb/mmBtu) (Lb/mmBtu) (Lb/mmBtu) (%) (%)Base LoadPulv. Coal (Ultra-Supercritical) (PRB) 618 624 612 2,682 24 8,980 3.45 3.1 33.7 0.1000 0.070 212.70 85 89.6Pulv. Coal (Advanced Ultra-Supercritical) (PRB) 750 757 742 2,804 20 8,470 3.45 3.2 33.1 0.1000 0.070 212.70 85 89.6IGCC "F" Class (PRB) 587 593 581 5,203 26 8,530 3.45 5.2 50.0 0.0638 0.062 212.70 85 87.5Pulv. Coal (Ultra-Supercritical) (Lignite) 618 624 612 2,691 24 9,657 3.31 3.1 37.0 0.1145 0.070 215.40 85 89.6IGCC "F" Class (Lignite) 638 644 631 5,190 24 10,100 3.31 5.2 48.1 0.0126 0.057 215.40 85 87.5Nuclear (MHI ABWR) 1,606 1,622 1,542 6,156 61 10,500 1.02 5.4 85.8 0.0000 0.000 0.00 90 94.0Base Load (90% CO2 Capture New Unit)IGCC "F" Class (PRB) 486 491 481 7,260 31 10,302 3.45 8.9 68.2 0.0638 0.062 21.27 85 87.5IntermediateCombined Cycle (1X1 GE7FA.05)305 321 356 1,665 60 7,098 7.47 4.4 15.1 0.0007 0.011 116.0 60 89.1Combined Cycle (2X1 GE7FA.05)610 653 558 1,267 60 6,835 7.47 3.4 17.4 0.0007 0.007 116.0 60 89.1Combined Cycle (2X1 GE7FA.05, w/ Duct Firing)610 767 669 1,269 60 6,835 7.47 3.4 17.4 0.0007 0.007 116.0 60 89.1Combined Cycle (2X1 GE7FA.05, w/ Duct Firing, Inlet Chillers)610 767 706 1,321 60 6,835 7.47 3.6 18.2 0.0007 0.007 116.0 60 89.1Combined Cycle (2X1 GE7FA.05, w/ Duct Firing, Blk Start)610 767 691 1,345 60 6,835 7.47 3.5 11.3 0.0007 0.011 116.0 60 89.1Combined Cycle (1X1 SGT6-5000, w/ Evap Coolers)320 338 307 1,603 60 6,769 7.47 4.2 16.7 0.0007 0.011 116.0 60 89.1Combined Cycle (2X1 SGT6-5000, w/ Evap Coolers)623 657 596 1,282 60 6,773 7.47 3.5 11.4 0.0007 0.011 116.0 60 89.1Combined Cycle (2X1 KA24-2, w/ Evap Coolers)638 673 610 1,266 60 6,822 7.47 3.5 11.2 0.0007 0.011 116.0 60 89.1Combined Cycle (2X1 M501GAC, w/ Duct Firing, Inlet Chillers)762 804 906 1,170 60 6,631 7.47 3.2 10.5 0.0007 0.007 116.0 60 89.1PeakingCombustion Turbine (2X1GE7EA)164 171 157 705 57 12,165 7.47 8.9 8.2 0.0007 0.033 116.00 3 93.0Combustion Turbine (2X1GE7EA,w/ Blk Start)164 171 157 811 57 12,165 7.47 8.9 8.7 0.0007 0.033 116.00 3 93.0Combustion Turbine (2X1GE7EA, w/ Inlet Chillers)164 171 160 1,011 59 12,347 7.47 9.4 9.6 0.0007 0.011 116.00 3 93.0Combustion Turbine (2X1GE7FA.05, w/ Inlet Chillers)408 424 398 784 59 10,340 7.47 4.4 5.7 0.0007 0.007 116.00 3 93.0Combustion Turbine (2X1GE7FA, w/ Recip Engine)201 201 201 1,007 60 8,868 7.47 6.4 6.6 0.0007 0.018 116.00 3 94.0Aero-Derivative (1X GE LM6000PF)46 48 44 1,047 60 9,585 7.47 3.3 15.8 0.0007 0.093 116.00 3 95.0Aero-Derivative (2X GE LM6000PF)92 96 88 906 60 9,585 7.47 3.3 9.2 0.0007 0.093 116.00 3 95.0Aero-Derivative (2X GE LM6000PF, w/ Blk Start)92 96 88 982 60 9,585 7.47 3.3 9.2 0.0007 0.093 116.00 3 95.0Aero-Derivative (1X GE LMS100PB)98 102 95 1,185 59 8,972 7.47 4.3 12.6 0.0007 0.011 116.00 30 95.0Aero-Derivative (2X GE LMS100PB, w/ Blk Start)196 203 191 786 59 8,972 7.47 4.3 9.0 0.0007 0.093 116.00 30 95.0Aero-Derivative (2X GE LMS100PB, w/ Inlet Chillers)196 203 191 1,010 59 8,972 7.47 4.3 10.1 0.0007 0.011 116.00 25 95.0Notes: (a) Installed cost, capability and heat rate numbers have been rounded.(b) All costs in 2011 dollars. Assume 1.6% escalation rate for 2011 and beyond.(c) $/kW costs are based on nominal capability.(d) Total Plant & Interconnection Cost w/AFUDC (AEP-West rate of 6.48%,site rating $/kW). Reflects deflation for decrease in capital costs for Nuclear option.(e) Transmission Cost ($/kW,w/AFUDC).(f) Levelized Fuel Cost (40-Yr. Period 2013-2052)Source: "New Generation Technology Cost and Performance Estimates," Nov.22, 2011, V1.0, GSF.Emission RatesPSO 2012 Integrated Resource Plan – Exhibit C76RESOURCE PLANNING MODEL RESULTS:C. Strategist Model Output ReportsThe following exhibits provide detailedeconomic and performance output, by year,withend‐effectsconsolidated,fortheAEP‐EastandAEP‐SPPHybridplans:Table 4: EPA Settlement Option-Low Band ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C) (D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 410,972(114,466)22,182 503,255 0(1,001) (1,001)502,254 375 502,629 0 502,629 502,629 0 502,254‐64.8135 44.042012 489,778(145,293)153,753 481,317 1,434(1,445) (11)481,306 9,801 491,107 11,111 479,996 945,511 0 479,872 264.5545 422013 436,740(264,677)122,861 578,556 1,434(1,704) (270)578,287 6,223 584,510 10,252 574,257 1,434,398 0 576,853 244.1065 422014 468,151(265,231)120,740 612,642 1,434(2,850) (1,416)611,226 4,173 615,399 9,834 605,564 1,910,076 0 609,792 234.1545 422015 486,768(275,087)134,802 627,052 1,434 16,410 17,844 644,897 4,281 649,178 12,993 636,185 2,371,167 0 643,463 245.5145 52.922016 540,921(289,417)124,197 706,141 65,106 52,790 117,896 824,037 3,111 827,148 2,679 824,468 2,922,518 0 758,931 40.18475 66.67922017 563,532(315,499)138,288 740,743 65,106 83,528 148,634 889,376 2,424 891,800 4,930 886,870 3,469,742 0 824,270 58.67733 84.015792018 557,667(330,759)113,608 774,818 65,106 83,846 148,952 923,770 482 924,252 6,693 917,559 3,992,126 0 858,664 63.22133 105.85992019 584,319(337,613)137,480 784,452 65,106 90,148 155,254 939,706 257 939,963 8,749 931,214 4,481,292 0 874,600 60.94933 143.53972020 519,820(356,119)70,434 805,504 69,943 87,477 157,420 962,924 0 962,924 11,009 951,915 4,942,669 0 892,981 75.33585 146.13682021 548,122(371,221)63,858 855,484 69,943 91,940 161,883 1,017,367 0 1,017,367 9,011 1,008,356 5,393,613 0 947,424 60.56785 148.76732022 560,658(362,490)45,139 878,009 69,943 96,369 166,312 1,044,321 132,298 1,176,619 6,764 1,169,855 5,876,329 0 974,378 44.66385 151.44512023 572,125(198,063)53,726 716,462 68,509 91,035 159,544 876,006 132,819 1,008,825 6,817 1,002,008 6,257,817 0 807,497 44.21788 154.17112024 574,920(207,704)34,565 748,060 115,558 93,174 208,732 956,792 133,045 1,089,836 6,427 1,083,410 6,638,404 266,781 0 1,108,015 40.94988 156.94622025 597,189(211,186)14,198 794,177 115,558 91,276 206,834 1,001,011 130,170 1,131,181 1,824 1,129,358 7,004,457 0 885,453 11.41388 159.77122026 594,455(238,576)14,547 818,484 165,958 116,005 281,963 1,100,448 131,617 1,232,064 37,639 1,194,426 7,361,665 276,471 0 1,210,961 231.4123 162.64712027 640,196(248,883) (22,319)911,398 230,390 52,354 282,744 1,194,142 111,372 1,305,514 35,068 1,270,446 7,712,231 703,008 0 1,666,760 211.7936 165.57482028 660,060(257,845) (14,182)932,086 230,390 57,966 288,356 1,220,442 113,923 1,334,365 31,972 1,302,393 8,043,825 0 990,052 189.6822 168.55512029 680,448(307,236)9,578 978,106 230,390 59,759 290,149 1,268,255 116,025 1,384,280 30,287 1,353,992 8,361,902 0 1,037,865 176.5109 171.58912030 689,759(328,808)7,448 1,011,119 230,390 61,914 292,304 1,303,423 117,595 1,421,018 25,062 1,395,956 8,664,480 0 1,073,033 143.4751 174.67772031 702,033(319,479) (33,123)1,054,635 290,249 41,859 332,108 1,386,743 119,740 1,506,484 12,859 1,493,624 8,963,196 302,266 0 1,398,760 72.31499 177.82192032 699,190(320,939) (73,596)1,093,726 290,249 25,116 315,365 1,409,091 120,128 1,529,219 6,921 1,522,298 9,244,106 0 1,118,842 38.23499 181.02272033 709,435(327,148) (88,011)1,124,594 354,374 28,456 382,830 1,507,424 121,691 1,629,116 41,652 1,587,464 9,514,392 313,245 0 1,466,296 226.023 184.28112034 732,707(334,730) (87,674)1,155,111 354,374 30,545 384,919 1,540,030 124,906 1,664,936 34,516 1,630,420 9,770,527 0 1,185,656 183.991 187.59822035 754,495(342,643) (99,781)1,196,918 354,374 31,023 385,397 1,582,316 127,868 1,710,184 25,592 1,684,592 10,014,710 0 1,227,942 134.007 190.97492036 786,774(352,062) (94,851)1,233,688 351,025 31,676 382,701 1,616,389 132,186 1,748,575 17,219 1,731,357 10,246,267 0 1,265,364 88.56699 194.41252037 802,658(359,571) (116,572)1,278,801 351,025 30,554 381,579 1,660,380 134,548 1,794,928 5,388 1,789,540 10,467,100 0 1,309,355 27.22299 197.91192038 834,857(368,650) (89,335)1,292,843 447,792 38,769 486,561 1,779,404 138,535 1,917,938 41,956 1,875,982 10,680,700 512,962 0 1,844,574 208.2473 201.47432039 859,602(378,187) (89,561)1,327,349 447,792 42,247 490,039 1,817,388 141,713 1,959,101 31,994 1,927,107 10,883,155 0 1,369,596 155.9913 205.10092040 892,996(379,267) (84,309)1,356,571 447,792 41,998 489,790 1,846,361 146,272 1,992,633 24,505 1,968,128 11,073,933 0 1,398,569 117.3673 208.79272011 Net Present ValuePeriodof2011‐2040 6,553,604(3,180,570)765,182 8,968,992 1,144,465 547,4881,691,953 10,660,945555,125 11,216,071 142,137 11,073,933BaseCaseO&M2011‐20401,151,8221,151,8221,151,822UtilityCostPresentValue2011‐20402,843,775 12,367,893 12,225,755Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingNortheastern 4 Retired 2/28/2016 and Northeastern 3 DSI+ACI+BH Retrofit 7/1/2015 with 2021-2026 Declining Capacity Factor and 12/31/2026 RetirementOptimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C77Table 5: EPA Settlement Option-Low Band BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,863 2,952 89 2011 8,455 7,274 2,123 880 2,863 21,5962012 18,688 2,906(2,906)2,740 5,756 3,016 2012 10,870 7,117 2,245 661 2,740 23,6332013 18,702 2,922(2,922)1,953 4,585 2,633 2013 7,671 6,754 2,237 685 1,953 19,2992014 18,748 2,777(2,777)2,096 4,497 2,401 2014 7,487 7,049 2,237 540 2,096 19,4092015 18,779 2,817(2,817)1,616 4,237 2,622 2015 7,973 6,720 2,237 580 1,616 19,1262016 18,832 2,803(2,803)1,905 3,956 2,052 2016 8,292 4,830 2,245 558 1,905 17,8292017 18,847 3,150(3,150)1,646 3,998 2,352 2017 8,454 3,960 2,532 618 1,646 17,2102018 18,883 3,285(3,285)1,839 3,629 1,791 2018 8,094 3,791 2,606 680 1,839 17,0092019 18,945 3,279(3,279)1,682 3,876 2,194 2019 8,284 3,939 2,606 674 1,682 17,1842020 18,996 3,570(3,570)1,797 2,826 1,029 2020 6,944 4,103 2,911 659 1,797 16,4142021 19,064 3,632(3,632)1,909 2,720 812 2021 7,308 3,439 2,975 657 1,909 16,2882022 19,169 3,632(3,632)2,339 2,680 341 2022 7,194 3,258 2,975 657 2,339 16,4232023 19,280 3,927(3,927)2,141 2,697 556 2023 7,085 2,976 3,270 657 2,141 16,1292024 19,404 4,014(4,014)2,382 2,589 208 2024 6,717 3,029 3,355 659 2,382 16,1422025 19,534 4,001(4,001)2,652 2,527(124)2025 7,045 2,561 3,343 657 2,652 16,2582026 19,671 4,307(4,307)2,602 2,496(105)2026 6,821 2,664 3,639 668 2,602 16,3922027 19,813 4,380(4,380)3,154 2,434(720)2027 7,496 598 3,712 668 3,154 15,6282028 19,969 4,409(4,409)3,056 2,496(560)2028 7,292 632 3,725 683 3,056 15,3892029 20,127 4,985(4,985)2,742 2,586(156)2029 7,261 650 4,303 682 2,742 15,6382030 20,300 5,149(5,149)2,840 2,620(220)2030 7,248 651 4,450 699 2,840 15,8882031 20,485 4,864(4,864)3,294 2,470(824)2031 8,076 637 4,165 699 3,294 16,8712032 20,678 4,766(4,766)3,877 2,427(1,451)2032 8,305 638 4,065 701 3,877 17,5872033 20,875 4,750(4,750)4,089 2,424(1,664)2033 8,321 631 4,051 699 4,089 17,7902034 21,092 4,750(4,750)4,044 2,380(1,663)2034 8,532 626 4,051 699 4,044 17,9522035 21,324 4,750(4,750)4,173 2,345(1,828)2035 8,581 631 4,051 699 4,173 18,1362036 21,568 4,766(4,766)4,105 2,348(1,756)2036 8,869 632 4,065 701 4,105 18,3722037 21,821 4,750(4,750)4,394 2,355(2,039)2037 8,876 627 4,051 699 4,394 18,6472038 22,060 4,750(4,750)4,159 2,470(1,689)2038 8,657 618 4,051 699 4,159 18,1842039 22,299 4,750(4,750)4,067 2,352(1,715)2039 8,392 613 4,051 699 4,067 17,8222040 22,541 4,765(4,765)4,103 2,445(1,658)2040 8,655 617 4,064 701 4,103 18,140PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,452 11,308 15,090 69720124,084 4,904 0 4,904 20.1%2012 22,426 12,708 14,615 45520134,102 4,904 0 4,904 19.6%2013 21,342 11,867 11,886 44520144,109 4,902 0 4,902 19.3%2014 22,355 11,992 12,092 40620154,099 4,902 0 4,902 19.6%2015 19,404 11,925 11,904 53320164,094 4,691 0 4,691 14.6%2016 10,294 10,650 8,175 55220174,083 4,697 0 4,697 15.0%2017 6,808 10,097 7,305 55320184,079 4,697 0 4,697 15.1%2018 6,293 9,732 7,084 64620194,081 4,697 0 4,697 15.1%2019 6,843 9,981 7,368 50920204,078 4,708 0 4,708 15.4%2020 6,861 9,381 6,193 67120214,091 4,708 0 4,708 15.1%2021 5,762 9,033 6,156 60820224,105 4,708 0 4,708 14.7%2022 5,687 8,774 5,860 46120234,117 4,721 0 4,721 14.7%2023 5,022 8,693 5,850 56120244,130 4,497 236 4,733 14.6%2024 5,033 8,597 5,776 61020254,156 4,497 0 4,733 13.9%2025 4,276 8,304 5,466 54820264,179 4,508 236 4,979 19.1%2026 4,282 8,286 5,436 65520274,204 4,048 469 4,988 18.6%2027 45 6,925 4,328 61520284,225 4,050 0 4,989 18.1%2028 49 6,993 4,077 65020294,253 4,068 0 5,008 17.8%2029 50 7,031 4,219 66820304,284 4,071 0 5,010 16.9%2030 51 7,032 4,332 66920314,318 3,803 236 4,978 15.3%2031 50 7,066 4,732 65620324,348 3,803 0 4,978 14.5%2032 51 6,996 4,990 65720334,390 3,803 236 5,213 18.7%2033 50 6,993 5,111 65020344,427 3,803 0 5,213 17.8%2034 50 7,083 5,107 64520354,471 3,803 0 5,213 16.6%2035 51 7,156 5,283 65020364,511 3,803 0 5,213 15.6%2036 51 7,300 5,527 65120374,565 3,803 0 5,213 14.2%2037 51 7,332 5,535 64620384,611 3,803 233 5,446 18.1%2038 52 7,450 5,192 63720394,657 3,803 0 5,446 16.9%2039 53 7,521 5,081 63120404,691 3,803 0 5,446 16.1%2040 53 7,660 5,320 636Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C78Table 6: Option #1 – 15 Year Low Band ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 410,972(114,466)22,182 503,255 0(1,144) (1,144)502,111 375 502,486 0 502,486 502,486 0 502,111‐64.8135 44.042012 489,778(145,293)153,753 481,317 0(1,652) (1,652)479,666 9,801 489,467 11,111 478,356 943,855 0 479,666 264.5545 422013 436,740(264,677)122,861 578,556 0(1,882) (1,882)576,674 6,223 582,897 10,252 572,644 1,431,368 0 576,674 244.1065 422014 468,151(265,231)120,740 612,642 0(1,738) (1,738)610,904 4,173 615,077 9,834 605,242 1,906,793 0 610,904 234.1545 422015 486,768(275,087)134,802 627,052 0 14,347 14,347 641,400 4,281 645,681 12,993 632,688 2,365,350 0 641,400 245.5145 52.922016 526,840(288,161)153,770 661,231 175,176 62,698 237,874 899,106 2,884 901,990 17,608 884,381 2,956,767 0 723,930 264.0729 66.67922017 539,396(313,755)170,012 683,139 175,176 101,313 276,489 959,627 2,266 961,893 23,740 938,153 3,535,634 0 784,451 282.5655 84.015792018 523,399(328,524)147,971 703,952 175,176 95,540 270,716 974,668 454 975,122 30,393 944,729 4,073,487 0 799,492 287.1095 105.85992019 555,144(335,407)163,956 726,595 175,176 101,042 276,218 1,002,813 243 1,003,056 40,885 962,170 4,578,914 0 827,637 284.8375 143.53972020 499,473(352,497)107,495 744,474 180,013 102,578 282,591 1,027,065 0 1,027,065 43,728 983,337 5,055,521 0 847,052 299.224 146.13682021 515,943(367,057)105,221 777,779 180,013 105,865 285,878 1,063,656 0 1,063,656 42,318 1,021,338 5,512,271 0 883,643 284.456 148.76732022 516,430(357,848)88,506 785,772 180,013 114,220 294,233 1,080,006 169,892 1,249,898 40,671 1,209,227 6,011,232 0 899,993 268.552 151.44512023 525,452(198,062)102,797 620,718 180,013 105,427 285,440 906,158 170,130 1,076,288 41,334 1,034,954 6,405,264 0 726,145 268.1061 154.17112024 527,088(207,705)97,334 637,459 180,013 114,076 294,089 931,548 175,085 1,106,633 4,604 1,102,028 6,792,391 0 751,535 29.33807 156.94622025 547,354(211,185)94,203 664,335 228,709 113,287 341,996 1,006,331 176,533 1,182,864 37,595 1,145,270 7,163,601 271,583 0 1,049,205 235.3021 159.77122026 551,708(238,576)96,892 693,392 228,709 114,055 342,764 1,036,156 178,569 1,214,725 35,750 1,178,975 7,516,189 0 807,447 219.8005 162.64712027 572,110(248,884)82,461 738,534 228,709 118,331 347,040 1,085,573 175,680 1,261,253 31,691 1,229,562 7,855,474 0 856,864 191.4005 165.57482028 586,944(257,846)99,384 745,406 228,709 120,637 349,346 1,094,752 185,269 1,280,021 28,535 1,251,486 8,174,107 0 866,043 169.2892 168.55512029 600,752(307,236)101,952 806,036 228,709 124,061 352,770 1,158,806 180,103 1,338,909 26,788 1,312,121 8,482,347 0 930,097 156.1179 171.58912030 617,465(328,808)123,112 823,161 228,709 118,514 347,223 1,170,384 189,301 1,359,685 21,500 1,338,185 8,772,403 0 941,675 123.0821 174.67772031 677,321(319,479) (17,451)1,014,251 318,828 221,411 540,239 1,554,489 136,183 1,690,672 12,859 1,677,813 9,107,956 1,359,539 0 2,595,200 72.31499 177.82192032 699,190(320,939) (73,596)1,093,726 318,828 25,116 343,944 1,437,670 120,128 1,557,798 6,921 1,550,877 9,394,140 0 1,118,842 38.23499 181.02272033 709,435(327,148) (88,011)1,124,594 382,953 28,456 411,409 1,536,003 121,691 1,657,695 41,652 1,616,043 9,669,291 313,245 0 1,466,296 226.023 184.28112034 732,707(334,730) (87,674)1,155,111 382,953 30,545 413,498 1,568,609 124,906 1,693,515 34,516 1,658,999 9,929,916 0 1,185,656 183.991 187.59822035 754,495(342,643) (99,781)1,196,918 382,953 31,023 413,976 1,610,895 127,868 1,738,763 25,592 1,713,171 10,178,241 0 1,227,942 134.007 190.97492036 786,774(352,062) (94,851)1,233,688 379,604 31,676 411,280 1,644,968 132,186 1,777,154 17,219 1,759,936 10,413,621 0 1,265,364 88.56699 194.41252037 802,658(359,571) (116,572)1,278,801 379,604 30,554 410,158 1,688,959 134,548 1,823,507 5,388 1,818,119 10,637,980 0 1,309,355 27.22299 197.91192038 834,857(368,650) (89,335)1,292,843 476,371 38,769 515,140 1,807,983 138,535 1,946,517 41,956 1,904,561 10,854,834 512,962 0 1,844,573 208.2473 201.47432039 859,602(378,187) (89,561)1,327,349 476,371 42,247 518,618 1,845,967 141,713 1,987,680 31,994 1,955,686 11,060,292 0 1,369,596 155.9913 205.10092040 892,996(379,267) (84,309)1,356,571 476,371 41,998 518,369 1,874,940 146,272 2,021,212 24,505 1,996,707 11,253,841 0 1,398,569 117.3673 208.79272011 Net Present ValuePeriodof2011‐2040 6,311,710(3,170,690)1,091,383 8,391,018 1,709,503 714,0922,423,596 10,814,613698,203 11,512,816 258,976 11,253,841BaseCaseO&M2011‐20401,151,8221,151,8221,151,822UtilityCostPresentValue2011‐20403,575,417 12,664,638 12,405,662Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingNortheastern 3 and Northeastern 4 DFGD 15 Year Retrofit 3/1/2016 and 2/28/2031 RetirementOptimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C79Table 7: Option #1 – 15 Year Low Band BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,863 2,952 89 2011 8,455 7,274 2,123 880 2,863 21,5962012 18,688 2,906(2,906)2,740 5,756 3,016 2012 10,870 7,117 2,245 661 2,740 23,6332013 18,702 2,922(2,922)1,953 4,585 2,633 2013 7,671 6,754 2,237 685 1,953 19,2992014 18,748 2,777(2,777)2,096 4,497 2,401 2014 7,487 7,049 2,237 540 2,096 19,4092015 18,779 2,817(2,817)1,616 4,237 2,622 2015 7,973 6,720 2,237 580 1,616 19,1262016 18,832 2,803(2,803)1,383 4,194 2,811 2016 7,626 7,318 2,245 558 1,383 19,1302017 18,847 3,150(3,150)1,103 4,271 3,169 2017 7,922 7,065 2,532 618 1,103 19,2402018 18,883 3,285(3,285)1,215 3,865 2,649 2018 7,178 7,209 2,606 680 1,215 18,8882019 18,945 3,279(3,279)1,231 4,089 2,859 2019 7,718 6,928 2,606 674 1,231 19,1562020 18,996 3,570(3,570)1,078 2,999 1,921 2020 6,308 7,277 2,911 659 1,078 18,2322021 19,064 3,632(3,632)1,175 2,948 1,772 2021 6,411 7,007 2,975 657 1,175 18,2252022 19,169 3,632(3,632)1,713 2,832 1,119 2022 6,113 6,793 2,975 657 1,713 18,2502023 19,280 3,927(3,927)1,469 2,880 1,411 2023 6,076 6,453 3,270 657 1,469 17,9262024 19,404 4,014(4,014)1,492 2,787 1,294 2024 5,589 6,848 3,355 659 1,492 17,9432025 19,534 4,001(4,001)1,564 2,787 1,223 2025 5,795 6,729 3,343 657 1,564 18,0882026 19,671 4,307(4,307)1,468 2,744 1,276 2026 5,648 6,763 3,639 668 1,468 18,1852027 19,813 4,380(4,380)1,703 2,712 1,009 2027 5,925 6,282 3,712 668 1,703 18,2902028 19,969 4,409(4,409)1,488 2,773 1,285 2028 5,768 6,825 3,725 683 1,488 18,4902029 20,127 4,985(4,985)1,538 2,831 1,293 2029 5,945 6,256 4,303 682 1,538 18,7232030 20,300 5,149(5,149)1,430 3,027 1,598 2030 5,799 6,718 4,450 699 1,430 19,0952031 20,485 4,864(4,864)3,140 2,567(573)2031 7,943 2,063 4,165 699 3,140 18,0102032 20,678 4,766(4,766)3,877 2,427(1,451)2032 8,305 638 4,065 701 3,877 17,5872033 20,875 4,750(4,750)4,089 2,424(1,664)2033 8,321 631 4,051 699 4,089 17,7902034 21,092 4,750(4,750)4,044 2,380(1,663)2034 8,532 626 4,051 699 4,044 17,9522035 21,324 4,750(4,750)4,173 2,345(1,828)2035 8,581 631 4,051 699 4,173 18,1362036 21,568 4,766(4,766)4,105 2,348(1,756)2036 8,869 632 4,065 701 4,105 18,3722037 21,821 4,750(4,750)4,394 2,355(2,039)2037 8,876 627 4,051 699 4,394 18,6472038 22,060 4,750(4,750)4,159 2,470(1,689)2038 8,657 618 4,051 699 4,159 18,1842039 22,299 4,750(4,750)4,067 2,352(1,715)2039 8,392 613 4,051 699 4,067 17,8222040 22,541 4,765(4,765)4,103 2,445(1,658)2040 8,655 617 4,064 701 4,103 18,140PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,452 11,308 15,090 69720124,084 4,904 0 4,904 20.1%2012 22,426 12,708 14,615 45520134,102 4,904 0 4,904 19.6%2013 21,342 11,867 11,886 44520144,109 4,902 0 4,902 19.3%2014 22,355 11,992 12,092 40620154,099 4,902 0 4,902 19.6%2015 19,404 11,925 11,904 53320164,094 4,915 0 4,915 20.1%2016 6,079 12,556 7,447 55920174,083 4,921 0 4,921 20.5%2017 1,272 12,491 6,705 56120184,079 4,921 0 4,921 20.6%2018 1,286 12,251 6,319 64820194,081 4,921 0 4,921 20.6%2019 1,252 12,248 6,632 51320204,078 4,932 0 4,932 20.9%2020 1,300 11,844 5,486 65620214,091 4,932 0 4,932 20.6%2021 1,257 11,651 5,586 59620224,105 4,932 0 4,932 20.1%2022 1,232 11,267 5,208 46320234,117 4,945 0 4,945 20.1%2023 1,160 11,136 5,332 55720244,130 4,721 0 4,721 14.3%2024 1,228 11,313 5,229 59220254,156 4,721 236 4,957 19.3%2025 1,216 11,262 5,080 50120264,179 4,732 0 4,967 18.9%2026 1,212 11,242 5,153 59820274,204 4,732 0 4,967 18.2%2027 1,125 10,923 5,189 56120284,225 4,733 0 4,969 17.6%2028 1,225 11,372 5,194 58520294,253 4,752 0 4,988 17.3%2029 1,115 10,915 5,269 61120304,284 4,754 0 4,990 16.5%2030 1,202 11,320 5,443 61220314,318 3,803 940 4,978 15.3%2031 320 8,037 5,163 64020324,348 3,803 0 4,978 14.5%2032 51 6,996 4,990 65720334,390 3,803 236 5,213 18.7%2033 50 6,993 5,111 65020344,427 3,803 0 5,213 17.8%2034 50 7,083 5,107 64520354,471 3,803 0 5,213 16.6%2035 51 7,156 5,283 65020364,511 3,803 0 5,213 15.6%2036 51 7,300 5,527 65120374,565 3,803 0 5,213 14.2%2037 51 7,332 5,535 64620384,611 3,803 233 5,446 18.1%2038 52 7,450 5,192 63720394,657 3,803 0 5,446 16.9%2039 53 7,521 5,081 63120404,691 3,803 0 5,446 16.1%2040 53 7,660 5,320 636Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C80Table 8: Option #1 – 25 Year Low Band ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 410,972(114,466)22,182 503,255 0(1,298) (1,298)501,957 375 502,332 0 502,332 502,332 0 501,957‐64.8135 44.042012 500,852(145,817)170,532 476,137 0(1,557) (1,557)474,580 9,855 484,434 11,111 473,323 939,058 0 474,580 264.5545 422013 447,221(265,574)135,405 577,390 0(1,899) (1,899)575,491 6,323 581,815 10,252 571,562 1,425,650 0 575,491 244.1065 422014 480,522(266,189)135,854 610,856 0(1,838) (1,838)609,018 4,262 613,280 9,834 603,446 1,899,663 0 609,018 234.1545 422015 496,863(275,918)146,965 625,817 0 13,820 13,820 639,637 4,347 643,984 12,993 630,991 2,356,990 0 639,637 245.5145 52.922016 535,999(288,906)164,615 660,291 150,933 59,377 210,310 870,600 2,941 873,541 17,608 855,933 2,929,382 0 719,667 264.0729 66.67922017 548,388(314,585)180,745 682,229 150,933 95,651 246,584 928,813 2,306 931,119 23,740 907,379 3,489,261 0 777,880 282.5655 84.015792018 531,713(329,331)157,722 703,322 150,933 89,503 240,436 943,757 461 944,219 30,393 913,825 4,009,520 0 792,824 287.1095 105.85992019 564,649(336,273)175,031 725,891 150,933 94,821 245,754 971,645 246 971,891 40,885 931,006 4,498,576 0 820,712 284.8375 143.53972020 501,550(352,849)110,130 744,268 155,770 96,167 251,937 996,205 0 996,205 43,728 952,477 4,960,226 0 840,435 299.224 146.13682021 517,933(367,399)107,581 777,750 155,770 99,135 254,905 1,032,656 0 1,032,656 42,318 990,338 5,403,112 0 876,886 284.456 148.76732022 519,260(358,284)92,507 785,037 155,770 107,083 262,853 1,047,890 170,846 1,218,736 40,671 1,178,065 5,889,215 0 892,120 268.552 151.44512023 528,717(198,062)106,955 619,824 155,770 98,070 253,840 873,664 171,050 1,044,715 41,334 1,003,381 6,271,226 0 717,894 268.1061 154.17112024 530,568(207,705)101,627 636,646 155,770 106,388 262,158 898,804 176,137 1,074,941 4,604 1,070,336 6,647,221 0 743,034 29.33807 156.94622025 550,169(211,185)97,921 663,433 204,466 105,342 309,808 973,241 177,492 1,150,733 37,595 1,113,139 7,008,016 271,583 0 1,040,358 235.3021 159.77122026 554,064(238,576)99,914 692,726 204,466 106,913 311,379 1,004,105 179,359 1,183,464 35,750 1,147,714 7,351,255 0 799,639 219.8005 162.64712027 575,245(248,884)86,256 737,873 204,466 111,380 315,846 1,053,718 176,610 1,230,329 31,691 1,198,638 7,682,006 0 849,252 191.4005 165.57482028 590,283(257,846)103,630 744,499 204,466 113,983 318,449 1,062,947 186,371 1,249,318 28,535 1,220,784 7,992,822 0 858,481 169.2892 168.55512029 604,464(307,236)106,580 805,120 204,466 117,986 322,452 1,127,572 181,176 1,308,749 26,788 1,281,961 8,293,977 0 923,106 156.1179 171.58912030 621,960(328,808)128,906 821,862 204,466 118,222 322,688 1,144,551 190,607 1,335,157 21,500 1,313,658 8,578,717 0 940,085 123.0821 174.67772031 647,715(319,479)107,944 859,250 204,466 121,185 325,651 1,184,902 191,518 1,376,419 13,589 1,362,830 8,851,275 0 980,436 76.42192 177.82192032 662,373(320,940)106,692 876,621 204,466 109,528 313,994 1,190,615 199,031 1,389,646 7,665 1,381,981 9,106,293 0 986,149 42.34192 181.02272033 684,334(327,148)90,188 921,294 268,591 111,848 380,439 1,301,733 198,556 1,500,289 42,409 1,457,880 9,354,515 313,245 0 1,346,387 230.1299 184.28112034 708,576(334,730)102,088 941,219 268,591 114,288 382,879 1,324,097 206,334 1,530,432 35,287 1,495,145 9,589,398 0 1,055,506 188.0979 187.59822035 724,624(342,643)81,703 985,564 268,591 113,992 382,583 1,368,147 206,757 1,574,904 26,376 1,548,528 9,813,859 0 1,099,556 138.1139 190.97492036 757,727(352,062)97,655 1,012,135 265,242 113,741 378,983 1,391,118 215,599 1,606,717 18,017 1,588,700 10,026,336 0 1,125,876 92.67392 194.41252037 769,339(359,572)70,084 1,058,826 265,242 111,445 376,687 1,435,513 215,401 1,650,915 6,201 1,644,714 10,229,297 0 1,170,271 31.32992 197.91192038 803,738(368,650)88,531 1,083,858 341,400 116,465 457,865 1,541,723 224,839 1,766,562 43,231 1,723,331 10,425,517 342,471 0 1,542,794 214.5739 201.47432039 804,327(378,187)40,126 1,142,388 341,400 114,292 455,692 1,598,080 220,277 1,818,357 33,292 1,785,066 10,613,050 0 1,256,680 162.3179 205.10092040 843,936(379,267)61,486 1,161,717 341,400 254,851 596,251 1,757,969 229,505 1,987,473 25,826 1,961,647 10,803,200 0 1,416,569 123.6939 208.79272011 Net Present ValuePeriodof2011‐2040 6,332,781(3,175,722)1,418,724 8,089,779 1,392,507 769,6732,162,180 10,251,959811,479 11,063,439 260,239 10,803,200BaseCaseO&M2011‐20401,151,8221,151,8221,151,822UtilityCostPresentValue2011‐20403,314,002 12,215,260 11,955,021Costs and Emissions Summary Under Low Band PricingNortheastern 3 and Northeastern 4 DFGD 25 Year Retrofit 3/1/2016Optimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C81Table 9: Option #1 – 25 Year Low Band BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,863 2,952 89 2011 8,455 7,274 2,123 880 2,863 21,5962012 18,688 2,906(2,906)3,738 7,085 3,347 2012 11,175 7,130 2,245 661 3,738 24,9492013 18,702 2,922(2,922)2,474 5,428 2,954 2013 7,925 6,793 2,237 685 2,474 20,1132014 18,748 2,777(2,777)2,570 5,321 2,751 2014 7,762 7,097 2,237 540 2,570 20,2052015 18,779 2,817(2,817)2,027 4,930 2,903 2015 8,193 6,757 2,237 580 2,027 19,7952016 18,832 2,803(2,803)1,553 4,610 3,057 2016 7,808 7,363 2,245 558 1,553 19,5262017 18,847 3,150(3,150)1,263 4,666 3,403 2017 8,097 7,103 2,532 618 1,263 19,6142018 18,883 3,285(3,285)1,305 4,169 2,864 2018 7,340 7,241 2,606 680 1,305 19,1722019 18,945 3,279(3,279)1,412 4,499 3,087 2019 7,898 6,954 2,606 674 1,412 19,5442020 18,996 3,570(3,570)1,031 3,024 1,992 2020 6,338 7,310 2,911 659 1,031 18,2482021 19,064 3,632(3,632)1,085 2,920 1,835 2021 6,443 7,029 2,975 657 1,085 18,1902022 19,169 3,632(3,632)1,614 2,826 1,212 2022 6,148 6,840 2,975 657 1,614 18,2342023 19,280 3,927(3,927)1,401 2,899 1,498 2023 6,119 6,496 3,270 657 1,401 17,9432024 19,404 4,014(4,014)1,384 2,771 1,387 2024 5,628 6,901 3,355 659 1,384 17,9272025 19,534 4,001(4,001)1,462 2,764 1,302 2025 5,822 6,781 3,343 657 1,462 18,0652026 19,671 4,307(4,307)1,337 2,678 1,341 2026 5,670 6,805 3,639 668 1,337 18,1182027 19,813 4,380(4,380)1,522 2,612 1,090 2027 5,960 6,328 3,712 668 1,522 18,1902028 19,969 4,409(4,409)1,341 2,714 1,374 2028 5,798 6,883 3,725 683 1,341 18,4302029 20,127 4,985(4,985)1,468 2,852 1,384 2029 5,984 6,306 4,303 682 1,468 18,7442030 20,300 5,149(5,149)1,361 3,066 1,705 2030 5,844 6,779 4,450 699 1,361 19,1332031 20,485 4,864(4,864)1,429 2,795 1,365 2031 6,250 6,506 4,165 699 1,429 19,0492032 20,678 4,766(4,766)1,526 2,836 1,309 2032 6,132 6,847 4,065 701 1,526 19,2712033 20,875 4,750(4,750)1,773 2,782 1,009 2033 6,389 6,514 4,051 699 1,773 19,4262034 21,092 4,750(4,750)1,661 2,815 1,154 2034 6,477 6,780 4,051 699 1,661 19,6692035 21,324 4,750(4,750)2,003 2,812 808 2035 6,558 6,593 4,051 699 2,003 19,9052036 21,568 4,766(4,766)2,072 3,087 1,015 2036 6,750 6,832 4,065 701 2,072 20,4202037 21,821 4,750(4,750)2,586 3,188 601 2037 6,819 6,620 4,051 699 2,586 20,7752038 22,060 4,750(4,750)2,519 3,332 813 2038 6,987 6,907 4,051 699 2,519 21,1632039 22,299 4,750(4,750)2,959 3,080 121 2039 6,963 6,480 4,051 699 2,959 21,1522040 22,541 4,765(4,765)2,866 3,223 357 2040 7,203 6,689 4,064 701 2,866 21,523PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,452 11,308 15,090 69720124,084 4,904 0 4,904 20.1%2012 22,469 12,875 14,841 45520134,102 4,904 0 4,904 19.6%2013 21,464 12,038 12,132 44520144,109 4,902 0 4,902 19.3%2014 22,506 12,180 12,354 40520154,099 4,902 0 4,902 19.6%2015 19,512 12,075 12,119 53220164,094 4,915 0 4,915 20.1%2016 6,101 12,692 7,607 56220174,083 4,921 0 4,921 20.5%2017 1,279 12,620 6,849 56020184,079 4,921 0 4,921 20.6%2018 1,292 12,366 6,456 64320194,081 4,921 0 4,921 20.6%2019 1,257 12,369 6,782 51220204,078 4,932 0 4,932 20.9%2020 1,306 11,891 5,513 65820214,091 4,932 0 4,932 20.6%2021 1,261 11,689 5,610 59720224,105 4,932 0 4,932 20.1%2022 1,241 11,330 5,241 46220234,117 4,945 0 4,945 20.1%2023 1,167 11,196 5,370 55820244,130 4,721 0 4,721 14.3%2024 1,238 11,381 5,269 59520254,156 4,721 236 4,957 19.3%2025 1,225 11,323 5,109 50320264,179 4,732 0 4,967 18.9%2026 1,219 11,292 5,177 60120274,204 4,732 0 4,967 18.2%2027 1,133 10,981 5,220 56320284,225 4,733 0 4,969 17.6%2028 1,235 11,439 5,227 58820294,253 4,752 0 4,988 17.3%2029 1,124 10,980 5,305 61520304,284 4,754 0 4,990 16.5%2030 1,213 11,399 5,487 61720314,318 4,746 0 4,982 15.4%2031 1,164 11,302 5,448 60420324,348 4,746 0 4,982 14.6%2032 1,227 11,590 5,484 60220334,390 4,746 236 5,217 18.8%2033 1,165 11,411 5,757 60320344,427 4,746 0 5,217 17.8%2034 1,215 11,701 5,690 59620354,471 4,746 0 5,217 16.7%2035 1,178 11,571 5,810 60520364,511 4,746 0 5,217 15.7%2036 1,225 11,906 6,077 60020374,565 4,746 0 5,217 14.3%2037 1,186 11,739 5,997 60020384,611 4,746 236 5,453 18.3%2038 1,239 12,091 6,058 59720394,657 4,746 0 5,453 17.1%2039 1,160 11,690 6,024 59820404,691 4,746 0 5,453 16.2%2040 1,199 12,019 6,308 602Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C82Table 10: Option #2 – 15 Year Low Band ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 410,972(114,466)22,182 503,255 0(1,144) (1,144)502,111 375 502,486 0 502,486 502,486 0 502,111‐64.8135 44.042012 489,778(145,293)153,753 481,317 1,262(1,652) (390)480,928 9,801 490,729 11,111 479,618 945,019 0 479,666 264.5545 422013 436,740(264,677)122,861 578,556 1,262(1,974) (712)577,844 6,223 584,067 10,252 573,815 1,433,529 0 576,582 244.1065 422014 468,151(265,231)120,740 612,642 1,262(3,210) (1,948)610,694 4,173 614,867 9,834 605,032 1,908,789 0 609,432 234.1545 422015 486,768(275,087)134,802 627,052 1,262 7,418 8,680 635,733 4,281 640,014 12,993 627,021 2,363,238 0 634,471 245.5145 52.922016 546,434(289,423)124,143 711,715 93,625 60,448 154,073 865,788 2,747 868,534 3,176 865,358 2,941,934 0 772,163 47.63543 66.67922017 567,743(315,761)132,083 751,421 93,625 82,478 176,103 927,524 2,111 929,635 5,556 924,079 3,512,117 0 833,899 66.12802 84.015792018 560,091(330,595)120,245 770,441 93,625 84,616 178,241 948,681 429 949,111 7,481 941,629 4,048,205 0 855,056 70.67202 105.85992019 586,939(337,687)126,253 798,372 93,625 89,417 183,042 981,413 227 981,640 9,818 971,822 4,558,702 0 887,788 68.40002 143.53972020 529,249(356,431)70,339 815,341 98,462 87,454 185,916 1,001,256 0 1,001,256 12,098 989,158 5,038,130 0 902,794 82.78653 146.13682021 546,520(370,825)66,250 851,095 98,462 93,211 191,673 1,042,769 0 1,042,769 10,119 1,032,650 5,499,938 0 944,307 68.01853 148.76732022 558,992(361,417)56,489 863,920 98,462 97,819 196,281 1,060,202 138,777 1,198,979 7,892 1,191,086 5,991,415 0 961,740 52.11453 151.44512023 570,252(198,063)68,053 700,262 98,462 93,625 192,087 892,349 138,843 1,031,192 7,966 1,023,227 6,380,982 0 793,887 51.66857 154.17112024 577,520(207,704)78,288 706,937 158,243 107,934 266,177 973,114 143,770 1,116,885 7,248 1,109,637 6,770,782 399,591 0 1,214,463 46.18133 156.94622025 597,526(211,187)78,706 730,007 158,243 107,471 265,714 995,721 144,727 1,140,448 2,659 1,137,788 7,139,567 0 837,478 16.64533 159.77122026 607,001(238,579)85,739 759,842 158,243 108,609 266,852 1,026,693 147,380 1,174,073 186 1,173,887 7,490,633 0 868,450 1.143793 162.64712027 630,311(248,884)81,407 797,788 209,145 115,501 324,646 1,122,434 146,868 1,269,302 34,480 1,234,822 7,831,369 281,448 0 1,194,737 208.2438 165.57482028 643,083(257,845)87,474 813,454 209,145 113,554 322,699 1,136,153 153,109 1,289,261 31,374 1,257,887 8,151,632 0 927,008 186.1324 168.55512029 662,600(307,236)99,460 870,376 209,145 122,395 331,540 1,201,917 150,128 1,352,045 29,678 1,322,366 8,462,279 0 992,772 172.9611 171.58912030 672,546(328,808)107,975 893,379 209,145 117,998 327,143 1,220,522 155,317 1,375,839 24,442 1,351,397 8,755,199 0 1,011,377 139.9253 174.67772031 701,255(319,479) (3,498)1,024,232 306,019 143,890 449,909 1,474,141 130,997 1,605,138 12,859 1,592,278 9,073,645 906,798 0 2,074,919 72.31499 177.82192032 699,190(320,939) (73,596)1,093,726 306,019 25,116 331,135 1,424,861 120,128 1,544,989 6,921 1,538,068 9,357,465 0 1,118,842 38.23499 181.02272033 709,435(327,148) (88,011)1,124,594 370,144 28,456 398,600 1,523,194 121,691 1,644,886 41,652 1,603,234 9,630,436 313,245 0 1,466,296 226.023 184.28112034 732,707(334,730) (87,674)1,155,111 370,144 30,545 400,689 1,555,800 124,906 1,680,706 34,516 1,646,190 9,889,048 0 1,185,656 183.991 187.59822035 754,495(342,643) (99,781)1,196,918 370,144 31,023 401,167 1,598,086 127,868 1,725,954 25,592 1,700,362 10,135,517 0 1,227,942 134.007 190.97492036 786,774(352,062) (94,851)1,233,688 366,795 31,676 398,471 1,632,159 132,186 1,764,345 17,219 1,747,127 10,369,183 0 1,265,364 88.56699 194.41252037 802,658(359,571) (116,572)1,278,801 366,795 30,554 397,349 1,676,150 134,548 1,810,698 5,388 1,805,310 10,591,962 0 1,309,355 27.22299 197.91192038 834,857(368,650) (89,335)1,292,843 463,562 38,769 502,331 1,795,174 138,535 1,933,708 41,956 1,891,752 10,807,358 512,962 0 1,844,574 208.2473 201.47432039 859,602(378,187) (89,561)1,327,349 463,562 42,247 505,809 1,833,158 141,713 1,974,871 31,994 1,942,877 11,011,470 0 1,369,596 155.9913 205.10092040 892,996(379,267) (84,309)1,356,571 463,562 41,998 505,560 1,862,131 146,272 2,008,403 24,505 1,983,898 11,203,777 0 1,398,569 117.3673 208.79272011 Net Present ValuePeriodof2011‐2040 6,554,743(3,180,215)931,252 8,803,706 1,289,739 633,8701,923,609 10,727,315611,021 11,338,336 134,560 11,203,777BaseCaseO&M2011‐20401,151,8221,151,8221,151,822UtilityCostPresentValue2011‐20403,075,431 12,490,158 12,355,599Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingNortheastern 3 DFGD 15 Year Retrofit 3/1/2016 and 2/28/2031 Retirement and Northeastern 4 Retirement 2/28/2016Optimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C83Table 11: Option #2 – 15 Year Low Band BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,863 2,952 89 2011 8,455 7,274 2,123 880 2,863 21,5962012 18,688 2,906(2,906)2,740 5,756 3,016 2012 10,870 7,117 2,245 661 2,740 23,6332013 18,702 2,922(2,922)1,953 4,585 2,633 2013 7,671 6,754 2,237 685 1,953 19,2992014 18,748 2,777(2,777)2,096 4,497 2,401 2014 7,487 7,049 2,237 540 2,096 19,4092015 18,779 2,817(2,817)1,616 4,237 2,622 2015 7,973 6,720 2,237 580 1,616 19,1262016 18,832 2,803(2,803)1,880 3,940 2,060 2016 8,363 4,741 2,245 558 1,880 17,7872017 18,847 3,150(3,150)1,743 3,952 2,209 2017 8,584 3,677 2,532 618 1,743 17,1542018 18,883 3,285(3,285)1,702 3,653 1,951 2018 7,958 4,090 2,606 680 1,702 17,0352019 18,945 3,279(3,279)1,840 3,784 1,944 2019 8,437 3,533 2,606 674 1,840 17,0892020 18,996 3,570(3,570)1,779 2,817 1,039 2020 7,087 3,917 2,911 659 1,779 16,3522021 19,064 3,632(3,632)1,867 2,734 867 2021 7,166 3,646 2,975 657 1,867 16,3102022 19,169 3,632(3,632)2,165 2,708 543 2022 6,942 3,770 2,975 657 2,165 16,5102023 19,280 3,927(3,927)1,939 2,740 801 2023 6,831 3,480 3,270 657 1,939 16,1772024 19,404 4,014(4,014)1,746 2,706 960 2024 5,853 3,886 3,355 659 1,746 15,4992025 19,534 4,001(4,001)1,739 2,709 970 2025 5,834 3,786 3,343 657 1,739 15,3602026 19,671 4,307(4,307)1,592 2,687 1,095 2026 5,775 3,856 3,639 668 1,592 15,5292027 19,813 4,380(4,380)1,680 2,691 1,011 2027 5,919 3,572 3,712 668 1,680 15,5502028 19,969 4,409(4,409)1,627 2,718 1,092 2028 5,836 3,919 3,725 683 1,627 15,7902029 20,127 4,985(4,985)1,532 2,810 1,278 2029 5,942 3,505 4,303 682 1,532 15,9632030 20,300 5,149(5,149)1,550 2,921 1,371 2030 5,839 3,757 4,450 699 1,550 16,2952031 20,485 4,864(4,864)2,919 2,577(343)2031 7,767 1,500 4,165 699 2,919 17,0502032 20,678 4,766(4,766)3,877 2,427(1,451)2032 8,305 638 4,065 701 3,877 17,5872033 20,875 4,750(4,750)4,089 2,424(1,664)2033 8,321 631 4,051 699 4,089 17,7902034 21,092 4,750(4,750)4,044 2,380(1,663)2034 8,532 626 4,051 699 4,044 17,9522035 21,324 4,750(4,750)4,173 2,345(1,828)2035 8,581 631 4,051 699 4,173 18,1362036 21,568 4,766(4,766)4,105 2,348(1,756)2036 8,869 632 4,065 701 4,105 18,3722037 21,821 4,750(4,750)4,394 2,355(2,039)2037 8,876 627 4,051 699 4,394 18,6472038 22,060 4,750(4,750)4,159 2,470(1,689)2038 8,657 618 4,051 699 4,159 18,1842039 22,299 4,750(4,750)4,067 2,352(1,715)2039 8,392 613 4,051 699 4,067 17,8222040 22,541 4,765(4,765)4,103 2,445(1,658)2040 8,655 617 4,064 701 4,103 18,140PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,452 11,308 15,090 69720124,084 4,904 0 4,904 20.1%2012 22,426 12,708 14,615 45520134,102 4,904 0 4,904 19.6%2013 21,342 11,867 11,886 44520144,109 4,902 0 4,902 19.3%2014 22,355 11,992 12,092 40620154,099 4,902 0 4,902 19.6%2015 19,404 11,925 11,904 53320164,094 4,698 0 4,698 14.8%2016 5,582 10,720 7,208 55220174,083 4,704 0 4,704 15.2%2017 618 10,029 5,989 55320184,079 4,704 0 4,704 15.3%2018 683 10,080 5,796 64820194,081 4,704 0 4,704 15.3%2019 596 9,805 5,966 50920204,078 4,715 0 4,715 15.6%2020 649 9,439 4,876 67020214,091 4,715 0 4,715 15.3%2021 606 9,233 4,989 60820224,105 4,715 0 4,715 14.9%2022 646 9,203 4,779 46120234,117 4,729 0 4,729 14.9%2023 582 9,088 4,893 56120244,130 4,505 233 4,738 14.7%2024 654 9,290 4,333 61020254,156 4,505 0 4,738 14.0%2025 645 9,233 3,961 52620264,179 4,515 0 4,748 13.6%2026 648 9,279 4,055 62320274,204 4,515 236 4,984 18.6%2027 600 9,132 4,047 58020284,225 4,517 0 4,986 18.0%2028 661 9,398 4,059 61020294,253 4,536 0 5,004 17.7%2029 582 9,098 4,156 63120304,284 4,538 0 5,007 16.9%2030 628 9,288 4,251 63620314,318 3,803 707 4,978 15.3%2031 211 7,731 4,774 64320324,348 3,803 0 4,978 14.5%2032 51 6,996 4,990 65720334,390 3,803 236 5,213 18.7%2033 50 6,993 5,111 65020344,427 3,803 0 5,213 17.8%2034 50 7,083 5,107 64520354,471 3,803 0 5,213 16.6%2035 51 7,156 5,283 65020364,511 3,803 0 5,213 15.6%2036 51 7,300 5,527 65120374,565 3,803 0 5,213 14.2%2037 51 7,332 5,535 64620384,611 3,803 233 5,446 18.1%2038 52 7,450 5,192 63720394,657 3,803 0 5,446 16.9%2039 53 7,521 5,081 63120404,691 3,803 0 5,446 16.1%2040 53 7,660 5,320 636Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C84Table 12: Option #2 – 25 Year Low Band ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 410,972(114,466)22,182 503,255 0(1,298) (1,298)501,957 375 502,332 0 502,332 502,332 0 501,957‐64.8135 44.042012 489,778(145,293)153,753 481,317 1,077(1,873) (796)480,521 9,801 490,323 11,111 479,211 944,491 0 479,444 264.5545 422013 436,740(264,677)122,861 578,556 1,077(2,265) (1,188)577,369 6,223 583,592 10,252 573,339 1,432,596 0 576,292 244.1065 422014 468,151(265,231)120,740 612,642 1,077(3,597) (2,520)610,122 4,173 614,295 9,834 604,461 1,907,407 0 609,045 234.1545 422015 486,768(275,087)134,802 627,052 1,077 6,843 7,920 634,973 4,281 639,254 12,993 626,261 2,361,305 0 633,896 245.5145 52.922016 546,434(289,423)124,143 711,715 81,327 59,494 140,821 852,536 2,747 855,282 3,176 852,106 2,931,139 0 771,209 47.63543 66.67922017 567,743(315,761)132,083 751,421 81,327 79,517 160,844 912,266 2,111 914,377 5,556 908,821 3,491,907 0 830,939 66.12802 84.015792018 560,091(330,595)120,245 770,441 81,327 81,471 162,798 933,239 429 933,668 7,481 926,187 4,019,203 0 851,912 70.67202 105.85992019 586,939(337,687)126,253 798,372 81,327 86,184 167,511 965,883 227 966,109 9,818 956,291 4,521,542 0 884,556 68.40002 143.53972020 529,249(356,431)70,339 815,341 86,164 84,191 170,355 985,696 0 985,696 12,098 973,597 4,993,428 0 899,532 82.78653 146.13682021 546,520(370,825)66,250 851,095 86,164 89,761 175,925 1,027,021 0 1,027,021 10,119 1,016,902 5,448,194 0 940,857 68.01853 148.76732022 558,992(361,417)56,489 863,920 86,164 94,121 180,285 1,044,206 138,777 1,182,983 7,892 1,175,090 5,933,070 0 958,042 52.11453 151.44512023 570,252(198,063)68,053 700,262 86,164 89,817 175,981 876,243 138,843 1,015,086 7,966 1,007,120 6,316,505 0 790,079 51.66857 154.17112024 571,738(207,704)59,616 719,826 133,213 99,731 232,944 952,771 143,200 1,095,971 7,596 1,088,374 6,698,835 266,781 0 1,086,339 48.40057 156.94622025 594,086(211,186)54,483 750,789 133,213 96,916 230,129 980,918 144,495 1,125,414 3,014 1,122,400 7,062,633 0 847,705 18.86457 159.77122026 599,425(238,577)58,323 779,679 133,213 98,499 231,712 1,011,392 146,736 1,158,128 547 1,157,581 7,408,822 0 878,179 3.363031 162.64712027 617,927(248,883)49,059 817,751 185,377 105,167 290,544 1,108,295 145,722 1,254,016 34,847 1,219,169 7,745,239 281,448 0 1,204,366 210.463 165.57482028 633,179(257,845)57,355 833,670 185,377 103,573 288,950 1,122,619 152,213 1,274,832 31,748 1,243,085 8,061,733 0 937,242 188.3517 168.55512029 650,117(307,236)65,897 891,456 185,377 112,367 297,744 1,189,200 148,959 1,338,159 30,059 1,308,100 8,369,029 0 1,003,823 175.1804 171.58912030 658,583(328,808)71,290 916,101 185,377 111,942 297,319 1,213,420 153,939 1,367,358 24,829 1,342,529 8,660,026 0 1,028,043 142.1446 174.67772031 668,218(319,479)21,298 966,399 245,236 92,708 337,944 1,304,343 153,295 1,457,638 12,623 1,445,016 8,949,021 302,266 0 1,361,373 70.98442 177.82192032 663,378(320,940) (4,908)989,226 245,236 68,978 314,214 1,303,440 158,578 1,462,018 6,681 1,455,338 9,217,575 0 1,058,204 36.90442 181.02272033 684,861(327,148) (24,059)1,036,069 309,361 71,836 381,197 1,417,266 157,273 1,574,539 41,407 1,533,132 9,478,610 313,245 0 1,421,150 224.6924 184.28112034 714,376(334,730) (6,401)1,055,507 309,361 74,348 383,709 1,439,216 166,128 1,605,344 34,267 1,571,077 9,725,422 0 1,129,855 182.6604 187.59822035 726,989(342,643) (22,734)1,092,365 309,361 74,903 384,264 1,476,629 168,437 1,645,066 25,338 1,619,728 9,960,203 0 1,167,268 132.6764 190.97492036 756,661(352,062) (20,449)1,129,172 306,012 74,179 380,191 1,509,363 172,837 1,682,200 16,960 1,665,240 10,182,917 0 1,203,351 87.23642 194.41252037 766,237(359,571) (53,538)1,179,346 304,935 72,248 377,183 1,556,529 171,764 1,728,293 5,124 1,723,168 10,395,560 0 1,251,594 25.89242 197.91192038 797,495(368,650) (37,542)1,203,687 381,093 78,009 459,102 1,662,789 180,561 1,843,350 42,136 1,801,214 10,600,647 342,471 0 1,624,167 209.1364 201.47432039 811,777(378,187) (76,477)1,266,442 381,093 78,396 459,489 1,725,931 176,956 1,902,887 32,176 1,870,711 10,797,178 0 1,344,838 156.8804 205.10092040 843,974(379,267) (61,561)1,284,802 381,093 154,847 535,940 1,820,742 184,963 2,005,705 24,691 1,981,014 10,989,205 0 1,439,649 118.2564 208.79272011 Net Present ValuePeriodof2011‐2040 6,490,615(3,180,214)955,877 8,714,952 1,097,012 650,6241,747,636 10,462,588661,672 11,124,261 135,056 10,989,205BaseCaseO&M2011‐20401,151,8221,151,8221,151,822UtilityCostPresentValue2011‐20402,899,458 12,276,082 12,141,027Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingNortheastern 3 DFGD 25 Year Retrofit 3/1/2016 and Northeastern 4 Retirement 2/28/2016Optimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C85Table 13: Option #2 – 25 Year Low Band BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,863 2,952 89 2011 8,455 7,274 2,123 880 2,863 21,5962012 18,688 2,906(2,906)2,740 5,756 3,016 2012 10,870 7,117 2,245 661 2,740 23,6332013 18,702 2,922(2,922)1,953 4,585 2,633 2013 7,671 6,754 2,237 685 1,953 19,2992014 18,748 2,777(2,777)2,096 4,497 2,401 2014 7,487 7,049 2,237 540 2,096 19,4092015 18,779 2,817(2,817)1,616 4,237 2,622 2015 7,973 6,720 2,237 580 1,616 19,1262016 18,832 2,803(2,803)1,880 3,940 2,060 2016 8,363 4,741 2,245 558 1,880 17,7872017 18,847 3,150(3,150)1,743 3,952 2,209 2017 8,584 3,677 2,532 618 1,743 17,1542018 18,883 3,285(3,285)1,702 3,653 1,951 2018 7,958 4,090 2,606 680 1,702 17,0352019 18,945 3,279(3,279)1,840 3,784 1,944 2019 8,437 3,533 2,606 674 1,840 17,0892020 18,996 3,570(3,570)1,779 2,817 1,039 2020 7,087 3,917 2,911 659 1,779 16,3522021 19,064 3,632(3,632)1,867 2,734 867 2021 7,166 3,646 2,975 657 1,867 16,3102022 19,169 3,632(3,632)2,165 2,708 543 2022 6,942 3,770 2,975 657 2,165 16,5102023 19,280 3,927(3,927)1,939 2,740 801 2023 6,831 3,480 3,270 657 1,939 16,1772024 19,404 4,014(4,014)1,999 2,648 649 2024 6,309 3,886 3,355 659 1,999 16,2092025 19,534 4,001(4,001)2,085 2,645 560 2025 6,512 3,788 3,343 657 2,085 16,3862026 19,671 4,307(4,307)1,984 2,619 635 2026 6,386 3,862 3,639 668 1,984 16,5392027 19,813 4,380(4,380)2,124 2,600 476 2027 6,536 3,584 3,712 668 2,124 16,6242028 19,969 4,409(4,409)2,036 2,641 605 2028 6,430 3,930 3,725 683 2,036 16,8042029 20,127 4,985(4,985)1,968 2,717 748 2029 6,582 3,514 4,303 682 1,968 17,0492030 20,300 5,149(5,149)1,997 2,796 799 2030 6,474 3,762 4,450 699 1,997 17,3822031 20,485 4,864(4,864)2,551 2,581 29 2031 7,317 3,524 4,165 699 2,551 18,2562032 20,678 4,766(4,766)2,944 2,551(394)2032 7,386 3,888 4,065 701 2,944 18,9852033 20,875 4,750(4,750)3,251 2,544(708)2033 7,658 3,527 4,051 699 3,251 19,1872034 21,092 4,750(4,750)2,994 2,538(455)2034 7,790 3,858 4,051 699 2,994 19,3922035 21,324 4,750(4,750)3,248 2,523(725)2035 7,757 3,861 4,051 699 3,248 19,6162036 21,568 4,766(4,766)3,256 2,567(689)2036 8,023 3,852 4,065 701 3,256 19,8972037 21,821 4,750(4,750)3,689 2,539(1,150)2037 8,063 3,625 4,051 699 3,689 20,1272038 22,060 4,750(4,750)3,584 2,617(967)2038 8,188 3,926 4,051 699 3,584 20,4482039 22,299 4,750(4,750)3,901 2,378(1,523)2039 8,315 3,483 4,051 699 3,901 20,4492040 22,541 4,765(4,765)3,845 2,500(1,345)2040 8,487 3,705 4,064 701 3,845 20,802PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,452 11,308 15,090 69720124,084 4,904 0 4,904 20.1%2012 22,426 12,708 14,615 45520134,102 4,904 0 4,904 19.6%2013 21,342 11,867 11,886 44520144,109 4,902 0 4,902 19.3%2014 22,355 11,992 12,092 40620154,099 4,902 0 4,902 19.6%2015 19,404 11,925 11,904 53320164,094 4,698 0 4,698 14.8%2016 5,582 10,720 7,208 55220174,083 4,704 0 4,704 15.2%2017 618 10,029 5,989 55320184,079 4,704 0 4,704 15.3%2018 683 10,080 5,796 64820194,081 4,704 0 4,704 15.3%2019 596 9,805 5,966 50920204,078 4,715 0 4,715 15.6%2020 649 9,439 4,876 67020214,091 4,715 0 4,715 15.3%2021 606 9,233 4,989 60820224,105 4,715 0 4,715 14.9%2022 646 9,203 4,779 46120234,117 4,729 0 4,729 14.9%2023 582 9,088 4,893 56120244,130 4,505 236 4,740 14.8%2024 652 9,253 4,737 60620254,156 4,505 0 4,740 14.1%2025 642 9,218 4,597 52720264,179 4,515 0 4,751 13.7%2026 646 9,238 4,644 62820274,204 4,515 236 4,986 18.6%2027 599 9,061 4,616 58320284,225 4,517 0 4,988 18.1%2028 659 9,343 4,650 61520294,253 4,536 0 5,007 17.7%2029 581 9,027 4,695 63420304,284 4,538 0 5,009 16.9%2030 625 9,206 4,795 63920314,318 4,270 236 4,976 15.2%2031 583 9,047 5,194 63020324,348 4,270 0 4,976 14.4%2032 651 9,235 5,446 63020334,390 4,270 236 5,212 18.7%2033 585 9,038 5,705 62720344,427 4,270 0 5,212 17.7%2034 646 9,421 5,777 62020354,471 4,270 0 5,212 16.6%2035 647 9,426 5,862 62620364,511 4,270 0 5,212 15.5%2036 645 9,545 6,056 63020374,565 4,270 0 5,212 14.2%2037 603 9,360 6,035 62720384,611 4,270 236 5,447 18.1%2038 660 9,710 6,094 62320394,657 4,270 0 5,447 17.0%2039 579 9,391 6,123 62320404,691 4,270 0 5,447 16.1%2040 619 9,686 6,376 628Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C86Table 14: Option #4 – Low Band ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 410,972(114,466)22,182 503,255 0 0 0 503,255 375 503,630 0 503,630 503,630 0 503,255‐64.8135 44.042012 489,778(145,293)153,753 481,317 5,107 0 5,107 486,424 9,801 496,226 11,111 485,114 951,235 0 481,317 264.5545 422013 436,740(264,677)122,861 578,556 5,107 0 5,107 583,663 6,223 589,886 10,252 579,634 1,444,699 0 578,556 244.1065 422014 468,151(265,231)120,740 612,642 5,107 8 5,115 617,757 4,173 621,930 9,834 612,096 1,925,507 0 612,650 234.1545 422015 486,768(275,087)134,802 627,052 5,107 10 5,117 632,169 4,281 636,450 12,993 623,458 2,377,374 0 627,062 245.5145 52.922016 555,482(289,938)92,888 752,532 100,456 27,617 128,073 880,605 2,531 883,137 3,117 880,020 2,965,874 692,889 0 1,473,038 46.74627 66.67922017 605,133(316,046)119,365 801,814 100,456 49,327 149,783 951,597 1,937 953,534 5,481 948,053 3,550,850 0 851,141 65.23886 84.015792018 601,430(331,211)100,926 831,715 100,456 50,193 150,649 982,364 393 982,757 7,387 975,370 4,106,147 0 881,908 69.78286 105.85992019 626,514(338,075)116,673 847,916 100,456 51,296 151,752 999,668 207 999,875 9,690 990,184 4,626,290 0 899,212 67.51086 143.53972020 562,398(357,692)50,441 869,649 105,293 51,697 156,990 1,026,639 0 1,026,639 11,968 1,014,671 5,118,083 0 921,346 81.89737 146.13682021 586,795(371,639)54,616 903,818 105,293 52,909 158,202 1,062,020 0 1,062,020 9,987 1,052,033 5,588,560 0 956,727 67.12937 148.76732022 604,899(363,945)39,197 929,647 105,293 54,008 159,301 1,088,948 106,281 1,195,229 7,758 1,187,471 6,078,545 0 983,655 51.22537 151.44512023 614,819(198,063)55,854 757,028 105,293 55,278 160,571 917,599 109,691 1,027,290 7,829 1,019,461 6,466,678 0 812,306 50.77941 154.17112024 621,549(207,705)39,757 789,497 152,342 57,899 210,241 999,738 109,819 1,109,557 7,457 1,102,100 6,853,831 266,781 0 1,114,177 47.51141 156.94622025 637,884(211,186)25,504 823,566 152,342 59,181 211,523 1,035,089 110,191 1,145,280 2,872 1,142,408 7,224,113 0 882,747 17.97541 159.77122026 648,613(238,578)33,805 853,387 152,342 60,398 212,740 1,066,127 113,003 1,179,130 402 1,178,728 7,576,627 0 913,785 2.473871 162.64712027 664,301(248,883)29,686 883,498 204,506 62,981 267,487 1,150,985 113,972 1,264,957 34,700 1,230,257 7,916,103 281,448 0 1,227,927 209.5739 165.57482028 680,657(257,845)25,343 913,159 204,506 64,663 269,169 1,182,329 116,111 1,298,440 31,598 1,266,842 8,238,646 0 977,823 187.4625 168.55512029 700,502(307,236)51,403 956,335 204,506 66,687 271,193 1,227,528 118,150 1,345,678 29,906 1,315,771 8,547,744 0 1,023,022 174.2912 171.58912030 712,641(328,808)51,826 989,622 204,506 68,557 273,063 1,262,685 120,006 1,382,692 24,674 1,358,017 8,842,099 0 1,058,179 141.2554 174.67772031 723,035(319,479)11,126 1,031,389 264,365 47,961 312,326 1,343,715 121,926 1,465,641 12,464 1,453,176 9,132,725 302,266 0 1,381,616 70.09526 177.82192032 717,220(320,940) (29,426)1,067,585 264,365 31,442 295,807 1,363,392 121,975 1,485,367 6,520 1,478,848 9,405,618 0 1,099,027 36.01526 181.02272033 735,349(327,148) (37,810)1,100,307 328,490 34,964 363,454 1,463,761 124,493 1,588,254 41,243 1,547,011 9,669,015 313,245 0 1,448,516 223.8033 184.28112034 763,660(334,730) (33,321)1,131,711 328,490 36,899 365,389 1,497,100 128,284 1,625,384 34,100 1,591,284 9,919,002 0 1,168,610 181.7713 187.59822035 779,132(342,643) (49,049)1,170,824 328,490 37,461 365,951 1,536,775 130,457 1,667,232 25,168 1,642,064 10,157,021 0 1,208,285 131.7873 190.97492036 805,611(352,062) (48,042)1,205,716 325,141 38,263 363,404 1,569,120 134,143 1,703,263 16,787 1,686,476 10,382,575 0 1,243,979 86.34726 194.41252037 818,822(359,572) (69,354)1,247,747 325,141 36,634 361,775 1,609,522 136,170 1,745,692 4,948 1,740,744 10,597,386 0 1,284,381 25.00326 197.91192038 851,049(368,650) (65,132)1,284,831 401,299 42,385 443,684 1,728,515 140,339 1,868,854 41,956 1,826,897 10,805,398 342,471 0 1,669,687 208.2473 201.47432039 859,602(378,187) (89,561)1,327,349 401,299 42,247 443,546 1,770,895 141,713 1,912,608 31,994 1,880,614 11,002,969 0 1,369,596 155.9913 205.10092040 892,996(379,267) (84,309)1,356,571 401,299 41,998 443,297 1,799,868 146,272 1,946,140 24,505 1,921,635 11,189,240 0 1,398,569 117.3673 208.79272011 Net Present ValuePeriodof2011‐2040 6,802,596(3,183,308)810,343 9,175,561 1,254,038 373,9881,628,026 10,803,587519,744 11,323,331 134,091 11,189,240BaseCaseO&M2011‐20401,151,8221,151,8221,151,822UtilityCostPresentValue2011‐20402,779,848 12,475,153 12,341,062Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingNortheastern 3 and Northeastern 4 Retirement 2/28/2016 Replaced with 2 233 MW Combined Cycle Units and 1 233 MW PPAOptimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C87Table 15: Option #4 – Low Band BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,863 2,952 89 2011 8,455 7,274 2,123 880 2,863 21,5962012 18,688 2,906(2,906)2,740 5,756 3,016 2012 10,870 7,117 2,245 661 2,740 23,6332013 18,702 2,922(2,922)1,953 4,585 2,633 2013 7,671 6,754 2,237 685 1,953 19,2992014 18,748 2,777(2,777)2,096 4,497 2,401 2014 7,487 7,049 2,237 540 2,096 19,4092015 18,779 2,817(2,817)1,616 4,237 2,622 2015 7,973 6,720 2,237 580 1,616 19,1262016 18,832 2,803(2,803)2,457 3,716 1,258 2016 8,595 2,208 2,245 558 2,457 16,0642017 18,847 3,150(3,150)2,027 3,870 1,843 2017 8,703 527 2,532 618 2,027 14,4072018 18,883 3,285(3,285)2,093 3,537 1,445 2018 8,246 625 2,606 680 2,093 14,2492019 18,945 3,279(3,279)2,111 3,763 1,652 2019 8,519 485 2,606 674 2,111 14,3952020 18,996 3,570(3,570)2,222 2,749 527 2020 7,230 663 2,911 659 2,222 13,6842021 19,064 3,632(3,632)2,139 2,694 556 2021 7,292 583 2,975 657 2,139 13,6452022 19,169 3,632(3,632)2,448 2,655 207 2022 7,246 438 2,975 657 2,448 13,7632023 19,280 3,927(3,927)2,130 2,706 576 2023 6,971 532 3,270 657 2,130 13,5602024 19,404 4,014(4,014)2,307 2,588 281 2024 6,639 584 3,355 659 2,307 13,5442025 19,534 4,001(4,001)2,501 2,549 48 2025 6,787 535 3,343 657 2,501 13,8242026 19,671 4,307(4,307)2,368 2,574 206 2026 6,707 642 3,639 668 2,368 14,0232027 19,813 4,380(4,380)2,389 2,534 145 2027 6,728 594 3,712 668 2,389 14,0902028 19,969 4,409(4,409)2,490 2,570 79 2028 6,756 626 3,725 683 2,490 14,2812029 20,127 4,985(4,985)2,161 2,668 507 2029 6,723 645 4,303 682 2,161 14,5132030 20,300 5,149(5,149)2,263 2,741 478 2030 6,717 644 4,450 699 2,263 14,7732031 20,485 4,864(4,864)2,694 2,546(149)2031 7,537 630 4,165 699 2,694 15,7252032 20,678 4,766(4,766)3,294 2,509(785)2032 7,724 633 4,065 701 3,294 16,4172033 20,875 4,750(4,750)3,460 2,533(927)2033 7,802 626 4,051 699 3,460 16,6392034 21,092 4,750(4,750)3,369 2,495(874)2034 8,066 619 4,051 699 3,369 16,8052035 21,324 4,750(4,750)3,590 2,477(1,113)2035 8,031 622 4,051 699 3,590 16,9932036 21,568 4,766(4,766)3,592 2,501(1,091)2036 8,248 625 4,065 701 3,592 17,2312037 21,821 4,750(4,750)3,888 2,505(1,383)2037 8,241 622 4,051 699 3,888 17,5002038 22,060 4,750(4,750)3,879 2,520(1,358)2038 8,515 615 4,051 699 3,879 17,7592039 22,299 4,750(4,750)4,067 2,352(1,715)2039 8,392 613 4,051 699 4,067 17,8222040 22,541 4,765(4,765)4,103 2,445(1,658)2040 8,655 617 4,064 701 4,103 18,140PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,452 11,308 15,090 69720124,084 4,904 0 4,904 20.1%2012 22,426 12,708 14,615 45520134,102 4,904 0 4,904 19.6%2013 21,342 11,867 11,886 44520144,109 4,902 0 4,902 19.3%2014 22,355 11,992 12,092 40620154,099 4,902 0 4,902 19.6%2015 19,404 11,925 11,904 53320164,094 4,232 466 4,698 14.7%2016 5,119 8,902 7,150 55020174,083 4,238 0 4,704 15.2%2017 45 7,968 4,943 54820184,079 4,238 0 4,704 15.3%2018 52 7,805 4,796 64420194,081 4,238 0 4,704 15.3%2019 42 7,830 4,949 50420204,078 4,249 0 4,715 15.6%2020 54 7,258 3,830 68120214,091 4,249 0 4,715 15.2%2021 48 7,243 3,945 60220224,105 4,249 0 4,715 14.8%2022 38 7,048 3,725 45620234,117 4,262 0 4,728 14.8%2023 45 7,180 3,817 55320244,130 4,038 236 4,739 14.8%2024 49 7,096 3,656 60420254,156 4,038 0 4,739 14.0%2025 44 7,030 3,546 54920264,179 4,048 0 4,750 13.7%2026 52 7,114 3,714 66020274,204 4,048 236 4,985 18.6%2027 49 7,086 3,574 61020284,225 4,050 0 4,987 18.0%2028 51 7,127 3,630 64420294,253 4,069 0 5,006 17.7%2029 52 7,160 3,660 66220304,284 4,071 0 5,008 16.9%2030 53 7,177 3,847 66220314,318 3,803 236 4,975 15.2%2031 52 7,195 4,210 64820324,348 3,803 0 4,975 14.4%2032 53 7,103 4,454 65220334,390 3,803 236 5,211 18.7%2033 52 7,154 4,668 64520344,427 3,803 0 5,211 17.7%2034 52 7,275 4,716 63820354,471 3,803 0 5,211 16.5%2035 52 7,301 4,826 64120364,511 3,803 0 5,211 15.5%2036 53 7,408 4,976 64420374,565 3,803 0 5,211 14.1%2037 53 7,421 4,997 64020384,611 3,803 236 5,446 18.1%2038 53 7,547 5,064 63320394,657 3,803 0 5,446 16.9%2039 53 7,521 5,081 63120404,691 3,803 0 5,446 16.1%2040 53 7,660 5,320 636Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Low Band PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C88Table 16: EPA Settlement Option – Base Case ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 411,796(114,466)22,114 504,148 0(1,001) (1,001)503,146 375 503,521 0 503,521 503,521 0 503,146‐64.8135 44.042012 479,961(200,051)148,785 531,227 1,434(1,445) (11)531,216 10,642 541,858 11,111 530,746 993,230 0 529,782 264.5545 422013 476,470(282,052)131,781 626,741 1,434(1,704) (270)626,471 7,537 634,009 10,252 623,756 1,524,257 0 625,037 244.1065 422014 526,735(283,890)146,960 663,665 1,434(2,858) (1,424)662,241 5,653 667,894 9,834 658,059 2,041,170 0 660,807 234.1545 422015 542,998(294,209)150,856 686,351 1,434 16,400 17,834 704,185 5,731 709,916 12,993 696,924 2,546,283 0 702,751 245.5145 52.922016 608,885(310,040)137,614 781,311 65,106 57,198 122,304 903,614 4,140 907,754 2,679 905,075 3,151,538 0 838,508 40.18475 66.67922017 627,848(336,257)148,522 815,583 65,106 82,318 147,424 963,007 3,147 966,154 4,930 961,224 3,744,641 0 897,901 58.67733 84.015792018 620,458(352,341)119,272 853,527 65,106 82,502 147,608 1,001,135 1,186 1,002,321 6,693 995,628 4,311,472 0 936,029 63.22133 105.85992019 644,928(359,145)138,441 865,633 65,106 88,830 153,936 1,019,569 443 1,020,012 8,749 1,011,263 4,842,687 0 954,463 60.94933 143.53972020 571,864(376,610)59,750 888,724 69,943 84,945 154,888 1,043,611 0 1,043,611 11,009 1,032,602 5,343,172 0 973,668 75.33585 146.13682021 599,397(392,003)45,913 945,487 69,943 89,368 159,311 1,104,797 0 1,104,797 9,011 1,095,787 5,833,216 0 1,034,854 60.56785 148.76732022 612,965(383,558)19,947 976,576 69,943 93,902 163,845 1,140,421 129,511 1,269,932 6,764 1,263,168 6,354,435 0 1,070,478 44.66385 151.44512023 623,939(198,063)30,192 791,809 68,509 88,548 157,057 948,867 130,106 1,078,972 6,817 1,072,155 6,762,630 0 880,358 44.21788 154.17112024 632,485(207,704)15,399 824,790 115,558 90,781 206,339 1,031,128 131,060 1,162,189 6,427 1,155,762 7,168,633 266,781 0 1,182,351 40.94988 156.94622025 664,024(211,186)555 874,654 115,558 89,029 204,587 1,079,241 129,106 1,208,347 1,824 1,206,523 7,559,697 0 963,683 11.41388 159.77122026 659,635(238,576) (766)898,976 165,958 113,619 279,577 1,178,553 130,393 1,308,946 37,639 1,271,308 7,939,898 276,471 0 1,289,067 231.4123 162.64712027 715,760(248,883) (39,075)1,003,719 230,390 49,973 280,363 1,284,082 110,363 1,394,445 35,068 1,359,377 8,315,004 703,008 0 1,756,700 211.7936 165.57482028 736,281(257,845) (32,193)1,026,318 230,390 56,236 286,626 1,312,944 112,791 1,425,735 31,972 1,393,763 8,669,861 0 1,082,554 189.6822 168.55512029 759,350(307,236) (6,329)1,072,915 230,390 57,177 287,567 1,360,482 114,925 1,475,408 30,287 1,445,120 9,009,345 0 1,130,092 176.5109 171.58912030 767,822(328,808) (10,605)1,107,234 230,390 59,427 289,817 1,397,051 116,259 1,513,310 25,062 1,488,248 9,331,928 0 1,166,661 143.4751 174.67772031 799,287(319,480) (22,701)1,141,468 306,448 42,244 348,692 1,490,160 119,981 1,610,141 12,464 1,597,676 9,651,454 452,742 0 1,636,453 70.09526 177.82192032 797,205(320,940) (53,273)1,171,418 306,448 28,691 335,139 1,506,557 120,524 1,627,082 6,520 1,620,562 9,950,497 0 1,200,109 36.01526 181.02272033 817,217(327,148) (61,882)1,206,246 370,573 32,244 402,817 1,609,063 123,045 1,732,108 41,243 1,690,866 10,238,388 313,245 0 1,551,736 223.8033 184.28112034 849,111(334,730) (58,373)1,242,213 370,573 34,173 404,746 1,646,959 126,670 1,773,629 34,100 1,739,529 10,511,663 0 1,276,386 181.7713 187.59822035 864,459(342,643) (77,478)1,284,579 370,573 34,758 405,331 1,689,911 128,662 1,818,573 25,168 1,793,405 10,771,619 0 1,319,338 131.7873 190.97492036 892,396(352,062) (78,086)1,322,545 367,224 36,267 403,491 1,726,037 132,124 1,858,161 16,787 1,841,374 11,017,890 0 1,358,813 86.34726 194.41252037 912,914(359,572) (94,144)1,366,630 367,224 34,718 401,942 1,768,572 134,767 1,903,339 4,948 1,898,390 11,252,155 0 1,401,348 25.00326 197.91192038 952,697(368,650) (87,455)1,408,802 443,382 40,339 483,721 1,892,524 139,264 2,031,788 41,956 1,989,832 11,478,718 342,471 0 1,791,613 208.2473 201.47432039 959,509(378,187) (120,023)1,457,719 443,382 40,460 483,842 1,941,561 140,275 2,081,836 31,994 2,049,842 11,694,068 0 1,498,179 155.9913 205.10092040 996,482(379,267) (115,099)1,490,848 443,382 40,285 483,667 1,974,514 144,730 2,119,244 24,505 2,094,739 11,897,119 0 1,531,132 117.3673 208.79272011 Net Present ValuePeriodof2011‐2040 7,197,033(3,352,520)771,377 9,778,175 1,161,118 542,7961,703,914 11,482,089556,706 12,038,794 141,676 11,897,119BaseCaseO&M2011‐20401,159,6561,159,6561,159,656UtilityCostPresentValue2011‐20402,863,570 13,198,451 13,056,775Northeastern 4 Retired 2/28/2016 and Northeastern 3 DSI+ACI+BH Retrofit 7/1/2015 with 2021-2026 Declining Capacity Factor and 12/31/2026 RetirementOptimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C89Table 17: EPA Settlement Option – Base Case BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,872 2,958 86 2011 8,454 7,272 2,123 880 2,872 21,6022012 18,688 2,906(2,906)2,570 5,365 2,795 2012 9,302 7,098 2,245 661 2,570 21,8762013 18,702 2,922(2,922)1,990 4,506 2,516 2013 7,510 6,792 2,237 685 1,990 19,2132014 18,748 2,777(2,777)1,948 4,533 2,585 2014 7,590 7,113 2,237 540 1,948 19,4272015 18,779 2,817(2,817)1,570 4,187 2,618 2015 7,945 6,732 2,237 580 1,570 19,0642016 18,832 2,803(2,803)1,865 3,874 2,010 2016 8,248 4,817 2,245 558 1,865 17,7342017 18,847 3,150(3,150)1,631 3,869 2,238 2017 8,327 3,949 2,532 618 1,631 17,0572018 18,883 3,285(3,285)1,834 3,492 1,658 2018 7,948 3,795 2,606 680 1,834 16,8632019 18,945 3,279(3,279)1,762 3,698 1,936 2019 8,059 3,924 2,606 674 1,762 17,0252020 18,996 3,570(3,570)2,041 2,763 722 2020 6,722 4,054 2,911 659 2,041 16,3862021 19,064 3,632(3,632)2,279 2,674 395 2021 7,010 3,379 2,975 657 2,279 16,3002022 19,169 3,632(3,632)2,695 2,612(83)2022 6,854 3,245 2,975 657 2,695 16,4262023 19,280 3,927(3,927)2,456 2,622 166 2023 6,727 2,963 3,270 657 2,456 16,0732024 19,404 4,014(4,014)2,615 2,534(82)2024 6,450 3,020 3,355 659 2,615 16,1002025 19,534 4,001(4,001)2,789 2,489(299)2025 6,848 2,573 3,343 657 2,789 16,2102026 19,671 4,307(4,307)2,752 2,449(302)2026 6,619 2,672 3,639 668 2,752 16,3482027 19,813 4,380(4,380)3,298 2,404(894)2027 7,318 616 3,712 668 3,298 15,6122028 19,969 4,409(4,409)3,222 2,460(761)2028 7,107 657 3,725 683 3,222 15,3942029 20,127 4,985(4,985)2,888 2,541(347)2029 7,072 676 4,303 682 2,888 15,6212030 20,300 5,149(5,149)2,991 2,558(434)2030 7,034 675 4,450 699 2,991 15,8502031 20,485 4,864(4,864)3,044 2,447(597)2031 7,545 664 4,165 699 3,044 16,1162032 20,678 4,766(4,766)3,457 2,427(1,031)2032 7,499 668 4,065 701 3,457 16,3902033 20,875 4,750(4,750)3,595 2,428(1,167)2033 7,574 663 4,051 699 3,595 16,5822034 21,092 4,750(4,750)3,543 2,417(1,126)2034 7,823 653 4,051 699 3,543 16,7692035 21,324 4,750(4,750)3,807 2,422(1,385)2035 7,769 655 4,051 699 3,807 16,9812036 21,568 4,766(4,766)3,815 2,433(1,382)2036 7,964 656 4,065 701 3,815 17,2012037 21,821 4,750(4,750)4,027 2,428(1,598)2037 8,026 654 4,051 699 4,027 17,4572038 22,060 4,750(4,750)4,026 2,490(1,536)2038 8,338 645 4,051 699 4,026 17,7592039 22,299 4,750(4,750)4,277 2,359(1,917)2039 8,169 642 4,051 699 4,277 17,8382040 22,541 4,765(4,765)4,235 2,374(1,861)2040 8,437 642 4,064 701 4,235 18,078PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,445 11,306 15,086 69720124,084 4,904 0 4,904 20.1%2012 22,371 12,380 13,391 45120134,102 4,904 0 4,904 19.6%2013 21,457 11,825 11,790 44620144,109 4,902 0 4,902 19.3%2014 22,560 12,107 12,213 40420154,099 4,902 0 4,902 19.6%2015 19,495 11,923 11,909 50020164,094 4,691 0 4,691 14.6%2016 10,331 10,619 8,130 52020174,083 4,697 0 4,697 15.0%2017 6,846 10,029 7,189 52120184,079 4,697 0 4,697 15.1%2018 6,327 9,662 6,954 63120194,081 4,697 0 4,697 15.1%2019 6,856 9,849 7,177 48620204,078 4,708 0 4,708 15.4%2020 6,846 9,223 6,025 62920214,091 4,708 0 4,708 15.1%2021 5,741 8,825 5,926 55920224,105 4,708 0 4,708 14.7%2022 5,642 8,589 5,618 47420234,117 4,721 0 4,721 14.7%2023 4,982 8,516 5,577 57020244,130 4,497 236 4,733 14.6%2024 5,000 8,469 5,584 62120254,156 4,497 0 4,733 13.9%2025 4,265 8,236 5,345 56620264,179 4,508 236 4,979 19.1%2026 4,255 8,209 5,307 67820274,204 4,048 469 4,988 18.6%2027 46 6,862 4,228 63220284,225 4,050 0 4,989 18.1%2028 50 6,923 3,967 67420294,253 4,068 0 5,008 17.8%2029 52 6,965 4,101 69420304,284 4,071 0 5,010 16.9%2030 52 6,952 4,190 69320314,318 3,803 233 4,975 15.2%2031 53 7,081 4,337 68220324,348 3,803 0 4,975 14.4%2032 55 7,019 4,319 68520334,390 3,803 236 5,211 18.7%2033 55 7,071 4,514 68120344,427 3,803 0 5,211 17.7%2034 54 7,183 4,558 67020354,471 3,803 0 5,211 16.5%2035 55 7,200 4,656 67320364,511 3,803 0 5,211 15.5%2036 55 7,296 4,775 67420374,565 3,803 0 5,211 14.1%2037 55 7,344 4,839 67220384,611 3,803 236 5,446 18.1%2038 55 7,489 4,948 66420394,657 3,803 0 5,446 16.9%2039 55 7,444 4,933 66020404,691 3,803 0 5,446 16.1%2040 55 7,579 5,142 660Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C90Table 18: Option#1 – 15 Year Base Case ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 411,796(114,466)22,114 504,148 0(1,144) (1,144)503,003 375 503,378 0 503,378 503,378 0 503,003‐64.8135 44.042012 479,961(200,051)148,785 531,227 0(1,652) (1,652)529,576 10,642 540,217 11,111 529,106 991,574 0 529,576 264.5545 422013 476,469(282,052)131,781 626,741 0(1,882) (1,882)624,858 7,537 632,396 10,252 622,143 1,521,227 0 624,858 244.1065 422014 526,735(283,890)146,960 663,665 0(1,746) (1,746)661,919 5,653 667,572 9,834 657,737 2,037,888 0 661,919 234.1545 422015 542,998(294,209)150,856 686,351 0 14,337 14,337 700,688 5,731 706,419 12,993 693,427 2,540,466 0 700,688 245.5145 52.922016 589,736(308,555)170,127 728,164 175,176 67,061 242,237 970,401 3,828 974,229 17,608 956,621 3,180,192 0 795,225 264.0729 66.67922017 595,830(334,241)183,223 746,848 175,176 100,034 275,210 1,022,058 2,942 1,024,999 23,740 1,001,259 3,797,998 0 846,882 282.5655 84.015792018 577,525(349,680)159,509 767,696 175,176 94,236 269,412 1,037,107 1,115 1,038,223 30,393 1,007,829 4,371,775 0 861,931 287.1095 105.85992019 608,466(356,561)170,542 794,485 175,176 99,812 274,988 1,069,472 422 1,069,895 40,885 1,029,009 4,912,312 0 894,296 284.8375 143.53972020 545,710(372,862)103,823 814,749 180,013 100,151 280,164 1,094,913 0 1,094,913 43,728 1,051,185 5,421,804 0 914,900 299.224 146.13682021 562,613(387,948)98,953 851,608 180,013 103,479 283,492 1,135,099 0 1,135,099 42,318 1,092,782 5,910,503 0 955,086 284.456 148.76732022 565,104(378,011)72,931 870,184 180,013 112,012 292,025 1,162,208 168,315 1,330,524 40,671 1,289,853 6,442,734 0 982,195 268.552 151.44512023 574,145(198,062)90,639 681,568 180,013 103,170 283,183 964,752 168,613 1,133,365 41,334 1,092,030 6,858,496 0 784,739 268.1061 154.17112024 580,302(207,706)90,698 697,310 180,013 111,916 291,929 989,239 174,291 1,163,531 4,604 1,158,926 7,265,611 0 809,226 29.33807 156.94622025 607,305(211,185)91,941 726,549 228,709 111,126 339,835 1,066,384 176,448 1,242,832 37,595 1,205,238 7,656,258 271,583 0 1,109,258 235.3021 159.77122026 611,278(238,576)94,142 755,712 228,709 111,824 340,533 1,096,245 178,338 1,274,583 35,750 1,238,833 8,026,747 0 867,536 219.8005 162.64712027 635,677(248,884)80,794 803,767 228,709 116,102 344,811 1,148,578 175,715 1,324,292 31,691 1,292,601 8,383,427 0 919,869 191.4005 165.57482028 652,850(257,846)99,940 810,756 228,709 119,203 347,912 1,158,667 185,492 1,344,159 28,535 1,315,624 8,718,389 0 929,958 169.2892 168.55512029 668,236(307,236)102,493 872,979 228,709 121,738 350,447 1,223,426 180,341 1,403,767 26,788 1,376,979 9,041,866 0 994,717 156.1179 171.58912030 686,665(328,808)127,356 888,117 228,709 116,368 345,077 1,233,195 189,974 1,423,169 21,500 1,401,669 9,345,683 0 1,004,486 123.0821 174.67772031 770,761(319,480) (3,155)1,093,396 335,027 221,940 556,967 1,650,363 136,670 1,787,033 12,464 1,774,568 9,700,586 1,510,015 0 2,825,351 70.09526 177.82192032 797,205(320,940) (53,273)1,171,418 335,027 28,691 363,718 1,535,136 120,524 1,655,661 6,520 1,649,141 10,004,902 0 1,200,109 36.01526 181.02272033 817,217(327,148) (61,882)1,206,246 399,152 32,244 431,396 1,637,642 123,045 1,760,687 41,243 1,719,445 10,297,659 313,245 0 1,551,736 223.8033 184.28112034 849,111(334,730) (58,373)1,242,213 399,152 34,173 433,325 1,675,538 126,670 1,802,208 34,100 1,768,108 10,575,425 0 1,276,386 181.7713 187.59822035 864,459(342,643) (77,478)1,284,579 399,152 34,758 433,910 1,718,490 128,662 1,847,152 25,168 1,821,984 10,839,523 0 1,319,338 131.7873 190.97492036 892,396(352,062) (78,086)1,322,545 395,803 36,267 432,070 1,754,616 132,124 1,886,740 16,787 1,869,953 11,089,616 0 1,358,813 86.34726 194.41252037 912,914(359,572) (94,144)1,366,630 395,803 34,718 430,521 1,797,151 134,767 1,931,918 4,948 1,926,969 11,327,408 0 1,401,348 25.00326 197.91192038 952,697(368,650) (87,455)1,408,802 471,961 40,339 512,300 1,921,103 139,264 2,060,367 41,956 2,018,411 11,557,225 342,471 0 1,791,613 208.2473 201.47432039 959,509(378,187) (120,023)1,457,719 471,961 40,460 512,421 1,970,140 140,275 2,110,415 31,994 2,078,421 11,775,577 0 1,498,179 155.9913 205.10092040 996,482(379,267) (115,099)1,490,848 471,961 40,285 512,246 2,003,093 144,730 2,147,823 24,505 2,123,318 11,981,398 0 1,531,132 117.3673 208.79272011 Net Present ValuePeriodof2011‐2040 6,913,825(3,341,493)1,154,810 9,100,507 1,726,156 710,1612,436,317 11,536,824703,088 12,239,912 258,514 11,981,398BaseCaseO&M2011‐20401,159,6561,159,6561,159,656UtilityCostPresentValue2011‐20403,595,973 13,399,568 13,141,054Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingNortheastern 3 and Northeastern 4 DFGD 15 Year Retrofit 3/1/2016 and 2/28/2031 RetirementOptimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C91Table 19: Option#1 – 15 Year Base Case BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,872 2,958 86 2011 8,454 7,272 2,123 880 2,872 21,6022012 18,688 2,906(2,906)2,570 5,365 2,795 2012 9,302 7,098 2,245 661 2,570 21,8762013 18,702 2,922(2,922)1,990 4,506 2,516 2013 7,510 6,792 2,237 685 1,990 19,2132014 18,748 2,777(2,777)1,948 4,533 2,585 2014 7,590 7,113 2,237 540 1,948 19,4272015 18,779 2,817(2,817)1,570 4,187 2,618 2015 7,945 6,732 2,237 580 1,570 19,0642016 18,832 2,803(2,803)1,335 4,092 2,757 2016 7,559 7,327 2,245 558 1,335 19,0242017 18,847 3,150(3,150)1,085 4,131 3,046 2017 7,791 7,076 2,532 618 1,085 19,1022018 18,883 3,285(3,285)1,177 3,727 2,550 2018 7,061 7,228 2,606 680 1,177 18,7512019 18,945 3,279(3,279)1,281 3,930 2,649 2019 7,520 6,928 2,606 674 1,281 19,0092020 18,996 3,570(3,570)1,249 2,930 1,681 2020 6,138 7,229 2,911 659 1,249 18,1852021 19,064 3,632(3,632)1,376 2,875 1,499 2021 6,215 6,958 2,975 657 1,376 18,1812022 19,169 3,632(3,632)1,968 2,766 798 2022 5,814 6,833 2,975 657 1,968 18,2472023 19,280 3,927(3,927)1,659 2,800 1,141 2023 5,784 6,475 3,270 657 1,659 17,8452024 19,404 4,014(4,014)1,631 2,748 1,117 2024 5,379 6,880 3,355 659 1,631 17,9052025 19,534 4,001(4,001)1,641 2,754 1,112 2025 5,627 6,786 3,343 657 1,641 18,0552026 19,671 4,307(4,307)1,546 2,706 1,160 2026 5,485 6,810 3,639 668 1,546 18,1482027 19,813 4,380(4,380)1,770 2,688 918 2027 5,776 6,341 3,712 668 1,770 18,2662028 19,969 4,409(4,409)1,553 2,759 1,206 2028 5,619 6,895 3,725 683 1,553 18,4762029 20,127 4,985(4,985)1,579 2,796 1,217 2029 5,795 6,329 4,303 682 1,579 18,6882030 20,300 5,149(5,149)1,445 2,992 1,547 2030 5,646 6,819 4,450 699 1,445 19,0592031 20,485 4,864(4,864)2,859 2,554(306)2031 7,415 2,092 4,165 699 2,859 17,2312032 20,678 4,766(4,766)3,457 2,427(1,031)2032 7,499 668 4,065 701 3,457 16,3902033 20,875 4,750(4,750)3,595 2,428(1,167)2033 7,574 663 4,051 699 3,595 16,5822034 21,092 4,750(4,750)3,543 2,417(1,126)2034 7,823 653 4,051 699 3,543 16,7692035 21,324 4,750(4,750)3,807 2,422(1,385)2035 7,769 655 4,051 699 3,807 16,9812036 21,568 4,766(4,766)3,815 2,433(1,382)2036 7,964 656 4,065 701 3,815 17,2012037 21,821 4,750(4,750)4,027 2,428(1,598)2037 8,026 654 4,051 699 4,027 17,4572038 22,060 4,750(4,750)4,026 2,490(1,536)2038 8,338 645 4,051 699 4,026 17,7592039 22,299 4,750(4,750)4,277 2,359(1,917)2039 8,169 642 4,051 699 4,277 17,8382040 22,541 4,765(4,765)4,235 2,374(1,861)2040 8,437 642 4,064 701 4,235 18,078PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,445 11,306 15,086 69720124,084 4,904 0 4,904 20.1%2012 22,371 12,380 13,391 45120134,102 4,904 0 4,904 19.6%2013 21,457 11,825 11,790 44620144,109 4,902 0 4,902 19.3%2014 22,560 12,107 12,213 40420154,099 4,902 0 4,902 19.6%2015 19,495 11,923 11,909 50020164,094 4,915 0 4,915 20.1%2016 6,092 12,530 7,380 53520174,083 4,921 0 4,921 20.5%2017 1,278 12,436 6,589 52720184,079 4,921 0 4,921 20.6%2018 1,292 12,208 6,214 62320194,081 4,921 0 4,921 20.6%2019 1,254 12,147 6,465 49320204,078 4,932 0 4,932 20.9%2020 1,296 11,712 5,349 61420214,091 4,932 0 4,932 20.6%2021 1,252 11,508 5,433 56220224,105 4,932 0 4,932 20.1%2022 1,240 11,162 5,063 46420234,117 4,945 0 4,945 20.1%2023 1,165 11,036 5,176 55220244,130 4,721 0 4,721 14.3%2024 1,235 11,262 5,135 58920254,156 4,721 236 4,957 19.3%2025 1,226 11,257 5,032 50920264,179 4,732 0 4,967 18.9%2026 1,220 11,228 5,102 60920274,204 4,732 0 4,967 18.2%2027 1,135 10,925 5,150 57020284,225 4,733 0 4,969 17.6%2028 1,237 11,385 5,161 59420294,253 4,752 0 4,988 17.3%2029 1,127 10,929 5,225 62220304,284 4,754 0 4,990 16.5%2030 1,220 11,361 5,408 62320314,318 3,803 937 4,975 15.2%2031 324 8,066 4,775 65920324,348 3,803 0 4,975 14.4%2032 55 7,019 4,319 68520334,390 3,803 236 5,211 18.7%2033 55 7,071 4,514 68120344,427 3,803 0 5,211 17.7%2034 54 7,183 4,558 67020354,471 3,803 0 5,211 16.5%2035 55 7,200 4,656 67320364,511 3,803 0 5,211 15.5%2036 55 7,296 4,775 67420374,565 3,803 0 5,211 14.1%2037 55 7,344 4,839 67220384,611 3,803 236 5,446 18.1%2038 55 7,489 4,948 66420394,657 3,803 0 5,446 16.9%2039 55 7,444 4,933 66020404,691 3,803 0 5,446 16.1%2040 55 7,579 5,142 660Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C92Table 20: Option#1 – 25 Year Base Case ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 411,796(114,466)22,114 504,148 0(1,298) (1,298)502,850 375 503,225 0 503,225 503,225 0 502,850‐64.8135 44.042012 479,961(200,051)148,785 531,227 0(1,873) (1,873)529,354 10,642 539,996 11,111 528,885 991,216 0 529,354 264.5545 422013 476,469(282,052)131,781 626,741 0(2,186) (2,186)624,554 7,537 632,092 10,252 621,839 1,520,611 0 624,554 244.1065 422014 526,735(283,890)146,960 663,665 0(2,186) (2,186)661,479 5,653 667,132 9,834 657,297 2,036,925 0 661,479 234.1545 422015 542,998(294,209)150,856 686,351 0 13,542 13,542 699,893 5,731 705,624 12,993 692,631 2,538,927 0 699,893 245.5145 52.922016 589,736(308,555)170,127 728,164 150,933 63,474 214,407 942,572 3,828 946,400 17,608 928,791 3,160,043 0 791,639 264.0729 66.67922017 595,830(334,241)183,223 746,848 150,933 94,089 245,022 991,870 2,942 994,812 23,740 971,072 3,759,222 0 840,937 282.5655 84.015792018 577,525(349,680)159,509 767,696 150,933 87,922 238,855 1,006,551 1,115 1,007,666 30,393 977,273 4,315,602 0 855,618 287.1095 105.85992019 608,466(356,561)170,542 794,485 150,933 93,326 244,259 1,038,744 422 1,039,166 40,885 998,281 4,839,998 0 887,811 284.8375 143.53972020 545,710(372,862)103,823 814,749 155,770 93,610 249,380 1,064,129 0 1,064,129 43,728 1,020,401 5,334,569 0 908,359 299.224 146.13682021 562,613(387,948)98,953 851,608 155,770 96,644 252,414 1,104,022 0 1,104,022 42,318 1,061,704 5,809,371 0 948,252 284.456 148.76732022 565,104(378,011)72,931 870,184 155,770 104,707 260,477 1,130,661 168,315 1,298,977 40,671 1,258,306 6,328,584 0 974,891 268.552 151.44512023 574,145(198,062)90,639 681,568 155,770 95,649 251,419 932,987 168,613 1,101,600 41,334 1,060,266 6,732,252 0 777,217 268.1061 154.17112024 580,302(207,706)90,698 697,310 155,770 104,039 259,809 957,120 174,291 1,131,411 4,604 1,126,806 7,128,084 0 801,350 29.33807 156.94622025 607,305(211,185)91,941 726,549 204,466 103,009 307,475 1,034,024 176,448 1,210,472 37,595 1,172,877 7,508,242 271,583 0 1,101,140 235.3021 159.77122026 611,278(238,576)94,142 755,712 204,466 104,540 309,006 1,064,718 178,338 1,243,056 35,750 1,207,306 7,869,303 0 860,252 219.8005 162.64712027 635,677(248,884)80,794 803,767 204,466 108,981 313,447 1,117,214 175,715 1,292,929 31,691 1,261,238 8,217,328 0 912,748 191.4005 165.57482028 652,850(257,846)99,940 810,756 204,466 112,351 316,817 1,127,573 185,492 1,313,064 28,535 1,284,530 8,544,374 0 923,107 169.2892 168.55512029 668,236(307,236)102,493 872,979 204,466 115,466 319,932 1,192,911 180,341 1,373,252 26,788 1,346,464 8,860,682 0 988,445 156.1179 171.58912030 686,665(328,808)127,356 888,117 204,466 115,843 320,309 1,208,427 189,974 1,398,400 21,500 1,376,901 9,159,130 0 1,003,961 123.0821 174.67772031 716,460(319,479)105,104 930,836 204,466 118,664 323,130 1,253,965 191,098 1,445,064 13,589 1,431,474 9,445,416 0 1,049,499 76.42192 177.82192032 732,190(320,940)104,042 949,088 204,466 107,146 311,612 1,260,699 198,827 1,459,526 7,665 1,451,861 9,713,329 0 1,056,233 42.34192 181.02272033 755,840(327,148)85,675 997,314 268,591 109,465 378,056 1,375,370 198,274 1,573,644 42,409 1,531,235 9,974,040 313,245 0 1,420,024 230.1299 184.28112034 782,716(334,730)98,255 1,019,191 268,591 111,919 380,510 1,399,701 206,322 1,606,023 35,287 1,570,736 10,220,799 0 1,131,110 188.0979 187.59822035 798,441(342,643)73,590 1,067,494 268,591 111,628 380,219 1,447,713 206,293 1,654,006 26,376 1,627,629 10,456,725 0 1,179,122 138.1139 190.97492036 836,753(352,063)92,743 1,096,072 265,242 112,076 377,318 1,473,390 215,112 1,688,503 18,017 1,670,486 10,680,141 0 1,208,148 92.67392 194.41252037 850,270(359,572)64,557 1,145,285 265,242 109,707 374,949 1,520,234 214,861 1,735,095 6,201 1,728,894 10,893,490 0 1,254,992 31.32992 197.91192038 886,804(368,650)83,944 1,171,510 341,400 114,570 455,970 1,627,480 224,426 1,851,906 43,231 1,808,675 11,099,427 342,471 0 1,628,551 214.5739 201.47432039 883,783(378,187)24,905 1,237,065 341,400 112,478 453,878 1,690,943 218,966 1,909,909 33,292 1,876,618 11,296,578 0 1,349,543 162.3179 205.10092040 929,955(379,267)50,758 1,258,464 341,400 253,173 594,573 1,853,037 228,603 2,081,640 25,826 2,055,813 11,495,856 0 1,511,637 123.6939 208.79272011 Net Present ValuePeriodof2011‐2040 6,823,439(3,341,493)1,370,367 8,794,564 1,392,507 756,9502,149,457 10,944,022812,073 11,756,095 260,239 11,495,856BaseCaseO&M2011‐20401,159,6561,159,6561,159,656UtilityCostPresentValue2011‐20403,309,114 12,915,751 12,655,512Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingNortheastern 3 and Northeastern 4 DFGD 25 Year Retrofit 3/1/2016Optimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C93Table 21: Option#1 – 25 Year Base Case BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,872 2,958 86 2011 8,454 7,272 2,123 880 2,872 21,6022012 18,688 2,906(2,906)2,570 5,365 2,795 2012 9,302 7,098 2,245 661 2,570 21,8762013 18,702 2,922(2,922)1,990 4,506 2,516 2013 7,510 6,792 2,237 685 1,990 19,2132014 18,748 2,777(2,777)1,948 4,533 2,585 2014 7,590 7,113 2,237 540 1,948 19,4272015 18,779 2,817(2,817)1,570 4,187 2,618 2015 7,945 6,732 2,237 580 1,570 19,0642016 18,832 2,803(2,803)1,335 4,092 2,757 2016 7,559 7,327 2,245 558 1,335 19,0242017 18,847 3,150(3,150)1,085 4,131 3,046 2017 7,791 7,076 2,532 618 1,085 19,1022018 18,883 3,285(3,285)1,177 3,727 2,550 2018 7,061 7,228 2,606 680 1,177 18,7512019 18,945 3,279(3,279)1,281 3,930 2,649 2019 7,520 6,928 2,606 674 1,281 19,0092020 18,996 3,570(3,570)1,249 2,930 1,681 2020 6,138 7,229 2,911 659 1,249 18,1852021 19,064 3,632(3,632)1,376 2,875 1,499 2021 6,215 6,958 2,975 657 1,376 18,1812022 19,169 3,632(3,632)1,968 2,766 798 2022 5,814 6,833 2,975 657 1,968 18,2472023 19,280 3,927(3,927)1,659 2,800 1,141 2023 5,784 6,475 3,270 657 1,659 17,8452024 19,404 4,014(4,014)1,631 2,748 1,117 2024 5,379 6,880 3,355 659 1,631 17,9052025 19,534 4,001(4,001)1,641 2,754 1,112 2025 5,627 6,786 3,343 657 1,641 18,0552026 19,671 4,307(4,307)1,546 2,706 1,160 2026 5,485 6,810 3,639 668 1,546 18,1482027 19,813 4,380(4,380)1,770 2,688 918 2027 5,776 6,341 3,712 668 1,770 18,2662028 19,969 4,409(4,409)1,553 2,759 1,206 2028 5,619 6,895 3,725 683 1,553 18,4762029 20,127 4,985(4,985)1,579 2,796 1,217 2029 5,795 6,329 4,303 682 1,579 18,6882030 20,300 5,149(5,149)1,445 2,992 1,547 2030 5,646 6,819 4,450 699 1,445 19,0592031 20,485 4,864(4,864)1,550 2,762 1,213 2031 6,044 6,561 4,165 699 1,550 19,0182032 20,678 4,766(4,766)1,637 2,802 1,165 2032 5,913 6,922 4,065 701 1,637 19,2372033 20,875 4,750(4,750)1,893 2,751 859 2033 6,163 6,589 4,051 699 1,893 19,3952034 21,092 4,750(4,750)1,770 2,770 999 2034 6,221 6,881 4,051 699 1,770 19,6232035 21,324 4,750(4,750)2,149 2,772 622 2035 6,285 6,678 4,051 699 2,149 19,8632036 21,568 4,766(4,766)2,054 2,898 844 2036 6,502 6,907 4,065 701 2,054 20,2302037 21,821 4,750(4,750)2,428 2,861 433 2037 6,586 6,683 4,051 699 2,428 20,4482038 22,060 4,750(4,750)2,319 2,954 635 2038 6,728 6,986 4,051 699 2,319 20,7832039 22,299 4,750(4,750)2,871 2,752(119)2039 6,672 6,529 4,051 699 2,871 20,8212040 22,541 4,765(4,765)2,697 2,849 152 2040 6,933 6,754 4,064 701 2,697 21,148PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,445 11,306 15,086 69720124,084 4,904 0 4,904 20.1%2012 22,371 12,380 13,391 45120134,102 4,904 0 4,904 19.6%2013 21,457 11,825 11,790 44620144,109 4,902 0 4,902 19.3%2014 22,560 12,107 12,213 40420154,099 4,902 0 4,902 19.6%2015 19,495 11,923 11,909 50020164,094 4,915 0 4,915 20.1%2016 6,092 12,530 7,380 53520174,083 4,921 0 4,921 20.5%2017 1,278 12,436 6,589 52720184,079 4,921 0 4,921 20.6%2018 1,292 12,208 6,214 62320194,081 4,921 0 4,921 20.6%2019 1,254 12,147 6,465 49320204,078 4,932 0 4,932 20.9%2020 1,296 11,712 5,349 61420214,091 4,932 0 4,932 20.6%2021 1,252 11,508 5,433 56220224,105 4,932 0 4,932 20.1%2022 1,240 11,162 5,063 46420234,117 4,945 0 4,945 20.1%2023 1,165 11,036 5,176 55220244,130 4,721 0 4,721 14.3%2024 1,235 11,262 5,135 58920254,156 4,721 236 4,957 19.3%2025 1,226 11,257 5,032 50920264,179 4,732 0 4,967 18.9%2026 1,220 11,228 5,102 60920274,204 4,732 0 4,967 18.2%2027 1,135 10,925 5,150 57020284,225 4,733 0 4,969 17.6%2028 1,237 11,385 5,161 59420294,253 4,752 0 4,988 17.3%2029 1,127 10,929 5,225 62220304,284 4,754 0 4,990 16.5%2030 1,220 11,361 5,408 62320314,318 4,746 0 4,982 15.4%2031 1,173 11,278 5,378 61320324,348 4,746 0 4,982 14.6%2032 1,239 11,579 5,410 61520334,390 4,746 236 5,217 18.8%2033 1,178 11,394 5,666 61720344,427 4,746 0 5,217 17.8%2034 1,233 11,700 5,605 61020354,471 4,746 0 5,217 16.7%2035 1,192 11,545 5,693 61720364,511 4,746 0 5,217 15.7%2036 1,237 11,879 5,964 61920374,565 4,746 0 5,217 14.3%2037 1,196 11,709 5,899 61820384,611 4,746 236 5,453 18.3%2038 1,253 12,069 5,959 60720394,657 4,746 0 5,453 17.1%2039 1,169 11,621 5,894 60820404,691 4,746 0 5,453 16.2%2040 1,211 11,972 6,177 610Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C94Table 22: Option#2 – 15 Year Base Case ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand Capital AllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C)(E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 411,796(114,466)22,114 504,148 0(1,144) (1,144)503,003 375 503,378 0 503,378 503,378 0 503,003‐64.8134844 44.042012 479,961(200,051)148,785 531,227 1,262(1,652) (390)530,838 10,642 541,479 11,111 530,368 992,738 0 529,576 264.5545156 422013 476,470(282,052)131,781 626,741 1,262(1,974) (712)626,029 7,537 633,566 10,252 623,313 1,523,388 0 624,767 244.1065156 422014 526,735(283,890)146,960 663,665 1,262(3,218) (1,956)661,709 5,653 667,362 9,834 657,527 2,039,883 0 660,447 234.1545156 422015 542,998(294,209)150,856 686,351 1,262 7,408 8,670 695,021 5,731 700,752 12,993 687,760 2,538,354 0 693,759 245.5145156 52.922016 615,410(310,069)137,802 787,676 93,625 64,827 158,452 946,128 3,650 949,778 3,176 946,602 3,171,380 0 852,503 47.63543359 66.67922017 631,814(336,383)140,488 827,709 93,625 81,196 174,821 1,002,531 2,737 1,005,268 5,556 999,712 3,788,231 0 908,906 66.12801563 84.0157922018 622,459(352,122)126,862 847,719 93,625 83,240 176,865 1,024,584 1,054 1,025,637 7,481 1,018,156 4,367,887 0 930,959 70.67201563 105.85989792019 647,727(359,086)125,042 881,770 93,625 88,053 181,678 1,063,449 397 1,063,845 9,818 1,054,027 4,921,567 0 969,824 68.40001563 143.53972292020 582,257(377,087)59,444 899,899 98,462 84,925 183,387 1,083,287 0 1,083,287 12,098 1,071,188 5,440,753 0 984,825 82.78653125 146.13683952021 597,810(391,528)49,497 939,841 98,462 90,668 189,130 1,128,972 0 1,128,972 10,119 1,118,853 5,941,112 0 1,030,510 68.01853125 148.76730262022 612,247(382,482)34,319 960,409 98,462 95,451 193,913 1,154,321 136,220 1,290,542 7,892 1,282,649 6,470,370 0 1,055,859 52.11453125 151.4451142023 622,102(198,063)46,492 773,672 98,462 91,194 189,656 963,328 136,199 1,099,528 7,966 1,091,562 6,885,954 0 864,866 51.66856641 154.17112612024 637,607(207,705)66,206 779,106 158,243 105,591 263,834 1,042,940 142,062 1,185,002 7,248 1,177,754 7,299,682 399,591 0 1,284,289 46.18132813 156.94620632025 664,344(211,187)71,982 803,549 158,243 105,140 263,383 1,066,933 143,778 1,210,711 2,659 1,208,051 7,691,242 0 908,690 16.64532813 159.77123812026 674,648(238,579)79,015 834,212 158,243 106,180 264,423 1,098,635 146,396 1,245,031 186 1,244,845 8,063,529 0 940,392 1.143792969 162.64712032027 702,575(248,884)76,699 874,760 209,145 113,082 322,227 1,196,987 146,052 1,343,039 34,480 1,308,559 8,424,612 281,448 0 1,269,290 208.243793 165.57476852028 717,344(257,845)83,438 891,752 209,145 111,893 321,038 1,212,790 152,361 1,365,150 31,374 1,333,777 8,764,196 0 1,003,645 186.1324219 168.55511432029 739,028(307,236)96,186 950,078 209,145 119,871 329,016 1,279,094 149,416 1,428,510 29,678 1,398,832 9,092,806 0 1,069,949 172.9611406 171.58910642030 749,947(328,808)106,436 972,319 209,145 115,603 324,748 1,297,067 154,727 1,451,794 24,442 1,427,352 9,402,190 0 1,087,922 139.9253164 174.67771032031 798,742(319,480)11,249 1,106,973 322,218 144,325 466,543 1,573,516 131,398 1,704,914 12,464 1,692,450 9,740,670 1,057,273 0 2,308,571 70.09526172 177.82190912032 797,205(320,940) (53,273)1,171,418 322,218 28,691 350,909 1,522,327 120,524 1,642,852 6,520 1,636,332 10,042,623 0 1,200,109 36.01526172 181.02270352033 817,217(327,148) (61,882)1,206,246 386,343 32,244 418,587 1,624,833 123,045 1,747,878 41,243 1,706,636 10,333,198 313,245 0 1,551,736 223.8032617 184.28111212034 849,111(334,730) (58,373)1,242,213 386,343 34,173 420,516 1,662,729 126,670 1,789,399 34,100 1,755,299 10,608,952 0 1,276,386 181.7712617 187.59817212035 864,459(342,643) (77,478)1,284,579 386,343 34,758 421,101 1,705,681 128,662 1,834,343 25,168 1,809,175 10,871,193 0 1,319,338 131.7872617 190.97493922036 892,396(352,062) (78,086)1,322,545 382,994 36,267 419,261 1,741,807 132,124 1,873,931 16,787 1,857,144 11,119,573 0 1,358,813 86.34726172 194.41248822037 912,914(359,572) (94,144)1,366,630 382,994 34,718 417,712 1,784,342 134,767 1,919,109 4,948 1,914,160 11,355,784 0 1,401,348 25.00326172 197.91191292038 952,697(368,650) (87,455)1,408,802 459,152 40,339 499,491 1,908,294 139,264 2,047,558 41,956 2,005,602 11,584,143 342,471 0 1,791,613 208.2472617 201.47432742039 959,509(378,187) (120,023)1,457,719 459,152 40,460 499,612 1,957,331 140,275 2,097,606 31,994 2,065,612 11,801,150 0 1,498,179 155.9912617 205.10086532040 996,482(379,267) (115,099)1,490,848 459,152 40,285 499,437 1,990,284 144,730 2,135,014 24,505 2,110,509 12,005,729 0 1,531,132 117.3672617 208.7926808sent Value011‐2040 7,198,961(3,352,038)959,907 9,591,092 1,306,391 629,1771,935,568 11,526,660613,167 12,139,827 134,098 12,005,729&M2011‐20401,159,6561,159,6561,159,656PresentValue2011‐2040 3,095,225 13,299,483 13,165,385Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingNortheastern 3 DFGD 15 Year Retrofit 3/1/2016 and 2/28/2031 Retirement and Northeastern 4 Retirement 2/28/2016Optimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C95Table 23: Option#2 – 15 Year Base Case BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,872 2,958 86 2011 8,454 7,272 2,123 880 2,872 21,6022012 18,688 2,906(2,906)2,570 5,365 2,795 2012 9,302 7,098 2,245 661 2,570 21,8762013 18,702 2,922(2,922)1,990 4,506 2,516 2013 7,510 6,792 2,237 685 1,990 19,2132014 18,748 2,777(2,777)1,948 4,533 2,585 2014 7,590 7,113 2,237 540 1,948 19,4272015 18,779 2,817(2,817)1,570 4,187 2,618 2015 7,945 6,732 2,237 580 1,570 19,0642016 18,832 2,803(2,803)1,841 3,862 2,021 2016 8,327 4,725 2,245 558 1,841 17,6982017 18,847 3,150(3,150)1,745 3,817 2,072 2017 8,446 3,663 2,532 618 1,745 17,0042018 18,883 3,285(3,285)1,696 3,516 1,819 2018 7,814 4,093 2,606 680 1,696 16,8892019 18,945 3,279(3,279)1,937 3,604 1,668 2019 8,204 3,513 2,606 674 1,937 16,9332020 18,996 3,570(3,570)2,028 2,755 727 2020 6,858 3,867 2,911 659 2,028 16,3232021 19,064 3,632(3,632)2,228 2,692 464 2021 6,881 3,587 2,975 657 2,228 16,3282022 19,169 3,632(3,632)2,487 2,640 153 2022 6,630 3,760 2,975 657 2,487 16,5092023 19,280 3,927(3,927)2,233 2,659 426 2023 6,492 3,466 3,270 657 2,233 16,1192024 19,404 4,014(4,014)1,937 2,656 719 2024 5,661 3,870 3,355 659 1,937 15,4822025 19,534 4,001(4,001)1,868 2,677 810 2025 5,693 3,793 3,343 657 1,868 15,3542026 19,671 4,307(4,307)1,717 2,646 929 2026 5,639 3,862 3,639 668 1,717 15,5242027 19,813 4,380(4,380)1,790 2,659 869 2027 5,794 3,582 3,712 668 1,790 15,5462028 19,969 4,409(4,409)1,740 2,695 954 2028 5,719 3,933 3,725 683 1,740 15,8012029 20,127 4,985(4,985)1,628 2,771 1,143 2029 5,810 3,527 4,303 682 1,628 15,9492030 20,300 5,149(5,149)1,625 2,874 1,249 2030 5,714 3,787 4,450 699 1,625 16,2752031 20,485 4,864(4,864)2,651 2,559(92)2031 7,251 1,527 4,165 699 2,651 16,2932032 20,678 4,766(4,766)3,457 2,427(1,031)2032 7,499 668 4,065 701 3,457 16,3902033 20,875 4,750(4,750)3,595 2,428(1,167)2033 7,574 663 4,051 699 3,595 16,5822034 21,092 4,750(4,750)3,543 2,417(1,126)2034 7,823 653 4,051 699 3,543 16,7692035 21,324 4,750(4,750)3,807 2,422(1,385)2035 7,769 655 4,051 699 3,807 16,9812036 21,568 4,766(4,766)3,815 2,433(1,382)2036 7,964 656 4,065 701 3,815 17,2012037 21,821 4,750(4,750)4,027 2,428(1,598)2037 8,026 654 4,051 699 4,027 17,4572038 22,060 4,750(4,750)4,026 2,490(1,536)2038 8,338 645 4,051 699 4,026 17,7592039 22,299 4,750(4,750)4,277 2,359(1,917)2039 8,169 642 4,051 699 4,277 17,8382040 22,541 4,765(4,765)4,235 2,374(1,861)2040 8,437 642 4,064 701 4,235 18,078PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,445 11,306 15,086 69720124,084 4,904 0 4,904 20.1%2012 22,371 12,380 13,391 45120134,102 4,904 0 4,904 19.6%2013 21,457 11,825 11,790 44620144,109 4,902 0 4,902 19.3%2014 22,560 12,107 12,213 40420154,099 4,902 0 4,902 19.6%2015 19,495 11,923 11,909 50020164,094 4,698 0 4,698 14.8%2016 5,591 10,690 7,162 51920174,083 4,704 0 4,704 15.2%2017 619 9,950 5,853 52120184,079 4,704 0 4,704 15.3%2018 685 10,011 5,661 63120194,081 4,704 0 4,704 15.3%2019 595 9,664 5,774 48420204,078 4,715 0 4,715 15.6%2020 644 9,278 4,704 62920214,091 4,715 0 4,715 15.3%2021 601 9,031 4,776 56020224,105 4,715 0 4,715 14.9%2022 643 9,034 4,568 47420234,117 4,729 0 4,729 14.9%2023 579 8,915 4,641 56820244,130 4,505 233 4,738 14.7%2024 651 9,180 4,205 61020254,156 4,505 0 4,738 14.0%2025 644 9,172 3,879 54120264,179 4,515 0 4,748 13.6%2026 647 9,217 3,977 64420274,204 4,515 236 4,984 18.6%2027 600 9,081 3,981 59620284,225 4,517 0 4,986 18.0%2028 661 9,352 3,997 62820294,253 4,536 0 5,004 17.7%2029 584 9,055 4,079 65420304,284 4,538 0 5,007 16.9%2030 630 9,253 4,176 65820314,318 3,803 704 4,975 15.2%2031 214 7,754 4,391 66920324,348 3,803 0 4,975 14.4%2032 55 7,019 4,319 68520334,390 3,803 236 5,211 18.7%2033 55 7,071 4,514 68120344,427 3,803 0 5,211 17.7%2034 54 7,183 4,558 67020354,471 3,803 0 5,211 16.5%2035 55 7,200 4,656 67320364,511 3,803 0 5,211 15.5%2036 55 7,296 4,775 67420374,565 3,803 0 5,211 14.1%2037 55 7,344 4,839 67220384,611 3,803 236 5,446 18.1%2038 55 7,489 4,948 66420394,657 3,803 0 5,446 16.9%2039 55 7,444 4,933 66020404,691 3,803 0 5,446 16.1%2040 55 7,579 5,142 660Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C96Table 24: Option#2 – 25 Year Base Case ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C) (D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 411,796(114,466)22,114 504,148 0(1,298) (1,298)502,850 375 503,225 0 503,225 503,225 0 502,850‐64.8135 44.042012 479,961(200,051)148,785 531,227 1,077(1,873) (796)530,431 10,642 541,073 11,111 529,962 992,210 0 529,354 264.5545 422013 476,470(282,052)131,781 626,741 1,077(2,265) (1,188)625,553 7,537 633,090 10,252 622,838 1,522,455 0 624,476 244.1065 422014 526,735(283,890)146,960 663,665 1,077(3,605) (2,528)661,137 5,653 666,790 9,834 656,956 2,038,501 0 660,060 234.1545 422015 542,998(294,209)150,856 686,351 1,077 6,833 7,910 694,261 5,731 699,992 12,993 687,000 2,536,421 0 693,184 245.5145 52.922016 615,410(310,069)137,802 787,676 81,327 63,873 145,200 932,876 3,650 936,526 3,176 933,350 3,160,585 0 851,549 47.63543 66.67922017 631,814(336,383)140,488 827,709 81,327 78,236 159,563 987,272 2,737 990,009 5,556 984,453 3,768,021 0 905,945 66.12802 84.015792018 622,459(352,122)126,862 847,719 81,327 80,096 161,423 1,009,141 1,054 1,010,195 7,481 1,002,714 4,338,885 0 927,814 70.67202 105.85992019 647,727(359,086)125,042 881,770 81,327 84,821 166,148 1,047,918 397 1,048,315 9,818 1,038,496 4,884,407 0 966,591 68.40002 143.53972020 582,257(377,087)59,444 899,899 86,164 81,662 167,826 1,067,726 0 1,067,726 12,098 1,055,628 5,396,051 0 981,562 82.78653 146.13682021 597,810(391,528)49,497 939,841 86,164 87,218 173,382 1,113,224 0 1,113,224 10,119 1,103,105 5,889,367 0 1,027,060 68.01853 148.76732022 612,247(382,482)34,319 960,409 86,164 91,753 177,917 1,138,326 136,220 1,274,546 7,892 1,266,653 6,412,025 0 1,052,162 52.11453 151.44512023 622,102(198,063)46,492 773,672 86,164 87,385 173,549 947,222 136,199 1,083,421 7,966 1,075,455 6,821,476 0 861,058 51.66857 154.17112024 637,607(207,705)66,206 779,106 145,945 101,534 247,479 1,026,586 142,062 1,168,648 7,248 1,161,400 7,229,460 399,591 0 1,280,232 46.18133 156.94622025 664,344(211,187)71,982 803,549 145,945 100,977 246,922 1,050,471 143,778 1,194,249 2,659 1,191,590 7,615,684 0 904,526 16.64533 159.77122026 674,648(238,579)79,015 834,212 145,945 102,697 248,642 1,082,853 146,396 1,229,249 186 1,229,063 7,983,251 0 936,908 1.143793 162.64712027 702,575(248,884)76,699 874,760 198,109 109,686 307,795 1,182,555 146,052 1,328,608 34,480 1,294,128 8,340,352 281,448 0 1,265,894 208.2438 165.57482028 717,344(257,845)83,438 891,752 198,109 108,708 306,817 1,198,569 152,361 1,350,929 31,374 1,319,556 8,676,316 0 1,000,460 186.1324 168.55512029 739,028(307,236)96,186 950,078 198,109 116,976 315,085 1,265,163 149,416 1,414,579 29,678 1,384,901 9,001,653 0 1,067,054 172.9611 171.58912030 749,947(328,808)106,436 972,319 198,109 117,065 315,174 1,287,493 154,727 1,442,219 24,442 1,417,778 9,308,961 0 1,089,384 139.9253 174.67772031 760,045(319,480)48,835 1,030,690 257,968 96,409 354,377 1,385,066 153,781 1,538,847 12,228 1,526,619 9,614,276 302,266 0 1,429,364 68.76567 177.82192032 764,137(320,940)29,811 1,055,266 257,968 73,181 331,149 1,386,415 160,424 1,546,839 6,279 1,540,560 9,898,556 0 1,128,447 34.68567 181.02272033 777,944(327,148)4,137 1,100,955 322,093 75,981 398,074 1,499,029 158,030 1,657,059 40,998 1,616,061 10,173,711 313,245 0 1,490,181 222.4737 184.28112034 805,642(334,730)18,451 1,121,920 322,093 78,783 400,876 1,522,796 166,170 1,688,966 33,851 1,655,116 10,433,725 0 1,200,703 180.4417 187.59822035 825,374(342,643)3,910 1,164,107 322,093 79,325 401,418 1,565,525 169,157 1,734,682 24,914 1,709,768 10,681,558 0 1,243,432 130.4577 190.97492036 860,480(352,063)9,854 1,202,688 318,744 79,812 398,556 1,601,244 173,642 1,774,886 16,528 1,758,357 10,916,726 0 1,282,500 85.01767 194.41252037 882,058(359,572) (16,051)1,257,681 317,667 78,027 395,694 1,653,374 173,699 1,827,073 4,685 1,822,388 11,141,612 0 1,335,707 23.67367 197.91192038 923,586(368,650)7,958 1,284,278 393,825 83,151 476,976 1,761,255 183,459 1,944,713 41,689 1,903,025 11,358,291 342,471 0 1,709,900 206.9177 201.47432039 931,854(378,187) (44,781)1,354,823 393,825 83,013 476,838 1,831,661 178,473 2,010,134 31,721 1,978,413 11,566,137 0 1,437,836 154.6617 205.10092040 963,390(379,267) (32,239)1,374,896 393,825 159,344 553,169 1,928,065 186,079 2,114,144 24,228 2,089,916 11,768,720 0 1,534,240 116.0377 208.7927Present Valuef2011‐2040 7,148,435(3,352,038)1,066,061 9,434,412 1,140,129 661,4671,801,596 11,236,008666,448 11,902,456 133,736 11,768,720eO&M2011‐20401,159,6561,159,6561,159,656ostPresentValue2011‐20402,961,252 13,062,112 12,928,376Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingNortheastern 3 DFGD 25 Year Retrofit 3/1/2016 and Northeastern 4 Retirement 2/28/2016Optimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C97Table 25: Option#2 – 25 Year Base Case BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,872 2,958 86 2011 8,454 7,272 2,123 880 2,872 21,6022012 18,688 2,906(2,906)2,570 5,365 2,795 2012 9,302 7,098 2,245 661 2,570 21,8762013 18,702 2,922(2,922)1,990 4,506 2,516 2013 7,510 6,792 2,237 685 1,990 19,2132014 18,748 2,777(2,777)1,948 4,533 2,585 2014 7,590 7,113 2,237 540 1,948 19,4272015 18,779 2,817(2,817)1,570 4,187 2,618 2015 7,945 6,732 2,237 580 1,570 19,0642016 18,832 2,803(2,803)1,841 3,862 2,021 2016 8,327 4,725 2,245 558 1,841 17,6982017 18,847 3,150(3,150)1,745 3,817 2,072 2017 8,446 3,663 2,532 618 1,745 17,0042018 18,883 3,285(3,285)1,696 3,516 1,819 2018 7,814 4,093 2,606 680 1,696 16,8892019 18,945 3,279(3,279)1,937 3,604 1,668 2019 8,204 3,513 2,606 674 1,937 16,9332020 18,996 3,570(3,570)2,028 2,755 727 2020 6,858 3,867 2,911 659 2,028 16,3232021 19,064 3,632(3,632)2,228 2,692 464 2021 6,881 3,587 2,975 657 2,228 16,3282022 19,169 3,632(3,632)2,487 2,640 153 2022 6,630 3,760 2,975 657 2,487 16,5092023 19,280 3,927(3,927)2,233 2,659 426 2023 6,492 3,466 3,270 657 2,233 16,1192024 19,404 4,014(4,014)1,937 2,656 719 2024 5,661 3,870 3,355 659 1,937 15,4822025 19,534 4,001(4,001)1,868 2,677 810 2025 5,693 3,793 3,343 657 1,868 15,3542026 19,671 4,307(4,307)1,717 2,646 929 2026 5,639 3,862 3,639 668 1,717 15,5242027 19,813 4,380(4,380)1,790 2,659 869 2027 5,794 3,582 3,712 668 1,790 15,5462028 19,969 4,409(4,409)1,740 2,695 954 2028 5,719 3,933 3,725 683 1,740 15,8012029 20,127 4,985(4,985)1,628 2,771 1,143 2029 5,810 3,527 4,303 682 1,628 15,9492030 20,300 5,149(5,149)1,625 2,874 1,249 2030 5,714 3,787 4,450 699 1,625 16,2752031 20,485 4,864(4,864)2,185 2,625 441 2031 6,585 3,545 4,165 699 2,185 17,1782032 20,678 4,766(4,766)2,447 2,597 150 2032 6,708 3,926 4,065 701 2,447 17,8472033 20,875 4,750(4,750)2,801 2,559(242)2033 6,882 3,569 4,051 699 2,801 18,0022034 21,092 4,750(4,750)2,606 2,540(66)2034 6,945 3,894 4,051 699 2,606 18,1952035 21,324 4,750(4,750)2,876 2,588(288)2035 6,930 3,904 4,051 699 2,876 18,4592036 21,568 4,766(4,766)2,865 2,627(238)2036 7,198 3,889 4,065 701 2,865 18,7182037 21,821 4,750(4,750)3,180 2,599(581)2037 7,362 3,656 4,051 699 3,180 18,9482038 22,060 4,750(4,750)3,024 2,709(315)2038 7,560 3,975 4,051 699 3,024 19,3092039 22,299 4,750(4,750)3,510 2,535(975)2039 7,585 3,501 4,051 699 3,510 19,3462040 22,541 4,765(4,765)3,425 2,601(824)2040 7,725 3,725 4,064 701 3,425 19,640PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,445 11,306 15,086 69720124,084 4,904 0 4,904 20.1%2012 22,371 12,380 13,391 45120134,102 4,904 0 4,904 19.6%2013 21,457 11,825 11,790 44620144,109 4,902 0 4,902 19.3%2014 22,560 12,107 12,213 40420154,099 4,902 0 4,902 19.6%2015 19,495 11,923 11,909 50020164,094 4,698 0 4,698 14.8%2016 5,591 10,690 7,162 51920174,083 4,704 0 4,704 15.2%2017 619 9,950 5,853 52120184,079 4,704 0 4,704 15.3%2018 685 10,011 5,661 63120194,081 4,704 0 4,704 15.3%2019 595 9,664 5,774 48420204,078 4,715 0 4,715 15.6%2020 644 9,278 4,704 62920214,091 4,715 0 4,715 15.3%2021 601 9,031 4,776 56020224,105 4,715 0 4,715 14.9%2022 643 9,034 4,568 47420234,117 4,729 0 4,729 14.9%2023 579 8,915 4,641 56820244,130 4,505 233 4,738 14.7%2024 651 9,180 4,205 61020254,156 4,505 0 4,738 14.0%2025 644 9,172 3,879 54120264,179 4,515 0 4,748 13.6%2026 647 9,217 3,977 64420274,204 4,515 236 4,984 18.6%2027 600 9,081 3,981 59620284,225 4,517 0 4,986 18.0%2028 661 9,352 3,997 62820294,253 4,536 0 5,004 17.7%2029 584 9,055 4,079 65420304,284 4,538 0 5,007 16.9%2030 630 9,253 4,176 65820314,318 4,270 236 4,974 15.2%2031 588 9,075 4,583 64720324,348 4,270 0 4,974 14.4%2032 657 9,342 4,903 64920334,390 4,270 236 5,210 18.7%2033 592 9,082 4,997 64920344,427 4,270 0 5,210 17.7%2034 653 9,423 5,009 63920354,471 4,270 0 5,210 16.5%2035 654 9,467 5,163 64420364,511 4,270 0 5,210 15.5%2036 652 9,589 5,343 64620374,565 4,270 0 5,210 14.1%2037 609 9,466 5,426 64520384,611 4,270 236 5,445 18.1%2038 669 9,866 5,577 63920394,657 4,270 0 5,445 16.9%2039 582 9,472 5,530 63820404,691 4,270 0 5,445 16.1%2040 623 9,745 5,728 640Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C98Table 26: Option#4 – Base Case ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand Capital AllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C) D)=(A)‐(B)‐(C)(E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 411,796(114,466)22,114 504,148 0 0 0 504,148 375 504,523 0 504,523 504,523 0 504,148‐64.8134844 44.042012 479,961(200,051)148,785 531,227 5,107 0 5,107 536,334 10,642 546,976 11,111 535,865 998,954 0 531,227 264.5545156 422013 476,469(282,052)131,781 626,741 5,107 0 5,107 631,848 7,537 639,385 10,252 629,133 1,534,558 0 626,741 244.1065156 422014 526,735(283,890)146,960 663,665 5,107 0 5,107 668,772 5,653 674,425 9,834 664,590 2,056,602 0 663,665 234.1545156 422015 542,998(294,209)150,856 686,351 5,107 0 5,107 691,458 5,731 697,189 12,993 684,196 2,552,490 0 686,351 245.5145156 52.922016 628,169(310,627)102,108 836,688 100,456 31,974 132,430 969,118 3,364 972,482 3,117 969,365 3,200,739 692,889 0 1,561,551 46.74627344 66.67922017 680,392(336,731)126,494 890,630 100,456 48,004 148,460 1,039,090 2,511 1,041,601 5,481 1,036,120 3,840,054 0 938,634 65.23885547 84.0157922018 676,451(352,847)105,530 923,768 100,456 48,825 149,281 1,073,049 963 1,074,012 7,387 1,066,625 4,447,304 0 972,593 69.78285547 105.85989792019 697,081(359,536)112,775 943,842 100,456 49,833 150,289 1,094,131 367 1,094,497 9,690 1,084,807 5,017,152 0 993,675 67.51085547 143.53972292020 624,270(378,418)35,590 967,098 105,293 48,990 154,283 1,121,381 0 1,121,381 11,968 1,109,413 5,554,866 0 1,016,088 81.89737109 146.13683952021 647,441(392,642)34,666 1,005,417 105,293 50,168 155,461 1,160,878 0 1,160,878 9,987 1,150,891 6,069,552 0 1,055,585 67.12937109 148.76730262022 663,853(385,509)11,937 1,037,426 105,293 51,382 156,675 1,194,101 103,562 1,297,663 7,758 1,289,905 6,601,804 0 1,088,808 51.22537109 151.4451142023 675,026(198,063)32,472 840,618 105,293 52,647 157,940 998,557 107,203 1,105,760 7,829 1,097,932 7,019,813 0 893,264 50.77940625 154.17112612024 692,926(207,706)40,058 860,575 165,074 59,396 224,470 1,085,045 108,500 1,193,545 7,108 1,186,436 7,436,592 399,591 0 1,319,562 45.29216797 156.94620632025 725,037(211,189)45,407 890,819 165,074 63,205 228,279 1,119,098 110,527 1,229,626 2,517 1,227,108 7,834,328 0 954,024 15.75616797 159.77123812026 724,313(238,580)44,777 918,117 165,074 64,212 229,286 1,147,403 111,947 1,259,350 41 1,259,309 8,210,940 0 982,329 0.254632813 162.64712032027 758,849(248,884)54,411 953,322 217,238 67,203 284,441 1,237,763 114,564 1,352,328 34,333 1,317,995 8,574,627 281,448 0 1,301,973 207.3546328 165.57476852028 766,668(257,846)42,436 982,078 217,238 69,442 286,680 1,268,759 115,643 1,384,402 31,224 1,353,178 8,919,151 0 1,051,521 185.2432617 168.55511432029 797,192(307,236)78,325 1,026,104 217,238 71,040 288,278 1,314,381 118,544 1,432,925 29,526 1,403,400 9,248,834 0 1,097,143 172.0719805 171.58910642030 818,465(328,808)86,341 1,060,931 217,238 73,404 290,642 1,351,574 121,190 1,472,764 24,287 1,448,477 9,562,797 0 1,134,336 139.0361563 174.67771032031 837,252(319,481)63,145 1,093,587 293,296 55,346 348,642 1,442,229 123,614 1,565,844 11,675 1,554,169 9,873,621 452,742 0 1,601,675 65.65678516 177.82190912032 831,468(320,942)32,089 1,120,320 293,296 41,761 335,057 1,455,377 123,714 1,579,092 5,716 1,573,376 10,163,957 0 1,162,081 31.57678516 181.02270352033 853,059(327,149)26,993 1,153,214 357,421 45,500 402,921 1,556,135 126,400 1,682,535 40,425 1,642,110 10,443,546 313,245 0 1,511,959 219.3647852 184.28111212034 889,250(334,731)33,621 1,190,360 357,421 47,437 404,858 1,595,218 130,442 1,725,661 33,267 1,692,393 10,709,417 0 1,237,797 177.3327852 187.59817212035 905,728(342,644)18,827 1,229,545 357,421 48,154 405,575 1,635,120 132,563 1,767,683 24,320 1,743,363 10,962,119 0 1,277,699 127.3487852 190.97493922036 946,910(352,063)29,662 1,269,311 354,072 50,189 404,261 1,673,572 137,353 1,810,924 15,924 1,795,000 11,202,188 0 1,319,500 81.90878516 194.41248822037 962,056(359,573)12,306 1,309,322 354,072 48,468 402,540 1,711,862 139,399 1,851,261 4,070 1,847,191 11,430,135 0 1,357,790 20.56478516 197.91191292038 1,001,580(368,650)19,275 1,350,955 430,230 53,980 484,210 1,835,166 143,886 1,979,051 41,062 1,937,989 11,650,795 342,471 0 1,747,406 203.8087852 201.47432742039 1,012,928(378,187) (6,235)1,397,350 430,230 54,757 484,987 1,882,337 145,336 2,027,672 31,084 1,996,589 11,860,551 0 1,452,107 151.5527852 205.10086532040 1,047,113(379,268) (2,425)1,428,806 430,230 54,454 484,684 1,913,490 149,503 2,062,992 23,579 2,039,414 12,058,238 0 1,483,260 112.9287852 208.79268082011 Net Present ValuePeriodof2011‐2040 7,550,548(3,355,672)955,115 9,951,105 1,320,317 392,6041,712,921 11,664,025526,378 12,190,404 132,165 12,058,238BaseCaseO&M2011‐20401,159,6561,159,6561,159,656UtilityCostPresentValue2011‐2040 2,872,577 13,350,060 13,217,895Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingNortheastern 3 and Northeastern 4 Retirement 2/28/2016 Replaced with 2 233 MW Combined Cycle Units and 1 233 MW PPAOptimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C99Table 27: Option#4 – Base Case BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,872 2,958 86 2011 8,454 7,272 2,123 880 2,872 21,6022012 18,688 2,906(2,906)2,570 5,365 2,795 2012 9,302 7,098 2,245 661 2,570 21,8762013 18,702 2,922(2,922)1,990 4,506 2,516 2013 7,510 6,792 2,237 685 1,990 19,2132014 18,748 2,777(2,777)1,948 4,533 2,585 2014 7,590 7,113 2,237 540 1,948 19,4272015 18,779 2,817(2,817)1,570 4,187 2,618 2015 7,945 6,732 2,237 580 1,570 19,0642016 18,832 2,803(2,803)2,452 3,658 1,206 2016 8,558 2,176 2,245 558 2,452 15,9892017 18,847 3,150(3,150)2,050 3,752 1,702 2017 8,582 492 2,532 618 2,050 14,2732018 18,883 3,285(3,285)2,102 3,418 1,315 2018 8,118 605 2,606 680 2,102 14,1112019 18,945 3,279(3,279)2,245 3,586 1,341 2019 8,281 461 2,606 674 2,245 14,2672020 18,996 3,570(3,570)2,512 2,680 169 2020 7,008 614 2,911 659 2,512 13,7042021 19,064 3,632(3,632)2,534 2,642 109 2021 7,013 530 2,975 657 2,534 13,7092022 19,169 3,632(3,632)2,834 2,587(247)2022 6,908 452 2,975 657 2,834 13,8252023 19,280 3,927(3,927)2,450 2,631 181 2023 6,652 543 3,270 657 2,450 13,5712024 19,404 4,014(4,014)2,298 2,584 286 2024 5,952 600 3,355 659 2,298 12,8642025 19,534 4,001(4,001)2,213 2,591 378 2025 6,047 562 3,343 657 2,213 12,8232026 19,671 4,307(4,307)2,202 2,586 384 2026 5,919 668 3,639 668 2,202 13,0962027 19,813 4,380(4,380)2,070 2,579 508 2027 5,993 617 3,712 668 2,070 13,0602028 19,969 4,409(4,409)2,282 2,602 320 2028 5,970 654 3,725 683 2,282 13,3132029 20,127 4,985(4,985)1,853 2,715 862 2029 5,946 675 4,303 682 1,853 13,4592030 20,300 5,149(5,149)1,874 2,802 928 2030 6,015 674 4,450 699 1,874 13,7122031 20,485 4,864(4,864)2,006 2,614 608 2031 6,415 662 4,165 699 2,006 13,9472032 20,678 4,766(4,766)2,448 2,587 138 2032 6,331 662 4,065 701 2,448 14,2072033 20,875 4,750(4,750)2,556 2,591 35 2033 6,408 659 4,051 699 2,556 14,3732034 21,092 4,750(4,750)2,464 2,579 115 2034 6,695 647 4,051 699 2,464 14,5562035 21,324 4,750(4,750)2,716 2,604(112)2035 6,623 651 4,051 699 2,716 14,7412036 21,568 4,766(4,766)2,701 2,710 10 2036 6,896 649 4,065 701 2,701 15,0122037 21,821 4,750(4,750)2,919 2,671(248)2037 6,931 648 4,051 699 2,919 15,2472038 22,060 4,750(4,750)2,948 2,757(191)2038 7,226 638 4,051 699 2,948 15,5632039 22,299 4,750(4,750)3,179 2,654(525)2039 7,075 633 4,051 699 3,179 15,6372040 22,541 4,765(4,765)3,188 2,692(496)2040 7,291 632 4,064 701 3,188 15,876PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,445 11,306 15,086 69720124,084 4,904 0 4,904 20.1%2012 22,371 12,380 13,391 45120134,102 4,904 0 4,904 19.6%2013 21,457 11,825 11,790 44620144,109 4,902 0 4,902 19.3%2014 22,560 12,107 12,213 40420154,099 4,902 0 4,902 19.6%2015 19,495 11,923 11,909 50020164,094 4,232 466 4,698 14.7%2016 5,125 8,859 7,101 51620174,083 4,238 0 4,704 15.2%2017 42 7,880 4,817 51420184,079 4,238 0 4,704 15.3%2018 50 7,726 4,664 62520194,081 4,238 0 4,704 15.3%2019 40 7,673 4,740 48020204,078 4,249 0 4,715 15.6%2020 50 7,084 3,662 63320214,091 4,249 0 4,715 15.2%2021 45 7,031 3,734 55120224,105 4,249 0 4,715 14.8%2022 39 6,868 3,503 46920234,117 4,262 0 4,728 14.8%2023 46 7,017 3,592 56320244,130 4,038 233 4,737 14.7%2024 51 7,011 3,149 61920254,156 4,038 0 4,737 14.0%2025 49 7,051 2,977 57720264,179 4,049 0 4,748 13.6%2026 57 7,048 2,925 68620274,204 4,049 236 4,983 18.5%2027 53 7,123 3,004 63320284,225 4,050 0 4,985 18.0%2028 56 7,098 2,955 67120294,253 4,069 0 5,003 17.6%2029 57 7,184 3,036 69320304,284 4,071 0 5,006 16.8%2030 57 7,247 3,205 69220314,318 3,803 233 4,971 15.1%2031 58 7,295 3,299 67920324,348 3,803 0 4,971 14.3%2032 59 7,204 3,273 68020334,390 3,803 236 5,206 18.6%2033 59 7,264 3,438 67620344,427 3,803 0 5,206 17.6%2034 59 7,397 3,462 66520354,471 3,803 0 5,206 16.4%2035 59 7,419 3,571 66820364,511 3,803 0 5,206 15.4%2036 59 7,585 3,852 66720374,565 3,803 0 5,206 14.1%2037 59 7,597 3,793 66520384,611 3,803 236 5,442 18.0%2038 59 7,738 3,916 65520394,657 3,803 0 5,442 16.9%2039 59 7,713 3,934 65020404,691 3,803 0 5,442 16.0%2040 59 7,829 4,158 650Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under FT-CSAPR PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C100Table 28: EPA Settlement Option – Early Carbon ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 411,796(114,466)22,114 504,148 0(1,001) (1,001)503,146 375 503,521 0 503,521 503,521 0 503,146‐64.8135 44.042012 483,942(200,119)153,605 530,456 1,434(1,524) (90)530,366 10,710 541,076 11,111 529,964 992,509 0 528,932 264.5545 422013 473,531(281,772)127,992 627,311 1,434(1,740) (306)627,005 7,514 634,519 10,252 624,266 1,523,970 0 625,571 244.1065 422014 528,040(283,890)148,609 663,321 1,434(2,889) (1,455)661,865 5,676 667,542 9,834 657,707 2,040,606 0 660,431 234.1545 422015 540,539(294,074)148,042 686,570 1,434 16,374 17,808 704,378 5,710 710,089 12,993 697,096 2,545,844 0 702,944 245.5145 52.922016 607,979(310,032)135,460 782,551 65,106 52,759 117,865 900,416 4,113 904,529 2,679 901,850 3,148,943 0 835,310 40.18475 66.67922017 631,003(342,912)144,539 829,376 65,106 83,580 148,686 978,062 150,988 1,129,050 4,930 1,124,120 3,842,557 0 912,956 58.67733 84.015792018 624,164(358,915)113,651 869,427 65,106 83,963 149,069 1,018,496 145,694 1,164,190 6,693 1,157,498 4,501,543 0 953,390 63.22133 105.85992019 642,407(364,902)128,860 878,449 65,106 90,192 155,298 1,033,746 149,172 1,182,919 8,749 1,174,170 5,118,333 0 968,640 60.94933 143.53972020 579,361(382,473)55,319 906,515 69,943 87,507 157,450 1,063,965 142,690 1,206,655 11,009 1,195,645 5,697,842 0 994,022 75.33585 146.13682021 609,030(398,975)37,662 970,343 69,943 92,101 162,044 1,132,387 138,334 1,270,721 9,011 1,261,710 6,262,088 0 1,062,444 60.56785 148.76732022 625,051(387,868)23,341 989,579 69,943 96,473 166,416 1,155,995 138,522 1,294,516 6,764 1,287,752 6,793,451 0 1,086,052 44.66385 151.44512023 631,992(198,063)32,958 797,096 68,509 91,085 159,594 956,690 138,978 1,095,668 6,817 1,088,851 7,208,003 0 888,181 44.21788 154.17112024 633,002(207,704)14,890 825,815 115,558 93,174 208,732 1,034,547 139,667 1,174,213 6,427 1,167,786 7,618,230 266,781 0 1,185,770 40.94988 156.94622025 662,289(211,186) (3,657)877,131 115,558 91,208 206,766 1,083,897 137,256 1,221,153 1,824 1,219,329 8,013,445 0 968,339 11.41388 159.77122026 657,628(238,576) (4,744)900,947 165,958 115,913 281,871 1,182,817 138,591 1,321,409 37,639 1,283,770 8,397,373 276,471 0 1,293,331 231.4123 162.64712027 721,963(248,883) (17,543)988,389 244,506 56,127 300,633 1,289,022 118,209 1,407,232 34,700 1,372,531 8,776,109 843,120 0 1,887,636 209.5739 165.57482028 759,128(257,845)9,796 1,007,177 244,506 64,599 309,105 1,316,282 122,552 1,438,834 31,598 1,407,236 9,134,396 0 1,071,776 187.4625 168.55512029 780,928(307,236)37,664 1,050,499 244,506 66,540 311,046 1,361,545 124,678 1,486,224 29,906 1,456,317 9,476,510 0 1,117,039 174.2912 171.58912030 792,051(328,808)35,310 1,085,549 244,506 68,420 312,926 1,398,475 126,347 1,524,822 24,674 1,500,148 9,801,673 0 1,153,969 141.2554 174.67772031 802,854(319,480) (11,605)1,133,939 304,365 47,739 352,104 1,486,043 128,237 1,614,280 12,464 1,601,816 10,122,026 302,266 0 1,483,944 70.09526 177.82192032 792,391(320,940) (60,368)1,173,698 304,365 31,196 335,561 1,509,259 127,869 1,637,128 6,520 1,630,608 10,422,923 0 1,204,894 36.01526 181.02272033 812,704(327,148) (69,261)1,209,113 368,490 34,755 403,245 1,612,357 130,504 1,742,862 41,243 1,701,619 10,712,645 313,245 0 1,557,113 223.8033 184.28112034 845,313(334,730) (65,861)1,245,903 368,490 36,696 405,186 1,651,089 134,480 1,785,569 34,100 1,751,469 10,987,797 0 1,282,599 181.7713 187.59822035 859,530(342,643) (86,935)1,289,108 368,490 37,238 405,728 1,694,836 136,416 1,831,252 25,168 1,806,084 11,249,590 0 1,326,346 131.7873 190.97492036 885,919(352,062) (90,410)1,328,392 365,141 38,045 403,186 1,731,577 139,876 1,871,454 16,787 1,854,667 11,497,639 0 1,366,436 86.34726 194.41252037 905,953(359,572) (107,430)1,372,955 365,141 36,476 401,617 1,774,572 142,558 1,917,130 4,948 1,912,182 11,733,606 0 1,409,431 25.00326 197.91192038 944,383(368,650) (102,999)1,416,033 441,299 42,259 483,558 1,899,590 147,165 2,046,755 41,956 2,004,799 11,961,873 342,471 0 1,800,762 208.2473 201.47432039 955,298(378,187) (131,200)1,464,685 441,299 42,192 483,491 1,948,176 148,695 2,096,871 31,994 2,064,877 12,178,802 0 1,506,877 155.9913 205.10092040 991,704(379,267) (128,414)1,499,385 441,299 42,054 483,353 1,982,737 153,312 2,136,049 24,505 2,111,544 12,383,482 0 1,541,438 117.3673 208.79272011 Net Present ValuePeriodof2011‐2040 7,226,604(3,370,852)780,111 9,817,345 1,172,004 560,4781,732,483 11,549,827974,960 12,524,788 141,306 12,383,482BaseCaseO&M2011‐20401,146,8111,146,8111,146,811UtilityCostPresentValue2011‐20402,879,293 13,671,599 13,530,293Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Early Carbon PricingNortheastern 4 Retired 2/28/2016 and Northeastern 3 DSI+ACI+BH Retrofit 7/1/2015 with 2021-2026 Declining Capacity Factor and 12/31/2026 RetirementOptimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C101Table 29: EPA Settlement Option – Early Carbon BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,872 2,958 86 2011 8,454 7,272 2,123 880 2,872 21,6022012 18,688 2,906(2,906)2,545 5,434 2,889 2012 9,391 7,101 2,245 661 2,545 21,9432013 18,702 2,922(2,922)2,043 4,483 2,440 2013 7,446 6,787 2,237 685 2,043 19,1982014 18,748 2,777(2,777)1,927 4,543 2,616 2014 7,615 7,118 2,237 540 1,927 19,4372015 18,779 2,817(2,817)1,595 4,158 2,563 2015 7,895 6,731 2,237 580 1,595 19,0392016 18,832 2,803(2,803)1,885 3,860 1,975 2016 8,221 4,819 2,245 558 1,885 17,7282017 18,847 3,150(3,150)1,917 3,752 1,835 2017 7,997 3,902 2,532 618 1,917 16,9652018 18,883 3,285(3,285)2,164 3,471 1,307 2018 7,656 3,725 2,606 680 2,164 16,8302019 18,945 3,279(3,279)2,146 3,649 1,503 2019 7,685 3,869 2,606 674 2,146 16,9802020 18,996 3,570(3,570)2,210 2,742 532 2020 6,573 3,993 2,911 659 2,210 16,3462021 19,064 3,632(3,632)2,477 2,664 187 2021 6,821 3,342 2,975 657 2,477 16,2722022 19,169 3,632(3,632)2,651 2,618(33)2022 6,868 3,253 2,975 657 2,651 16,4032023 19,280 3,927(3,927)2,442 2,641 199 2023 6,749 2,962 3,270 657 2,442 16,0802024 19,404 4,014(4,014)2,640 2,552(88)2024 6,463 3,008 3,355 659 2,640 16,1262025 19,534 4,001(4,001)2,843 2,490(353)2025 6,839 2,556 3,343 657 2,843 16,2382026 19,671 4,307(4,307)2,795 2,440(355)2026 6,602 2,656 3,639 668 2,795 16,3602027 19,813 4,380(4,380)3,019 2,444(575)2027 6,905 606 3,712 668 3,019 14,9102028 19,969 4,409(4,409)2,681 2,540(141)2028 6,589 644 3,725 683 2,681 14,3222029 20,127 4,985(4,985)2,354 2,642 288 2029 6,543 664 4,303 682 2,354 14,5452030 20,300 5,149(5,149)2,459 2,687 227 2030 6,500 664 4,450 699 2,459 14,7722031 20,485 4,864(4,864)2,903 2,484(418)2031 7,312 653 4,165 699 2,903 15,7312032 20,678 4,766(4,766)3,527 2,424(1,103)2032 7,438 662 4,065 701 3,527 16,3922033 20,875 4,750(4,750)3,670 2,435(1,235)2033 7,518 653 4,051 699 3,670 16,5912034 21,092 4,750(4,750)3,629 2,445(1,184)2034 7,779 647 4,051 699 3,629 16,8052035 21,324 4,750(4,750)3,901 2,445(1,457)2035 7,711 647 4,051 699 3,901 17,0092036 21,568 4,766(4,766)3,903 2,431(1,472)2036 7,893 647 4,065 701 3,903 17,2092037 21,821 4,750(4,750)4,142 2,448(1,694)2037 7,947 642 4,051 699 4,142 17,4802038 22,060 4,750(4,750)4,116 2,468(1,648)2038 8,238 633 4,051 699 4,116 17,7382039 22,299 4,750(4,750)4,343 2,364(1,979)2039 8,122 630 4,051 699 4,343 17,8462040 22,541 4,765(4,765)4,285 2,355(1,930)2040 8,382 628 4,064 701 4,285 18,059PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,445 11,306 15,086 69720124,084 4,904 0 4,904 20.1%2012 22,382 12,430 13,462 45120134,102 4,904 0 4,904 19.6%2013 21,440 11,786 11,730 44620144,109 4,902 0 4,902 19.3%2014 22,575 12,124 12,247 40420154,099 4,902 0 4,902 19.6%2015 19,484 11,895 11,860 50420164,094 4,691 0 4,691 14.6%2016 10,328 10,603 8,101 52420174,083 4,697 0 4,697 15.0%2017 6,749 9,811 6,881 52820184,079 4,697 0 4,697 15.1%2018 6,232 9,461 6,678 61320194,081 4,697 0 4,697 15.1%2019 6,759 9,615 6,831 48620204,078 4,708 0 4,708 15.4%2020 6,737 9,103 5,863 62920214,091 4,708 0 4,708 15.1%2021 5,670 8,709 5,746 56220224,105 4,708 0 4,708 14.7%2022 5,652 8,613 5,620 47520234,117 4,721 0 4,721 14.7%2023 4,979 8,530 5,592 57120244,130 4,497 236 4,733 14.6%2024 4,986 8,464 5,590 61620254,156 4,497 0 4,733 13.9%2025 4,245 8,208 5,332 56020264,179 4,508 236 4,979 19.1%2026 4,242 8,180 5,288 67020274,204 4,048 466 4,985 18.6%2027 47 6,887 3,824 62320284,225 4,050 0 4,987 18.0%2028 52 7,050 3,537 66120294,253 4,069 0 5,006 17.7%2029 54 7,082 3,552 68220304,284 4,071 0 5,008 16.9%2030 54 7,084 3,715 68220314,318 3,803 236 4,975 15.2%2031 54 7,097 4,073 67120324,348 3,803 0 4,975 14.4%2032 55 6,985 4,278 67920334,390 3,803 236 5,211 18.7%2033 54 7,036 4,473 67120344,427 3,803 0 5,211 17.7%2034 54 7,156 4,529 66520354,471 3,803 0 5,211 16.5%2035 54 7,165 4,615 66520364,511 3,803 0 5,211 15.5%2036 54 7,252 4,717 66520374,565 3,803 0 5,211 14.1%2037 54 7,295 4,778 66020384,611 3,803 236 5,446 18.1%2038 54 7,433 4,874 65120394,657 3,803 0 5,446 16.9%2039 54 7,413 4,898 64920404,691 3,803 0 5,446 16.1%2040 54 7,543 5,097 646Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Early Carbon PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)PSO 2012 Integrated Resource Plan – Exhibit C102Table 30: Option 1 – 25 Year Early Carbon ACash Flow ($000)Market MarketBaseRateImpacts Valueof ValueofTotalFuel Contract Market Fuel& Carrying Incremental Total Allowances Grand Valueof Grand CapitalAllowancesTotalExcess AvoidedCostRevenue/(Cost)Revenue/(Cost)TransactionsChargesO&MTotalCostConsumedTotalICAPTotalCPWExpendituresPurchased(P)=(D)+(F)CapacityCostAnnual Costs(A) (B)(C)(D)=(A)‐(B)‐(C) (E) (F) (G)=(E)+(F) (H)=(D)+(G) (I) (J)=(H)+(I) (K) (L)=(J)‐(K) (M) (N) (O) +(N)+(O)2011 411,796(114,466)22,114 504,148 0(1,298) (1,298)502,850 375 503,225 0 503,225 503,225 0 502,850‐64.8135 44.042012 483,942(200,119)153,605 530,456 0(1,952) (1,952)528,504 10,710 539,214 11,111 528,103 990,494 0 528,504 264.5545 422013 473,531(281,772)127,992 627,311 0(2,223) (2,223)625,088 7,514 632,602 10,252 622,349 1,520,323 0 625,088 244.1065 422014 528,040(283,890)148,609 663,321 0(2,217) (2,217)661,103 5,676 666,780 9,834 656,945 2,036,361 0 661,103 234.1545 422015 540,539(294,074)148,042 686,570 0 13,516 13,516 700,086 5,710 705,796 12,993 692,804 2,538,489 0 700,086 245.5145 52.922016 589,606(308,561)169,471 728,697 150,933 59,091 210,024 938,720 3,809 942,529 17,608 924,921 3,157,016 0 787,787 264.0729 66.67922017 592,236(340,736)181,472 751,500 150,933 95,026 245,959 997,459 184,867 1,182,326 23,740 1,158,586 3,871,896 0 846,526 282.5655 84.015792018 572,679(355,778)154,318 774,139 150,933 88,924 239,857 1,013,996 182,165 1,196,161 30,393 1,165,768 4,535,590 0 863,063 287.1095 105.85992019 599,618(362,231)160,174 801,674 150,933 94,255 245,188 1,046,862 182,241 1,229,103 40,885 1,188,218 5,159,760 0 895,929 284.8375 143.53972020 542,386(378,836)96,119 825,104 155,770 95,555 251,325 1,076,429 178,262 1,254,691 43,728 1,210,963 5,746,693 0 920,659 299.224 146.13682021 560,963(394,788)88,369 867,382 155,770 98,685 254,455 1,121,837 177,421 1,299,258 42,318 1,256,940 6,308,805 0 966,067 284.456 148.76732022 575,976(382,181)79,177 878,980 155,770 107,247 263,017 1,141,997 180,241 1,322,238 40,671 1,281,568 6,837,617 0 986,227 268.552 151.44512023 580,280(198,062)93,527 684,816 155,770 98,121 253,891 938,707 179,849 1,118,556 41,334 1,077,222 7,247,741 0 782,937 268.1061 154.17112024 580,814(207,705)91,103 697,416 155,770 106,414 262,184 959,600 185,417 1,145,017 4,604 1,140,413 7,648,352 0 803,830 29.33807 156.94622025 605,242(211,185)89,389 727,038 204,466 105,248 309,714 1,036,752 187,377 1,224,129 37,595 1,186,534 8,032,937 271,583 0 1,103,869 235.3021 159.77122026 609,259(238,576)90,986 756,849 204,466 106,841 311,307 1,068,156 189,189 1,257,345 35,750 1,221,595 8,398,271 0 863,690 219.8005 162.64712027 633,400(248,884)77,154 805,130 204,466 111,298 315,764 1,120,893 186,489 1,307,383 31,691 1,275,692 8,750,285 0 916,427 191.4005 165.57482028 650,794(257,846)97,894 810,746 204,466 114,075 318,541 1,129,287 197,231 1,326,518 28,535 1,297,984 9,080,756 0 924,821 169.2892 168.55512029 664,847(307,236)98,413 873,670 204,466 117,886 322,352 1,196,022 191,308 1,387,330 26,788 1,360,542 9,400,371 0 991,556 156.1179 171.58912030 683,162(328,808)122,041 889,928 204,466 118,190 322,656 1,212,585 201,331 1,413,916 21,500 1,392,416 9,702,182 0 1,008,119 123.0821 174.67772031 713,168(319,479)100,578 932,069 204,466 121,211 325,677 1,257,746 202,845 1,460,591 13,589 1,447,002 9,991,574 0 1,053,280 76.42192 177.82192032 728,006(320,940)98,131 950,815 204,466 109,630 314,096 1,264,911 211,096 1,476,007 7,665 1,468,342 10,262,528 0 1,060,445 42.34192 181.02272033 752,108(327,148)79,517 999,739 268,591 111,932 380,523 1,380,262 210,402 1,590,665 42,409 1,548,256 10,526,138 313,245 0 1,424,917 230.1299 184.28112034 780,101(334,730)92,459 1,022,372 268,591 114,432 383,023 1,405,396 219,093 1,624,489 35,287 1,589,202 10,775,797 0 1,136,805 188.0979 187.59822035 794,950(342,643)66,925 1,070,669 268,591 114,121 382,712 1,453,380 219,053 1,672,433 26,376 1,646,057 11,014,395 0 1,184,789 138.1139 190.97492036 833,840(352,063)85,183 1,100,720 265,242 113,919 379,161 1,479,881 228,380 1,708,261 18,017 1,690,244 11,240,453 0 1,214,639 92.67392 194.41252037 845,906(359,572)54,423 1,151,055 265,242 111,453 376,695 1,527,750 227,783 1,755,533 6,201 1,749,332 11,456,324 0 1,262,508 31.32992 197.91192038 881,895(368,650)71,923 1,178,623 341,400 116,459 457,859 1,636,482 237,885 1,874,367 43,231 1,831,136 11,664,818 342,471 0 1,637,553 214.5739 201.47432039 880,279(378,187)13,370 1,245,096 341,400 114,120 455,520 1,700,616 231,989 1,932,605 33,292 1,899,314 11,864,354 0 1,359,216 162.3179 205.10092040 926,448(379,267)38,343 1,267,371 341,400 254,852 596,252 1,863,623 242,290 2,105,913 25,826 2,080,087 12,065,984 0 1,522,223 123.6939 208.79272011 Net Present ValuePeriodof2011‐2040 6,809,637(3,359,356)1,339,903 8,829,090 1,392,507 766,9122,159,419 10,988,5091,337,714 12,326,223 260,239 12,065,984BaseCaseO&M2011‐20401,146,8111,146,8111,146,811UtilityCostPresentValue2011‐20403,306,230 13,473,034 13,212,795Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Early Carbon PricingNortheastern 3 and Northeastern 4 DFGD 25 Year Retrofit 3/1/2016Optimal Plan Cost Summary ($000)PSO 2012 Integrated Resource Plan – Exhibit C103Table 31: Option 1 – 25 Year Early Carbon BNetNetInternal Contract Contract Contract Market Market Market Solid Other EconomySalesPurchasesSalesTransactionsPurchasesSalesTransactionsGasFuelWindTransactionsPurchasesTotal2011 18,643 3,003(3,003)2,872 2,958 86 2011 8,454 7,272 2,123 880 2,872 21,6022012 18,688 2,906(2,906)2,545 5,434 2,889 2012 9,391 7,101 2,245 661 2,545 21,9432013 18,702 2,922(2,922)2,043 4,483 2,440 2013 7,446 6,787 2,237 685 2,043 19,1982014 18,748 2,777(2,777)1,927 4,543 2,616 2014 7,615 7,118 2,237 540 1,927 19,4372015 18,779 2,817(2,817)1,595 4,158 2,563 2015 7,895 6,731 2,237 580 1,595 19,0392016 18,832 2,803(2,803)1,330 4,084 2,754 2016 7,556 7,327 2,245 558 1,330 19,0172017 18,847 3,150(3,150)1,484 3,982 2,498 2017 7,486 6,871 2,532 618 1,484 18,9902018 18,883 3,285(3,285)1,648 3,670 2,022 2018 6,794 7,005 2,606 680 1,648 18,7322019 18,945 3,279(3,279)1,757 3,803 2,046 2019 7,177 6,710 2,606 674 1,757 18,9242020 18,996 3,570(3,570)1,650 2,888 1,238 2020 5,988 6,964 2,911 659 1,650 18,1712021 19,064 3,632(3,632)1,801 2,835 1,034 2021 6,038 6,706 2,975 657 1,801 18,1762022 19,169 3,632(3,632)1,912 2,784 873 2022 5,867 6,850 2,975 657 1,912 18,2612023 19,280 3,927(3,927)1,663 2,820 1,157 2023 5,813 6,463 3,270 657 1,663 17,8662024 19,404 4,014(4,014)1,656 2,767 1,111 2024 5,419 6,836 3,355 659 1,656 17,9242025 19,534 4,001(4,001)1,686 2,754 1,067 2025 5,637 6,732 3,343 657 1,686 18,0562026 19,671 4,307(4,307)1,602 2,702 1,100 2026 5,487 6,748 3,639 668 1,602 18,1442027 19,813 4,380(4,380)1,827 2,685 858 2027 5,775 6,283 3,712 668 1,827 18,2642028 19,969 4,409(4,409)1,579 2,751 1,171 2028 5,624 6,856 3,725 683 1,579 18,4672029 20,127 4,985(4,985)1,662 2,810 1,148 2029 5,785 6,272 4,303 682 1,662 18,7032030 20,300 5,149(5,149)1,521 2,989 1,468 2030 5,634 6,754 4,450 699 1,521 19,0572031 20,485 4,864(4,864)1,618 2,772 1,155 2031 6,033 6,514 4,165 699 1,618 19,0292032 20,678 4,766(4,766)1,702 2,800 1,098 2032 5,881 6,887 4,065 701 1,702 19,2362033 20,875 4,750(4,750)1,968 2,763 795 2033 6,143 6,547 4,051 699 1,968 19,4082034 21,092 4,750(4,750)1,871 2,819 948 2034 6,205 6,846 4,051 699 1,871 19,6722035 21,324 4,750(4,750)2,233 2,805 572 2035 6,266 6,648 4,051 699 2,233 19,8972036 21,568 4,766(4,766)2,110 2,912 802 2036 6,497 6,871 4,065 701 2,110 20,2442037 21,821 4,750(4,750)2,537 2,906 369 2037 6,566 6,638 4,051 699 2,537 20,4912038 22,060 4,750(4,750)2,411 2,970 559 2038 6,685 6,951 4,051 699 2,411 20,7972039 22,299 4,750(4,750)2,951 2,771(181)2039 6,663 6,474 4,051 699 2,951 20,8382040 22,541 4,765(4,765)2,770 2,866 96 2040 6,922 6,706 4,064 701 2,770 21,163PSO Reserve Margin - MWCarbonCaseSO2 Dioxide NOX - OK NOX - TXExisting Capacity Total ReserveEmissions Emissions Emissions EmissionsDemandCapacityChangesCapacityMargin - %(Tons)(kTons)(Tons)(Tons)20114,072 4,561 0 4,561 12.0%2011 22,445 11,306 15,086 69720124,084 4,904 0 4,904 20.1%2012 22,382 12,430 13,462 45120134,102 4,904 0 4,904 19.6%2013 21,440 11,786 11,730 44620144,109 4,902 0 4,902 19.3%2014 22,575 12,124 12,247 40420154,099 4,902 0 4,902 19.6%2015 19,484 11,895 11,860 50420164,094 4,915 0 4,915 20.1%2016 6,094 12,529 7,377 53520174,083 4,921 0 4,921 20.5%2017 1,239 12,072 6,294 53720184,079 4,921 0 4,921 20.6%2018 1,253 11,853 5,963 60820194,081 4,921 0 4,921 20.6%2019 1,214 11,753 6,141 49020204,078 4,932 0 4,932 20.9%2020 1,248 11,372 5,165 60920214,091 4,932 0 4,932 20.6%2021 1,206 11,170 5,242 55820224,105 4,932 0 4,932 20.1%2022 1,243 11,207 5,110 46520234,117 4,945 0 4,945 20.1%2023 1,163 11,039 5,193 55220244,130 4,721 0 4,721 14.3%2024 1,227 11,237 5,147 58820254,156 4,721 236 4,957 19.3%2025 1,216 11,205 5,014 50520264,179 4,732 0 4,967 18.9%2026 1,209 11,167 5,078 60420274,204 4,732 0 4,967 18.2%2027 1,125 10,866 5,123 56520284,225 4,733 0 4,969 17.6%2028 1,230 11,346 5,142 59020294,253 4,752 0 4,988 17.3%2029 1,118 10,867 5,197 61620304,284 4,754 0 4,990 16.5%2030 1,208 11,289 5,372 61820314,318 4,746 0 4,982 15.4%2031 1,165 11,226 5,351 60820324,348 4,746 0 4,982 14.6%2032 1,234 11,531 5,379 61120334,390 4,746 236 5,217 18.8%2033 1,171 11,344 5,637 61120344,427 4,746 0 5,217 17.8%2034 1,227 11,659 5,583 60520354,471 4,746 0 5,217 16.7%2035 1,187 11,505 5,666 61120364,511 4,746 0 5,217 15.7%2036 1,231 11,840 5,938 61320374,565 4,746 0 5,217 14.3%2037 1,189 11,655 5,860 61120384,611 4,746 236 5,453 18.3%2038 1,246 12,014 5,909 60620394,657 4,746 0 5,453 17.1%2039 1,159 11,565 5,862 60720404,691 4,746 0 5,453 16.2%2040 1,202 11,921 6,141 607Public Service Company of OklahomaAEP Capacity Resource OptimizationCosts and Emissions Summary Under Early Carbon PricingSummary of Energy Purchases and Sales (Gwh)Summary of Energy Sources (Gwh)

### PSO 2012 Integrated Resource Plan - Exhibit D

104 

## Exhibit D: Technical Conference Transcript

Attached is the PSO IRP Techni cal Conference Transcript before the Corporation Commission

of the State of Oklahoma.

### PSOIRPtechconf.txt

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1 BEFORE THE CORPORATION COMMISSION OF THE STATE OF OKLAHOMA 2

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10 11 TRANSCRIPTION OF QUESTION AND ANSWER SESSION

12 PSO IRP STAKEHOLDER MEETING 13 SEPTEMBER 20TH, 2012 - 1:00 P.M.

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24 OFFICIAL REPORTER: 25 LYNETTE H. WRANY, C.S.R.



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6 7 REPORTER'S NOTE: A Special Meeting/PSO IRP 8 Stakeholder Meeting was held on the 20th day of September, 9 2012, at 1:00 P.M., in Room 301 at the Oklahoma Corporation

10 Commission. 11 After a Powerpoint presentation, the following 12 question and answer session was had:

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24 OFFICIAL REPORTER: 25 LYNETTE H. WRANY, C.S.R.



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1 P R O C E E D I N G S 2 MR. FAIRO MITCHELL: If you would just come to the 3 microphone and state your name and the organization that 4 you're with and then ask the question. Page 2

### PSOIRPtechconf.txt 5 MR. BILL HUMES: Bill Humes with the Attorney 6 General's Office. Could you look back at your slide number 7 12, please?

8 MR. WILLIAM CASTLE: Yes. 9 MR. BILL HUMES: And I think your statement was 10 that the EPA Settlement Option was the cheapest of the 11 alternatives that is shown on that page. 12 Was it the cheapest option of all alternatives that

13 was modeled? 14 MR. WILLIAM CASTLE: When we reupped it? So, the 15 IRP did the reup when they adjusted costs for some of the 16 technologies, I guess the ACI technologies, so it was the 17 cheapest of those. 18 MR. BILL HUMES: So, all the alternatives that you 19 considered and modeled, it was the cheapest of all of those

20 alternatives? 21 MR. WILLIAM CASTLE: For the reup, yes. 22 MR. BILL HUMES: Okay. And then I'm going to go 23 back in time some, because I remember maybe a year and a 24 half or so ago, maybe slightly more, when we first started 25 talking about the EPA regulations coming down the pike, PSO



lw-4 1 provided some information that indicated, if I recall, at 2 that time that the scrubbing technology was a much, much 3 cheaper route to take than the fuel switch or other

4 alternatives. 5 What has happened in that time period that has changed 6 that assumption? 7 MR. STEVEN FATE: This is Steve Fate. Bill, I Page 3

### PSOIRPtechconf.txt 8 didn't catch the very first part of your question. Can you 9 repeat about the time frame? 10 MR. BILL HUMES: Sure. Sure. Approximately a 11 year and a half or so ago we were talking about these 12 coming regulations and PSO -- both PSO and OG&E provided 13 some information where they had compared the cost of 14 different mitigation efforts.

15 MR. STEVEN FATE: Got it. 16 MR. BILL HUMES: And at that point the PSO 17 information, as well as the OG&E, showed that the scrubber 18 technology was a much cheaper route to take than fuel 19 switching or any of the other mitigation efforts. And I'm 20 wondering what has changed in that time frame that has 21 turned that around, as seen on this slide number 12? 22 MR. STEVEN FATE: Well, do you want to address 23 that Mark, or do you want me to? 24 MR. MARK BECKER: My name is Mark Becker. I'm the 25 Manager of Resource Planning for AEP.



lw-5 1 A couple of things have changed in that time frame. 2 Probably first and foremost is the price of the scrubbers, 3 the Triad GE scrubbers has gone from roughly $500 a kW up 4 to about $640 a kW in the analysis that is on slide 12.

5 We have also seen some increases in fixed O & M costs 6 and ongoing capital for the unit. The DSI/ACI baghouse has 7 stayed fairly constant in price. It has gone up a little 8 bit, but by no mirror to the degree of the dry scrubber. 9 MR. BILL HUMES: And that accounts for -- because, 10 if I recall right, I believe that the scrubber technology Page 4

### PSOIRPtechconf.txt 11 you anticipated an increase in consumer rates of 12 approximately 10 percent with the scrubber technology and 13 up to 30 percent for a fuel switch. And what you're 14 talking about accounts for that large of a difference

15 there? 16 MR. MARK BECKER: I believe so, yes. Well, and we 17 have got -- we have other option now as far as doing the 18 DSI as well, and also these other options of, you know, 19 scrubbing one, retiring one. So, there has been a little 20 bit of shift in price and, perhaps, a little bit of shift

21 in the alternatives as well. 22 MR. BILL HUMES: And then when you discuss the 23 importance that PSO places on a diversified fuel mix and 24 the importance of fossil fuel, are you primarily -- I mean, 25 from your plan and your settlement it seems like the fossil



lw-6 1 fuel you're talking about is natural gas, correct? You're 2 not as interested in utilizing the coal, apparently, from 3 your plan? 4 MR. MARK BECKER: Well, I think we are interested 5 in using the coal. We have kept one of the units and we 6 will run that unit for another decade or so, as well as 7 picking up some purchased power capacity. So, I think we 8 are trying as best we can to diversify that mix in light of 9 any kind of regulation that may come. 10 MR. BILL HUMES: The unit though you're running 11 you're not going to run at a full capacity though over the 12 next decade, correct? 13 MR. MARK BECKER: Well, the capacity factor will Page 5

### PSOIRPtechconf.txt 14 begin to diminish for about a five-year period starting in

15 2020. 16 MR. BILL HUMES: Okay.

17 MR. STEVEN FATE: 2021.

18 MR. MARK BECKER: 2021.

19 MR. BILL HUMES: And then that unit will be 20 retired in 2026 at the very latest, correct? 21 MR. MARK BECKER: Its latest, 2026. Right. 22 Right. 23 MR. BILL HUMES: Okay. And at that point you will 24 have no coal on your system, is that correct?

25 MR. MARK BECKER: We will have Oklaunion.



lw-7 1 MR. BILL HUMES: Oh, okay. 2 MR. STEVEN FATE: Well, and the other thing, Bill, 3 to note is that between now and then we are going to have 4 several opportunities to consider what makes sense in light 5 of ongoing environmental regulations, cost profiles of 6 various generation or demand side options in 2022 when our 7 Exelon contract expires, in 2026 when the Northeast 3 is 8 removed from service, and then 2030 when the PPA that we 9 are currently working on expires. We will have an 10 opportunity. It is going to provide us a lot of 11 flexibility over that time frame to look at what makes 12 incrementally the best resource decision at that time given 13 all the uncertainties with, as I said, environmental 14 regulations, the SPP integrated marketplace that is coming 15 into play in 2014. 16 So, I think we have future flexibility to respond to, Page 6

### PSOIRPtechconf.txt 17 more certainty around all of those very significant 18 currently uncertainties over that time period. 19 MR. BILL HUMES: And when you decommission the 20 Northeast 3 and 4, is that a -- is there a possibility that 21 the type of decommissioning you're talking about, is there 22 ever the possibility of making use of those units again, 23 once they're decommissioned?

24 MR. STEVEN FATE: I don't think so. Not in their

25 current form.



lw-8 1 MR. BILL HUMES: Okay. All right. Thank you. 2 MR. JIM ROTH: Jim Roth with Chesapeake Energy. 3 Just a question I think on slide 13.

4 From the announcement of the EPA settlement to this 5 IRP I always understood Unit 4 to be retrofitted with the 6 step down beginning in 2021, and Unit 3 to be retired and

7 that is switched. 8 Can you explain to us what led to the decision to 9 change the units? Not faulting the decision, just curious

10 what led to the decision.

11 MR. STEVEN FATE: Jim -- this is Steve Fate. I 12 don't know for certain what communication you're referring 13 to. For modeling purposes we have to make a choice 14 sometimes. And so, it may have been at some point during 15 the analysis we had assumed Unit 4, but we did a more 16 rigorous analysis that looked at the overall condition of 17 the two units, which one is more easily retrofitted because 18 of the site layout, and made a -- did a fairly rigorous 19 analysis to determine that Unit 3 was the one that was best Page 7

### PSOIRPtechconf.txt 20 to continue to operate. 21 MR. JIM ROTH: Okay. Thank you. Appreciate the 22 information and, most assuredly, appreciate the

23 conclusions. 24 MS. CHERYL VAUGHT: Cheryl Vaught on behalf of 25 Chermac and Dogwood.



lw-9 1 On your page 8 -- and I'm going to put this question 2 in context, because it could be misconstrued if I don't. I 3 think we all, many of us in this room anyway that worked 4 towards the competitive bidding rules and hoped that the 5 utilities in the state would look at more competitive 6 markets when they were at the lowest reasonable costs 7 entering into PPAs and all, realize that PSO has 8 aggressively pursued PPAs generally. I think about -- is 9 it correct that about 30 percent of your generation is 10 received from -- about what is the percentage, if you can 11 tell us, from PPAs? 12 MR. STEVEN FATE: On an energy basis? 13 MS. CHERYL VAUGHT: On an energy basis. Yes. 14 MR. STEVEN FATE: Well, considering our wind, the 15 Exelon contract, and then what we do on a -- just on an 16 hourly or opportunity basis, I think it is about 30 17 percent. 18 MS. CHERYL VAUGHT: Okay. That was the number we 19 seemed to see in previous modeling and et cetera. 20 On page 8, I'm going to ask some questions just because 21 you have moved in that direction greatly. As to these 22 Gas-Steam Units, the Gas-Combined Cycle Units and Page 8

### PSOIRPtechconf.txt 23 Gas-Combustion, the G-C Turbine Units or Combustion Turbine 24 Units, does anyone here for PSO today have a feel for what 25 the heat rates might be on those particular units? Or is



lw-10 1 that data we would have to get separate of this meeting 2 today? 3 MR. STEVEN FATE: You want us to go through each 4 of our 25 units and give you heat rates?

5 MS. CHERYL VAUGHT: I think it would be 6 important -- my question is this. Let me -- 7 MR. STEVEN FATE: I think we ought to get back to 8 you so we can make sure we give you accurate information. 9 MS. CHERYL VAUGHT: That would be great. That 10 would be great. That would be really helpful, Steve. 11 Thank you. 12 I ask that question generally because PSO has made 13 good progress, I think, when it sees a unit on its own 14 system that it thinks it could efficiently replace or back 15 down or not utilize as much in purchasing power. And, as 16 we have looked at some models in the past, we have seen 17 that some of the units, particularly in off-peak months, 18 that you're using pretty aggressively, you know, do have 19 high heat rates and wonder, when you did your modeling, did 20 you look at alternatives to running some of these units or 21 replacing some of them or backing some of them down and 22 utilizing other natural gas resources? If you can help us

23 with that? 24 MR. MARK BECKER: This is Mark Becker again. In 25 our modeling, the way Strategist works, it will look at the Page 9

### PSOIRPtechconf.txt



lw-11 1 cost of the native fleet generation. And then, if it is 2 economically feasible, those generators would be backed 3 down if market purchases could be made on an hourly basis. 4 So, there is that potential for the Gas-Steam Units to run 5 less if there is cheaper energy on the market. 6 MR. STEVEN FATE: Let me add to Mark's response in 7 that there are some units that are run for reliability 8 purposes. So, they're run out of merit. So, I will just 9 point to that fact. 10 MS. CHERYL VAUGHT: And I know we have got voltage 11 support and reliability issues and all of those things. 12 MR. STEVEN FATE: Right. Right. 13 MS. CHERYL VAUGHT: Absolutely. I'm just trying 14 to get a feel from some of the history back with the days 15 of PROMOD, and you still utilize that model, right? You 16 know, there was -- there were always debates over inputs

17 into the model and what was made available for assessment 18 purposes, as best we have tried to figure out what was the

19 lowest reasonable cost. 20 And I'm just trying to get some feel for when we look 21 specifically at these gas units and look at the question of

22 lowest reasonable costs how much that was vetted in 23 conjunction with preparation of this IRP. And what did you

24 look at as alternatives? 25 And I know it is a very complex question which kind of



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### PSOIRPtechconf.txt 1 disadvantages everybody but the utility when we ask these 2 questions, frankly, because we just don't know all your 3 modeling inputs and what you do.

4 MR. MARK BECKER: As far as alternatives to 5 additional capacity needs, we will look at simple cycle 6 combustion turbines, combined cycle capacity. And, as 7 those alternatives are optimized through the process, part 8 of that process is, is looking at those alternatives, as 9 well as buying this, you know, hourly market energy. So, 10 it is kind of a mixture of, I will call it, iron in the 11 ground, which could be a surrogate for a PPA perhaps, as 12 well as taking advantage of the SPP hourly market. 13 MS. CHERYL VAUGHT: Okay. So, it is probably 14 impossible to tell us today, because of the volume of data 15 that goes into this modeling process, and different 16 assumptions, and you probably did a lot of different -- ran

17 a lot of different model -- or ran a lot of different 18 scenarios, what you might have utilized as alternatives to 19 these gas units that are listed on this page, potential

20 alternatives. Is that accurate? 21 MR. MARK BECKER: Again, it is combustion turbine 22 technology, simple cycle technology. 23 MS. CHERYL VAUGHT: As if you were building it or

24 -- 25 MR. MARK BECKER: As if we were building it, yes.



lw-13 1 MS. CHERYL VAUGHT: As if you were building it.

2 Not -- 3 MR. MARK BECKER: But again -- Page 11

### PSOIRPtechconf.txt

4 MS. CHERYL VAUGHT: Go ahead. 5 MR. MARK BECKER: Again, that is just a 6 placeholder for a certain type of capacity. 7 MS. CHERYL VAUGHT: Right. Right. 8 MR. MARK BECKER: Combined cycle resources, highly 9 efficient combined cycle resources, yet another placeholder 10 for a certain type of capacity. And then what we would do 11 is we look at those capacity needs and determine when they 12 are required in the program or in the process. And then, 13 you know, if -- and, as in the past, we have issued an RFP

14 to test the market. 15 MS. CHERYL VAUGHT: Right. But when you talk about 16 the RFP that is currently pending as being close to a PPA 17 on that, that is to replace a portion of a coal unit,

18 correct?

19 MR. MARK BECKER: Correct. 20 MS. CHERYL VAUGHT: So, when you ran 21 alternatives -- and I understand I don't know how to model, 22 but I know it is extremely complicated just from looking at 23 a lot of runs over the last 20 years. 24 When you looked at alternatives to these units to try 25 to come up with lowest reasonable costs, you were utilizing



lw-14 1 a build scenario as an alternative. You weren't looking -- 2 the PPA issue is separate and relates to retirement of -- 3 your proposed retirement of a coal facility? 4 MR. MARK BECKER: And when you say these units, 5 can you help me? 6 MS. CHERYL VAUGHT: Northeastern Unit 2, for Page 12

### PSOIRPtechconf.txt 7 example. Again, when you're doing modeling, okay, and I'm 8 going to be overly simple here. You're the expert, I'm

9 not. 10 But when you were doing your modeling, what -- and 11 you're trying to determine -- you're coming in here with an 12 Integrated Resource Plan proposal that says this is the 13 lowest reasonable cost to the customer, I want to know how 14 you vetted these units on this page, these Gas-Steam Units, 15 the Combined Cycle Units and the Combustion Turbine Units 16 to assure that they are creating lowest reasonable costs to 17 the customer. That is all I'm trying to get to. 18 MR. STEVEN FATE: Do you understand what she -- 19 let me see if I can regurgitate your question to see if I

20 understand it. 21 MS. CHERYL VAUGHT: Okay. 22 MR. STEVEN FATE: Are you asking did we do 23 individual unit disposition to say does it make sense to 24 continue to operate each of these units as compared to

25 other alternatives?



lw-15 1 MS. CHERYL VAUGHT: That is definitely a part of 2 the question.

3 MR. STEVEN FATE: We can answer that. I don't 4 know what the rest of the question is. 5 MS. CHERYL VAUGHT: Okay. All right. I will get 6 you the rest when you answer that. 7 MR. MARK BECKER: We did not necessarily look at 8 each one of these individual units. As those units, you 9 know, as those units get older as we go through this Page 13

### PSOIRPtechconf.txt 10 process, we'll look at those units, continually look at 11 those units, to see if they're retirement candidates. As 12 far as going to replace those units with certain types of 13 resources in our modeling, they were there and we looked at 14 the need going forward when, as Steven said, when the 15 Exelon contract expires, when this current PPA expires. 16 MS. CHERYL VAUGHT: Okay. 17 MR. STEVEN FATE: So, the times that we -- this is 18 Steve Fate. So, the times that we do individual unit 19 disposition analysis, time and time again what it has shown 20 is generally these older gas units, we need them for 21 capacity. Their energy value is diminished over time as 22 new combined cycle technologies come on. But they still 23 are needed for capacity purposes. And just from a straight 24 swap out on capacity, you can't replace them as cheap as we 25 can continue to operate them.



lw-16 1 MS. CHERYL VAUGHT: Okay. And I'm not implying at 2 all that you don't need them for capacity, because, 3 obviously, your reserve margin is not excessive. You know, 4 so understand that what I was trying to find out is how 5 deeply did you model whether or not these -- another

6 resource could be utilized in lieu of these units to save 7 costs to customers. That is what I'm trying to find out. 8 MR. STEVEN FATE: From an energy basis, we did

9 that. 10 MR. MARK BECKER: Every hour. 11 MR. STEVEN FATE: And it is hourly dispatch of the

12 model. Page 14

### PSOIRPtechconf.txt 13 MS. CHERYL VAUGHT: Utilizing as alternative the

14 market? 15 MR. MARK BECKER: Right.

16 MR. STEVEN FATE: Yes. 17 MS. CHERYL VAUGHT: And utilizing self-build?

18 MR. STEVEN FATE: Yes. 19 MS. CHERYL VAUGHT: As an option, correct? 20 MR. MARK BECKER: As a placeholder, yes. 21 MS. CHERYL VAUGHT: As a placeholder, but not 22 utilizing -- in conjunction with analyzing these units and 23 whether they're lowest reasonable costs to the customers, 24 but not PPAs in conjunction with these? Am I getting that 25 correctly?



lw-17 1 MR. STEVEN FATE: Well, the plan didn't call --

2 but for the one PPA that we talked about related to the 3 disposition of Unit 4, the plan didn't call for any 4 additional capacity. 5 MS. CHERYL VAUGHT: I'm talking about replacement 6 capacity, okay? I'm talking about replacement capacity.

7 So -- 8 MR. STEVEN FATE: Nor did the plan call for 9 retirement of any of these other gas units. 10 MS. CHERYL VAUGHT: Well, we are here to talk 11 about an Integrated Resource Plan beyond the EPA, you know, 12 settlement. That's why I'm -- I'm just trying to 13 understand and you answered my question. So, that is all I 14 have. I appreciate your time. Thank you for putting this 15 together for all of us. It is helpful. Page 15

### PSOIRPtechconf.txt 16 COMMISSIONER MURPHY: I have just a -- kind of a 17 few just fundamental questions. 18 Is the IRP -- because I think you all serve part of 19 Arkansas, is this just for the Oklahoma jurisdiction or is

20 it for Arkansas as well? 21 MR. STEVEN FATE: We only serve Oklahoma. 22 COMMISSIONER MURPHY: Okay. All right. Because I 23 saw an old -- I know OG&E serves part of Arkansas. But I 24 was looking back at your 2009? 25 MR. STEVEN FATE: Yeah. Earlier IRPs, some of



lw-18 1 them, we planned -- or the plan was consolidated with our 2 affiliate operating company, SWEPCO, which does operate in 3 Louisiana, Texas and Arkansas. 4 COMMISSIONER MURPHY: Okay. That was my question. 5 I know PSO -- I just didn't know if this was just for

6 Oklahoma.

7 MR. STEVEN FATE: Yes. 8 COMMISSIONER MURPHY: Because you have one plant 9 that is shown, I think, in Vernon, Texas, where you all 10 have some ownership?

11 MR. STEVEN FATE: That is correct. 12 COMMISSIONER MURPHY: Okay. All right. Just in 13 general, looking at slide number 4 where you say that you 14 expect that your load growth will be .03 percent, and just 15 for comparison purposes, you know, I understand about the 16 economy and the recession and such, but I note that back in 17 your -- in the IRP for 2009 you all had talked about load 18 growth and a compound annual rate of 1.5 percent per year Page 16

### PSOIRPtechconf.txt 19 and then you talked about recession depressing 2009, '10

20 and '11. 21 So, I understand the economy probably impacts this as 22 well, but what is your basis for coming up with the .03 23 percent on the load growth? Does that encompass the 24 economy? Does that encompass what you anticipate as 25 Southwest Power Pool, or what is in this .03 percent?



lw-19 1 MR. STEVEN FATE: Commissioner Murphy, I think we 2 have Jeff Brown from our Economic Forecasting Department on 3 the phone. Jeff, are you on? 4 MR. JEFF BROWN: I am, Steve. 5 MR. STEVEN FATE: Did you hear that question? 6 MR. JEFF BROWN: I did. Generally the biggest 7 impact, you know, to the load forecast is kind of what I 8 believe Will Castle mentioned earlier, is the increase in 9 the company's energy efficiency plans and the impact that 10 kind of goes along with it. You know, there has been a 11 number of things in addition to that that are affecting it. 12 But, you know, that would be probably the biggest driver is 13 just the increase as we have seen in energy efficiency. 14 COMMISSIONER MURPHY: Okay. Thank you.

15 MR. JEFF BROWN: Uh-huh.

16 MR. THOMAS P. SCHROEDTER: This is Tom Schroedter 17 on behalf of Oklahoma Industrial Energy Consumers. 18 Just kind of a fundamental question about the -- your 19 plant as it now exists versus what your IRP shows in the

20 future. 21 Now, as I see it, right now you have 930 megawatts, if Page 17

### PSOIRPtechconf.txt 22 I'm right, of coal-fired generation. Is that right?

23 MR. STEVEN FATE: No. 24 MR. THOMAS P. SCHROEDTER: 470, 460, then you have 25 the Oklaunion, excuse me, which is 100 megawatts?



lw-20 1 MR. STEVEN FATE: Approximately. 2 MR. THOMAS P. SCHROEDTER: Okay. So, what you're 3 going to do then is -- and my understanding is that there

4 is around $240 million left that has not been collected 5 from ratepayers for you to recover on those two coal 6 plants? Does that sound about right? 7 MR. STEVEN FATE: That sounds about right.

8 Yeah. 9 MR. THOMAS P. SCHROEDTER: Okay. All right. So, 10 you have got 930 megawatts of coal. It is going to cost

11 customers $240 million. 12 Now, in 2016, you're going to retire 470 megawatts of 13 that and you're going to replace it with 260 megawatts of a 14 Purchased Power Agreement. Okay. So, you have retired 470 15 megawatts, you're replacing that with 260 megawatts. Then 16 down the road you're going to also retire the 460 17 megawatts. 18 So, basically 930 megawatts at a cost of $240 million 19 are going to be gone. I mean, ratepayers aren't going to 20 get those coal-fired generating kilowatt hours. But I 21 think it is your plan that they're going to continue to pay 22 for them as if they were, is that correct? 23 MR. STEVEN FATE: Well, we will be -- in our 24 upcoming filing for our Environmental Compliance Plan, we Page 18

### PSOIRPtechconf.txt 25 will be making some recommendations on how to recover the



lw-21 1 remaining balance of those plants, yes. 2 MR. THOMAS P. SCHROEDTER: Okay. But -- I want to 3 get all that. I understand. But I guess my question is it 4 is your plan though to seek to recover that 240 million. 5 And that 240 million is in your -- is in this IRP? You 6 figured that in when you ran your calculations?

7 MR. STEVEN FATE: It is some cost. Yes. 8 MR. THOMAS P. SCHROEDTER: All right. So, we are 9 going to -- ratepayers are going to lose 930 megawatts for 10 $240 million and eventually you're going to need to replace 11 that 930 megawatts. I understand that your forecast is 12 that in the first ten years you only need 260. But your 13 forecast has very little growth. And, as I look to the end 14 of that forecast, guys, you were really close, I mean, in 15 terms of needing capacity. 16 All right. So, we lose 930 megawatts for $240 million 17 and you're going to have to replace the 930. And this is 18 all steel in the ground. So, looking at what steel in the 19 ground costs today, Scott, it is, what, 1200 per kW for a 20 new combined cycle? 21 MR. SCOTT NORWOOD? I think they're around 1300.

22 MR. THOMAS P. SCHROEDTER: It seems to me that 23 the economics, and I'm not getting into your EPA stuff and 24 the reasons for it, but the simple economics are we are 25 going to lose 930 megawatts, eventually, of cheap

Page 19

### PSOIRPtechconf.txt 

lw-22 1 coal-fired electricity, which I haven't even started 2 talking about, for $240 million. And you're going to -- 3 and, if you added steel in the ground to replace it, you 4 would be looking at about $1.2 to $1.5 billion of combined 5 cycle to replace the 240 million in coal. 6 Now, that is basically the numbers that I see. And, 7 if that is totally wrong, if the combined cycle numbers are 8 wrong, I would like to know it. But it seems to me that 9 ratepayers are not only going to have to pay the combined 10 cycle of 1.2 billion to 1.5 billion eventually, but then 11 you add on the 240 million. So, you're looking at 1.5 12 billion plus. Whereas, under the plan today that you have 13 or that you don't have, if you went along under current 14 conditions, it would only cost ratepayers $240 million? 15 MR. STEVEN FATE: Well, the problem with your 16 argument, this is Steve Fate, is that we can't just go on 17 the way we are. We have environmental compliance 18 requirements that are going to require us to make 19 significant decisions about those units. So, we can't 20 separate those arguments. 21 MR. THOMAS P. SCHROEDTER: That is a separate 22 issue. That is a separate issue. I'm just trying to 23 understand -- I'm just trying to understand the economics 24 of what is happening here. That is all. 25 MR. STEVEN FATE: Right. And I'm telling you that



lw-23 1 business as usual, without making some decision on that Page 20

### PSOIRPtechconf.txt 2 unit, is not an option. So, the notion that we can 3 continue to operate those units and ignore EPA compliance 4 requirements and run them for a full sixty years without 5 doing anything to them is not an option that we have. So

6 --

7 MR. THOMAS P. SCHROEDTER: I understand that is 8 your position. I'm just trying to understand what the 9 numbers are. And it seems to me that we are going to lose 10 eventually 930 megawatts of capacity that is currently in 11 the ground in Oklahoma? 12 MR. STEVEN FATE: Uh-huh. And you would be losing 13 those at some point anyway. 14 MR. THOMAS P. SCHROEDTER: Well, I don't agree

15 with that. But -- 16 MR. STEVEN FATE: But also, I just want to add 17 that all of what you're describing is accounted for in Will 18 and Mark's Strategist runs. So, your estimate of $1200 a 19 kW for new combined cycle, I think that is in the ballpark 20 of what we have got. 21 MR. THOMAS P. SCHROEDTER: Okay.

22 MR. STEVEN FATE: But all that calculus is 23 accounted for in the economic analyses that Mark and Will

24 have run. So --

25 MR. SCOTT NORWOOD: I'm Scott Norwood for OIEC.



lw-24 1 First of all, I wanted to start off with some 2 questions on information that I think wasn't in the report 3 and see if we can get you to agree or not to agree to 4 provide these as supplement. A lot of this stuff I think Page 21

### PSOIRPtechconf.txt 5 you provided in prior reports and stuff OG&E has provided. 6 So, I hope we can get an agreement on this. 7 First of all, I think under Schedule L, the Company is 8 supposed to provide a technical appendixes with details of 9 the modeling of each scenario you studied, including the 10 sensitivity runs. And that would include things like, I 11 would hope, the fuel and O & M and capital cost assumptions 12 for the retrofit options under each alternative and then 13 some costs by year over each plan incurred that you expect

14 to incur. 15 And in the original IRP in Table 6.5 you included 16 scenarios that looked at both a 2030 end date for coal, 17 which is a 15 year, and then, of course, the 25 year study 18 that assumed the coal plants could run another ten years. 19 So, I would hope that we could get that information for all

20 of those runs for those sensitivities. 21 MR. MARK BECKER: Scott, when you say information, 22 can you give me a little bit more of a definition? Or is 23 it in that technical appendixes?

24 MR. SCOTT NORWOOD: Yeah. I think what we are 25 talking about, Mark, is -- because what you provided in the



lw-25 1 report, a lot of it ends at 2021. What we are looking at 2 is taking it through 2030, on the runs you did through 2030 3 and through 2040 on the other runs. And I would be looking

4 for information like the assumed resource additions in each 5 option, and then all the incremental costs associated with 6 those options. And so, for retrofits, that would include 7 capital and the O & M, which you know is quite large. Page 22

### PSOIRPtechconf.txt 8 MR. MARK BECKER: Fixed O & M, ongoing capital, 9 the cost of the retrofit, cost of new generation 10 technologies that we would be evaluating and those 11 operating costs and performance characteristics?

12 MR. SCOTT NORWOOD: And variable O & M also. 13 MR. MARK BECKER: Right. Right. The costs and 14 operating characteristics for the new units. 15 MR. SCOTT NORWOOD: Right. And something that 16 would show, for example, unit retirements.

17 MR. MARK BECKER: Uh-huh. 18 MR. SCOTT NORWOOD: The last plan we had some 19 capacity dropping out in about 2021. So, something that 20 would show what you have assumed --

21 MR. MARK BECKER: Sure.

22 MR. SCOTT NORWOOD: -- on those resources in these

23 new runs. 24 MR. MARK BECKER: All the way out? All the way 25 out until the end of the study period?



lw-26 1 MR. SCOTT NORWOOD: Well, I think that is the only 2 way we can verify these results. 3 MR. MARK BECKER: Okay. 4 MR. SCOTT NORWOOD: I think that would be very 5 helpful. 6 MR. MARK BECKER: Okay. 7 MR. SCOTT NORWOOD: The other thing we would 8 request is that you consider doing a run that looked at the 9 SIP, the State Implementation Plan, the original SIP. And 10 we realize that may be a long shot, but the Courts have Page 23

### PSOIRPtechconf.txt 11 stayed the Regional Haze FIP, it is my understanding, in

12 the OG&E case. And we would like to know what would have 13 happened if the original SIP had been implemented and how 14 would those costs look relative to these options. I would 15 think you would want to look at that both for 30 and 40 16 years, if that is not too difficult. I think it is an 17 important data point. But -- 18 The third thing we would like to see supplemented in 19 the report is what you have done in prior reports, which is 20 the risk analysis, the revenue requirement at risk. I know 21 you have done this over in Arkansas on all power plants 22 that I have seen. And I think that is an important piece, 23 to capture the fuel cost risk due to the loss of fuel 24 diversity of these various plants and other uncertainty in 25 these plants.



lw-27 1 So, is there a reason you can't provide that? Or have 2 you looked at that? Or -- 3 MR. MARK BECKER: Well, you know, that is a 4 separate analysis altogether. And I can't produce it, I 5 don't think, in a week. But we will take that under 6 consideration as far as something that we would add in 7 future plans as well. 8 MR. SCOTT NORWOOD: Okay. Well, the reason I 9 asked is I know you all did that for the Flint Creek 10 analysis. 11 MR. MARK BECKER: Right.

12 MR. SCOTT NORWOOD: And it did tend to favor the 13 retrofit options, the continued coal use options. And so, Page 24

### PSOIRPtechconf.txt 14 we think, you know, that it is certainly a risk. It is a 15 way of getting at the fuel diversity issue. 16 MR. MARK BECKER: Sure. And one of the ways that 17 we tried to deal with risk and fuel diversity issues in the 18 evaluation of the Environmental Compliance Plan is we ran 19 it under a couple of different scenarios. One of them is

20 our base scenario and then we ran it because some of the 21 alternatives to doing the retrofits were heavily gas based. 22 We ran it under a low gas scenario as well. So, we have 23 done a couple of at least variations around fuel and market 24 prices just to try to quantify that risk anyway or at least 25 capture some of that risk.



lw-28 1 MR. SCOTT NORWOOD: Right. And I think that was 2 one of the next things I was going to ask, that it looked 3 like the sensitivities focused on a base gas and a low gas 4 scenario and we didn't pick up any high gas forecasts 5 which, you know, certainly is a concern to our customers. 6 What happens if, you know, increasing demand for gas makes 7 those prices float up. And we would like to see that run 8 done, too. 9 MR. MARK BECKER: Well, when we look at these 10 different scenarios there is more than just low gas or high 11 gas or base gas in them. It is how they are all woven 12 together and the correlation between market prices, gas 13 prices, coal prices, any kind of emission regulations that 14 we may have in the plan, CO2 as well. So, it is not just 15 low gas. It is a correlated low band forecast or a base

16 band forecast. Page 25

### PSOIRPtechconf.txt 17 MR. SCOTT NORWOOD: Okay. But, as I understand,

18 what we have is a base and a low band? 19 MR. MARK BECKER: Right. 20 MR. SCOTT NORWOOD: And what we are requesting is 21 you also pick up a high band forecast so we can get that 22 full spectrum. 23 In that regard also, I think OG&E also has run cases in 24 their IRP that look at delayed carbon and/or no carbon 25 regulations. And I know we have only studied carbon



lw-29 1 scenarios here and, you know, that is certainly something 2 most people expect to happen, you know, at some level in

3 the future now. But I think it would be useful information 4 to know what happens if carbon legislation is further 5 delayed and/or there is no carbon taxes. So, if we could 6 pick that up as we are doing these new runs, that would be 7 very useful. 8 One other thing, and this really dealt with the first 9 technical appendix issue on assumptions, I didn't see any 10 assumptions in the IRP on the PPA in terms of pricing terms 11 or -- and so, we don't know really what the impact of 12 modeling that is or, you know, what the cost is there, what 13 the dispatch constraints might be, what you're assuming on 14 transmission costs or any of that. So -- 15 MR. MARK BECKER: Well, that PPA is still being 16 negotiated. So, you wouldn't see that in the IRP. 17 MR. SCOTT NORWOOD: Okay. So, the terms may not 18 be what you modeled here. Is that what you're saying? 19 MR. MARK BECKER: In the analysis that it is on Page 26

### PSOIRPtechconf.txt 20 table 13 or page 13, I think it is -- 12. 21 MR. SCOTT NORWOOD: Right. 22 MR. MARK BECKER: We tried to pick up the PPA 23 conditions in that analysis. 24 MR. SCOTT NORWOOD: Right.

25 MR. MARK BECKER: As best we could at the time.



lw-30 1 MR. SCOTT NORWOOD: Well, I guess -- do you have

2 different terms now? 3 MR. MARK BECKER: I'm sorry -- 4 MR. SCOTT NORWOOD: You're saying the terms are

5 not final? 6 MR. MARK BECKER: I'm sorry. The PPA that we 7 modeled in August was kind of our best guess of the market 8 conditions, what we thought we could get from a PPA, what 9 is on that page. So, the eventual PPA that we will 10 negotiate will be a little bit different, yes. 11 MR. SCOTT NORWOOD: Okay. I mean, if that is a 12 number that can be refreshed to reflect your current 13 expectation of the contract, or if the contract is near 14 finalization and you're just dealing with non-pricing 15 terms, could this be updated?

16 MR. MARK BECKER: The runs themselves? 17 MR. SCOTT NORWOOD: Yes, sir.

18 MR. STEVEN FATE: It wouldn't make a material

19 difference.

20 MR. MARK BECKER: I don't think it would. Yes. I 21 don't think it would make a -- we were fairly good guessers 22 when we put in our mock PPA as far as what we finally would Page 27

### PSOIRPtechconf.txt 23 get. 24 MR. SCOTT NORWOOD: Well, in that case can we at 25 least have what you assumed for these runs in the technical



lw-31 1 appendix so we know for that -- for this proxy PPA?

2 MR. STEVEN FATE: We will look at that. 3 MR. SCOTT NORWOOD: I guess the final thing that 4 was missing, and this is stuff we have talked about 5 probably the last several IRPs, and that is we are very 6 interested in rate impacts of these options, both base rate 7 and fuel in the near term. We have got a lot of dollars 8 coming down the pike from SPP and these EPA regs and I 9 guess our customers would like to see in the near term, 10 next five or ten years, whatever, what the cost of these 11 various options would be by year and some split between 12 fuel, energy and the base rate component year by year of

13 course. 14 That is my laundry list of stuff we would like to see, 15 which I hope we can get. 16 Now, going to -- well, starting on slide 4, as I 17 understand it, a lot of the value that is being imputed to 18 the EPA settlement, Mark, tell me if I'm wrong, but this 19 initial assumption that you had excess capacity in the near 20 term so you don't have to buy 470 megawatts of power but 21 you only have to buy 260 to replace the coal unit that you

22 retire. Is that correct? 23 MR. STEVEN FATE: Well, it is one factor. 24 MR. MARK BECKER: It is a part of it, yeah. 25 MR. STEVEN FATE: It is not overweighted, doesn't Page 28

### PSOIRPtechconf.txt



lw-32 1 provide any overweighted economic benefit, I don't think. 2 MR. SCOTT NORWOOD: Well, I mean, in essence 3 you're having to buy 260 instead of 470 megawatts?

4 MR. STEVEN FATE: Correct.

5 MR. MARK BECKER: Correct. 6 MR. SCOTT NORWOOD: So there is definitely a cost

7 there.

8 MR. STEVEN FATE: Sure. 9 MR. SCOTT NORWOOD: My question is in the case 10 where you assumed the units were retrofitted and continued 11 to be used, are you providing any value to the system from

12

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