INTEGRATED RESOURCE PLAN 

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

the time of preparation. However, changes that may impact this plan can, and do, 

occur without notice. Therefore this plan is not a commitment to a specific course of 

action, since the future, now more than ever before, is highly uncertain, particularly 

in light of the current economic conditions, access to capital, the movement towards 

increasing use of renewable generation and end-use efficiency, as well as legislative 

proposals to control greenhouse gases. 

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

information becomes available or as circumstances warrant. . 

2012-2021 

Date Issued: October 1, 2012 

 

 
 PSO 2012 Integrated Resource Plan 

 

TABLE OF CONTENTS 

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

1.1 OVERVIEW .................................................................................................................................................................1

1.2 IRP PROCESS..............................................................................................................................................................1

1.3 INTRODUCTION TO PSO................................................................................................................................................2

1.4 ENVIRONMENTAL REGULATIONS.....................................................................................................................................5

1.5 EPA SETTLEMENT (NORTHEASTERN 3 & 4 SETTLEMENT)....................................................................................................6

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

2.1 LOAD AND DEMAND FORECAST ‐ PROCESS OVERVIEW......................................................................................................11

2.2 PEAK DEMAND FORECAST ...........................................................................................................................................13

2.3 LOAD UNCERTAINTY...................................................................................................................................................14

2.4 PSO CURRENT DEMAND‐SIDE RESOURCES.....................................................................................................................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 CURRENT RESOURCES.................................................................................................................................................21

3.2 EXISTING PSO GENERATING RESOURCES .......................................................................................................................21

3.3 CAPACITY NEEDS ASSESSMENT.....................................................................................................................................24

3.4 IMPACTS OF ENVIRONMENTAL COMPLIANCE PLAN...........................................................................................................25

3.5 DEMAND SIDE ALTERNATIVES ......................................................................................................................................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 TRANSMISSION ...........................................................................................................................................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 INTRODUCTION .........................................................................................................................................................35

4.2 HEDGING NOW AND FOR THE SHORT‐TERM ...................................................................................................................35
 PSO 2012 Integrated Resource Plan 

 

4.3 PSO’S FUEL SUPPLY MIX & REGIONAL MARKET STRUCTURES ARE CHANGING......................................................................37

4.4 HEDGING FOR THE LONGER‐TERM ................................................................................................................................38

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

5.1 MODELING AND PLANNING PROCESS – AN OVERVIEW .....................................................................................................42

5.2 METHODOLOGY ........................................................................................................................................................42

5.3 FUNDAMENTAL MODELING INPUT PARAMETERS .............................................................................................................43

5.3.1 CO2 Forecast..................................................................................................................................................46

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

6.1 THE STRATEGIST® MODEL ‐ AN OVERVIEW ....................................................................................................................47

6.1.1 Key Input Parameters ...................................................................................................................................49

6.2 STRATEGIST® OPTIMIZATION .......................................................................................................................................49

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

6.2.2 Strategic Portfolios .......................................................................................................................................50

6.3 PSO PLAN DEVELOPMENT ..........................................................................................................................................51

6.4 MODELING RESULTS ..................................................................................................................................................54

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

7.1 CAPACITY AND ENERGY PLAN.......................................................................................................................................56

7.2 PLAN SUMMARY .......................................................................................................................................................57

7.3 FIVE YEAR ACTION PLAN.............................................................................................................................................57

7.4 CONCLUSION............................................................................................................................................................58

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

EXHIBIT A: DEMAND‐SIDE RESOURCES ..................................................................................................................................1

EXHIBIT B: FUEL SUPPLY PLAN...........................................................................................................................................27

EXHIBIT C: TECHNICAL ADDENDUM ....................................................................................................................................63

EXHIBIT D: TECHNICAL CONFERENCE TRANSCRIPT................................................................................................................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 demand 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 available to the utility to address the identified 

needs 

IRP pp. 21-34 

(6) Schedule F: A fuel procurement plan, purchased-power procurement 

plan, and risk management plan 

Appendix, Exhibit B pp. 27-62 

(7) Schedule G: An action plan identifying the near-term (i.e., across 

the first five [5] years) actions that 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 the utility intends to solicit and 

evaluate new resources 

Appendix, Exhibit B pp. 43-57 

(9) Schedule I: A technical appendix 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 and analysis of the adequacy of its 

existing transmission system to determine its capability to serve load 

over the next ten (10) years, including 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 important uncertainties, including but 

not limited to load growth, fuel prices, and availability of planned 

supplies 

IRP pp. 21-26 

(12) Schedule L: An analysis of the utility’s proposed resource plan and 

any alternative scenarios necessary to demonstrate how the preferred 

plan best meets the planning criteria. Technical appendices should be 

included to document the planning analysis and assumptions used in 

preparing this analysis 

IRP pp. 47-58 

(13) Schedule M: A description and analysis of the Utility’s 

consideration of physical and financial hedging to determine the 

Utility’s ability to mitigate price volatility 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 descriptions of assumptions, study 

parameters, and methodologies. The results incorporate the integration 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 energy to customers at the least reasonable cost. 

In addition to developing a long-term strategy for achieving reliability/reserve margin 

requirements as set forth by the Southwest Power 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 critical component of recovery 

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

 Integration with other Strategic Business Initiatives—generation/capacity 

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

environmental compliance, transmission planning, and other corporate planning 

initiatives such as 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 resource 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, including projected changes to those resources 

(e.g., de-rates or retirements), and transmission system integration issues. 
 PSO 2012 Integrated Resource Plan 

2 

 Identify and describe supply-side resource options. 

 Describe the analysis and assumptions that will be used to develop the plan such as 

Regional Transmission Organization (RTO) reserve margin criteria, and 

fundamental modeling parameters. 

 Perform resource modeling and use the results to develop portfolios, including the 

selection of the ultimate plan. 

 Present the findings and recommendations, Action Plan and, finally, Plan 

implications on PSO. 

1.3 Introduction to PSO 

PSO is an affiliate company of American Electric 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, Oklahoma, 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 customers are served by one of the world’s 

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

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

companies in AEP's SPP zone collectively serve a population of about 3.83 million customers 

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

Texas (see Figure 1-1). 

 PSO serves approximately 532,000 retail customers in Oklahoma and one wholesale 

customer. The peak load requirement of PSO’s total retail and wholesale customers is seasonal in 

nature, with distinctive peaks occurring in the summer and winter seasons. The 2011 weather 

normalized summer and winter peaks were 4,099 MW and 2,682 MW respectively. 

PSO’s historical (ten-year average, ending 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 

3 

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 energy sales, plus losses, to its retail and 

firm-requirement wholesale customer (i.e., internal load) were 18,486 Gigawatt-hours (GWh). 

The weather-normalized 2011 load factor from those total company sales (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 factors. This exhibit also offers 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 

4 

Table 1-1: PSO Peak Demand 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 4,233 4,424 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

Actual 

WeatherNormalized

Actual 

WeatherNormalized

Actual 

Reported
 PSO 2012 Integrated Resource Plan 

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1.4 Environmental Regulations 

The two major final U.S. EPA rulemakings that 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 Implementation Plan (SIP). On March 22, 2011, the U.S. EPA 

published its proposed partial approval and disapproval of the Oklahoma Regional Haze SIP and 

Federal Implementation Plan (FIP) in the Federal Register. The Regional Haze FIP requires 0.06 

lbs SO2/MMBtu on SO2 which is considerably lower than the presumptive limits of 0.15 lbs 

SO2/MMBtu in the RHR. This would require that Northeastern Units 3 and 4 be retrofitted with a 

DFGD to meet the prescribed SO2 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 NOx 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 Station’s environmental control requirements: 

 Cross State Air Pollution Rule2

 

2

U.S. EPA issued the final CSAPR in July, 2011. The rule was 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 Gas (GHG) Regulation 

 Revisions to the 1 hour SO2 Primary National Ambient 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 settlement in principle 

around the Northeastern coal units, AEPSC, as agent for PSO, issued an RFP for 260 MW of 

base-load capacity and energy and ancillary services for a desired term of 15 years, beginning 

June 1, 2016. This capacity and energy would serve to effectively replace Northeastern Unit 4. 

Specifically, the agreement addresses PSO’s future obligations under the EPA’s Regional 

Haze rule (RHR) and effectively allows PSO to comply with the Mercury and Air Toxics 

Standard (MATS). Under the agreement, PSO would meet specified emissions rates at both 

Northeastern coal units, install certain emissions control equipment on one of the Northeastern 

coal units in 2016, and retire the other unit in 2016. The coal unit with the emissions controls 

would be retired in the 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 Quality (ODEQ), and ODEQ 

will develop and adopt after public notice and hearing, 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 Regional 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 for 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 combustion 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 Station (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 Northeastern Units 3 and 4 of 0.65 lbs/MMBtu on 

a 30-day rolling average, and beginning on December 31, 2014, PSO will comply with a 

new SO2 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 retired as provided in 

subparagraph d). The RHA will include an alternative operating scenario that addresses 

potential disruption of coal supplies during 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 fabric 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 SO2 on a 30-day rolling average basis.

f) The RHA will require that during the first year of operation of the controls required under 

the RHA, PSO will develop and propose a monitoring program to test various operating 

profiles and other measures, to determine whether increased SO2 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 and will implement the 

monitoring program during the second and third 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 

8 

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 hearing, the ODEQ will submit the revised RH 

SIP revision to EPA for approval. If the demonstrated emission rate is 0.37 Ibs/MMbtu or 

greater, no adjustment will be made to the RHA, and the emission rate limitation for SO2

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

Ibs/MMBtu.

g) The RHA will require that beginning in calendar year 2021, the Annual Capacity Factor

(calculated for each calendar year as a percentage of MWH based on a rated capacity of 

470 MW X 8760 hours) for the operating coal-fired 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 unit at Northeastern Station. However, in 

calendar year 2021, the RHA will 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 available from such resources at a lower 

projected total cost (including consideration of PSO's need to recover its remaining 

investment in the units), then the operating unit will retire no later than December 31, 

2025.
 PSO 2012 Integrated Resource Plan 

9 

2. Nothing in the RHA relieves PSO from its obligations to comply with all applicable federal, 

state, and local laws and regulations, including 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 Pollution Rule and the Mercury and Air Toxics 

Standards (MATS). Nothing in the revised BART 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 SO2 reductions from sources other than those operated 

by PSO, to the extent necessary to achieve the anticipated visibility benefits from the 2018 

regional modeling. This proposed SIP revision will be implemented if the SO2 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 and PSO will enter into an agreement under which 

PSO will report biannually to EPA (beginning 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. Requests 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 copies of any RFPs issued during the reporting period, and a 

summary of the capacity or energy secured through any long-term power purchase 

agreements executed during the reporting period, 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 described in the RHA, 
 PSO 2012 Integrated Resource Plan 

10 

when properly designed and operated, would be expected to achieve the emission limitations 

prescribed by the MATS rule issued February 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 attached to the Settlement Agreement. 
 PSO 2012 Integrated Resource Plan 

11 

2.0 Load Forecast and Forecasting 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 process 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 electricity at the aggregated customer level: 

Residential, Commercial, Industrial, Other Ultimate customers, and Municipals and 

Cooperatives. It involves modeling both the short- and long-term sales. The second process 

contains models that derive hourly load estimates from blended short- and long-term sales, 

estimates of energy losses for distribution and transmission, and class and end-use load shapes. 

The aggregate revenue class sales and energy losses 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 process reconciles historical net internal energy requirements and 

seasonal peak demands through a load factor analysis which results in the load forecast. 

The long-term forecasts are developed using a combination of econometric models to 

project load for the Industrial, Other Ultimate and Municipal and Cooperative customer classes, 

as well as using Itron Inc. Statistically-Adjusted End-use (SAE) models for the modeling of 

Residential and Commercial 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 projections of employment, population, and other 

demographic and financial variables for both the U.S. as a whole and for specific AEP service 

territories. The long-term forecasting process incorporates these economic projections and other 

inputs to produce a forecast of kilowatt-hour (kWh) sales. Other inputs include regional and 

national economic and demographic conditions, energy prices, weather data, and customerspecific information. 

The AEP Economic Forecasting department employs Itron’s Statistically Adjusted Enduse (SAE) models for forecasting long-term Residential and Commercial kWh energy sales. 

 SAE models are econometric models with end-use features included to account 

for energy efficiency impacts, such as those included in the Energy Policy Act 

of 2005 (EPAct 2005) and the Energy Independence and Security Act of 2007 

(EISA). 

 SAE models start with the construction of structured end-use variables that 

embody end-use trends, including equipment saturation levels and efficiency. 

Factors are also included to account for changes in energy prices (retail rates), 

household size, home size, income, and weather conditions. 

 Regression models are used to estimate the relationship between observed 

customer usage and the structured end-use variables. The result is a model that 

has implicit end-use structure, but is econometric in its model-fitting technique. 

 The SAE approach explicitly accounts for naturally occurring energy efficiency 

which has served to slightly lower the forecast of Residential and Commercial 
 PSO 2012 Integrated Resource Plan 

13 

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 employ the latest available sales 

and weather information to represent the variation in sales on a monthly basis for short-term 

applications. While these models generally produce accurate forecasts in the short run, without 

specific ties to economic factors they are less capable of capturing the structural trends in 

electricity consumption that are important for longer-term planning. The long-term modeling 

process, with its explicit ties to economic and demographic factors, is appropriate for longerterm decisions and the establishment of the most likely, or base case, load and demand over the 

forecast period. By overlaying these respective output profiles, AEP Economic Forecasting can 

then effectively apply the strengths of both load-modeling approaches, thereby achieving a 

reasonable validation of such forecasted results. 

2.2 Peak Demand Forecast 

Figure 2-2 identifies the PSO internal demand and energy profile as having -0.03% and 

0.22%, respectively, compound annual growth rates (CAGR) in the forecast period. 

Figure 2-2: PSO Peak Demand and Energy Projection
 PSO 2012 Integrated Resource Plan 

14 

Figure 2-3 reflects PSO’s actual and weather normalized historical and forecast of annual 

peak demand. PSO’s weather normalized historical 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 2022

Peak Demand in MW

Actual Weather Normalized Forecast

2.3 Load Uncertainty 

Two factors of load uncertainty is weather in the short-term and the gain 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 two 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 and winter peak demands were 

significant at 4,411 MW and 2,829 MW, occurring on August 3rd and February 10th, 

respectively. This all-time PSO summer peak demand 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 peak demand created an increase versus the 

forecast of 216 MW, or a 5.1 percent increase. 
 PSO 2012 Integrated Resource Plan 

15 

The preliminary 2012 summer peak demand has 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 two summers loads have been driven by record 

setting summer weather. 

PSO is currently learning about increases in potential new load as a result of increased oil 

and natural gas production and natural gas processing and compression that is beyond that 

reflected in the current peak demand forecast. If this new load materializes over the next two – 

three years PSO will need to secure additional supply- or demand-side resources to reliably serve 

this new load. 

2.4 PSO Current Demand-Side Resources

2.4.1 Energy Efficiency 

PSO has had energy efficiency programs in place since 2009. Since 2009, PSO has 

residential and commercial programs that resulted in an annual reduction of 53 GWh through 

year-end 2011. Current and proposed programs are expected to improve this 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 programs, as well as a continuation of programs 

through 2025 are shown, where the difference between installed and forecast illustrates the 

measure degradation that results over time. Programs amounting to the installation of 

approximately 800 GWh of annual reductions are factored into the load forecast. These programs 

place PSO on a pace to exceed the plan presented in the 2009 Market Potential Study. 

Currently, energy efficiency programs are limited to the residential and commercial 

sectors; industrial customers have the ability, and have in most part chosen, to opt out. 
 PSO 2012 Integrated Resource Plan 

16 

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 2021

Annual Energy Savings from Energy Efficiency (GWh)

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

Figure 2-5: Annual Energy Consumption 
 PSO 2012 Integrated Resource Plan 

17 

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 response capability. It is constituted of the 

Business Demand Response Program (56MW), and interruptible tariffs (22MW). Residential 

direct load control has been discontinued. PSO expects to grow demand response capability to 

150 MW by 2025, primarily in the commercial and industrial sectors. 

2.4.3 Smart Grid 

2.4.3.1 gridSMART® Smart Meter Pilots 

PSO’s gridSMART® project includes up to 16,000 smart meters, distribution automation 

and Volt/VaR Optimization equipment, and consumer energy management devices. The total 

cost of the project is estimated at $17.88 million. PSO was awarded an $8.7 million low-interest 

loan from the Oklahoma Department of Commerce’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 communication in Owasso, Oklahoma. 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 customers to time-of-use rates 

in conjunction with technologies such as in-home displays, programmable two-way 

communicating thermostats, and a home energy manager with remote access and control via the 

web. Because this program is still in the piloting 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 provides all of the benefits of 

power factor correction, voltage optimization, and condition-based maintenance in a single, 

optimized package. In addition, VVO enables conservation voltage reduction (CVR) on a 
 PSO 2012 Integrated Resource Plan 

18 

utility’s system. CVR is a process by which the utility systematically reduces 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 designed so that customers close to the substation 

received voltages close to 126 volts and customers farther from the substation received lower 

voltages. This design kept line construction costs low because voltage regulating equipment was 

only applied when necessary to assure the required minimum voltages were provided. However, 

since most devices operated by electricity, especially motors, are designed to operate most 

efficiently at 115 volts, any excess voltage is typically 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 energy to accomplish the same tasks. 

Not all circuits are good economic candidates for VVO. Currently, PSO anticipates 

fitting distribution circuits serving 62% of its load with the new technology. 

Figure 2-6: Integrated Voltage/VaR Optimization 

PSO anticipates accelerating and increasing the roll-out of VVO technology relative to 

what was in the August 2011 forecast. This acceleration and increase in the VVO plan amounts 

to a decreased requirement of 20MW by 2021 relative to the forecast used in the IRP modeling 

(see Table 2-1). This variation would not materially affect the modeling results. 
 PSO 2012 Integrated Resource Plan 

19 

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 efficiency programs, 

demand response, and the newest smart grid technologies to meet its resource needs. Under the 

current plan, demand-side resource reduces capacity requirements by 166 MW (see Table 2-2) 

from the current capability by 2021. 

Table 2-2 Demand-Side Resource Summary3

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-term 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. 
 PSO 2012 Integrated Resource Plan 

20 

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
 PSO 2012 Integrated Resource Plan 

21 

3.0 Existing Resources and Transactions 

3.1 Current Resources 

The initial step in the IRP process is the demonstration of the capacity resource 

requirements. This needs assessment must consider projections of: 

 Existing capacity resources—current levels and anticipated changes 

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

projects 

 Changes resulting from decisions surrounding unit disposition evaluations 

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

 Load and (peak) demand 

 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 Capacity, Demand and Reserves (CDR) 

report for the 15-year period through the year 2025 assuming no new capacity additions. In 

addition to identifying current projected peak demand 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 (seasonal ratings) to achieve this threshold. 

 

4

 Per Section 2.1.9 of the “Southwest Power Pool 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. 
 PSO 2012 Integrated Resource Plan 

22 

Table 3-1: Capacity, Demand and 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 Responsibility 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 resources 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 under a 10-year power purchase agreement (PPA) 

with Exelon Generating Company LLC, from the Green Country Generating Station located in 

Jenks, OK. 
 PSO 2012 Integrated Resource Plan 

23 

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 Capability (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 Company is receiving energy, capacity, and renewable 

energy credit attributes under separate renewable 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 
 PSO 2012 Integrated Resource Plan 

24 

capacity rating. Specifically, the latest SPP Criteria (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 the 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 current resources and its peak demand 

projections (Section 2); a capacity needs assessment can be established that will determine the 

amount and timing of capacity resources 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 (bar) trends over the period. Figure 3-2 reflects the culmination of 

the separate impacts. 

Figure 3-1 Capacity vs. SPP Minimum Required Reserves 
 PSO 2012 Integrated Resource Plan 

25 

Figure 3-2 Summary of Capacity Deficiency Position 

3.4 Impacts of Environmental Compliance Plan 

As a result of the environmental rules, there 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) and the established requirements of the Mercury 

Air Toxic Standard (MATS) rulemaking, it would suggest that Northeastern Units 3 and 4 will 

ultimately require nitrogen oxide (NOX), sulfur dioxide (SO2), hazardous air pollutant (HAP) and 

acid gas emission reductions under 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 Baghouse) by 2016 assuming the one year compliance 

deadline extension is granted by ODEQ or cease 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 various times. Generally, these investments fall 
 PSO 2012 Integrated Resource Plan 

26 

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

Distributed Generation

3.5.2 Energy Efficiency 

Energy efficiency programs offer consumers incentives to replace or otherwise purchase 

end-use devices (light bulbs, air conditioners, refrigerators, 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 current 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 reduction in load at times of peak demand on 

the system. For a monetary incentive, customers agree to reduce load within an allocated time of 

receiving a signal from the utility. The demand response mechanism can be as simple as a direct 

load control device that turns off an air conditioner or as sophisticated as a programmed suite of 

controls that selectively reduces load on several systems, minimizing 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-efficient utility generators are called upon to run.

3.5.4 Smart Grid 

Smart Grid investments are improvements to the distribution grid, up to and including the 

meter. In a general sense, it is the replacement 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 utility 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 small, dispersed generation 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 
 PSO 2012 Integrated Resource Plan 

27 

solar, wind, and combined heat and power (CHP). Back-up (emergency) generators are not 

counted here, but may be considered 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, approximately 3,490 miles of 138 kV, and 2,320 miles 

of 69 kV. The AEP-SPP zone is also integrated with and directly connected to ten other 

companies at 89 interconnection points, of which 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 resources, as well as a delivery mechanism to 

neighboring systems. 

3.6.2 Current AEP-SPP Transmission System Issues 

The limited capacity of interconnections between SPP and neighboring systems, as well 

as the electrical topology of the SPP footprint transmission system, influences the ability to 

deliver 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 significantly slowed down the 

process of developing new interconnections. Despite the robust nature of the AEP-SPP 

transmission system as originally designed, its current use is in a different manner than originally 

designed, in order to meet SPP RTO requirements, which can stress the system. In addition, 

factors such as outages, extreme weather, and power transfers also stress the system. This has 

resulted in a transmission system in the AEP-SPP zone that is constrained when generation is 

dispatched in a manner inconsistent with the original design of utilizing local generation to serve 

local load. The resulting use of the AEP-SPP system is inconsistent with the assumptions used to 

develop the modeling data AEP provides to SPP to develop and plan the system. SPP uses 

models developed from data provided 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 transmission expansion plan (STEP). The STEP 

is developed through an open stakeholder process with AEP participation. SPP studies the 
 PSO 2012 Integrated Resource Plan 

28 

transmission system, checking for base case and contingency overload and voltage violations in 

all of the SPP base case load flow models, plus models which include power transfers biased in 

the various transfer directions. 

The 2012 STEP summarizes 2011 activities, including expansion planning and long-term 

SPP Open Access Transmission Tariff studies (Tariff Studies) that impact future development of 

the SPP transmission grid. Seven key topics are included in the STEP: 

1) Integrated Transmission Planning 

2) Tariff Studies, 

3) Sub-regional and local area planning, 

4) Transmission Congestion and top Flowgates 

5) Interregional coordination, 

6) Project tracking; and 

7) Public Policy Impacts 

These topics are critical to meeting mandates of either the SPP strategic plan or the nine 

planning principles in FERC Order 890. As a RTO under the domain of the Federal Energy 

Regulatory Commission (FERC), SPP must meet FERC requirements and the SPP Open Access 

Transmission Tariff (OATT or Tariff). The SPP RTO acts independently of any single market 

participant or class of participants. It has sufficient scope and configuration to maintain electric 

reliability, effectively perform its functions, and support efficient and non-discriminatory power 

markets. Regarding short-term reliability, the SPP RTO has the capability and exclusive 

authority to receive, confirm, and implement all interchange schedules. It also has operational 

authority for all transmission facilities under its control. The 10-year RTO regional reliability 

assessment continues to be a primary focus. 

STEP projects are categorized by the following designations: 

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

 Generation Interconnect – Projects associated with a FERC-filed Interconnection 

Agreement; 

 Interregional- Projects developed with neighboring Transmission Providers; 

 ITP - Projects needed to meet regional reliability, economic, or policy needs in the 

ITP study process; 
 PSO 2012 Integrated Resource Plan 

29 

 ITP – Non-OATT – Projects to maintain reliability for SPP members not 

participating under the SPP OATT 

 Transmission service – Projects associated 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 network upgrades with a total cost of 

approximately $7.1 billion. These include Network Upgrades required for NERC Reliability 

Standards or SPP Criteria; Zonal Reliability Upgrades (compliance to Transmission Owner 

company-specific planning criteria); requests for transmission service under the Tariff with a 

FERC-filed Service Agreement; and generation interconnections with a FERC-filed 

interconnection agreement. 

At the heart of SPP’s STEP process is its Integrated Transmission Planning (ITP) 

process. The ITP process was designed to maintain reliability and provide economic benefits to 

the SPP region in both the near and long-term. The ITP process was conducted in three phases. 

The first phase recommended a long-term transmission 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 projects for comprehensive regional solutions, local 

reliability upgrades, and the expected reliability and economic needs of a 10-year horizon. 

Finally, the third phase of the ITP 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 assessments of company transmission capabilities 

indicate that, when considering a single contingency outage event, the present firm capability 

transfer limit from PSO to SWEPCO is about 200 MW, and from SWEPCO to PSO is about 900 

MW. As much as 900 MW may be available bi-directionally for economical energy transfers 

when no transmission facilities are out of service. However, the intra-company available 

transmission capability between the two companies is available to all transmission users under 

the provisions established by FERC Order 888 and subsequent orders. Thus, there is some 
 PSO 2012 Integrated Resource Plan 

30 

question as to whether, in the future, as SPP grants further transmission rights, any transfer 

capability will in fact be available without further upgrades to the transmission system. 

As previously indicated, each company’s capacity additions are planned so that each 

meets its own reserve requirement over the long-term. Any capacity transfers (i.e. “reserve 

sharing”) should be considered for short time frames only. Specifically, the practice has been 

that, as the last step of the planning process, the respective PSO and SWEPCO expansion plans 

are adjusted to take advantage of any surplus of one company that might match a potential deficit 

of the other, and thereby delay some of the identified new capacity. Because of the sizes, 

demand growth rates, and peak coincidence of the two companies, it rarely appears that either 

company would ever have more than 200 MW of surplus capacity in any year that could be 

transferred to the other company. 

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 transmission facilities by the neighboring systems or through 

sponsored upgrades by SPP transmission owners. An analysis of the cost of the upgrades cannot 

be performed until the capacity resources are determined. For identified resources, the cost of 

any transmission upgrades necessary on AEP’s transmission system can be estimated by AEP 

once SPP has identified the upgrade. AEP’s West Transmission Planning group can identify 

constraints on third-party systems through ad hoc power flow modeling 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 performs other special studies or area studies 

on an as needed basis. One recent SPP study that resulted in approved projects that may lead to 

improve transfer capability between AEP-SPP and neighboring companies and regions is the 

Priority Projects study. Among the projects approved as a result of this study are: 
 PSO 2012 Integrated Resource Plan 

31 

 Double circuit 345 kV line in southwestern Kansas from Spearville to Comanche 

County to Medicine Lodge to Wichita 

 Double circuit 345 kV line from southwestern Kansas (Medicine Lodge) to 

northwestern Oklahoma (Woodward) 

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

 A 345 kV line from Valliant, in southeastern Oklahoma to Northwest Texarkana in 

northeastern Texas 

3.6.3 Recent AEP-SPP Bulk Transmission Improvements 

Over the past several years, there have been several major transmission enhancements 

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

 Northwest Arkansas— Northwest Arkansas is one of the fastest growing areas on the 

AEP-SPP Transmission System. The approximate 1,300 MW of load in this area, about 

49% 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 Clarksville-Chamber Springs 345 kV line. WalMart’s international headquarters and its supplying businesses’ offices and Tyson’s 

headquarters are all located in this area. A new 345 kV line 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 Centerton 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 will 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 Lake 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 contingency low voltage and thermal overloads in 

Bossier City, Louisiana and the vicinity; and supply a second feed to the Port, Bean, 

Caplis, McDade, and Haughton stations. 
 PSO 2012 Integrated Resource Plan 

32 

 Turk Generation Interconnection – In order to connect the 600 MW coal-fired Turk 

Power Plant in southwestern Arkansas, near McNab, to the transmission system, the 

Turk 345/138/115 kV substation was built and several 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 completed in the second half of 2012. This 

expansion provides the interconnection of the Turk Power Plant, transmission service, 

improved reliability for the City of Hope and southwestern Arkansas, and improved 

reliability to Texarkana by completing 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 approximately 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 generation capacity within the AEP-SPP zone will likely require 

significant transmission upgrades. At most locations, any additional generation resources will 

aggravate existing transmission constraints. Specifically: 

 Western Oklahoma/Texas Panhandle—there are very few EHV transmission lines in 

this area. In fact, transmission facilities above 69 kV are limited. However, the area is 

one of the highest wind density areas within the SPP RTO footprint. The potential wind 

farm capacity for this area has been estimated to exceed 4,000 MW. Several wind farms 

have already been built, and several more are in the development stages. Wind 

generation additions in the SPP footprint in this region will likely require significant 
 PSO 2012 Integrated Resource Plan 

33 

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 resources in its service area. The Danville 

to North Magazine 161 kV line rebuild increased the transfer capability from SWEPCO 

to PSO to approximately 900 MW. Also, the Broken Bow to Craig Junction 138 kV 

line rebuild increased the transfer capability from PSO to SWEPCO to approximately 

200 MW. An SPP approved project, mentioned above, to build a 345 kV line 

approximately 76 miles from Valliant substation to Northwest Texarkana substation will 

improve transfer capability by forming a second 345 kV path between PSO and 

SWEPCO’s transmission system in northeastern Texas. Significant generation additions 

to the AEP-SPP transmission facilities (or connection to neighbor’s facilities) may 

require significant transmission enhancements, possibly including EHV line and station 

construction, to address thermal, voltage, and stability constraints. 

 Tulsa Metro Area—the Tulsa metro area load is supplied primarily by the PSO 

Northeastern, Riverside, and Tulsa Power Station generating plants. Additionally, 

Oklahoma Gas & Electric Company has large generation plants located to the southeast 

and southwest of Tulsa, and there are large merchant plants just east and south of Tulsa. 

The Grand River Dam Authority has a large plant located to the east of Tulsa. 

Generation additions in the Tulsa area would likely require significant enhancements in 

the EHV and sub-transmission system to address thermal, voltage and stability 

constraints. 

 SPP Eastern Interface—there are only five east-west EHV lines into the SPP region, 

which stretches from the Gulf of Mexico (east of Houston) north to Des Moines, Iowa. 

This limitation constrains the amount of imports and exports along the eastern interface 

of SPP with neighboring regions. It also constrains the amount of transfers from the 

capacity rich western SPP region to the market hubs east and north of the SPP RTO 

region. Significant generation additions near or along the SPP eastern interface would 

likely require significant transmission enhancements, including EHV line and station 

construction, to address thermal and stability constraints should such generation 

additions adversely impact existing transactions along the interface. 
 PSO 2012 Integrated Resource Plan 

34 

Integration of generation resources at any location within the AEP-SPP zone will require 

significant analysis by SPP to identify potential thermal, short circuit, and stability constraints 

resulting from the addition of generation. Depending on the specific location, EHV line and 

station construction, in addition to connection facilities, could be necessary. Other station 

enhancements, including transformer additions and breaker replacements may be necessary. 

Some of the required transmission upgrades could be reduced or increased in scope if existing 

generating capacity is retired concurrent with the addition of new capacity. 

3.6.5 Summary of Transmission Overview 

In the SPP region, the process of truly integrating Generation and Transmission planning 

is still developing. AEP continues to stand ready to engage in that process. At this time, though, 

PSO and SWEPCO can do very little to import capacity from outside of its control area. Both 

companies have been open to such imports as evidenced by the issuing of recent RFP’s for nonsite specific generation types. These RFP’s allow bidding entities to offer generation coupled 

with transmission solutions, which would be subject to SPP approvals. 
 PSO 2012 Integrated Resource Plan 

35 

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 speculative trading. In many respects, 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 the 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 foundation of its risk 

management plan. By investing in and using generating plants that 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 costs due to the potential price volatility of any 

one particular fuel source. PSO’s ability to mitigate the price volatility of its overall fuel cost has 

been primarily attributable to effective management 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 economically 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 fuel factor period and are effectively insulated 

from short term price volatility in the fuel markets. To date, PSO’s successful hedging and risk 

management program has not utilized instruments 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 retired, and as natural gas Purchased Power Agreements (PPAs) are 

added to the portfolio, PSO’s efforts to mitigate the price volatility of its fuel supply will be 

faced with additional challenges and opportunities 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 
 PSO 2012 Integrated Resource Plan 

36 

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

the overall lowest reasonable fuel cost. PSO helps to ensure the provision of reliable electric 

service to its customers by maintaining a coal inventory to be both proactive and responsive to 

known, anticipated, and potential changes in operating, coal supply, and rail transportation 

conditions. In addition, PSO’s coal inventory mitigates risk and allows the Company to take 

advantage of favorable market conditions. 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 volatility of coal, through a variety of methods. The majority 

of the coal used as boiler fuel on PSO’s system is procured through competitive 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 additional 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 portfolio of coal contracts has sufficiently provided 

an effective price hedge for PSO’s coal costs. PSO’s hedging strategy for coal was driven in part 

by (1) coal’s position as a base load fuel, (2) the fairly predictable 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 later time at PSO’s discretion. 

The marginal supply source in PSO’s generation portfolio is typically 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 during real-time market operations, 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 maintenance and forced outages, to follow daily and hourly load swings, and 

for voltage support. 

In the intra-day market (real-time), American Electric Power Service Corporation’s 

(AEPSC’s) hourly marketers, production coordinators, natural gas coordinators, and generation 

dispatchers work closely to optimize the PSO system by taking into consideration 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 
 PSO 2012 Integrated Resource Plan 

37 

forecasted marginal generation (dispatch) cost, 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 natural 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 the summer peak period of June through August, PSO 

has entered into some seasonal firm supply contracts 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 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 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, PSO’s existing natural gas transportation contracts 

include services that already provide the reliability that storage services would offer. Unlike coal 

stockpiling, where stockpiles can be created for use at a later time at PSO’s discretion, ratable 

flow restrictions are required when pulling natural gas from storage. PSO’s analysis has 

indicated 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 advance. Storage injections and 

withdrawals must be accomplished at a steady flow rate and are not responsive to the peaking 

demands of natural gas electric 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 typically higher and withdraw 

gas in the summer to meet the summer peak demands. As a result, natural gas storage has not 

evolved to be a viable operational or economic alternative for PSO. 

4.3 PSO’s Fuel Supply Mix & Regional Market Structures Are Changing 

PSO’s fuel supply portfolio will experience significant changes in the years ahead. By 

recent agreement, PSO will be required to meet specified emission rates at both Northeastern 

coal units, install certain emissions control equipment on one of the Northeastern coal units and 
 PSO 2012 Integrated Resource Plan 

38 

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 MWs of capacity and energy through its longterm PPA with Exelon Generation Company LLC, a subsidiary of Exelon Corporation. The 

agreement is the result of PSO’s 2008 Request for 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 base 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 capacity and energy shortage resulting from the 

retirement of Northeastern Unit 4 in 2016 as a part of PSO’s settlement with the Environmental 

Protection Agency (EPA). Between these aforementioned PPA’s, PSO will have the contractual 

rights to over 750 MWs of highly efficient natural gas-fired generation. 

Although PSO’s generation portfolio 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 that PSO will need to procure. SPP is currently pursuing the 

implementation of its SPP IM, with an expected start date in the first half of 2014. The SPP IM 

requirement for centralized unit commitment could result in material changes to the dispatch of 

PSO’s generation fleet. Until the SPP IM begins operation, it is difficult to determine the level 

of PSO’s base load natural gas hedging needs. 

The implementation of the SPP IM will also provide PSO with additional tools to 

optimize its purchased power activities. A centralized day-ahead power market is likely to 

increase the number of market participants, provide additional clarity on medium-term power 

prices, and spur the introduction of additional trading 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 portfolio 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 dominant reliance on natural gas introduces both 

challenges and opportunities that will be incorporated into PSO’s ongoing analysis of its fuel and 

purchased power hedging strategy. In particular, there are markedly different hedging 

opportunities, hedging instruments, pricing dynamics, and the relative willingness of producers 
 PSO 2012 Integrated Resource Plan 

39 

and end users that are different between coal and natural gas. For example, coal hedging 

opportunities have been traditionally 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 that the plants would 

run if available to run. As a result of that relative certainty, it was quite reasonable to lock-in 

some long-term and mid-term agreements and pursue spot purchases to address variations in 

generation burn from the forecasted burn. However, the broad changes underway to PSO’s fuel 

supply requirements creates less certainty and will 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 more 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 inventory of a plant with less certainty of burn would 

require less coal in its inventory as it could manage through short to medium delivery disruptions 

with more ease. Circumstances will still warrant maintaining a diversity of suppliers and 

staggering terms. 

The increasing uncertainty regarding PSO’s physical natural gas needs will add 

additional complexity to hedging PSO’s natural gas price risk through a staggered portfolio of 

physical contract purchases. Although PSO anticipates a decline over its current level, some 

mid- to long-term procurement of physical natural gas may continue to be utilized to ensure 

reliable supply and to hedge price risk. In part, PSO’s natural gas supply portfolio will be 

influenced by projections for the overall supply of natural gas. Mid- to long-term physical 

contracts would become more likely should natural gas supplies, which are currently plentiful, 

become more difficult to obtain and the Company must ensure that natural gas supplies are 

available to support the reliability of electric supply to customers. In light of the uncertainty 

surrounding PSO’s expected natural gas burn, natural gas storage may provide 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 plants will be called on to run on any given day, 

potentially increasing the value of the flexibility provided by natural gas storage. In addition, 
 PSO 2012 Integrated Resource Plan 

40 

certain hedging strategies, using the financial hedging tools discussed in greater detail below, can 

be used in combination with physical hedges which can be executed through the use of natural 

gas storage. As a result, storage may become a more viable operational and economic 

alternative. 

As mentioned above, mitigating the price volatility of natural gas introduces a much 

broader range of considerations and instruments. For example, natural gas has moved from a 

long-term physical contracting basis that existed prior to the deregulation of the natural gas 

market, to a much shorter-term contract basis as competition increased. Another significant 

factor impacting the successful hedging strategy surrounding natural gas procurement has been 

the unprecedented price volatility over the last decade and a half. And finally, until recently, 

there has been a great deal of concern over the long-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 liquid, robust number of financial trading 

instruments that could be used to hedge some of PSO’s natural gas price 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. Financial derivatives are hedging instruments in the 

form of contractual agreements between two parties 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 swaps, (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 whereby a floating (market or spot) price is 

 exchanged for a fixed price on a future, specified 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. 
 PSO 2012 Integrated Resource Plan 

41 

 Call and Put Options – a financial 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 (option holder) must pay the option seller (option 

 writer) a premium to enter the contract. Regardless of how the market swings, the 

 most an option buyer can lose 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 selling 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. 
 PSO 2012 Integrated Resource Plan 

42 

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 flexibility, asset mix considerations, adaptability to 

risk, conformance with applicable North American Electric Reliability Corporation (NERC) and 

RTO criteria, and customer affordability. In addition, given the unique impact of generation on 

the environment, the planning effort must ultimately 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 supply-side resources and 

demand-side management (DSM) programs. 

In general, assumptions and plans are continually reviewed and modified as new 

information becomes available. Such continuous analysis is required by multiple disciplines 

across AEP to ensure that: market structures and governances; technical parameters; regulatory 

constructs; capacity supply; energy adequacy and operational reliability; and environmental 

mandate requirements are constantly reassessed to ensure optimal capacity resource planning. 

Further impacting this process are a growing number of federal and state initiatives that 

address many issues relating to industry restructuring, customer choice, and reliability planning. 

Currently, fulfilling a regulatory obligation to serve native load customers represents one of the 

cornerstones of the PSO IRP process. Therefore, as a result, the “objective function” of the 

modeling applications utilized in this process is the establishment of the least-cost plan, with cost

being more accurately described as revenue requirement under a traditional ratemaking 

construct. 

That does not mean, however, that the best or optimal plan is the one with the absolute 

least cost over the planning horizon evaluated. Other factors–some more difficult to monetize 

than others–were considered in the determination of the plan. To challenge the robustness of the 

Plan, sensitivity analyses were performed to address these factors.

5.2 Methodology 

The IRP process aims to address the long-term gap between resource needs and current 

resources. Given the various assets and resources that can satisfy this expected long-term gap, a 
 PSO 2012 Integrated Resource Plan 

43 

tool is needed to sort through the myriad of potential combinations and return an optimum 

solution–or portfolio–subject to constraints. Strategist® 7 is the primary modeling application, 

used by AEP for identifying and ranking portfolios that address the gap between needs and 

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

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

prices including CO2, and demand, Strategist® will return all combinations of the proxy 

resources (portfolios) that meet the resource need. The portfolios are ranked on the basis of cost, 

or cumulative present worth (CPW), of the resulting stream of revenue requirements. The least 

cost option was considered the initial “optimum” portfolio for that unique input parameter 

scenario. 

5.3 Fundamental Modeling Input Parameters 

The long-term power sector suite of commodity forecasts are derived from a proprietary 

model known as AURORAxmp. AURORAxmp is a long-term fundamental production-costing 

tool developed by EPIS, Inc. that is driven by comprehensive 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 

AURORAxmp. Similarly, capital costs and performance parameters for various new-build 

generating options, by duty-type are vetted through AEP Engineering Services and incorporated 

into the tool. Other information specific to the 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 unit capacity, heat rates, retirement dates and 

emission controls status. AEP uses AURORAxmp to model the eastern synchronous interconnect 

as well as ERCOT. The CO2 forecast is based on assumptions 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. 
 PSO 2012 Integrated Resource Plan 

44 

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 initially used to generate the output report. The 

output is used as feedback to change the base input assumptions. This iterative process is 

repeated until the output is congruent with the input assumptions (e.g., level of natural gas 

consumption is suitable for the established price and all emission constraints are met). 

Commodity pricing forecasts as well as modeled CO2 pricing that were used in the IRP 

economic modeling are shown in Table 5-1.
 PSO 2012 Integrated Resource Plan 

45 

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)

CO2

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 CO2 Forecast 

Each of the pricing forecasts also assume a CO2/carbon impact as a result of the 

implementation of any prospective carbon-reduction legislation; however, that perspective is 

reflected assuming three unique sets of implementation timing. The Base view assumed such 

legislation would be effective by 2022. The relative timing for the Base view (2022) is largely in 

recognition of the potential continued aversion in the U.S. Congress to passing comprehensive 

CO2 legislation that would establish either a carbon-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, plus the assumption based on prior proposed CO2

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 

CO2/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 calculation tool from which the PSO 

capacity requirements were examined and resource addition recommendations were made as part 

of the IRP process. In this process, Strategist® offers unique “portfolios” of capacity resource 

options for PSO 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-defined sets of resource technologies, commodity 

pricing, and prescribed sets of constraints. 

Strategist® develops a least-cost resource mix by considering a variety of expansion 

planning assumptions including: 

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

life). 

 Operating parameters (e.g., capacity ratings, heat rates, outage rates, emission 

effluent rates, must-run status, etc.) of existing and new units. 

 Unit dispositions (retirement/mothballing). 

 Delivered fuel prices. 

 Prices of external market energy as well as SO2, NOX, and CO2 emission 

allowances. 

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

 Transmission limitations. 

 Emission limits and environmental compliance options. 

 Alternative distribution system solution (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 scenarios. The model determines and reflects such 

impacts on overall system variable operating costs. Strategist® does not develop a full 

regulatory cost-of-service (COS) profile. Rather, it typically considers only those 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 would 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 words, generic (nondescript or 

non-site specific) capacity resource modeling would not typically incorporate significant capital 

for transmission interconnection. 

Specifically, Strategist® includes and recognizes in its revenue requirement 

calculation: 

 Fixed costs of capacity additions, i.e., carrying charges on capacity and associated 

transmission (based on PSO’s weighted average cost of capital), and fixed O&M. 

 Fixed costs of any capacity purchases. 

 Installation and administrative costs of DR/EE alternatives. 

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

Agreement. 

 Variable costs associated with the entire fleet of new and existing generating units 

(using its probabilistic unit dispatch optimization engine). This includes fuel, 

purchased energy, market replacement cost of emission allowances, and variable 

O&M costs. 

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

are netted against costs. 

In the PROVIEW module of Strategist®, the least-cost expansion plan is formulated from 

potentially tens of thousands of resource alternative combinations created by the module’s 

dynamic programming algorithm. On an annual basis, each capacity resource combination that 

satisfies various user-defined constraints (to be discussed below) is considered to be a “feasible 

state” and is saved by the program for consideration in following years. As the years progress, 

the previous years’ feasible states are used as starting points for the addition of more resources 

that can be used to meet the current year’s minimum reserve requirement. As the need for 

additional capacity on the system increases, the number of possible combinations and the number 

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

considered. 
 PSO 2012 Integrated Resource Plan 

49 

6.1.1 Key Input Parameters 

Two of the major underpinnings in this process are long-term forecasts of PSO’s energy 

requirements and peak demand, as well as the price of various generation-related commodities, 

including energy, capacity, coal, natural gas, and CO2/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 organization, while the long-term commodity pricing 

forecast was created by the AEP Fundamental Analysis group. Moreover, the Fundamental 

Analysis group constantly performs peer review by way of comparing and contrasting its 

commodity pricing projections versus consensus 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 Information Administration (EIA). 

Other critical input parameters include the installed cost of both environmental retrofits 

required and replacement capacity alternative options, as well as the attendant operating costs 

associated with those options; data which was sourced from the AEP Engineering 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 the answer; rather, it produces or suggests many portfolios that 

have different cost profiles under different scenarios and sensitivities. Portfolios that fare well 

under all scenarios and sensitivities are considered for further evaluation. The optimum, or leastcost, portfolio under one scenario may not be the least-cost portfolio in other scenarios. Portfolio 

selection may reflect strategic decisions embraced by PSO Management, including a 

commitment to DR/EE, renewable resources, 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 substitutes a combined cycle plant for an equivalent 

amount of CTs might be constructed and tested to determine whether the revenue requirements 

are significantly different. Constraining the model to insert some additional practical constraints 
 PSO 2012 Integrated Resource Plan 

50 

or conform to a company’s strategy often can yield a more diversified solution that is not 

significantly more expensive. The optimum or least expensive portfolio under a scenario may 

have practical limitations that Strategist® does not take into full account or may result in a plan 

that is very expensive under a different scenario. 

6.2.2 Strategic Portfolios 

Strategist® was used to develop the PSO plan development alternatives below. Portfolios 

with various options concerning Northeastern 3 & 4 were evaluated under different pricing 

scenarios. As indicated below in TABLE 6-1, three 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 6-18

(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 minimal. 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 retirement decisions and hence ultimate 

attendant impacts on commodity pricing. Given that the option-specific economic analyses around the Northeastern 

coal units were not distinguishable until at least the 2015 forecast year, by default, 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 modeling 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 Sorbent 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 SO2, particulate matter (PM), FF bag 

house and ACI technology—for mercury removal—by April 2016, 

operating each unit for 15 years, then retiring and optimally replacing 

both units with either/both new-build 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 capacity need created by a Unit 4 retirement with an 

assumed contemporaneous market capacity purchase; operating Unit 3 

for 15 years, then retiring and replacing 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 technology 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 for 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 unit 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 460 216 $428 24 240 $476

     PLUS:     Add'l Environmental Project Costs included in Modeling :

CEMS and CCR‐Related (by 12/2017) 40 $75 4 44 $84

(8)    TOTAL  All Projects Modeled 460 256 $503 29 285 $560

(9) Option #1:  Northeastern Units 3 and 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 44 $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 with 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 installed 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 under the various commodity pricing scenarios identified in 

TABLE 6-1 above. This tabulation represents a relative cost analysis, meaning each are 

compared to a base profile for purposes of determining 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 - Retrofit both Northeastern Units 3&4 with DFGD 

technology). 

The analysis indicates that the EPA Settlement Option offers a $201 million, or 1.5% 

CPW savings, versus Option 1, under the BASE commodity pricing scenario. Likewise, under 

the Lower Band scenario pricing, the EPA Settlement 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-year CPW perspective over the course of the longterm study period. 

Further, the relative costs of the EPA Settlement Option also continued to be on par with 

the results of either Option 2 or Option 4, with such 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/Replace 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 favorthe 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 $4.94 per Mwh (0.494 cents/kWh) impact on levelized annual PSO G‐rev req (2011$), 2016‐2040

      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 ty

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 remen

      (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 incremental 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

$MM 146

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 = ‘RESERVE’ MARGIN 18.8% (CDR Section 12)

(E)=(C)/(B) = ‘CAPACITY’ MARGIN 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 Load 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 predicated on a more gas-friendly earlier 

CO2/carbon (Fleet Transition-CSAPR: Early Carbon) and lower natural gas and attendant energy 

pricing (Fleet Transition-CSAPR: Lower Band) scenarios, the analysis indicates that three of the 

compliance alternatives were reasonably similar in overall cost over the study period. That is, the 

study period CPW cost of retrofitting both units in 2016 (Option 1) or retrofitting in some form 

one unit in 2016, and retiring the other unit in 2016 and replacing (at 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 (Option 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 the unique compliance plan alternatives, those 

differences are not materially significant, particularly in light of all of the necessary assumptions, 

forecasts, and underlying estimates. Put differently, PSO had several reasonable alternative 

compliance plans or strategies around the Northeastern coal units to choose from. A follow-up 

analysis performed more recently in August of 2012 tended to support the earlier results. That is, 

the subsequent analysis continued to indicate that the compliance alternatives were reasonably 

similar in overall CPW cost 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 replacing 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 technology, ACI and fabric filter baghouse by 

April 16, 2016 

 Replace with approximately 260MW of load 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 reflected in Table 7-1. The optimal option has significant economic 

advantages, particularly after considering the relative impacts associated with three of the more 

critical driving economic risk parameters: the potential future cost of natural gas, the timing of 

CO2/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 Weatherization Program seeks to generate energy and demand 

savings for limited income residential customers through the installation of a wide range of cost 

effective weatherization and other measures in eligible dwellings. The purpose of the Home 

Weatherization Program is to provide PSO’s limited 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 installation of measures, PSO or third-party 

implementer costs, measurement and verification, online program management and tracking 

systems, and other administrative functions. PSO may choose to use a third party implementer to 

process payments to various weatherization agencies, provide contractor training, customer 

outreach, and other program processes. 

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

or communities with customers with total annual household incomes at or below 200% of federal 

poverty guidelines, and households 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 continued 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, federal, nonprofit, and tribal housing authority 

weatherization programs to allow more eligible 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 receiving state, federal, nonprofit, and tribal 

housing funds, under the condition that specific energy efficiency and conservation 

measures, as deemed cost effective by PSO, are also installed at the residence. 

The program is designed to facilitate the installation of a wide range 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 through 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 environmental 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 measures installed, invoices, 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 either 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 living 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 incomes 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 below 200% of federal poverty guidelines 

 Low income communities with a substantial population living at or below 200% of the 

federal poverty level, as indicated 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 measure at the customer’s meter if installation 

standards are properly applied. Because savings estimates represent averages, they are not 

appropriate for making measure savings representations 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. 

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 level of efficacy for 

general service lamps, phasing out the 100W, 75W, 60W, and 40W incandescents beginning in 

2012. Savings were calculated using the new baseline set by EISA for general service lamps. 

In each case the customers are living at or near 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 and make the necessary repairs. 

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

for the installation of measures that will 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 homes owned or rented by limited income 

customers. Customers will be approached by agencies or contractors who will inform 

them of improvement opportunities. By removing 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 Corporation Commission rules requires that PSO 

offer a low income weatherization program. Additionally, PSO recognizes that this program, 

when combined with other federal and state weatherization programs, could provide low income 

and limited income customers with significant upgrades 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 monitor 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 consider extending their funds to other nonprofit 

agencies in order to make sure that their funds 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 Poverty Guidelines where customers may need financial assistance 

to improve the efficiency of their homes. 

Program Costs

The total annual budget is reflected in the 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 include internal labor, tracking and advertising expenses, and 

EM&V activities. The table below provides a breakdown 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 Program. PSO expects the savings provided by its energy 

efficiency program to be evenly distributed 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 Program seeks to generate energy and 

demand savings for residential customers through 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 increasing building envelope efficiencies and 

installing items such as high efficiency appliances and HVAC equipment. 

PSO’s program budget includes funds for customer rebates, PSO or third-party 

implementer costs, measurement and verification, online program management and tracking 

systems, and other administrative functions. The estimated customer rebates in the analysis 

performed coincided with roughly 75% of incremental cost; however, PSO 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 implementer to process rebates, provide contractor 

training, customer outreach, and other program processes. 

The objective of the High Performance Homes Program is to promote comprehensive 

efficiency upgrades to building envelope measures 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 inducements for higher efficiency measures offsets 

the first cost obstacle, encouraging customers to choose the upgraded products. PSO intends to 

provide audits to their residential customers to help them identify what energy efficiency 

measures could improve their comfort while reducing their 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 order 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 installation of a wide range of cost-effective measures 

including, but not limited to: 

 Ceiling insulation 

 Duct sealing and insulation 

 Infiltration control 

 ENERGY STAR air conditioners 

 ENERGY STAR heat pumps 

 ENERGY STAR 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 estimated by the program implementor, ICF, 

based on deemed savings values. 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 customer’s meter 

if installation standards are properly applied, assuming a baseline adherent to national and 

regional standards. Because these represent averages, they are not appropriate for making 

measure savings representations to customers. It is the installer’s responsibility 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 involve 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 certified representatives. 

 Offer outreach to various types of contractors who can perform the measures proposed in 

this program, especially licensed HVAC contractors. 

The measures evaluated for this program were based on previous program experience. 

Past program implementation showed the areas for the potential expansion or contraction of 

certain efficiency measures.

Cost Effectiveness

Analysis demonstrates that the High Performance 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 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 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 penetration if it is not meeting expectations, or to reduce freeridership if the program is over-subscribed and free-ridership is suspected. As the market for a 

given technology matures, PSO may need to increase minimum efficiency levels for certain 

equipment. 

This program design reflects the current state of the residential housing markets. Retrofit 

building practices, and high efficiency appliances and equipment are subject to minimum 

efficiency standard changes as a result of federal, state or local code increases at any given time. 

PSO will its programs in conjunction with any efficiency code changes that go into effect with 

regards to housing retrofit requirements, appliances, and HVAC equipment rebated under this 

program. 

Program Costs

The total annual budget is reflected in Table 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 include internal labor, tracking and advertising expenses, and 

EM&V activities. Table A8 below provides a breakdown 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 annual demand reduction, energy savings, and gas 

savings (if applicable) estimated for this program. PSO expects the savings produced by this 

program to be evenly distributed 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 provided in the table above represent generation 

impacts, in that estimated transmission and distribution 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 planning requirements will be analyzed outside of 

the efforts directly associated with the development 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 Services Program seeks to generate energy 

and demand savings for residential customers through the promotion of ENERGY STAR cooling 

equipment, CFLs, window replacements, duct sealing, 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 customer rebates, PSO or third-party 

implementer costs, measurement and verification, online program management and tracking 

systems, and other administrative functions. For cooling equipment, rebates will only be offered 

on products with SEER ratings greater than 17. The 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 requirements, or installation standards prior to 

program rollout. This program provides financial inducements for the purchase of cooling 

equipment with an ENERGY STAR rating, CFLs, or advanced power strips that reduce customer 

energy costs, reduce peak demand and/or save energy for residential customers. 

The primary goal of this program is to achieve cost-effective reduction in energy 

consumption, and to reduce peak demand during the summer by encouraging customers to 

purchase high efficiency equipment, and to reduce phantom load by installation of advanced 

power strips. Additional objectives of the program may be to: 

 Increase customer awareness of the ENERGY STAR 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 installation of a wide range 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 measure life. Additionally, the 

targets for the advanced power strips are those customers with home offices or home 

entertainment systems. Participants in the program must be existing single-family homeowners 

who purchase retail electricity from PSO on a residential tariff.

Baselines for all program measures (with the 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 customer’s meter if installation standards are properly 

applied, assuming a baseline adherent to national and regional standards. Because these represent 

averages, they are not appropriate for making measure savings representations 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 level of efficacy for 

general service lamps, phasing out the 100W, 75W, 60W, and 40W incandescents beginning in 

2012. Savings were calculated using the new baseline set by EISA for general service lamps. 

Assumptions for energy savings and incremental costs for replacing general service 

lamps with LED products came from two sources: (1) 2011 EPA Report. “Next Generation 

Lighting Programs: Opportunities for Advance Efficient 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 certified representatives. 

 Offer outreach to various types of contractors who can perform the measures proposed in 

this program, especially licensed HVAC contractors. 

Based on the 2006 Residential Appliance 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 potentially 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 continuous appliance replacements over the years that 

this program is offered. Additionally, the increase 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 found it very important that PSO offer 
 PSO 2012 Integrated Resource Plan - Exhibit A 

15 

inducements for high efficiency cooling and appliances. Given various levels of inducements, 

survey results showed that PSO can expect active participation in this residential program. 

Cost Effectiveness

Analysis demonstrates that the Energy Saving Products program passes all cost 

effectiveness tests except the Ratepayer Impact Measure, 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, 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 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 minimum efficiency levels for certain equipment. 

A key goal for this program is to promote market transformation to encourage adoption of all 

relevant equipment. 

This program is designed based on the current state of the residential 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 equipment rebated under this program.

 Cost Effectiveness

The total annual budget is reflected in Table 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 include internal labor, tracking and advertising expenses, and 

EM&V activities. Table A13 below provides a breakdown of the EM&V costs 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 demand reduction, energy savings, and gas savings 

(if applicable) estimated for this program. PSO expects the savings provided by this program to 

be evenly distributed throughout 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 provided in the table above represent generation 

impacts, in that estimated transmission and distribution 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 planning requirements will be analyzed outside of 

the efforts directly associated with the development 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 students with easy self-install 

energy efficiency measures, such as CFLs and Advanced Power Strips. The purpose of the 

Educational Program is to provide PSO residential 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 existing 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 minimal 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 install energy efficiency measures on their own. Many customers do not 

know enough about home energy use to identify 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 Survey of Home Characteristics conducted by 

PSO found that the average existing home in the PSO service territory would be eligible to 

participate in energy efficiency program offerings. 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 other PSO residential rebate programs. 

Program Costs

The total annual budget is reflected in the 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 program 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 including (but not limited to) lighting, HVAC, and motors. The 

program provides PSO’s C&I customers with flexibility 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 for customer rebates, PSO or third-party 

implementer costs, measurement and verification, online program management and tracking 

systems, and other administrative functions. The estimated 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 level 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 combine provision of financial inducements with 

access to technical expertise to maximize program penetration across 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 grade 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 expects saturation rates and awareness levels of 

efficient equipment to be lower. PSO’s proposed High Performance Businesses program 

incorporates two modes of customer participation: customers can choose to self-sponsor and 

participate directly with PSO, or they can work 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 includes 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. Any entity meeting the application requirements that is capable 

of carrying out the program requirements is eligible to be a project sponsor. PSO anticipates 

active participation from both the commercial and industrial sectors. 

The High Performance Businesses Program involves a wide variety of equipment. This 

evaluation used past performance of PSO’s programs 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”) lighting, 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 longer be rebating retrofits of T12s. 

PSO anticipates that most of the C&I customers 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 replacement 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 systems. For chiller equipment, relevant standards 

are the existing federal standards. For equipment being replaced before the end of its useful life, 

the baseline is determined by the efficiency of the unit being replaced and the remainder of its 

estimated useful life. Several commercial baseline assumptions can be found in Exhibit WLB08(b). The applicable baseline for motors that are replaced on burnout is NEMA premium 

efficiency. For retrofit applications of motors that would otherwise be rewound and kept in 

operation, the applicable baseline is EPACT 1992. 

The following barriers may impede C&I customers’ decisions to install more efficient 

equipment or undertake efficiency-seeking activities (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 maximum market penetration 

 Bounded rationality - where the customer acts against its own best economic 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 desire to install more energy-efficient 

technology, but is unwilling to spend or unable to obtain the required 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 third party implementers, (4) providing complete website presence, (5) comarketing, when possible, and (6) conducting workshops. 

PSO has consulted with the primary stakeholders 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 state of the markets for each equipment type. 

Furthermore, PSO contracted with experts in energy efficiency program development and 

design, Frontier Associates, for the development of a portfolio of cost-effective programs, from 

which this proposed program was derived. 

Cost Effectiveness

The benefit-cost test ratios for 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 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 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 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 state of the markets for each equipment type. 

Lighting technology is rapidly evolving, as new technologies enter the marketplace and replace 

traditional lighting retrofit technologies. HVAC equipment is also evolving, as are minimum 

efficiency standards set by local building codes, national standard-setting entities (e.g., ASHRAE 

or ICC), and the federal government. With the emergence of new technologies and promulgation 

of higher standards, PSO will occasionally need to alter its rebate structure to incorporate these 

new technologies and regulatory changes, modifying program objectives to focus on 

maintenance and emphasizing market transformation. 

Program Costs

The total annual budget is reflected in the 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 include internal labor, tracking and advertising expenses, and 

EM&V activities. Table A18 below provides a breakdown of the EM&V costs 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 program. PSO expects the savings provided by this 

program to be evenly distributed 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 provided in the table above represent generation 

impacts, in that estimated transmission and distribution 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 these 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 short notice. Typically, this capability is predicated on having 

load-producing equipment that is operated by a control system capable of receiving a load shed 

signal and reducing equipment operation to produce demand savings. Such equipment may 

include programmable, communicating HVAC controls (thermostats), or commercial lighting 

equipped with dimmable ballasts linked to a central control system, among others. 

PSO’s program budget includes an estimated average of $32/kW-year for customer 

rebates, and PSO or third-party 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 amounts when programs are implemented to ensure 

cost effectiveness, and to incentivize customer participation. 

The primary goal of this program is to achieve 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 efficiency and conservation 

efforts. The target market includes all commercial 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) within a customer facility. PSO anticipates active 

participation from both the commercial and industrial 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 program intends to address; rather, PSO must create a 

market for demand reduction by offering to pay for this service. PSO may choose 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 customers’ participation in this program: 

 Opportunity Cost - Customer concern that the temporary 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 economic interest 

PSO provides a healthy inducement for participation 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 work with DLC implementation service providers 

and/or load aggregators, and (3) will provide complete website presence. 
 PSO 2012 Integrated Resource Plan - Exhibit A 

25 

PSO has consulted with the primary stakeholders in its service territory, including 

representatives of the program’s target market, and has consulted 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 benefit/cost test ratios for this program are 

favorable. The program also passes the RIM, which is typical of load management programs. 

PSO expects the program to grow modestly over the 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 effectively it reaches its target market. If participation increases 

more rapidly than expected, such that budget constraints 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 include internal labor, tracking and advertising expenses, and 

EM&V activities. Table A22 below provides a breakdown 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 annual demand reduction, energy savings, and gas 

savings (if applicable) estimated for this program. PSO expects the savings provided by this 

program to be evenly distributed 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 procurement plan, purchased-power 

procurement plan, and risk management plan. 
PSO 2012 Integrated Resource Plan – Exhibit B 

Table of Contents

I. INTRODUCTION..............................................................................................................................29

A. FUEL PLANNING OBJECTIVES.........................................................................................................................30

B. RESOURCES & CAPABILITIES .........................................................................................................................30

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

2. Purchased Power ......................................................................................................................................... 32

C. PRIOR PERIOD RESULTS .................................................................................................................................33

II. ENERGY AND SUPPLY FORECAST ..............................................................................................40

A. DEMAND FORECAST.......................................................................................................................................40

B. FUEL SUPPLY AND ENERGY FORECAST..........................................................................................................40

1. Fuel .............................................................................................................................................................. 41

2. Energy .......................................................................................................................................................... 43

III. PROCUREMENT STRATEGY.........................................................................................................45

A. DISCUSSION OF ALTERNATIVES .....................................................................................................................45

1. Coal Procurement and Transportation......................................................................................................... 48

2. Natural Gas Procurement and Transportation............................................................................................. 49

3. Fuel Oil.......................................................................................................................................................... 51

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

B. SELECTED FUEL PROCUREMENT PLAN...........................................................................................................53

IV. RISK MANAGEMENT......................................................................................................................57

A. HEDGING........................................................................................................................................................57

B. FUEL DIVERSITY AND OPTIMIZATION ............................................................................................................58

C. CONTRACT TERMS .........................................................................................................................................59

D. CUSTOMER PROGRAMS ..................................................................................................................................60

V. COST OF ENERGY ...........................................................................................................................................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 since 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 Power 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 portfolio of resources. The map (Exhibit 1) below 

indicates the approximate boundaries of PSO’s service territory (in green) and the location of its 

generation resources. The red squares represent PSO’s coal units and the purple diamonds 

indicate the location of natural gas generation units. 

Exhibit 1: Map of PSO in Oklahoma 

Under Order 454610 of the Oklahoma Corporate 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 also 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 obligation to serve its customers reliably at all 

times and at all load levels. Loads vary instantaneously and sometimes change in an 

unforeseen manner due to weather patterns that are unpredictable or due to system 

conditions. PSO’s fuel procurement and risk management plan is designed to meet concerns 

for: 

 Reliability - Ensure fuel will be available when needed 

 Adequacy - Sufficient quantities are procured 

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

 Price - Ensure the lowest reasonable delivered cost while considering other objectives 

In other words, PSO’s fuel procurement activities are first and foremost focused on ensuring 

that all the electric power that its customers want is available 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. These 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 Riverside and Southwestern can also use fuel oil 

to generate electricity. PSO maintains a limited quantity of fuel oil at these units as an 

emergency back-up fuel supply. PSO can also use natural gas to run Northeastern 3 and 

4 at partial load in the event of coal curtailments or coal-related equipment outages. 

Comanche, Weleetka, Northeastern Unit 1, Riverside Units 3 and 4, and Southwestern 

Units 4 and 5 are each connected to one pipeline 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 three pipelines. These multiple natural gas 

pipeline connections provide the Company with access to reliable, flexible, and 

competitively priced natural gas supplies. The 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 competing rail carriers, 

Union Pacific (UP) and Burlington Northern Santa Fe (BNSF), for coal deliveries. 

Currently, UP provides coal deliveries to the Northeastern power plant with a shipping 
PSO 2012 Integrated Resource Plan – Exhibit B 

32 

distance of approximately 1,000 miles. The BNSF railroad provides deliveries of coal to 

the Oklaunion power plant with a shipping distance 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 PSO Coal Plants relative to the PRB* coal supply region 

*Powder River Basin 

2. Purchased Power 

American Electric Power Service Corporation (AEPSC), as agent for PSO, forecasts 

hourly, daily, monthly, and annual loads to anticipate purchased power requirements. 

Because of PSO’s diverse generation portfolio, 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 costs, projected operations and maintenance costs 

and emissions costs to predict dispatch costs, 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 purchased power market. 

Wind Energy 

PSO has made a significant commitment 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 expectation 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 offset by a decrease in generation from natural gas and purchased 

power. Additionally, wind generation increased 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 generation available during the year 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 detailed in the 2011 Fuel Supply 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 oil pipeline connected to Riverside. 
PSO 2012 Integrated Resource Plan – Exhibit B 

35 

The chart below (Exhibit 4) illustrates, on a monthly basis, how fuel costs at PSO generation 

resources and purchased power contributed 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 consumed), 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 lower and tighter range, between a low of $2.09 

per MMBtu in November 2011 to a high 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 generation. 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 generating 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 (Exhibit 5) summarizes the 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 Basin (PRB) to the Northeastern and Oklaunion 

plants during 2011 were made pursuant to transportation arrangements 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 brought 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 illustrates how PSO utilized multiple transaction types 

for purchasing gas to meet the varying demands for natural gas generation. The chart 

indicates a range of total purchases 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 representation 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 percent of purchases for the year were at an 

index price. Conversely, as shown below, almost 19 percent were on a fixed price basis. 

Fixed price contracts mitigate price volatility; they are not intended to lower fuel cost. PSO 

used monthly index prices to effectively lock in prices on a monthly basis and provide 

greater price stability compared to daily indexes. The figure below illustrates the correlation 

between price and percentage of each pricing mechanism 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, transportation contracts 

with Enogex and ONEOK Gas Transportation, LLC (ONEOK or OGT) were used. PSO 

uses a mix of firm and interruptible agreements 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 prices for 2011 displayed a yearover-year decrease in both the off-peak and on-peak hours. The change in 2011 SPP power 

prices relative to 2010 prices can be seen in Table 4 below. 

Month

Average OnPeak 

($/MWh)

Average OffPeak ($/MWh) Month

Average 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 market conditions, weather patterns, unit outages, 

transmission outages, and purchased 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 from 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 responsibility is expected to decrease as compared 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, natural gas, and fuel oil generation, as well as 

wholesale economic energy purchases. Additionally, PSO has entered into long-term wind 

energy purchases. PSO optimizes available generation resources by first dispatching its 

lower cost coal units (and solid fuel units from Southwestern Electric Power Company 

(SWEPCO) when available to PSO) and wind resources, in addition to its Reliability Must 

Run (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, and to meet load-following, voltage support and reserve ancillary service 

requirements. 

AEPSC, as agent for PSO, forecasts hourly, daily, monthly, and annual loads to anticipate 

both its fuel and purchased power requirements. As previously mentioned, AEPSC uses the 

GenTrader algorithmic optimization model to combine the load forecast with heat rate 

curves, projected fuel costs, projected operations and maintenance costs and emissions costs 

to predict dispatch costs, unit loading, and fuel consumption. The output from this model, 
PSO 2012 Integrated Resource Plan – Exhibit B 

41 

along with market price projections, is then used to optimize the PSO system and to identify 

opportunities in the purchased power market. 

To meet its constantly changing load obligations, PSO uses all available resources while 

taking into account fuel markets, environmental constraints, and regulatory requirements. 

PSO routinely displaces its own generation with economic purchases from the competitive 

market (through both bilateral transactions and the SPP Energy 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 economic 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 contracts and anticipated market prices for noncommitted fuel. 

The fuel cost for each of PSO’s generating plants 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 contained in the coal supply and transportation 

contracts, with replacement and supplemental coal costs based on projected market 

prices for coal. 

Coal 

Northeastern 3 & 4 and Oklaunion use sub-bituminous coal from the PRB of Wyoming 

that typically has a heat content of 8,200 to 8,800 Btu per pound. Projections of coal 

supply needs must consider railroad 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 sector decreases overall in 2012, many PRB 

consumers are negotiating with suppliers to defer 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 expected 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 committed under contracts in 2012, PSO does not 

anticipate any coal supply issues at PSO plants in 2012. 

Natural Gas 

Natural gas prices can vary based on supply and demand realities in the natural gas 

market. Recently, shale gas has been a “game changer” and is contributing significantly 

to increased natural gas supplies and lower, less volatile natural gas prices. However, 

PSO’s utilization of natural gas has declined over the last few years due to increased 

wind generation. In addition, PSO has executed 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 utilization of natural gas during 2012. As such, 

PSO currently plans to reduce its long-term 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 pricing provisions contained in 

the varied term supply and transportation contracts and the trading prices of natural gas 

futures contracts from the New York Mercantile Exchange (NYMEX) for delivery at the 

Henry Hub, and then they are adjusted for transportation basis differentials applicable to 

PSO’s geographic region and delivery points. PSO analyzes the fundamental drivers of 

the fuel markets daily and considers industry standard forecasts published by analysts 
PSO 2012 Integrated Resource Plan – Exhibit B 

43 

such as Cambridge Energy Research Associates, 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 makes (long-term, annual, seasonal, monthly and daily) reduces 

its exposure to potential price volatility and secures a reliable supply of natural gas. PSO 

is active in the daily natural gas markets and stays abreast of current market changes, 

including any new potential natural gas 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 increase 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 activities include affiliate purchases 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 the terms of the Exelon PPA. The Exelon 

contract is a 520 MW Power Purchase and Sale 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 increase in PSO’s purchased power. While the total 

amount of purchased power in 2012 is expected to increase as a result of the Exelon 

PPA, the relative contribution of PSO’s individual 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 transmission outages. 

Wind Energy

PSO’s commitment to a diversified generation 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 and 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 reliable, 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 contract terms for fuel suitable for use in its 

generating units. 

The flexibility in PSO’s fuel supply plan and the diversity of its generating 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 balanced 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 flexible portfolio of coal, 

natural gas, fuel oil, and purchased power resources, including wind, which manages overall 

variable costs due to the potential price volatility of any one particular fuel source. PSO’s 

ability to mitigate the potential impact of price 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 supply and transportation contracts, periodic use 

of fuel oil, and the use of purchased power when it economically displaces PSO’s own 

generation. 

Typically, PSO meets its generation requirements 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 proactive and responsive to known, 

anticipated, and potential changes in operating, coal supply, and rail transportation 

conditions. In addition, PSO’s coal 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 maintenance and forced outages, to follow daily and 

hourly load swings, and for voltage support. Fuel oil is also used in PSO’s power plants 

when appropriate. Exhibit 8 provides a graphical 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 Resource 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 Ending

MWH

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 Characteristics 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 procurement and risk management plan must have 

concerns for reliability, adequacy, flexibility, and 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 flexibility 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 Company to potential price instability. 
PSO 2012 Integrated Resource Plan – Exhibit B 

49 

Coal Procurement Option 2 

PSO could procure all forecasted coal needs using 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 estimate of fuel costs. As discussed previously, 

forecasts have inherent flaws and their accuracy reduces with increases in time. 

Therefore, purchasing all coal based on long-term forecasts could lead to overcommitments, inventory issues, and possibly force majeure penalties. It would also 

prohibit PSO from taking advantage of favorable 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 receive coal deliveries under a transportation 

agreement with UP through the end of 2012. Oklaunion is captive to BNSF as the only 

carrier with physical access to the plant. Coal was received under a rail tariff established 

by the Surface Transportation Board (STB) through 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 gas supply needs through fixed-price supply 

contracts for terms of one year or greater if there were suppliers willing to sell all 

volumes at a fixed price and assume all of the price risk. This 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 higher prices for PSO’s customers. Use of 

contracts with longer terms would 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 market opportunities as they arise. Though these 

prices could be lower than purchases made on a longer-term basis, PSO would, however, 

face the uncertainty of not knowing whether sufficient 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 contracts if suppliers 

were willing to commit to sales of natural gas. During periods of declining prices, this 

option could lower natural gas generation costs. Purchasing all natural gas supply needs 

under index-priced supply contracts also increases risk through the Company’s exposure 

to gas price volatility. However, 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 natural 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 capacity were available. This would 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. Historically, natural gas storage has been used by 

both natural gas and electric utilities primarily for supply reliability and to meet peak 

energy demands, not for price arbitrage purposes. Pipelines and local natural gas 

distribution companies also require physical storage for operational balancing and 

system supply. If the storage facility is directly connected to a pipeline system owned by 

the utility or its affiliate, storage can be used to meet instantaneous unforeseen natural 

gas use (real-time load following service). However, physical storage agreements with 

third-party providers require withdrawals to be nominated in advance and withdrawn at a 

steady flow rate. Because PSO, like other electric utilities, cannot precisely predict 

hourly loads, they cannot nominate hourly storage requirements for third-party storage 

service. 

3. Fuel Oil 

PSO could use fuel oil on a limited basis as an alternative to natural gas in selected units. 

However, fuel oil is generally a higher-priced alternative to natural gas and could 

decrease the flexibility and efficiency of plant operations, including decreased generation 

capacity. There are also environmental issues that need to be considered when fuel oil is 

consumed for an extended period. 

4. Purchased Power 

PSO has adequate generating resources, including 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 operating 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 purchases, supplemented by much less frequent 
PSO 2012 Integrated Resource Plan – Exhibit B 

52 

economic energy purchases from PSO’s neighboring utilities. Such third party purchases 

were most typically short-term in duration. 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 continue 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 Transmission Organization (RTO), with PSO 

raising or lowering its generation output based 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 another 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 performed 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 energy 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 purchased power activity using 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 growth and development of wholesale power 

markets. AEPSC, on behalf of PSO, engages 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 third party bilateral trading 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 regulatory 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 incorporate the use of a variety of alternatives to 

provide adequate, reliable, and flexible fuel supplies. 

PSO’s generation portfolio includes coal, natural gas, and fuel oil generation, as well as 

wholesale economic energy purchases. Additionally, PSO has entered into long-term wind 

energy purchases. PSO optimizes available generation resources by first dispatching its 

lower cost coal units (and solid fuel units from SWEPCO when available 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, and 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 majority of the coal used as boiler fuel on PSO’s system is 

obtained at fixed prices through supply and transportation 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 transportation 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 also serve as a physical hedge against price 

volatility for that volume of coal already secured, 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 purchases and consumption can 

be stockpiled on site for use at a later time at PSO’s discretion–unlike the ratable flow 

restrictions required when pulling 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 fuel cost certainty for its coal portfolio. In 

contrast, many natural gas suppliers 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 contract 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 Northeastern and Oklaunion beyond 2012. The 

negotiation process is ongoing. As previously mentioned, coal was received under a rail 

tariff established by the Surface Transportation Board (STB) through 2011 and then under a 

long-term rail transportation agreement beginning 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 gas 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 June through August, PSO has entered into some 

seasonal firm supply contracts to ensure deliveries of natural gas as a hedge against a 
PSO 2012 Integrated Resource Plan – Exhibit B 

55 

shortage of supply rather than against a change 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 supply 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 seasonal firm supply contracts, PSO may secure 

daily call gas on Enogex and OGT for the 2012 summer to ensure supply 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 reservation fee for the demand service. 

PSO’s plan for 2012 is to start each month with approximately 75,000 MMBtu/day of longterm and annual firm natural gas and supplement the natural gas supply as needed with 

competitively-bid monthly and seasonal firm natural gas purchases to meet forecasted 

minimum monthly supply requirements. PSO typically 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 market adder represents the market price for 

natural gas. PSO has seen a decrease in market adders since 2009. Production from the 

shale gas reserves (Haynesville, Fayetteville, 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 arrangements with connecting pipelines for swing 

service beyond its daily nominations to meet its peak hourly and daily demands. PSO 

currently has a firm transportation agreement with Enogex and 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 request 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 agreement by July 27, 2012. PSO also has 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 storage, if available, to meet its natural gas peaking supply 

needs for reliability purposes. However, PSO’s analysis has indicated 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 advance. Storage injections and withdrawals must 

be accomplished at a steady flow rate and are not responsive to the peaking demands of 

natural gas electric 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 typically higher and 

withdraw gas in the summer to meet the summer peak demands. 

PSO’s existing natural gas transportation contracts include services which already provide 

the reliability that storage services would offer. The most recent estimates indicate that firm 

natural gas storage arrangements (including transportation) would cost approximately $1.61-

$1.63 per MMBtu above the commodity costs of the related natural gas. Thus, natural gas 

storage has not evolved as a viable operational 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 competitive 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 Riverside and Southwestern for reliability purposes. 

At the end of 2011, PSO had 72,897 barrels of fuel oil at Riverside for units 1 & 2 and 

46,312 barrels at Southwestern for unit 3. 

Purchased Power Plan 

The purchased power plan for 2012 relies on a mixture of transactions that take advantage of 

many of the alternative approaches 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 demonstrates 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 overall 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 broad and diversified generation fleet that 

provide access to a range of economic purchased power options derived from a wide range 

of fuel types. Additionally, AEPSC, on behalf 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 relationships within the SPP and across the Eastern 

Interconnect, including PJM and MISO (Midwest Independent System Operator). AEPSC’s 

production optimization group and trading group are able to use this network of contacts and 

expertise to provide PSO with numerous opportunities 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 potentially increase the overall 

fuel cost based on transaction costs and premiums required to lock in pricing. While 

financial hedging will continue to be considered, PSO, under normal circumstances, does not 

believe it meets the objective of providing the lowest reasonable 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 availability, new pipeline construction, and market 

changes have significantly reduced price volatility and minimized the potential advantages 

of financial hedging. 

B. Fuel Diversity and Optimization 

AEPSC’s purchased power and optimization activities 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 outages are used to develop projections of fuel consumption 

and power purchases for PSO. These projections are part of the day-ahead resource 

commitment process PSO uses, which is presented 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 own generation when it is economical to do so. 

Exhibit 9: Day-Ahead Resource Commitment Process 

AEPSC’s optimization activities continue into the real-time operation of the PSO system. In 

the intra-day market (real-time), AEPSC hourly marketers, production coordinators, natural 

gas coordinators, and generation dispatchers work 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 and balance of day resource dispatch process outlined in Exhibit 10 on 

the next page. 

The Company’s generating units are economically dispatched in real time with other 

resources in SPP. The SPP EIS market participation allows, on a five-minute dispatch 

basis, for PSO to buy economic energy from other 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 procures 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 assist 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 cover 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 monthly 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 Service 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 and risk management plan must contemplate and 

address reliability, adequacy, flexibility, and price. The foundation of PSO’s risk management 

plan has been to have a diversified generation and supply portfolio, which includes coal 

generation, natural gas generation, fuel-oil generation, wholesale energy purchases, and 

renewable energy. Each of these commodities is procured under a competitive bidding or 

competitive market offer process. This includes energy purchases in lieu of PSO’s generation 

when it can be arranged both economically and reliably. 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 delivered cost. Recognizing the dynamic 

nature of the markets, PSO will continue to review its fuel procurement activities, and modify 

them as appropriate, to ensure that any fuel procurement and risk management plan continues to 

meet the standards of reliability, adequacy, flexibility, and lowest reasonable 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 (Strategist) 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 DESCRIPTION & PROCESSES 

A. Capacity Resource Modeling (Strategist) and Levelized Busbar Costs 

The overriding objective of the modeling effort 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 affordability. 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 experience is gained to take into account emerging issues identified by 

supporting work groups and management. 

The Strategist Model 

The Strategist resource-planning model, developed 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 technologies, 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 carrying 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) emission 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 study to be considered with 

the depth and accuracy required for informed decision-making. Hourly chronological load 

patterns are recognized, detailed production costing logic is utilized, and the system employs a 

dynamic programming algorithm to develop the “optimal” and large suites of “sub-optimal” 

portfolios of capacity addition alternatives over a user-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 calculate 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 forecast. The Generation and 

Fuel module (GAF) works with the LFA to simulate the operation of a utility’s generating units 

and any interaction with external 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 prescribed sets of constraints and assumptions. 

Strategist develops an initial “macro” (zone-specific)* least-cost resource mix for a system 

by incorporating a wide variety of expansion planning assumptions 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, heat 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 margin 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 views 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 considered in order to develop 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 plan, not costs that are fixed, such as embedded 

costs of existing generating capacity or distribution 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 “incremental revenue requirement” output profile: 

 Fixed costs of capacity additions, i.e. carrying charges on capacity and associated 

transmission based on a weighted average cost of capital (WACC) and fixed O&M 

 Fixed costs of any capacity purchases 

 Variable costs of the entire fleet of existing and any added units. This includes fuel, 

purchased energy, the market replacement cost of emission allowances (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 integrated, 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 alternative combinations created by 

the module’s chronological “dynamic programming” algorithm. On an annual basis, each 

capacity resource alternative combination that satisfies 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 saved by the program for consideration in following 

years. As the years progress, the previous years’ feasible states are used as starting points for the 

addition of more resources that can be used to meet the current year’s minimum reserve 

requirement. As the need for additional capacity on the system increases, the number of possible 

combinations as well as the number of feasible states increases approximately exponentially with 

the number of resource alternatives being considered. 
PSO 2012 Integrated Resource Plan – Exhibit C 

67

Exhibit A-1 offers a very simplistic example 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 types over a three- year 

period. Six unique plans result after the elimination of one of the more expensive paths.

Exhibit A-1 Strategist chronological “dynamic programming” algorithm 

As can be seen in this example, the potential 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 specifically 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 alternative that can be considered by 

the model during the Planning Period. In addition, other variables limit the years that a 

particular alternative is available 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 processes used to evaluate 

Proposals received in response to PSO and SWEPCO RFPs. Two types of price evaluation 

processes are described in this document. One process used for evaluating a significant number 

of Proposals where Proposal clustering is necessary and a second process for evaluating a limited 

number of Proposals where Proposal clustering isn’t necessary. Included 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 Short-list of Proposals, the 

Portfolio Evaluation of Proposals and selection of the Award Group. 

Price Evaluation Assumptions: 

 Gas and Market Prices - Prior to the receipt 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 again 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 New 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 Evaluation and Short-list Determination 

 Baseline Comparison Plan - A Baseline Plan will be developed for both PSO and 

SWEPCO for Proposal comparison purposes based 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 minimize PSO and SWEPCO reliance on the SPP 

capacity and energy markets to meet their ongoing capacity and energy requirements. 

 Proposals will replace the generic resources identified 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 Proposal with a 20xx in-service date would 

replace 100 MW of the IRP Plan’s generic CT capacity and the remaining 400 MW 

would have the operating and cost characteristics of the IRP Plan’s generic CT capacity. 

Additional capacity added in the years following 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 cluster. Each Proposal will be 

placed in a cluster that has other Proposals with similar Contract Terms. A Strategist run 

will be conducted for each Proposal for the period of the longest Contract Term possible. 

For example, in the case of 2008 Peaking Proposals, if the longest 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 Term, Strategist will replace the 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 evaluated. At the end of the Proposal’s 20 year 

Contract Term, the Proposal would be replaced with 100 MW of generic CT capacity for 

the remaining 10 years of the evaluation. 

 If a limited number of Proposals are received, it will not be necessary to cluster Proposals 

by like characteristics (e.g. Contract Term, PPA, APP, etc) in order to create a short-list. 

All Proposals may be evaluated against each other 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 compare 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 equivalence 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 total 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 Comparison Plan will be divided 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 factors and non-price points will be assigned to each Proposal 

within a cluster. 

 Short-list Selection for a significant number of Proposals - Within each Proposal cluster, 

a short-list of Proposals will be developed based 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 the 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 Reso

Table 1 

JAN. FEB. MAR. APR. MAY JUN. JUL. AUG. SEP. OCT. 

2011 2647 2803 2323 2662 3309 3678 4192 4179 3227 2702 2012 2478 2735 2192 2439 2929 3820 4207 4192 3331 2723 2013 2498 2760 2207 2448 2943 3838 4227 4212 3348 2746 2014 2508 2769 2216 2453 2949 3846 4235 4220 3357 2764 2015 2516 2777 2223 2452 2946 3840 4226 4212 3355 2774 2016 2516 2774 2224 2451 2943 3837 4222 4208 3355 2797 2017 2535 2797 2244 2460 2949 3834 4212 4197 3349 2736 2018 2541 2801 2250 2462 2948 3831 4208 4193 3350 2739 2019 2550 2810 2259 2467 2962 3834 4210 4196 3356 2756 2020 2548 2804 2260 2466 2951 3832 4207 4193 3356 2780 2021 2567 2824 2276 2478 2962 3845 4220 4205 3371 2805 2022 2582 2838 2290 2489 2974 3859 4234 4220 3386 2830 2023 2602 2860 2314 2508 2993 3874 4246 4230 3395 2780 2024 2608 2863 2321 2517 3017 3886 4259 4243 3408 2802 2025 2635 2891 2346 2537 3028 3912 4285 4271 3434 2837 2026 2653 2908 2362 2554 3042 3934 4308 4294 3456 2868 2027 2671 2925 2379 2570 3061 3957 4333 4319 3479 2899 2028 2681 2933 2391 2584 3076 3977 4354 4340 3498 2941 2029 2717 2973 2428 2614 3107 4007 4382 4366 3522 2888 2030 2740 2994 2448 2635 3151 4036 4413 4397 3550 2924 2031 2763 3017 2471 2658 3164 4068 4447 4432 3580 2963 2032 2776 3028 2484 2675 3176 4095 4477 4461 3605 3010 2033 2811 3065 2517 2705 3209 4135 4519 4504 3644 3057 2034 2845 3100 2552 2740 3246 4173 4556 4539 3674 3018 2035 2874 3129 2580 2769 3279 4214 4600 4584 3713 3051 2036 2897 3151 2602 2794 3318 4251 4640 4623 3747 3106 2037 2938 3192 2640 2831 3349 4302 4694 4678 3795 3161 2038 2968 3222 2668 2860 3383 4344 4740 4724 3835 3209 2039 2999 3252 2697 2889 3416 4387 4786 4770 3875 3257 2040 3025 3281 2728 2922 3451 4423 4820 4802 3901 3212 

PSO MONTHLY PEAK NATIVE DEMAND (MW)
PSO 2012 Integrated Reso

Table 2 

JAN. FEB. MAR. APR. MAY JUN. JUL. AUG. SEP. OCT. 

2011 1,554 1,376 1,362 1,306 1,518 1,733 2,061 2,021 1,579 1,335 

2012 1,515 1,382 1,359 1,277 1,452 1,765 2,130 2,078 1,600 1,348 

2013 1,523 1,335 1,360 1,284 1,456 1,768 2,142 2,081 1,609 1,352 

2014 1,526 1,339 1,366 1,288 1,455 1,776 2,146 2,081 1,617 1,355 

2015 1,527 1,343 1,374 1,291 1,455 1,782 2,143 2,081 1,618 1,355 

2016 1,523 1,396 1,375 1,289 1,461 1,782 2,133 2,087 1,618 1,353 

2017 1,539 1,351 1,383 1,292 1,470 1,785 2,134 2,089 1,618 1,363 

2018 1,544 1,354 1,384 1,299 1,473 1,782 2,137 2,088 1,618 1,371 

2019 1,550 1,360 1,387 1,308 1,478 1,783 2,145 2,088 1,626 1,377 

2020 1,548 1,408 1,393 1,310 1,472 1,792 2,142 2,083 1,630 1,373 

2021 1,551 1,369 1,402 1,318 1,483 1,802 2,147 2,096 1,640 1,380 

2022 1,564 1,377 1,412 1,323 1,495 1,811 2,151 2,109 1,648 1,389 

2023 1,578 1,386 1,422 1,329 1,509 1,820 2,161 2,120 1,653 1,403 

2024 1,583 1,445 1,421 1,343 1,515 1,819 2,176 2,121 1,660 1,413 

2025 1,600 1,405 1,438 1,357 1,525 1,839 2,192 2,133 1,680 1,427 

2026 1,606 1,415 1,453 1,368 1,533 1,856 2,204 2,146 1,692 1,434 

2027 1,613 1,425 1,463 1,378 1,546 1,869 2,213 2,164 1,704 1,442 2028 1,625 1,488 1,473 1,380 1,564 1,879 2,220 2,180 1,708 1,455 2029 1,649 1,449 1,487 1,399 1,581 1,893 2,243 2,198 1,723 1,476 2030 1,663 1,461 1,497 1,417 1,595 1,904 2,265 2,210 1,742 1,490 2031 1,677 1,475 1,512 1,430 1,605 1,926 2,283 2,224 1,763 1,505 2032 1,681 1,536 1,526 1,440 1,615 1,945 2,292 2,244 1,775 1,507 2033 1,704 1,503 1,547 1,455 1,639 1,968 2,312 2,273 1,795 1,528 2034 1,726 1,518 1,565 1,468 1,662 1,987 2,335 2,296 1,810 1,550 

2035 1,745 1,535 1,579 1,489 1,681 2,004 2,363 2,319 1,827 1,572 

2036 1,760 1,600 1,592 1,509 1,692 2,023 2,389 2,329 1,853 1,586 

2037 1,779 1,571 1,621 1,532 1,712 2,057 2,418 2,360 1,879 1,606 

2038 1,793 1,587 1,637 1,548 1,733 2,079 2,437 2,389 1,900 1,621 

2039 1,817 1,604 1,656 1,561 1,757 2,101 2,456 2,418 1,920 1,641 

2040 1,836 1,680 1,667 1,577 1,778 2,113 2,482 2,437 1,927 1,664 

MONTHLY INTERNAL ENERGY REQUIREMENTS (GWH)
PSO 2012 Integrated Reso

Table 3 

AEP System-West Zone 

New Generation Technologies

Key Supply-Side Resource Option Assumptions (a)(b)(c)

Installed Trans. Full Load Fuel Variable Fixed 

Capability (MW) Cost (d) Cost (e) Heat Rate Cost (f) O&M O&M SO2 NOx 

Type Std. ISO Winter Summer ($/kW) ($/kW) (HHV,Btu/kWh) ($/MBtu) ($/MWh) ($/kW-yr) (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 Pulv. Coal (Advanced Ultra-Supercritical) (PRB) 750 757 742 2,804 20 8,470 3.45 3.2 33.1 0.1000 0.070 IGCC "F" Class (PRB) 587 593 581 5,203 26 8,530 3.45 5.2 50.0 0.0638 0.062 Pulv. Coal (Ultra-Supercritical) (Lignite) 618 624 612 2,691 24 9,657 3.31 3.1 37.0 0.1145 0.070 IGCC "F" Class (Lignite) 638 644 631 5,190 24 10,100 3.31 5.2 48.1 0.0126 0.057 Nuclear (MHI ABWR) 1,606 1,622 1,542 6,156 61 10,500 1.02 5.4 85.8 0.0000 0.000 Base 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 IntermediateCombined Cycle (1X1 GE7FA.05) 305 321 356 1,665 60 7,098 7.47 4.4 15.1 0.0007 0.011 Combined Cycle (2X1 GE7FA.05) 610 653 558 1,267 60 6,835 7.47 3.4 17.4 0.0007 0.007 Combined 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 Combined 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 Combined 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 Combined 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 Combined 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 Combined 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 Combined 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 

Peaking

Combustion Turbine (2X1GE7EA) 164 171 157 705 57 12,165 7.47 8.9 8.2 0.0007 0.033 Combustion Turbine (2X1GE7EA,w/ Blk Start) 164 171 157 811 57 12,165 7.47 8.9 8.7 0.0007 0.033 Combustion Turbine (2X1GE7EA, w/ Inlet Chillers) 164 171 160 1,011 59 12,347 7.47 9.4 9.6 0.0007 0.011 Combustion Turbine (2X1GE7FA.05, w/ Inlet Chillers) 408 424 398 784 59 10,340 7.47 4.4 5.7 0.0007 0.007 Combustion Turbine (2X1GE7FA, w/ Recip Engine) 201 201 201 1,007 60 8,868 7.47 6.4 6.6 0.0007 0.018 Aero-Derivative (1X GE LM6000PF) 46 48 44 1,047 60 9,585 7.47 3.3 15.8 0.0007 0.093 Aero-Derivative (2X GE LM6000PF) 92 96 88 906 60 9,585 7.47 3.3 9.2 0.0007 0.093 Aero-Derivative (2X GE LM6000PF, w/ Blk Start) 92 96 88 982 60 9,585 7.47 3.3 9.2 0.0007 0.093 Aero-Derivative (1X GE LMS100PB) 98 102 95 1,185 59 8,972 7.47 4.3 12.6 0.0007 0.011 Aero-Derivative (2X GE LMS100PB, w/ Blk Start) 196 203 191 786 59 8,972 7.47 4.3 9.0 0.0007 0.093 Aero-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 Notes: (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 Rates
PSO 2012 Integrated Reso

RESOURCE PLANNING MODEL RESULTS: C. Strategist Model Output Reports The following exhibits provide detailed economic and performance output, by year, with end‐effects consolidated, 

AEP‐SPP Hybrid plans:

Table 4: EPA Settlement Option-Low Band A 

Cash Flow ($000)

Market Market

Base Rate Impacts Value of Value of Total

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances Total 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased (P)=(D)+(F) 

Annual 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 

2012 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 2013 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 2014 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 2015 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 2016 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 2017 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 2018 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 2019 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 2020 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 2021 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 2022 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 2023 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 2024 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 2025 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 2026 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 2027 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 

2028 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 

2029 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 2030 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 2031 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 2032 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 2033 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 2034 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 2035 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 2036 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 2037 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 2038 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 

2039 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 2040 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 

2011 Net Present Value

Period of 2011‐2040 6,553,604 (3,180,570) 765,182 8,968,992 1,144,465 547,488 1,691,953 10,660,945 555,125 11,216,071 142,137 11,073,933

Base Case O&M 2011 ‐ 2040 1,151,822 1,151,822 1,151,822

Utility Cost Present Value 2011 ‐ 2040 2,843,775 12,367,893 12,225,755

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Northeastern 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 Retirement

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 5: EPA Settlement Option-Low Band B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pur

2011 18,643 3,003 (3,003) 2,863 2,952 89 2011 8,455 7,274 2,123 880 22012 18,688 2,906 (2,906) 2,740 5,756 3,016 2012 10,870 7,117 2,245 661 22013 18,702 2,922 (2,922) 1,953 4,585 2,633 2013 7,671 6,754 2,237 685 12014 18,748 2,777 (2,777) 2,096 4,497 2,401 2014 7,487 7,049 2,237 540 22015 18,779 2,817 (2,817) 1,616 4,237 2,622 2015 7,973 6,720 2,237 580 12016 18,832 2,803 (2,803) 1,905 3,956 2,052 2016 8,292 4,830 2,245 558 12017 18,847 3,150 (3,150) 1,646 3,998 2,352 2017 8,454 3,960 2,532 618 12018 18,883 3,285 (3,285) 1,839 3,629 1,791 2018 8,094 3,791 2,606 680 12019 18,945 3,279 (3,279) 1,682 3,876 2,194 2019 8,284 3,939 2,606 674 12020 18,996 3,570 (3,570) 1,797 2,826 1,029 2020 6,944 4,103 2,911 659 12021 19,064 3,632 (3,632) 1,909 2,720 812 2021 7,308 3,439 2,975 657 12022 19,169 3,632 (3,632) 2,339 2,680 341 2022 7,194 3,258 2,975 657 22023 19,280 3,927 (3,927) 2,141 2,697 556 2023 7,085 2,976 3,270 657 22024 19,404 4,014 (4,014) 2,382 2,589 208 2024 6,717 3,029 3,355 659 22025 19,534 4,001 (4,001) 2,652 2,527 (124) 2025 7,045 2,561 3,343 657 2

2026 19,671 4,307 (4,307) 2,602 2,496 (105) 2026 6,821 2,664 3,639 668 2

2027 19,813 4,380 (4,380) 3,154 2,434 (720) 2027 7,496 598 3,712 668 3

2028 19,969 4,409 (4,409) 3,056 2,496 (560) 2028 7,292 632 3,725 683 3

2029 20,127 4,985 (4,985) 2,742 2,586 (156) 2029 7,261 650 4,303 682 2

2030 20,300 5,149 (5,149) 2,840 2,620 (220) 2030 7,248 651 4,450 699 2

2031 20,485 4,864 (4,864) 3,294 2,470 (824) 2031 8,076 637 4,165 699 3

2032 20,678 4,766 (4,766) 3,877 2,427 (1,451) 2032 8,305 638 4,065 701 3

2033 20,875 4,750 (4,750) 4,089 2,424 (1,664) 2033 8,321 631 4,051 699 42034 21,092 4,750 (4,750) 4,044 2,380 (1,663) 2034 8,532 626 4,051 699 42035 21,324 4,750 (4,750) 4,173 2,345 (1,828) 2035 8,581 631 4,051 699 42036 21,568 4,766 (4,766) 4,105 2,348 (1,756) 2036 8,869 632 4,065 701 4

2037 21,821 4,750 (4,750) 4,394 2,355 (2,039) 2037 8,876 627 4,051 699 4

2038 22,060 4,750 (4,750) 4,159 2,470 (1,689) 2038 8,657 618 4,051 699 42039 22,299 4,750 (4,750) 4,067 2,352 (1,715) 2039 8,392 613 4,051 699 42040 22,541 4,765 (4,765) 4,103 2,445 (1,658) 2040 8,655 617 4,064 701 4

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,452 11,308 15,090 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,426 12,708 14,615 4552013 4,102 4,904 0 4,904 19.6% 2013 21,342 11,867 11,886 4452014 4,109 4,902 0 4,902 19.3% 2014 22,355 11,992 12,092 4062015 4,099 4,902 0 4,902 19.6% 2015 19,404 11,925 11,904 5332016 4,094 4,691 0 4,691 14.6% 2016 10,294 10,650 8,175 5522017 4,083 4,697 0 4,697 15.0% 2017 6,808 10,097 7,305 5532018 4,079 4,697 0 4,697 15.1% 2018 6,293 9,732 7,084 6462019 4,081 4,697 0 4,697 15.1% 2019 6,843 9,981 7,368 5092020 4,078 4,708 0 4,708 15.4% 2020 6,861 9,381 6,193 6712021 4,091 4,708 0 4,708 15.1% 2021 5,762 9,033 6,156 6082022 4,105 4,708 0 4,708 14.7% 2022 5,687 8,774 5,860 4612023 4,117 4,721 0 4,721 14.7% 2023 5,022 8,693 5,850 5612024 4,130 4,497 236 4,733 14.6% 2024 5,033 8,597 5,776 6102025 4,156 4,497 0 4,733 13.9% 2025 4,276 8,304 5,466 5482026 4,179 4,508 236 4,979 19.1% 2026 4,282 8,286 5,436 6552027 4,204 4,048 469 4,988 18.6% 2027 45 6,925 4,328 6152028 4,225 4,050 0 4,989 18.1% 2028 49 6,993 4,077 6502029 4,253 4,068 0 5,008 17.8% 2029 50 7,031 4,219 6682030 4,284 4,071 0 5,010 16.9% 2030 51 7,032 4,332 6692031 4,318 3,803 236 4,978 15.3% 2031 50 7,066 4,732 6562032 4,348 3,803 0 4,978 14.5% 2032 51 6,996 4,990 6572033 4,390 3,803 236 5,213 18.7% 2033 50 6,993 5,111 6502034 4,427 3,803 0 5,213 17.8% 2034 50 7,083 5,107 6452035 4,471 3,803 0 5,213 16.6% 2035 51 7,156 5,283 6502036 4,511 3,803 0 5,213 15.6% 2036 51 7,300 5,527 6512037 4,565 3,803 0 5,213 14.2% 2037 51 7,332 5,535 6462038 4,611 3,803 233 5,446 18.1% 2038 52 7,450 5,192 6372039 4,657 3,803 0 5,446 16.9% 2039 53 7,521 5,081 6312040 4,691 3,803 0 5,446 16.1% 2040 53 7,660 5,320 636

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 6: Option #1 – 15 Year Low Band A

Cash Flow ($

Market Market

Base Rate Impacts Value of Value of Tot

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

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 

2012 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 

2013 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 

2014 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 

2015 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 2016 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 2017 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 2018 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 2019 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 2020 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 2021 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 2022 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 2023 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 2024 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 2025 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 2026 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 2027 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 2028 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 2029 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 2030 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 2031 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 2032 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 2033 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 2034 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 2035 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 2036 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 2037 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 2038 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 

2039 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 2040 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 

2011 Net Present Value

Period of 2011‐2040 6,311,710 (3,170,690) 1,091,383 8,391,018 1,709,503 714,092 2,423,596 10,814,613 698,203 11,512,816 258,976 11,253,841

Base Case O&M2011 ‐ 2040 1,151,822 1,151,822 1,151,822

Utility Cost Present Value 2011 ‐ 2040 3,575,417 12,664,638 12,405,662

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Northeastern 3 and Northeastern 4 DFGD 15 Year Retrofit 3/1/2016 and 2/28/2031 Retirement

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 7: Option #1 – 15 Year Low Band B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pur

2011 18,643 3,003 (3,003) 2,863 2,952 89 2011 8,455 7,274 2,123 880 22012 18,688 2,906 (2,906) 2,740 5,756 3,016 2012 10,870 7,117 2,245 661 22013 18,702 2,922 (2,922) 1,953 4,585 2,633 2013 7,671 6,754 2,237 685 12014 18,748 2,777 (2,777) 2,096 4,497 2,401 2014 7,487 7,049 2,237 540 22015 18,779 2,817 (2,817) 1,616 4,237 2,622 2015 7,973 6,720 2,237 580 12016 18,832 2,803 (2,803) 1,383 4,194 2,811 2016 7,626 7,318 2,245 558 12017 18,847 3,150 (3,150) 1,103 4,271 3,169 2017 7,922 7,065 2,532 618 12018 18,883 3,285 (3,285) 1,215 3,865 2,649 2018 7,178 7,209 2,606 680 12019 18,945 3,279 (3,279) 1,231 4,089 2,859 2019 7,718 6,928 2,606 674 12020 18,996 3,570 (3,570) 1,078 2,999 1,921 2020 6,308 7,277 2,911 659 12021 19,064 3,632 (3,632) 1,175 2,948 1,772 2021 6,411 7,007 2,975 657 12022 19,169 3,632 (3,632) 1,713 2,832 1,119 2022 6,113 6,793 2,975 657 12023 19,280 3,927 (3,927) 1,469 2,880 1,411 2023 6,076 6,453 3,270 657 12024 19,404 4,014 (4,014) 1,492 2,787 1,294 2024 5,589 6,848 3,355 659 12025 19,534 4,001 (4,001) 1,564 2,787 1,223 2025 5,795 6,729 3,343 657 12026 19,671 4,307 (4,307) 1,468 2,744 1,276 2026 5,648 6,763 3,639 668 12027 19,813 4,380 (4,380) 1,703 2,712 1,009 2027 5,925 6,282 3,712 668 12028 19,969 4,409 (4,409) 1,488 2,773 1,285 2028 5,768 6,825 3,725 683 12029 20,127 4,985 (4,985) 1,538 2,831 1,293 2029 5,945 6,256 4,303 682 12030 20,300 5,149 (5,149) 1,430 3,027 1,598 2030 5,799 6,718 4,450 699 12031 20,485 4,864 (4,864) 3,140 2,567 (573) 2031 7,943 2,063 4,165 699 32032 20,678 4,766 (4,766) 3,877 2,427 (1,451) 2032 8,305 638 4,065 701 3

2033 20,875 4,750 (4,750) 4,089 2,424 (1,664) 2033 8,321 631 4,051 699 42034 21,092 4,750 (4,750) 4,044 2,380 (1,663) 2034 8,532 626 4,051 699 42035 21,324 4,750 (4,750) 4,173 2,345 (1,828) 2035 8,581 631 4,051 699 42036 21,568 4,766 (4,766) 4,105 2,348 (1,756) 2036 8,869 632 4,065 701 42037 21,821 4,750 (4,750) 4,394 2,355 (2,039) 2037 8,876 627 4,051 699 42038 22,060 4,750 (4,750) 4,159 2,470 (1,689) 2038 8,657 618 4,051 699 42039 22,299 4,750 (4,750) 4,067 2,352 (1,715) 2039 8,392 613 4,051 699 4

2040 22,541 4,765 (4,765) 4,103 2,445 (1,658) 2040 8,655 617 4,064 701 4

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,452 11,308 15,090 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,426 12,708 14,615 4552013 4,102 4,904 0 4,904 19.6% 2013 21,342 11,867 11,886 4452014 4,109 4,902 0 4,902 19.3% 2014 22,355 11,992 12,092 4062015 4,099 4,902 0 4,902 19.6% 2015 19,404 11,925 11,904 5332016 4,094 4,915 0 4,915 20.1% 2016 6,079 12,556 7,447 5592017 4,083 4,921 0 4,921 20.5% 2017 1,272 12,491 6,705 5612018 4,079 4,921 0 4,921 20.6% 2018 1,286 12,251 6,319 6482019 4,081 4,921 0 4,921 20.6% 2019 1,252 12,248 6,632 5132020 4,078 4,932 0 4,932 20.9% 2020 1,300 11,844 5,486 6562021 4,091 4,932 0 4,932 20.6% 2021 1,257 11,651 5,586 5962022 4,105 4,932 0 4,932 20.1% 2022 1,232 11,267 5,208 4632023 4,117 4,945 0 4,945 20.1% 2023 1,160 11,136 5,332 5572024 4,130 4,721 0 4,721 14.3% 2024 1,228 11,313 5,229 5922025 4,156 4,721 236 4,957 19.3% 2025 1,216 11,262 5,080 5012026 4,179 4,732 0 4,967 18.9% 2026 1,212 11,242 5,153 5982027 4,204 4,732 0 4,967 18.2% 2027 1,125 10,923 5,189 5612028 4,225 4,733 0 4,969 17.6% 2028 1,225 11,372 5,194 5852029 4,253 4,752 0 4,988 17.3% 2029 1,115 10,915 5,269 6112030 4,284 4,754 0 4,990 16.5% 2030 1,202 11,320 5,443 6122031 4,318 3,803 940 4,978 15.3% 2031 320 8,037 5,163 6402032 4,348 3,803 0 4,978 14.5% 2032 51 6,996 4,990 6572033 4,390 3,803 236 5,213 18.7% 2033 50 6,993 5,111 6502034 4,427 3,803 0 5,213 17.8% 2034 50 7,083 5,107 6452035 4,471 3,803 0 5,213 16.6% 2035 51 7,156 5,283 6502036 4,511 3,803 0 5,213 15.6% 2036 51 7,300 5,527 6512037 4,565 3,803 0 5,213 14.2% 2037 51 7,332 5,535 6462038 4,611 3,803 233 5,446 18.1% 2038 52 7,450 5,192 6372039 4,657 3,803 0 5,446 16.9% 2039 53 7,521 5,081 6312040 4,691 3,803 0 5,446 16.1% 2040 53 7,660 5,320 636

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 8: Option #1 – 25 Year Low Band A 

Cash Flow ($

Market Market

Base Rate Impacts Value of Value of Tot

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

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 

2012 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 

2013 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 

2014 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 

2015 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 

2016 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 

2017 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 

2018 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 

2019 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 

2020 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 

2021 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 

2022 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 2023 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 

2024 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 

2025 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 2026 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 2027 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 2028 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 

2029 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 

2030 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 

2031 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 

2032 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 

2033 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 2034 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 

2035 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 2036 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 2037 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 2038 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 

2039 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 2040 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 

2011 Net Present Value

Period of 2011‐2040 6,332,781 (3,175,722) 1,418,724 8,089,779 1,392,507 769,673 2,162,180 10,251,959 811,479 11,063,439 260,239 10,803,200

Base Case O&M2011 ‐ 2040 1,151,822 1,151,822 1,151,822

Utility Cost Present Value 2011 ‐ 2040 3,314,002 12,215,260 11,955,021

Costs and Emissions Summary Under Low Band Pricing

Northeastern 3 and Northeastern 4 DFGD 25 Year Retrofit 3/1/2016

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 9: Option #1 – 25 Year Low Band B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pur

2011 18,643 3,003 (3,003) 2,863 2,952 89 2011 8,455 7,274 2,123 880 22012 18,688 2,906 (2,906) 3,738 7,085 3,347 2012 11,175 7,130 2,245 661 32013 18,702 2,922 (2,922) 2,474 5,428 2,954 2013 7,925 6,793 2,237 685 22014 18,748 2,777 (2,777) 2,570 5,321 2,751 2014 7,762 7,097 2,237 540 22015 18,779 2,817 (2,817) 2,027 4,930 2,903 2015 8,193 6,757 2,237 580 22016 18,832 2,803 (2,803) 1,553 4,610 3,057 2016 7,808 7,363 2,245 558 12017 18,847 3,150 (3,150) 1,263 4,666 3,403 2017 8,097 7,103 2,532 618 12018 18,883 3,285 (3,285) 1,305 4,169 2,864 2018 7,340 7,241 2,606 680 12019 18,945 3,279 (3,279) 1,412 4,499 3,087 2019 7,898 6,954 2,606 674 12020 18,996 3,570 (3,570) 1,031 3,024 1,992 2020 6,338 7,310 2,911 659 12021 19,064 3,632 (3,632) 1,085 2,920 1,835 2021 6,443 7,029 2,975 657 12022 19,169 3,632 (3,632) 1,614 2,826 1,212 2022 6,148 6,840 2,975 657 12023 19,280 3,927 (3,927) 1,401 2,899 1,498 2023 6,119 6,496 3,270 657 12024 19,404 4,014 (4,014) 1,384 2,771 1,387 2024 5,628 6,901 3,355 659 12025 19,534 4,001 (4,001) 1,462 2,764 1,302 2025 5,822 6,781 3,343 657 12026 19,671 4,307 (4,307) 1,337 2,678 1,341 2026 5,670 6,805 3,639 668 12027 19,813 4,380 (4,380) 1,522 2,612 1,090 2027 5,960 6,328 3,712 668 12028 19,969 4,409 (4,409) 1,341 2,714 1,374 2028 5,798 6,883 3,725 683 12029 20,127 4,985 (4,985) 1,468 2,852 1,384 2029 5,984 6,306 4,303 682 12030 20,300 5,149 (5,149) 1,361 3,066 1,705 2030 5,844 6,779 4,450 699 12031 20,485 4,864 (4,864) 1,429 2,795 1,365 2031 6,250 6,506 4,165 699 12032 20,678 4,766 (4,766) 1,526 2,836 1,309 2032 6,132 6,847 4,065 701 12033 20,875 4,750 (4,750) 1,773 2,782 1,009 2033 6,389 6,514 4,051 699 12034 21,092 4,750 (4,750) 1,661 2,815 1,154 2034 6,477 6,780 4,051 699 12035 21,324 4,750 (4,750) 2,003 2,812 808 2035 6,558 6,593 4,051 699 22036 21,568 4,766 (4,766) 2,072 3,087 1,015 2036 6,750 6,832 4,065 701 22037 21,821 4,750 (4,750) 2,586 3,188 601 2037 6,819 6,620 4,051 699 22038 22,060 4,750 (4,750) 2,519 3,332 813 2038 6,987 6,907 4,051 699 22039 22,299 4,750 (4,750) 2,959 3,080 121 2039 6,963 6,480 4,051 699 22040 22,541 4,765 (4,765) 2,866 3,223 357 2040 7,203 6,689 4,064 701 2

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,452 11,308 15,090 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,469 12,875 14,841 4552013 4,102 4,904 0 4,904 19.6% 2013 21,464 12,038 12,132 4452014 4,109 4,902 0 4,902 19.3% 2014 22,506 12,180 12,354 4052015 4,099 4,902 0 4,902 19.6% 2015 19,512 12,075 12,119 5322016 4,094 4,915 0 4,915 20.1% 2016 6,101 12,692 7,607 5622017 4,083 4,921 0 4,921 20.5% 2017 1,279 12,620 6,849 5602018 4,079 4,921 0 4,921 20.6% 2018 1,292 12,366 6,456 6432019 4,081 4,921 0 4,921 20.6% 2019 1,257 12,369 6,782 5122020 4,078 4,932 0 4,932 20.9% 2020 1,306 11,891 5,513 6582021 4,091 4,932 0 4,932 20.6% 2021 1,261 11,689 5,610 5972022 4,105 4,932 0 4,932 20.1% 2022 1,241 11,330 5,241 4622023 4,117 4,945 0 4,945 20.1% 2023 1,167 11,196 5,370 5582024 4,130 4,721 0 4,721 14.3% 2024 1,238 11,381 5,269 5952025 4,156 4,721 236 4,957 19.3% 2025 1,225 11,323 5,109 5032026 4,179 4,732 0 4,967 18.9% 2026 1,219 11,292 5,177 6012027 4,204 4,732 0 4,967 18.2% 2027 1,133 10,981 5,220 5632028 4,225 4,733 0 4,969 17.6% 2028 1,235 11,439 5,227 5882029 4,253 4,752 0 4,988 17.3% 2029 1,124 10,980 5,305 6152030 4,284 4,754 0 4,990 16.5% 2030 1,213 11,399 5,487 6172031 4,318 4,746 0 4,982 15.4% 2031 1,164 11,302 5,448 6042032 4,348 4,746 0 4,982 14.6% 2032 1,227 11,590 5,484 6022033 4,390 4,746 236 5,217 18.8% 2033 1,165 11,411 5,757 6032034 4,427 4,746 0 5,217 17.8% 2034 1,215 11,701 5,690 5962035 4,471 4,746 0 5,217 16.7% 2035 1,178 11,571 5,810 6052036 4,511 4,746 0 5,217 15.7% 2036 1,225 11,906 6,077 6002037 4,565 4,746 0 5,217 14.3% 2037 1,186 11,739 5,997 6002038 4,611 4,746 236 5,453 18.3% 2038 1,239 12,091 6,058 5972039 4,657 4,746 0 5,453 17.1% 2039 1,160 11,690 6,024 5982040 4,691 4,746 0 5,453 16.2% 2040 1,199 12,019 6,308 602

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 10: Option #2 – 15 Year Low Band A 

Cash Flow ($

Market Market

Base Rate Impacts Value of Value of Tot

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

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 

2012 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 

2013 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 

2014 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 

2015 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 

2016 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 

2017 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 

2018 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 

2019 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 

2020 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 2021 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 2022 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 2023 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 2024 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 2025 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 2026 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 2027 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 2028 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 2029 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 2030 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 

2031 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 2032 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 2033 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 2034 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 2035 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 2036 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 2037 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 2038 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 

2039 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 2040 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 

2011 Net Present Value

Period of 2011‐2040 6,554,743 (3,180,215) 931,252 8,803,706 1,289,739 633,870 1,923,609 10,727,315 611,021 11,338,336 134,560 11,203,777

Base Case O&M2011 ‐ 2040 1,151,822 1,151,822 1,151,822

Utility Cost Present Value 2011 ‐ 2040 3,075,431 12,490,158 12,355,599

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Northeastern 3 DFGD 15 Year Retrofit 3/1/2016 and 2/28/2031 Retirement and Northeastern 4 Retirement 2/28/2016

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 11: Option #2 – 15 Year Low Band B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pur

2011 18,643 3,003 (3,003) 2,863 2,952 89 2011 8,455 7,274 2,123 880 22012 18,688 2,906 (2,906) 2,740 5,756 3,016 2012 10,870 7,117 2,245 661 22013 18,702 2,922 (2,922) 1,953 4,585 2,633 2013 7,671 6,754 2,237 685 12014 18,748 2,777 (2,777) 2,096 4,497 2,401 2014 7,487 7,049 2,237 540 22015 18,779 2,817 (2,817) 1,616 4,237 2,622 2015 7,973 6,720 2,237 580 12016 18,832 2,803 (2,803) 1,880 3,940 2,060 2016 8,363 4,741 2,245 558 12017 18,847 3,150 (3,150) 1,743 3,952 2,209 2017 8,584 3,677 2,532 618 12018 18,883 3,285 (3,285) 1,702 3,653 1,951 2018 7,958 4,090 2,606 680 12019 18,945 3,279 (3,279) 1,840 3,784 1,944 2019 8,437 3,533 2,606 674 12020 18,996 3,570 (3,570) 1,779 2,817 1,039 2020 7,087 3,917 2,911 659 12021 19,064 3,632 (3,632) 1,867 2,734 867 2021 7,166 3,646 2,975 657 12022 19,169 3,632 (3,632) 2,165 2,708 543 2022 6,942 3,770 2,975 657 22023 19,280 3,927 (3,927) 1,939 2,740 801 2023 6,831 3,480 3,270 657 12024 19,404 4,014 (4,014) 1,746 2,706 960 2024 5,853 3,886 3,355 659 12025 19,534 4,001 (4,001) 1,739 2,709 970 2025 5,834 3,786 3,343 657 12026 19,671 4,307 (4,307) 1,592 2,687 1,095 2026 5,775 3,856 3,639 668 12027 19,813 4,380 (4,380) 1,680 2,691 1,011 2027 5,919 3,572 3,712 668 12028 19,969 4,409 (4,409) 1,627 2,718 1,092 2028 5,836 3,919 3,725 683 12029 20,127 4,985 (4,985) 1,532 2,810 1,278 2029 5,942 3,505 4,303 682 12030 20,300 5,149 (5,149) 1,550 2,921 1,371 2030 5,839 3,757 4,450 699 12031 20,485 4,864 (4,864) 2,919 2,577 (343) 2031 7,767 1,500 4,165 699 22032 20,678 4,766 (4,766) 3,877 2,427 (1,451) 2032 8,305 638 4,065 701 3

2033 20,875 4,750 (4,750) 4,089 2,424 (1,664) 2033 8,321 631 4,051 699 42034 21,092 4,750 (4,750) 4,044 2,380 (1,663) 2034 8,532 626 4,051 699 42035 21,324 4,750 (4,750) 4,173 2,345 (1,828) 2035 8,581 631 4,051 699 42036 21,568 4,766 (4,766) 4,105 2,348 (1,756) 2036 8,869 632 4,065 701 42037 21,821 4,750 (4,750) 4,394 2,355 (2,039) 2037 8,876 627 4,051 699 42038 22,060 4,750 (4,750) 4,159 2,470 (1,689) 2038 8,657 618 4,051 699 42039 22,299 4,750 (4,750) 4,067 2,352 (1,715) 2039 8,392 613 4,051 699 4

2040 22,541 4,765 (4,765) 4,103 2,445 (1,658) 2040 8,655 617 4,064 701 4

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,452 11,308 15,090 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,426 12,708 14,615 4552013 4,102 4,904 0 4,904 19.6% 2013 21,342 11,867 11,886 4452014 4,109 4,902 0 4,902 19.3% 2014 22,355 11,992 12,092 4062015 4,099 4,902 0 4,902 19.6% 2015 19,404 11,925 11,904 5332016 4,094 4,698 0 4,698 14.8% 2016 5,582 10,720 7,208 5522017 4,083 4,704 0 4,704 15.2% 2017 618 10,029 5,989 5532018 4,079 4,704 0 4,704 15.3% 2018 683 10,080 5,796 6482019 4,081 4,704 0 4,704 15.3% 2019 596 9,805 5,966 5092020 4,078 4,715 0 4,715 15.6% 2020 649 9,439 4,876 6702021 4,091 4,715 0 4,715 15.3% 2021 606 9,233 4,989 6082022 4,105 4,715 0 4,715 14.9% 2022 646 9,203 4,779 4612023 4,117 4,729 0 4,729 14.9% 2023 582 9,088 4,893 5612024 4,130 4,505 233 4,738 14.7% 2024 654 9,290 4,333 6102025 4,156 4,505 0 4,738 14.0% 2025 645 9,233 3,961 5262026 4,179 4,515 0 4,748 13.6% 2026 648 9,279 4,055 6232027 4,204 4,515 236 4,984 18.6% 2027 600 9,132 4,047 5802028 4,225 4,517 0 4,986 18.0% 2028 661 9,398 4,059 6102029 4,253 4,536 0 5,004 17.7% 2029 582 9,098 4,156 6312030 4,284 4,538 0 5,007 16.9% 2030 628 9,288 4,251 6362031 4,318 3,803 707 4,978 15.3% 2031 211 7,731 4,774 6432032 4,348 3,803 0 4,978 14.5% 2032 51 6,996 4,990 6572033 4,390 3,803 236 5,213 18.7% 2033 50 6,993 5,111 6502034 4,427 3,803 0 5,213 17.8% 2034 50 7,083 5,107 6452035 4,471 3,803 0 5,213 16.6% 2035 51 7,156 5,283 6502036 4,511 3,803 0 5,213 15.6% 2036 51 7,300 5,527 6512037 4,565 3,803 0 5,213 14.2% 2037 51 7,332 5,535 6462038 4,611 3,803 233 5,446 18.1% 2038 52 7,450 5,192 6372039 4,657 3,803 0 5,446 16.9% 2039 53 7,521 5,081 6312040 4,691 3,803 0 5,446 16.1% 2040 53 7,660 5,320 636

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 12: Option #2 – 25 Year Low Band A 

Cash Flow ($

Market Market

Base Rate Impacts Value of Value of Tot

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

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 

2012 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 

2013 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 

2014 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 

2015 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 

2016 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 

2017 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 

2018 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 

2019 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 

2020 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 2021 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 2022 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 2023 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 2024 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 2025 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 2026 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 2027 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 2028 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 2029 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 2030 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 2031 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 2032 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 2033 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 2034 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 2035 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 2036 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 2037 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 2038 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 

2039 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 2040 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 

2011 Net Present Value

Period of 2011‐2040 6,490,615 (3,180,214) 955,877 8,714,952 1,097,012 650,624 1,747,636 10,462,588 661,672 11,124,261 135,056 10,989,205

Base Case O&M2011 ‐ 2040 1,151,822 1,151,822 1,151,822

Utility Cost Present Value 2011 ‐ 2040 2,899,458 12,276,082 12,141,027

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Northeastern 3 DFGD 25 Year Retrofit 3/1/2016 and Northeastern 4 Retirement 2/28/2016

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 13: Option #2 – 25 Year Low Band B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pur

2011 18,643 3,003 (3,003) 2,863 2,952 89 2011 8,455 7,274 2,123 880 22012 18,688 2,906 (2,906) 2,740 5,756 3,016 2012 10,870 7,117 2,245 661 22013 18,702 2,922 (2,922) 1,953 4,585 2,633 2013 7,671 6,754 2,237 685 12014 18,748 2,777 (2,777) 2,096 4,497 2,401 2014 7,487 7,049 2,237 540 22015 18,779 2,817 (2,817) 1,616 4,237 2,622 2015 7,973 6,720 2,237 580 12016 18,832 2,803 (2,803) 1,880 3,940 2,060 2016 8,363 4,741 2,245 558 12017 18,847 3,150 (3,150) 1,743 3,952 2,209 2017 8,584 3,677 2,532 618 12018 18,883 3,285 (3,285) 1,702 3,653 1,951 2018 7,958 4,090 2,606 680 12019 18,945 3,279 (3,279) 1,840 3,784 1,944 2019 8,437 3,533 2,606 674 12020 18,996 3,570 (3,570) 1,779 2,817 1,039 2020 7,087 3,917 2,911 659 12021 19,064 3,632 (3,632) 1,867 2,734 867 2021 7,166 3,646 2,975 657 12022 19,169 3,632 (3,632) 2,165 2,708 543 2022 6,942 3,770 2,975 657 22023 19,280 3,927 (3,927) 1,939 2,740 801 2023 6,831 3,480 3,270 657 12024 19,404 4,014 (4,014) 1,999 2,648 649 2024 6,309 3,886 3,355 659 12025 19,534 4,001 (4,001) 2,085 2,645 560 2025 6,512 3,788 3,343 657 22026 19,671 4,307 (4,307) 1,984 2,619 635 2026 6,386 3,862 3,639 668 12027 19,813 4,380 (4,380) 2,124 2,600 476 2027 6,536 3,584 3,712 668 22028 19,969 4,409 (4,409) 2,036 2,641 605 2028 6,430 3,930 3,725 683 22029 20,127 4,985 (4,985) 1,968 2,717 748 2029 6,582 3,514 4,303 682 12030 20,300 5,149 (5,149) 1,997 2,796 799 2030 6,474 3,762 4,450 699 12031 20,485 4,864 (4,864) 2,551 2,581 29 2031 7,317 3,524 4,165 699 22032 20,678 4,766 (4,766) 2,944 2,551 (394) 2032 7,386 3,888 4,065 701 22033 20,875 4,750 (4,750) 3,251 2,544 (708) 2033 7,658 3,527 4,051 699 32034 21,092 4,750 (4,750) 2,994 2,538 (455) 2034 7,790 3,858 4,051 699 22035 21,324 4,750 (4,750) 3,248 2,523 (725) 2035 7,757 3,861 4,051 699 32036 21,568 4,766 (4,766) 3,256 2,567 (689) 2036 8,023 3,852 4,065 701 32037 21,821 4,750 (4,750) 3,689 2,539 (1,150) 2037 8,063 3,625 4,051 699 3

2038 22,060 4,750 (4,750) 3,584 2,617 (967) 2038 8,188 3,926 4,051 699 32039 22,299 4,750 (4,750) 3,901 2,378 (1,523) 2039 8,315 3,483 4,051 699 3

2040 22,541 4,765 (4,765) 3,845 2,500 (1,345) 2040 8,487 3,705 4,064 701 3

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,452 11,308 15,090 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,426 12,708 14,615 4552013 4,102 4,904 0 4,904 19.6% 2013 21,342 11,867 11,886 4452014 4,109 4,902 0 4,902 19.3% 2014 22,355 11,992 12,092 4062015 4,099 4,902 0 4,902 19.6% 2015 19,404 11,925 11,904 5332016 4,094 4,698 0 4,698 14.8% 2016 5,582 10,720 7,208 5522017 4,083 4,704 0 4,704 15.2% 2017 618 10,029 5,989 5532018 4,079 4,704 0 4,704 15.3% 2018 683 10,080 5,796 6482019 4,081 4,704 0 4,704 15.3% 2019 596 9,805 5,966 5092020 4,078 4,715 0 4,715 15.6% 2020 649 9,439 4,876 6702021 4,091 4,715 0 4,715 15.3% 2021 606 9,233 4,989 6082022 4,105 4,715 0 4,715 14.9% 2022 646 9,203 4,779 4612023 4,117 4,729 0 4,729 14.9% 2023 582 9,088 4,893 5612024 4,130 4,505 236 4,740 14.8% 2024 652 9,253 4,737 6062025 4,156 4,505 0 4,740 14.1% 2025 642 9,218 4,597 5272026 4,179 4,515 0 4,751 13.7% 2026 646 9,238 4,644 6282027 4,204 4,515 236 4,986 18.6% 2027 599 9,061 4,616 5832028 4,225 4,517 0 4,988 18.1% 2028 659 9,343 4,650 6152029 4,253 4,536 0 5,007 17.7% 2029 581 9,027 4,695 6342030 4,284 4,538 0 5,009 16.9% 2030 625 9,206 4,795 6392031 4,318 4,270 236 4,976 15.2% 2031 583 9,047 5,194 6302032 4,348 4,270 0 4,976 14.4% 2032 651 9,235 5,446 6302033 4,390 4,270 236 5,212 18.7% 2033 585 9,038 5,705 6272034 4,427 4,270 0 5,212 17.7% 2034 646 9,421 5,777 6202035 4,471 4,270 0 5,212 16.6% 2035 647 9,426 5,862 6262036 4,511 4,270 0 5,212 15.5% 2036 645 9,545 6,056 6302037 4,565 4,270 0 5,212 14.2% 2037 603 9,360 6,035 6272038 4,611 4,270 236 5,447 18.1% 2038 660 9,710 6,094 6232039 4,657 4,270 0 5,447 17.0% 2039 579 9,391 6,123 6232040 4,691 4,270 0 5,447 16.1% 2040 619 9,686 6,376 628

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 14: Option #4 – Low Band A 

Cash Flow ($

Market Market

Base Rate Impacts Value of Value of Tot

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

2011 410,972 (114,466) 22,182 503,255 0 0 0 503,255 375 503,630 0 503,630 503,630 0 

2012 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 2013 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 2014 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 2015 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 2016 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 

2017 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 2018 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 2019 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 2020 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 

2021 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 

2022 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 

2023 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 

2024 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 

2025 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 

2026 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 

2027 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 

2028 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 

2029 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 

2030 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 

2031 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 

2032 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 

2033 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 2034 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 

2035 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 

2036 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 2037 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 

2038 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 

2039 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 2040 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 

2011 Net Present Value

Period of 2011‐2040 6,802,596 (3,183,308) 810,343 9,175,561 1,254,038 373,988 1,628,026 10,803,587 519,744 11,323,331 134,091 11,189,240

Base Case O&M 2011 ‐ 2040 1,151,822 1,151,822 1,151,822

Utility Cost Present Value 2011 ‐ 2040 2,779,848 12,475,153 12,341,062

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Northeastern 3 and Northeastern 4 Retirement 2/28/2016 Replaced with 2 233 MW Combined Cycle Units and 1 233 MW PPA

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 15: Option #4 – Low Band B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Purc

2011 18,643 3,003 (3,003) 2,863 2,952 89 2011 8,455 7,274 2,123 880 2

2012 18,688 2,906 (2,906) 2,740 5,756 3,016 2012 10,870 7,117 2,245 661 2

2013 18,702 2,922 (2,922) 1,953 4,585 2,633 2013 7,671 6,754 2,237 685 1

2014 18,748 2,777 (2,777) 2,096 4,497 2,401 2014 7,487 7,049 2,237 540 2

2015 18,779 2,817 (2,817) 1,616 4,237 2,622 2015 7,973 6,720 2,237 580 1

2016 18,832 2,803 (2,803) 2,457 3,716 1,258 2016 8,595 2,208 2,245 558 2

2017 18,847 3,150 (3,150) 2,027 3,870 1,843 2017 8,703 527 2,532 618 2

2018 18,883 3,285 (3,285) 2,093 3,537 1,445 2018 8,246 625 2,606 680 2

2019 18,945 3,279 (3,279) 2,111 3,763 1,652 2019 8,519 485 2,606 674 2

2020 18,996 3,570 (3,570) 2,222 2,749 527 2020 7,230 663 2,911 659 2

2021 19,064 3,632 (3,632) 2,139 2,694 556 2021 7,292 583 2,975 657 2

2022 19,169 3,632 (3,632) 2,448 2,655 207 2022 7,246 438 2,975 657 2

2023 19,280 3,927 (3,927) 2,130 2,706 576 2023 6,971 532 3,270 657 2

2024 19,404 4,014 (4,014) 2,307 2,588 281 2024 6,639 584 3,355 659 2

2025 19,534 4,001 (4,001) 2,501 2,549 48 2025 6,787 535 3,343 657 2

2026 19,671 4,307 (4,307) 2,368 2,574 206 2026 6,707 642 3,639 668 2

2027 19,813 4,380 (4,380) 2,389 2,534 145 2027 6,728 594 3,712 668 2

2028 19,969 4,409 (4,409) 2,490 2,570 79 2028 6,756 626 3,725 683 2

2029 20,127 4,985 (4,985) 2,161 2,668 507 2029 6,723 645 4,303 682 2

2030 20,300 5,149 (5,149) 2,263 2,741 478 2030 6,717 644 4,450 699 2

2031 20,485 4,864 (4,864) 2,694 2,546 (149) 2031 7,537 630 4,165 699 2

2032 20,678 4,766 (4,766) 3,294 2,509 (785) 2032 7,724 633 4,065 701 3

2033 20,875 4,750 (4,750) 3,460 2,533 (927) 2033 7,802 626 4,051 699 3

2034 21,092 4,750 (4,750) 3,369 2,495 (874) 2034 8,066 619 4,051 699 3

2035 21,324 4,750 (4,750) 3,590 2,477 (1,113) 2035 8,031 622 4,051 699 3

2036 21,568 4,766 (4,766) 3,592 2,501 (1,091) 2036 8,248 625 4,065 701 3

2037 21,821 4,750 (4,750) 3,888 2,505 (1,383) 2037 8,241 622 4,051 699 3

2038 22,060 4,750 (4,750) 3,879 2,520 (1,358) 2038 8,515 615 4,051 699 3

2039 22,299 4,750 (4,750) 4,067 2,352 (1,715) 2039 8,392 613 4,051 699 4

2040 22,541 4,765 (4,765) 4,103 2,445 (1,658) 2040 8,655 617 4,064 701 4

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,452 11,308 15,090 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,426 12,708 14,615 4552013 4,102 4,904 0 4,904 19.6% 2013 21,342 11,867 11,886 4452014 4,109 4,902 0 4,902 19.3% 2014 22,355 11,992 12,092 4062015 4,099 4,902 0 4,902 19.6% 2015 19,404 11,925 11,904 5332016 4,094 4,232 466 4,698 14.7% 2016 5,119 8,902 7,150 5502017 4,083 4,238 0 4,704 15.2% 2017 45 7,968 4,943 5482018 4,079 4,238 0 4,704 15.3% 2018 52 7,805 4,796 6442019 4,081 4,238 0 4,704 15.3% 2019 42 7,830 4,949 5042020 4,078 4,249 0 4,715 15.6% 2020 54 7,258 3,830 6812021 4,091 4,249 0 4,715 15.2% 2021 48 7,243 3,945 6022022 4,105 4,249 0 4,715 14.8% 2022 38 7,048 3,725 4562023 4,117 4,262 0 4,728 14.8% 2023 45 7,180 3,817 5532024 4,130 4,038 236 4,739 14.8% 2024 49 7,096 3,656 6042025 4,156 4,038 0 4,739 14.0% 2025 44 7,030 3,546 5492026 4,179 4,048 0 4,750 13.7% 2026 52 7,114 3,714 6602027 4,204 4,048 236 4,985 18.6% 2027 49 7,086 3,574 6102028 4,225 4,050 0 4,987 18.0% 2028 51 7,127 3,630 6442029 4,253 4,069 0 5,006 17.7% 2029 52 7,160 3,660 6622030 4,284 4,071 0 5,008 16.9% 2030 53 7,177 3,847 6622031 4,318 3,803 236 4,975 15.2% 2031 52 7,195 4,210 6482032 4,348 3,803 0 4,975 14.4% 2032 53 7,103 4,454 6522033 4,390 3,803 236 5,211 18.7% 2033 52 7,154 4,668 6452034 4,427 3,803 0 5,211 17.7% 2034 52 7,275 4,716 6382035 4,471 3,803 0 5,211 16.5% 2035 52 7,301 4,826 6412036 4,511 3,803 0 5,211 15.5% 2036 53 7,408 4,976 6442037 4,565 3,803 0 5,211 14.1% 2037 53 7,421 4,997 6402038 4,611 3,803 236 5,446 18.1% 2038 53 7,547 5,064 6332039 4,657 3,803 0 5,446 16.9% 2039 53 7,521 5,081 6312040 4,691 3,803 0 5,446 16.1% 2040 53 7,660 5,320 636

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Low Band Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 16: EPA Settlement Option – Base Case A 

Cash Flow ($

Market Market

Base Rate Impacts Value of Value of Tot

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

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 

2012 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 

2013 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 

2014 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 

2015 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 2016 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 2017 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 2018 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 2019 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 2020 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 2021 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 2022 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 2023 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 2024 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 2025 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 2026 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 2027 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 2028 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 2029 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 2030 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 2031 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 2032 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 2033 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 2034 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 2035 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 2036 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 2037 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 2038 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 

2039 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 2040 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 

2011 Net Present Value

Period of 2011‐2040 7,197,033 (3,352,520) 771,377 9,778,175 1,161,118 542,796 1,703,914 11,482,089 556,706 12,038,794 141,676 11,897,119

Base Case O&M 2011 ‐ 2040 1,159,656 1,159,656 1,159,656

Utility Cost Present Value 2011 ‐ 2040 2,863,570 13,198,451 13,056,775

Northeastern 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 Retirement

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 17: EPA Settlement Option – Base Case B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pur

2011 18,643 3,003 (3,003) 2,872 2,958 86 2011 8,454 7,272 2,123 880 22012 18,688 2,906 (2,906) 2,570 5,365 2,795 2012 9,302 7,098 2,245 661 22013 18,702 2,922 (2,922) 1,990 4,506 2,516 2013 7,510 6,792 2,237 685 12014 18,748 2,777 (2,777) 1,948 4,533 2,585 2014 7,590 7,113 2,237 540 12015 18,779 2,817 (2,817) 1,570 4,187 2,618 2015 7,945 6,732 2,237 580 12016 18,832 2,803 (2,803) 1,865 3,874 2,010 2016 8,248 4,817 2,245 558 12017 18,847 3,150 (3,150) 1,631 3,869 2,238 2017 8,327 3,949 2,532 618 12018 18,883 3,285 (3,285) 1,834 3,492 1,658 2018 7,948 3,795 2,606 680 12019 18,945 3,279 (3,279) 1,762 3,698 1,936 2019 8,059 3,924 2,606 674 12020 18,996 3,570 (3,570) 2,041 2,763 722 2020 6,722 4,054 2,911 659 22021 19,064 3,632 (3,632) 2,279 2,674 395 2021 7,010 3,379 2,975 657 22022 19,169 3,632 (3,632) 2,695 2,612 (83) 2022 6,854 3,245 2,975 657 2

2023 19,280 3,927 (3,927) 2,456 2,622 166 2023 6,727 2,963 3,270 657 22024 19,404 4,014 (4,014) 2,615 2,534 (82) 2024 6,450 3,020 3,355 659 2

2025 19,534 4,001 (4,001) 2,789 2,489 (299) 2025 6,848 2,573 3,343 657 22026 19,671 4,307 (4,307) 2,752 2,449 (302) 2026 6,619 2,672 3,639 668 22027 19,813 4,380 (4,380) 3,298 2,404 (894) 2027 7,318 616 3,712 668 32028 19,969 4,409 (4,409) 3,222 2,460 (761) 2028 7,107 657 3,725 683 32029 20,127 4,985 (4,985) 2,888 2,541 (347) 2029 7,072 676 4,303 682 22030 20,300 5,149 (5,149) 2,991 2,558 (434) 2030 7,034 675 4,450 699 22031 20,485 4,864 (4,864) 3,044 2,447 (597) 2031 7,545 664 4,165 699 32032 20,678 4,766 (4,766) 3,457 2,427 (1,031) 2032 7,499 668 4,065 701 32033 20,875 4,750 (4,750) 3,595 2,428 (1,167) 2033 7,574 663 4,051 699 32034 21,092 4,750 (4,750) 3,543 2,417 (1,126) 2034 7,823 653 4,051 699 32035 21,324 4,750 (4,750) 3,807 2,422 (1,385) 2035 7,769 655 4,051 699 3

2036 21,568 4,766 (4,766) 3,815 2,433 (1,382) 2036 7,964 656 4,065 701 32037 21,821 4,750 (4,750) 4,027 2,428 (1,598) 2037 8,026 654 4,051 699 42038 22,060 4,750 (4,750) 4,026 2,490 (1,536) 2038 8,338 645 4,051 699 42039 22,299 4,750 (4,750) 4,277 2,359 (1,917) 2039 8,169 642 4,051 699 42040 22,541 4,765 (4,765) 4,235 2,374 (1,861) 2040 8,437 642 4,064 701 4

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,445 11,306 15,086 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,371 12,380 13,391 4512013 4,102 4,904 0 4,904 19.6% 2013 21,457 11,825 11,790 4462014 4,109 4,902 0 4,902 19.3% 2014 22,560 12,107 12,213 4042015 4,099 4,902 0 4,902 19.6% 2015 19,495 11,923 11,909 5002016 4,094 4,691 0 4,691 14.6% 2016 10,331 10,619 8,130 5202017 4,083 4,697 0 4,697 15.0% 2017 6,846 10,029 7,189 5212018 4,079 4,697 0 4,697 15.1% 2018 6,327 9,662 6,954 6312019 4,081 4,697 0 4,697 15.1% 2019 6,856 9,849 7,177 4862020 4,078 4,708 0 4,708 15.4% 2020 6,846 9,223 6,025 6292021 4,091 4,708 0 4,708 15.1% 2021 5,741 8,825 5,926 5592022 4,105 4,708 0 4,708 14.7% 2022 5,642 8,589 5,618 4742023 4,117 4,721 0 4,721 14.7% 2023 4,982 8,516 5,577 5702024 4,130 4,497 236 4,733 14.6% 2024 5,000 8,469 5,584 6212025 4,156 4,497 0 4,733 13.9% 2025 4,265 8,236 5,345 5662026 4,179 4,508 236 4,979 19.1% 2026 4,255 8,209 5,307 6782027 4,204 4,048 469 4,988 18.6% 2027 46 6,862 4,228 6322028 4,225 4,050 0 4,989 18.1% 2028 50 6,923 3,967 6742029 4,253 4,068 0 5,008 17.8% 2029 52 6,965 4,101 6942030 4,284 4,071 0 5,010 16.9% 2030 52 6,952 4,190 6932031 4,318 3,803 233 4,975 15.2% 2031 53 7,081 4,337 6822032 4,348 3,803 0 4,975 14.4% 2032 55 7,019 4,319 6852033 4,390 3,803 236 5,211 18.7% 2033 55 7,071 4,514 6812034 4,427 3,803 0 5,211 17.7% 2034 54 7,183 4,558 6702035 4,471 3,803 0 5,211 16.5% 2035 55 7,200 4,656 6732036 4,511 3,803 0 5,211 15.5% 2036 55 7,296 4,775 6742037 4,565 3,803 0 5,211 14.1% 2037 55 7,344 4,839 6722038 4,611 3,803 236 5,446 18.1% 2038 55 7,489 4,948 6642039 4,657 3,803 0 5,446 16.9% 2039 55 7,444 4,933 6602040 4,691 3,803 0 5,446 16.1% 2040 55 7,579 5,142 660

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 18: Option#1 – 15 Year Base Case A 

Cash Flow ($

Market Market

Base Rate Impacts Value of Value of Tot

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

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 

2012 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 

2013 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 

2014 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 

2015 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 2016 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 2017 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 2018 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 2019 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 2020 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 2021 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 

2022 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 

2023 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 

2024 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 

2025 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 

2026 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 

2027 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 

2028 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 

2029 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 2030 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 2031 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 

2032 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 2033 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 

2034 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 

2035 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 2036 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 

2037 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 

2038 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 

2039 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 

2040 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 

2011 Net Present Value

Period of 2011‐2040 6,913,825 (3,341,493) 1,154,810 9,100,507 1,726,156 710,161 2,436,317 11,536,824 703,088 12,239,912 258,514 11,981,398

Base Case O&M 2011 ‐ 2040 1,159,656 1,159,656 1,159,656

Utility Cost Present Value 2011 ‐ 2040 3,595,973 13,399,568 13,141,054

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Northeastern 3 and Northeastern 4 DFGD 15 Year Retrofit 3/1/2016 and 2/28/2031 Retirement

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 19: Option#1 – 15 Year Base Case B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Purc

2011 18,643 3,003 (3,003) 2,872 2,958 86 2011 8,454 7,272 2,123 880 22012 18,688 2,906 (2,906) 2,570 5,365 2,795 2012 9,302 7,098 2,245 661 22013 18,702 2,922 (2,922) 1,990 4,506 2,516 2013 7,510 6,792 2,237 685 12014 18,748 2,777 (2,777) 1,948 4,533 2,585 2014 7,590 7,113 2,237 540 12015 18,779 2,817 (2,817) 1,570 4,187 2,618 2015 7,945 6,732 2,237 580 12016 18,832 2,803 (2,803) 1,335 4,092 2,757 2016 7,559 7,327 2,245 558 12017 18,847 3,150 (3,150) 1,085 4,131 3,046 2017 7,791 7,076 2,532 618 12018 18,883 3,285 (3,285) 1,177 3,727 2,550 2018 7,061 7,228 2,606 680 12019 18,945 3,279 (3,279) 1,281 3,930 2,649 2019 7,520 6,928 2,606 674 12020 18,996 3,570 (3,570) 1,249 2,930 1,681 2020 6,138 7,229 2,911 659 12021 19,064 3,632 (3,632) 1,376 2,875 1,499 2021 6,215 6,958 2,975 657 12022 19,169 3,632 (3,632) 1,968 2,766 798 2022 5,814 6,833 2,975 657 12023 19,280 3,927 (3,927) 1,659 2,800 1,141 2023 5,784 6,475 3,270 657 12024 19,404 4,014 (4,014) 1,631 2,748 1,117 2024 5,379 6,880 3,355 659 12025 19,534 4,001 (4,001) 1,641 2,754 1,112 2025 5,627 6,786 3,343 657 12026 19,671 4,307 (4,307) 1,546 2,706 1,160 2026 5,485 6,810 3,639 668 12027 19,813 4,380 (4,380) 1,770 2,688 918 2027 5,776 6,341 3,712 668 12028 19,969 4,409 (4,409) 1,553 2,759 1,206 2028 5,619 6,895 3,725 683 12029 20,127 4,985 (4,985) 1,579 2,796 1,217 2029 5,795 6,329 4,303 682 12030 20,300 5,149 (5,149) 1,445 2,992 1,547 2030 5,646 6,819 4,450 699 12031 20,485 4,864 (4,864) 2,859 2,554 (306) 2031 7,415 2,092 4,165 699 22032 20,678 4,766 (4,766) 3,457 2,427 (1,031) 2032 7,499 668 4,065 701 32033 20,875 4,750 (4,750) 3,595 2,428 (1,167) 2033 7,574 663 4,051 699 32034 21,092 4,750 (4,750) 3,543 2,417 (1,126) 2034 7,823 653 4,051 699 32035 21,324 4,750 (4,750) 3,807 2,422 (1,385) 2035 7,769 655 4,051 699 32036 21,568 4,766 (4,766) 3,815 2,433 (1,382) 2036 7,964 656 4,065 701 32037 21,821 4,750 (4,750) 4,027 2,428 (1,598) 2037 8,026 654 4,051 699 42038 22,060 4,750 (4,750) 4,026 2,490 (1,536) 2038 8,338 645 4,051 699 42039 22,299 4,750 (4,750) 4,277 2,359 (1,917) 2039 8,169 642 4,051 699 4

2040 22,541 4,765 (4,765) 4,235 2,374 (1,861) 2040 8,437 642 4,064 701 4

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,445 11,306 15,086 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,371 12,380 13,391 4512013 4,102 4,904 0 4,904 19.6% 2013 21,457 11,825 11,790 4462014 4,109 4,902 0 4,902 19.3% 2014 22,560 12,107 12,213 4042015 4,099 4,902 0 4,902 19.6% 2015 19,495 11,923 11,909 5002016 4,094 4,915 0 4,915 20.1% 2016 6,092 12,530 7,380 5352017 4,083 4,921 0 4,921 20.5% 2017 1,278 12,436 6,589 5272018 4,079 4,921 0 4,921 20.6% 2018 1,292 12,208 6,214 6232019 4,081 4,921 0 4,921 20.6% 2019 1,254 12,147 6,465 4932020 4,078 4,932 0 4,932 20.9% 2020 1,296 11,712 5,349 6142021 4,091 4,932 0 4,932 20.6% 2021 1,252 11,508 5,433 5622022 4,105 4,932 0 4,932 20.1% 2022 1,240 11,162 5,063 4642023 4,117 4,945 0 4,945 20.1% 2023 1,165 11,036 5,176 5522024 4,130 4,721 0 4,721 14.3% 2024 1,235 11,262 5,135 5892025 4,156 4,721 236 4,957 19.3% 2025 1,226 11,257 5,032 5092026 4,179 4,732 0 4,967 18.9% 2026 1,220 11,228 5,102 6092027 4,204 4,732 0 4,967 18.2% 2027 1,135 10,925 5,150 5702028 4,225 4,733 0 4,969 17.6% 2028 1,237 11,385 5,161 5942029 4,253 4,752 0 4,988 17.3% 2029 1,127 10,929 5,225 6222030 4,284 4,754 0 4,990 16.5% 2030 1,220 11,361 5,408 6232031 4,318 3,803 937 4,975 15.2% 2031 324 8,066 4,775 6592032 4,348 3,803 0 4,975 14.4% 2032 55 7,019 4,319 6852033 4,390 3,803 236 5,211 18.7% 2033 55 7,071 4,514 6812034 4,427 3,803 0 5,211 17.7% 2034 54 7,183 4,558 6702035 4,471 3,803 0 5,211 16.5% 2035 55 7,200 4,656 6732036 4,511 3,803 0 5,211 15.5% 2036 55 7,296 4,775 6742037 4,565 3,803 0 5,211 14.1% 2037 55 7,344 4,839 6722038 4,611 3,803 236 5,446 18.1% 2038 55 7,489 4,948 6642039 4,657 3,803 0 5,446 16.9% 2039 55 7,444 4,933 6602040 4,691 3,803 0 5,446 16.1% 2040 55 7,579 5,142 660

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 20: Option#1 – 25 Year Base Case A 

Cash Flow ($

Market Market

Base Rate Impacts Value of Value of Tot

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

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 

2012 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 

2013 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 

2014 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 

2015 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 2016 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 2017 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 2018 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 2019 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 2020 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 2021 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 

2022 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 

2023 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 

2024 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 

2025 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 

2026 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 

2027 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 

2028 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 

2029 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 2030 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 2031 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 2032 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 2033 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 

2034 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 

2035 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 

2036 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 

2037 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 

2038 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 

2039 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 

2040 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 

2011 Net Present Value

Period of 2011‐2040 6,823,439 (3,341,493) 1,370,367 8,794,564 1,392,507 756,950 2,149,457 10,944,022 812,073 11,756,095 260,239 11,495,856

Base Case O&M 2011 ‐ 2040 1,159,656 1,159,656 1,159,656

Utility Cost Present Value 2011 ‐ 2040 3,309,114 12,915,751 12,655,512

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Northeastern 3 and Northeastern 4 DFGD 25 Year Retrofit 3/1/2016

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 21: Option#1 – 25 Year Base Case B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Purc

2011 18,643 3,003 (3,003) 2,872 2,958 86 2011 8,454 7,272 2,123 880 22012 18,688 2,906 (2,906) 2,570 5,365 2,795 2012 9,302 7,098 2,245 661 22013 18,702 2,922 (2,922) 1,990 4,506 2,516 2013 7,510 6,792 2,237 685 12014 18,748 2,777 (2,777) 1,948 4,533 2,585 2014 7,590 7,113 2,237 540 12015 18,779 2,817 (2,817) 1,570 4,187 2,618 2015 7,945 6,732 2,237 580 12016 18,832 2,803 (2,803) 1,335 4,092 2,757 2016 7,559 7,327 2,245 558 12017 18,847 3,150 (3,150) 1,085 4,131 3,046 2017 7,791 7,076 2,532 618 12018 18,883 3,285 (3,285) 1,177 3,727 2,550 2018 7,061 7,228 2,606 680 12019 18,945 3,279 (3,279) 1,281 3,930 2,649 2019 7,520 6,928 2,606 674 12020 18,996 3,570 (3,570) 1,249 2,930 1,681 2020 6,138 7,229 2,911 659 12021 19,064 3,632 (3,632) 1,376 2,875 1,499 2021 6,215 6,958 2,975 657 12022 19,169 3,632 (3,632) 1,968 2,766 798 2022 5,814 6,833 2,975 657 12023 19,280 3,927 (3,927) 1,659 2,800 1,141 2023 5,784 6,475 3,270 657 12024 19,404 4,014 (4,014) 1,631 2,748 1,117 2024 5,379 6,880 3,355 659 12025 19,534 4,001 (4,001) 1,641 2,754 1,112 2025 5,627 6,786 3,343 657 12026 19,671 4,307 (4,307) 1,546 2,706 1,160 2026 5,485 6,810 3,639 668 12027 19,813 4,380 (4,380) 1,770 2,688 918 2027 5,776 6,341 3,712 668 12028 19,969 4,409 (4,409) 1,553 2,759 1,206 2028 5,619 6,895 3,725 683 12029 20,127 4,985 (4,985) 1,579 2,796 1,217 2029 5,795 6,329 4,303 682 12030 20,300 5,149 (5,149) 1,445 2,992 1,547 2030 5,646 6,819 4,450 699 12031 20,485 4,864 (4,864) 1,550 2,762 1,213 2031 6,044 6,561 4,165 699 12032 20,678 4,766 (4,766) 1,637 2,802 1,165 2032 5,913 6,922 4,065 701 12033 20,875 4,750 (4,750) 1,893 2,751 859 2033 6,163 6,589 4,051 699 12034 21,092 4,750 (4,750) 1,770 2,770 999 2034 6,221 6,881 4,051 699 12035 21,324 4,750 (4,750) 2,149 2,772 622 2035 6,285 6,678 4,051 699 22036 21,568 4,766 (4,766) 2,054 2,898 844 2036 6,502 6,907 4,065 701 22037 21,821 4,750 (4,750) 2,428 2,861 433 2037 6,586 6,683 4,051 699 22038 22,060 4,750 (4,750) 2,319 2,954 635 2038 6,728 6,986 4,051 699 22039 22,299 4,750 (4,750) 2,871 2,752 (119) 2039 6,672 6,529 4,051 699 22040 22,541 4,765 (4,765) 2,697 2,849 152 2040 6,933 6,754 4,064 701 2

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,445 11,306 15,086 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,371 12,380 13,391 4512013 4,102 4,904 0 4,904 19.6% 2013 21,457 11,825 11,790 4462014 4,109 4,902 0 4,902 19.3% 2014 22,560 12,107 12,213 4042015 4,099 4,902 0 4,902 19.6% 2015 19,495 11,923 11,909 5002016 4,094 4,915 0 4,915 20.1% 2016 6,092 12,530 7,380 5352017 4,083 4,921 0 4,921 20.5% 2017 1,278 12,436 6,589 5272018 4,079 4,921 0 4,921 20.6% 2018 1,292 12,208 6,214 6232019 4,081 4,921 0 4,921 20.6% 2019 1,254 12,147 6,465 4932020 4,078 4,932 0 4,932 20.9% 2020 1,296 11,712 5,349 6142021 4,091 4,932 0 4,932 20.6% 2021 1,252 11,508 5,433 5622022 4,105 4,932 0 4,932 20.1% 2022 1,240 11,162 5,063 4642023 4,117 4,945 0 4,945 20.1% 2023 1,165 11,036 5,176 5522024 4,130 4,721 0 4,721 14.3% 2024 1,235 11,262 5,135 5892025 4,156 4,721 236 4,957 19.3% 2025 1,226 11,257 5,032 5092026 4,179 4,732 0 4,967 18.9% 2026 1,220 11,228 5,102 6092027 4,204 4,732 0 4,967 18.2% 2027 1,135 10,925 5,150 5702028 4,225 4,733 0 4,969 17.6% 2028 1,237 11,385 5,161 5942029 4,253 4,752 0 4,988 17.3% 2029 1,127 10,929 5,225 6222030 4,284 4,754 0 4,990 16.5% 2030 1,220 11,361 5,408 6232031 4,318 4,746 0 4,982 15.4% 2031 1,173 11,278 5,378 6132032 4,348 4,746 0 4,982 14.6% 2032 1,239 11,579 5,410 6152033 4,390 4,746 236 5,217 18.8% 2033 1,178 11,394 5,666 6172034 4,427 4,746 0 5,217 17.8% 2034 1,233 11,700 5,605 6102035 4,471 4,746 0 5,217 16.7% 2035 1,192 11,545 5,693 6172036 4,511 4,746 0 5,217 15.7% 2036 1,237 11,879 5,964 6192037 4,565 4,746 0 5,217 14.3% 2037 1,196 11,709 5,899 6182038 4,611 4,746 236 5,453 18.3% 2038 1,253 12,069 5,959 6072039 4,657 4,746 0 5,453 17.1% 2039 1,169 11,621 5,894 6082040 4,691 4,746 0 5,453 16.2% 2040 1,211 11,972 6,177 610

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 22: Option#2 – 15 Year Base Case A 

Cash Flow ($000)

Market Market

Base Rate Impacts Value of Value of Total

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances To

Cost Revenue/(Cost)Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased (P)=(D

Annual 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)

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,

2012 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 0 529,2013 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 0 624,2014 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 0 660,2015 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,

2016 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,

2017 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,

2018 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,

2019 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,

2020 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 0 984,2021 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 1,0302022 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 1,0552023 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 0 864,2024 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 1,2842025 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 0 908,2026 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 0 940,2027 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 1,2692028 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 1,0032029 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 1,0692030 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

2031 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 2,3082032 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 1,2002033 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 1,5512034 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 1,2762035 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 1,3192036 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 1,3582037 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 1,4012038 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 1,7912039 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 1,4982040 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

sent Value

011‐2040 7,198,961 (3,352,038) 959,907 9,591,092 1,306,391 629,177 1,935,568 11,526,660 613,167 12,139,827 134,098 12,005,729

&M2011 ‐ 2040 1,159,656 1,159,656 1,159,656

Present Value 2011 ‐ 2040 3,095,225 13,299,483 13,165,385

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Northeastern 3 DFGD 15 Year Retrofit 3/1/2016 and 2/28/2031 Retirement and Northeastern 4 Retirement 2/28/2016

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 23: Option#2 – 15 Year Base Case B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Ec

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pu

2011 18,643 3,003 (3,003) 2,872 2,958 86 2011 8,454 7,272 2,123 880 

2012 18,688 2,906 (2,906) 2,570 5,365 2,795 2012 9,302 7,098 2,245 661 

2013 18,702 2,922 (2,922) 1,990 4,506 2,516 2013 7,510 6,792 2,237 685 

2014 18,748 2,777 (2,777) 1,948 4,533 2,585 2014 7,590 7,113 2,237 540 

2015 18,779 2,817 (2,817) 1,570 4,187 2,618 2015 7,945 6,732 2,237 580 

2016 18,832 2,803 (2,803) 1,841 3,862 2,021 2016 8,327 4,725 2,245 558 

2017 18,847 3,150 (3,150) 1,745 3,817 2,072 2017 8,446 3,663 2,532 618 

2018 18,883 3,285 (3,285) 1,696 3,516 1,819 2018 7,814 4,093 2,606 680 

2019 18,945 3,279 (3,279) 1,937 3,604 1,668 2019 8,204 3,513 2,606 674 

2020 18,996 3,570 (3,570) 2,028 2,755 727 2020 6,858 3,867 2,911 659 

2021 19,064 3,632 (3,632) 2,228 2,692 464 2021 6,881 3,587 2,975 657 

2022 19,169 3,632 (3,632) 2,487 2,640 153 2022 6,630 3,760 2,975 657 

2023 19,280 3,927 (3,927) 2,233 2,659 426 2023 6,492 3,466 3,270 657 

2024 19,404 4,014 (4,014) 1,937 2,656 719 2024 5,661 3,870 3,355 659 

2025 19,534 4,001 (4,001) 1,868 2,677 810 2025 5,693 3,793 3,343 657 

2026 19,671 4,307 (4,307) 1,717 2,646 929 2026 5,639 3,862 3,639 668 

2027 19,813 4,380 (4,380) 1,790 2,659 869 2027 5,794 3,582 3,712 668 

2028 19,969 4,409 (4,409) 1,740 2,695 954 2028 5,719 3,933 3,725 683 

2029 20,127 4,985 (4,985) 1,628 2,771 1,143 2029 5,810 3,527 4,303 682 

2030 20,300 5,149 (5,149) 1,625 2,874 1,249 2030 5,714 3,787 4,450 699 

2031 20,485 4,864 (4,864) 2,651 2,559 (92) 2031 7,251 1,527 4,165 699 

2032 20,678 4,766 (4,766) 3,457 2,427 (1,031) 2032 7,499 668 4,065 701 2033 20,875 4,750 (4,750) 3,595 2,428 (1,167) 2033 7,574 663 4,051 699 2034 21,092 4,750 (4,750) 3,543 2,417 (1,126) 2034 7,823 653 4,051 699 2035 21,324 4,750 (4,750) 3,807 2,422 (1,385) 2035 7,769 655 4,051 699 2036 21,568 4,766 (4,766) 3,815 2,433 (1,382) 2036 7,964 656 4,065 701 2037 21,821 4,750 (4,750) 4,027 2,428 (1,598) 2037 8,026 654 4,051 699 2038 22,060 4,750 (4,750) 4,026 2,490 (1,536) 2038 8,338 645 4,051 699 2039 22,299 4,750 (4,750) 4,277 2,359 (1,917) 2039 8,169 642 4,051 699 

2040 22,541 4,765 (4,765) 4,235 2,374 (1,861) 2040 8,437 642 4,064 701 

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,445 11,306 15,086 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,371 12,380 13,391 4512013 4,102 4,904 0 4,904 19.6% 2013 21,457 11,825 11,790 4462014 4,109 4,902 0 4,902 19.3% 2014 22,560 12,107 12,213 4042015 4,099 4,902 0 4,902 19.6% 2015 19,495 11,923 11,909 5002016 4,094 4,698 0 4,698 14.8% 2016 5,591 10,690 7,162 5192017 4,083 4,704 0 4,704 15.2% 2017 619 9,950 5,853 5212018 4,079 4,704 0 4,704 15.3% 2018 685 10,011 5,661 6312019 4,081 4,704 0 4,704 15.3% 2019 595 9,664 5,774 4842020 4,078 4,715 0 4,715 15.6% 2020 644 9,278 4,704 6292021 4,091 4,715 0 4,715 15.3% 2021 601 9,031 4,776 5602022 4,105 4,715 0 4,715 14.9% 2022 643 9,034 4,568 4742023 4,117 4,729 0 4,729 14.9% 2023 579 8,915 4,641 5682024 4,130 4,505 233 4,738 14.7% 2024 651 9,180 4,205 6102025 4,156 4,505 0 4,738 14.0% 2025 644 9,172 3,879 5412026 4,179 4,515 0 4,748 13.6% 2026 647 9,217 3,977 6442027 4,204 4,515 236 4,984 18.6% 2027 600 9,081 3,981 5962028 4,225 4,517 0 4,986 18.0% 2028 661 9,352 3,997 6282029 4,253 4,536 0 5,004 17.7% 2029 584 9,055 4,079 6542030 4,284 4,538 0 5,007 16.9% 2030 630 9,253 4,176 6582031 4,318 3,803 704 4,975 15.2% 2031 214 7,754 4,391 6692032 4,348 3,803 0 4,975 14.4% 2032 55 7,019 4,319 6852033 4,390 3,803 236 5,211 18.7% 2033 55 7,071 4,514 6812034 4,427 3,803 0 5,211 17.7% 2034 54 7,183 4,558 6702035 4,471 3,803 0 5,211 16.5% 2035 55 7,200 4,656 6732036 4,511 3,803 0 5,211 15.5% 2036 55 7,296 4,775 6742037 4,565 3,803 0 5,211 14.1% 2037 55 7,344 4,839 6722038 4,611 3,803 236 5,446 18.1% 2038 55 7,489 4,948 6642039 4,657 3,803 0 5,446 16.9% 2039 55 7,444 4,933 6602040 4,691 3,803 0 5,446 16.1% 2040 55 7,579 5,142 660

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 24: Option#2 – 25 Year Base Case A 

Cash Flow ($0

Market Market

Base Rate Impacts Value of Value of Total

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

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 

2012 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 

2013 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 

2014 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 

2015 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 2016 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 2017 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 2018 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 2019 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 2020 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 2021 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 2022 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 2023 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 2024 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 2025 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 2026 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 2027 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 2028 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 2029 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 2030 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 2031 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 2032 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 2033 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 

2034 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 2035 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 

2036 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 

2037 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 2038 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 

2039 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 2040 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 

Present Value

f 2011‐2040 7,148,435 (3,352,038) 1,066,061 9,434,412 1,140,129 661,467 1,801,596 11,236,008 666,448 11,902,456 133,736 11,768,720

e O&M 2011 ‐ 2040 1,159,656 1,159,656 1,159,656

ost Present Value 2011 ‐ 2040 2,961,252 13,062,112 12,928,376

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Northeastern 3 DFGD 25 Year Retrofit 3/1/2016 and Northeastern 4 Retirement 2/28/2016

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 25: Option#2 – 25 Year Base Case B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pur

2011 18,643 3,003 (3,003) 2,872 2,958 86 2011 8,454 7,272 2,123 880 22012 18,688 2,906 (2,906) 2,570 5,365 2,795 2012 9,302 7,098 2,245 661 22013 18,702 2,922 (2,922) 1,990 4,506 2,516 2013 7,510 6,792 2,237 685 12014 18,748 2,777 (2,777) 1,948 4,533 2,585 2014 7,590 7,113 2,237 540 12015 18,779 2,817 (2,817) 1,570 4,187 2,618 2015 7,945 6,732 2,237 580 12016 18,832 2,803 (2,803) 1,841 3,862 2,021 2016 8,327 4,725 2,245 558 12017 18,847 3,150 (3,150) 1,745 3,817 2,072 2017 8,446 3,663 2,532 618 12018 18,883 3,285 (3,285) 1,696 3,516 1,819 2018 7,814 4,093 2,606 680 12019 18,945 3,279 (3,279) 1,937 3,604 1,668 2019 8,204 3,513 2,606 674 12020 18,996 3,570 (3,570) 2,028 2,755 727 2020 6,858 3,867 2,911 659 22021 19,064 3,632 (3,632) 2,228 2,692 464 2021 6,881 3,587 2,975 657 22022 19,169 3,632 (3,632) 2,487 2,640 153 2022 6,630 3,760 2,975 657 22023 19,280 3,927 (3,927) 2,233 2,659 426 2023 6,492 3,466 3,270 657 22024 19,404 4,014 (4,014) 1,937 2,656 719 2024 5,661 3,870 3,355 659 12025 19,534 4,001 (4,001) 1,868 2,677 810 2025 5,693 3,793 3,343 657 12026 19,671 4,307 (4,307) 1,717 2,646 929 2026 5,639 3,862 3,639 668 12027 19,813 4,380 (4,380) 1,790 2,659 869 2027 5,794 3,582 3,712 668 12028 19,969 4,409 (4,409) 1,740 2,695 954 2028 5,719 3,933 3,725 683 12029 20,127 4,985 (4,985) 1,628 2,771 1,143 2029 5,810 3,527 4,303 682 12030 20,300 5,149 (5,149) 1,625 2,874 1,249 2030 5,714 3,787 4,450 699 12031 20,485 4,864 (4,864) 2,185 2,625 441 2031 6,585 3,545 4,165 699 22032 20,678 4,766 (4,766) 2,447 2,597 150 2032 6,708 3,926 4,065 701 22033 20,875 4,750 (4,750) 2,801 2,559 (242) 2033 6,882 3,569 4,051 699 2

2034 21,092 4,750 (4,750) 2,606 2,540 (66) 2034 6,945 3,894 4,051 699 2

2035 21,324 4,750 (4,750) 2,876 2,588 (288) 2035 6,930 3,904 4,051 699 2

2036 21,568 4,766 (4,766) 2,865 2,627 (238) 2036 7,198 3,889 4,065 701 2

2037 21,821 4,750 (4,750) 3,180 2,599 (581) 2037 7,362 3,656 4,051 699 3

2038 22,060 4,750 (4,750) 3,024 2,709 (315) 2038 7,560 3,975 4,051 699 3

2039 22,299 4,750 (4,750) 3,510 2,535 (975) 2039 7,585 3,501 4,051 699 3

2040 22,541 4,765 (4,765) 3,425 2,601 (824) 2040 7,725 3,725 4,064 701 3

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,445 11,306 15,086 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,371 12,380 13,391 4512013 4,102 4,904 0 4,904 19.6% 2013 21,457 11,825 11,790 4462014 4,109 4,902 0 4,902 19.3% 2014 22,560 12,107 12,213 4042015 4,099 4,902 0 4,902 19.6% 2015 19,495 11,923 11,909 5002016 4,094 4,698 0 4,698 14.8% 2016 5,591 10,690 7,162 5192017 4,083 4,704 0 4,704 15.2% 2017 619 9,950 5,853 5212018 4,079 4,704 0 4,704 15.3% 2018 685 10,011 5,661 6312019 4,081 4,704 0 4,704 15.3% 2019 595 9,664 5,774 4842020 4,078 4,715 0 4,715 15.6% 2020 644 9,278 4,704 6292021 4,091 4,715 0 4,715 15.3% 2021 601 9,031 4,776 5602022 4,105 4,715 0 4,715 14.9% 2022 643 9,034 4,568 4742023 4,117 4,729 0 4,729 14.9% 2023 579 8,915 4,641 5682024 4,130 4,505 233 4,738 14.7% 2024 651 9,180 4,205 6102025 4,156 4,505 0 4,738 14.0% 2025 644 9,172 3,879 5412026 4,179 4,515 0 4,748 13.6% 2026 647 9,217 3,977 6442027 4,204 4,515 236 4,984 18.6% 2027 600 9,081 3,981 5962028 4,225 4,517 0 4,986 18.0% 2028 661 9,352 3,997 6282029 4,253 4,536 0 5,004 17.7% 2029 584 9,055 4,079 6542030 4,284 4,538 0 5,007 16.9% 2030 630 9,253 4,176 6582031 4,318 4,270 236 4,974 15.2% 2031 588 9,075 4,583 6472032 4,348 4,270 0 4,974 14.4% 2032 657 9,342 4,903 6492033 4,390 4,270 236 5,210 18.7% 2033 592 9,082 4,997 6492034 4,427 4,270 0 5,210 17.7% 2034 653 9,423 5,009 6392035 4,471 4,270 0 5,210 16.5% 2035 654 9,467 5,163 6442036 4,511 4,270 0 5,210 15.5% 2036 652 9,589 5,343 6462037 4,565 4,270 0 5,210 14.1% 2037 609 9,466 5,426 6452038 4,611 4,270 236 5,445 18.1% 2038 669 9,866 5,577 6392039 4,657 4,270 0 5,445 16.9% 2039 582 9,472 5,530 6382040 4,691 4,270 0 5,445 16.1% 2040 623 9,745 5,728 640

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 26: Option#4 – Base Case A 

Cash Flow ($000)

Market Market

Base Rate Impacts Value of Value of Total

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances T

Cost Revenue/(Cost)Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased (P)=

Annual 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) +(

2011 411,796 (114,466) 22,114 504,148 0 0 0 504,148 375 504,523 0 504,523 504,523 0 50

2012 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 53

2013 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 622014 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 662015 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 682016 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 1,52017 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 932018 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 972019 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 992020 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 1,02021 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 1,02022 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 1,02023 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 892024 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 1,32025 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 952026 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 982027 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 1,32028 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 1,02029 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 1,02030 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 1,12031 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 1,62032 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 1,12033 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 1,52034 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 1,22035 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 1,22036 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 1,32037 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 1,32038 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 1,72039 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 1,4

2040 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 1,4

2011 Net Present Value

Period of 2011‐2040 7,550,548 (3,355,672) 955,115 9,951,105 1,320,317 392,604 1,712,921 11,664,025 526,378 12,190,404 132,165 12,058,238

Base Case O&M 2011 ‐ 2040 1,159,656 1,159,656 1,159,656

Utility Cost Present Value 2011 ‐ 2040 2,872,577 13,350,060 13,217,895

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Northeastern 3 and Northeastern 4 Retirement 2/28/2016 Replaced with 2 233 MW Combined Cycle Units and 1 233 MW PPA

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 27: Option#4 – Base Case B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Ec

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pu

2011 18,643 3,003 (3,003) 2,872 2,958 86 2011 8,454 7,272 2,123 880 

2012 18,688 2,906 (2,906) 2,570 5,365 2,795 2012 9,302 7,098 2,245 661 

2013 18,702 2,922 (2,922) 1,990 4,506 2,516 2013 7,510 6,792 2,237 685 

2014 18,748 2,777 (2,777) 1,948 4,533 2,585 2014 7,590 7,113 2,237 540 

2015 18,779 2,817 (2,817) 1,570 4,187 2,618 2015 7,945 6,732 2,237 580 

2016 18,832 2,803 (2,803) 2,452 3,658 1,206 2016 8,558 2,176 2,245 558 

2017 18,847 3,150 (3,150) 2,050 3,752 1,702 2017 8,582 492 2,532 618 

2018 18,883 3,285 (3,285) 2,102 3,418 1,315 2018 8,118 605 2,606 680 

2019 18,945 3,279 (3,279) 2,245 3,586 1,341 2019 8,281 461 2,606 674 

2020 18,996 3,570 (3,570) 2,512 2,680 169 2020 7,008 614 2,911 659 

2021 19,064 3,632 (3,632) 2,534 2,642 109 2021 7,013 530 2,975 657 

2022 19,169 3,632 (3,632) 2,834 2,587 (247) 2022 6,908 452 2,975 657 2023 19,280 3,927 (3,927) 2,450 2,631 181 2023 6,652 543 3,270 657 

2024 19,404 4,014 (4,014) 2,298 2,584 286 2024 5,952 600 3,355 659 

2025 19,534 4,001 (4,001) 2,213 2,591 378 2025 6,047 562 3,343 657 

2026 19,671 4,307 (4,307) 2,202 2,586 384 2026 5,919 668 3,639 668 

2027 19,813 4,380 (4,380) 2,070 2,579 508 2027 5,993 617 3,712 668 

2028 19,969 4,409 (4,409) 2,282 2,602 320 2028 5,970 654 3,725 683 

2029 20,127 4,985 (4,985) 1,853 2,715 862 2029 5,946 675 4,303 682 

2030 20,300 5,149 (5,149) 1,874 2,802 928 2030 6,015 674 4,450 699 

2031 20,485 4,864 (4,864) 2,006 2,614 608 2031 6,415 662 4,165 699 

2032 20,678 4,766 (4,766) 2,448 2,587 138 2032 6,331 662 4,065 701 

2033 20,875 4,750 (4,750) 2,556 2,591 35 2033 6,408 659 4,051 699 

2034 21,092 4,750 (4,750) 2,464 2,579 115 2034 6,695 647 4,051 699 

2035 21,324 4,750 (4,750) 2,716 2,604 (112) 2035 6,623 651 4,051 699 2036 21,568 4,766 (4,766) 2,701 2,710 10 2036 6,896 649 4,065 701 

2037 21,821 4,750 (4,750) 2,919 2,671 (248) 2037 6,931 648 4,051 699 2038 22,060 4,750 (4,750) 2,948 2,757 (191) 2038 7,226 638 4,051 699 2039 22,299 4,750 (4,750) 3,179 2,654 (525) 2039 7,075 633 4,051 699 2040 22,541 4,765 (4,765) 3,188 2,692 (496) 2040 7,291 632 4,064 701 

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,445 11,306 15,086 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,371 12,380 13,391 4512013 4,102 4,904 0 4,904 19.6% 2013 21,457 11,825 11,790 4462014 4,109 4,902 0 4,902 19.3% 2014 22,560 12,107 12,213 4042015 4,099 4,902 0 4,902 19.6% 2015 19,495 11,923 11,909 5002016 4,094 4,232 466 4,698 14.7% 2016 5,125 8,859 7,101 5162017 4,083 4,238 0 4,704 15.2% 2017 42 7,880 4,817 5142018 4,079 4,238 0 4,704 15.3% 2018 50 7,726 4,664 6252019 4,081 4,238 0 4,704 15.3% 2019 40 7,673 4,740 4802020 4,078 4,249 0 4,715 15.6% 2020 50 7,084 3,662 6332021 4,091 4,249 0 4,715 15.2% 2021 45 7,031 3,734 5512022 4,105 4,249 0 4,715 14.8% 2022 39 6,868 3,503 4692023 4,117 4,262 0 4,728 14.8% 2023 46 7,017 3,592 5632024 4,130 4,038 233 4,737 14.7% 2024 51 7,011 3,149 6192025 4,156 4,038 0 4,737 14.0% 2025 49 7,051 2,977 5772026 4,179 4,049 0 4,748 13.6% 2026 57 7,048 2,925 6862027 4,204 4,049 236 4,983 18.5% 2027 53 7,123 3,004 6332028 4,225 4,050 0 4,985 18.0% 2028 56 7,098 2,955 6712029 4,253 4,069 0 5,003 17.6% 2029 57 7,184 3,036 6932030 4,284 4,071 0 5,006 16.8% 2030 57 7,247 3,205 6922031 4,318 3,803 233 4,971 15.1% 2031 58 7,295 3,299 6792032 4,348 3,803 0 4,971 14.3% 2032 59 7,204 3,273 6802033 4,390 3,803 236 5,206 18.6% 2033 59 7,264 3,438 6762034 4,427 3,803 0 5,206 17.6% 2034 59 7,397 3,462 6652035 4,471 3,803 0 5,206 16.4% 2035 59 7,419 3,571 6682036 4,511 3,803 0 5,206 15.4% 2036 59 7,585 3,852 6672037 4,565 3,803 0 5,206 14.1% 2037 59 7,597 3,793 6652038 4,611 3,803 236 5,442 18.0% 2038 59 7,738 3,916 6552039 4,657 3,803 0 5,442 16.9% 2039 59 7,713 3,934 6502040 4,691 3,803 0 5,442 16.0% 2040 59 7,829 4,158 650

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under FT-CSAPR Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 28: EPA Settlement Option – Early Carbon A 

Cash Flow ($

Market Market

Base Rate Impacts Value of Value of Tot

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

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 

2012 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 

2013 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 

2014 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 

2015 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 2016 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 2017 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 2018 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 2019 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 2020 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 2021 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 2022 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 2023 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 2024 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 2025 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 2026 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 2027 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 2028 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 

2029 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 2030 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 2031 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 

2032 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 2033 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 2034 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 2035 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 2036 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 2037 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 2038 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 

2039 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 2040 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 

2011 Net Present Value

Period of 2011‐2040 7,226,604 (3,370,852) 780,111 9,817,345 1,172,004 560,478 1,732,483 11,549,827 974,960 12,524,788 141,306 12,383,482

Base Case O&M2011 ‐ 2040 1,146,811 1,146,811 1,146,811

Utility Cost Present Value 2011 ‐ 2040 2,879,293 13,671,599 13,530,293

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Early Carbon Pricing

Northeastern 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 Retirement

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 29: EPA Settlement Option – Early Carbon B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pur

2011 18,643 3,003 (3,003) 2,872 2,958 86 2011 8,454 7,272 2,123 880 22012 18,688 2,906 (2,906) 2,545 5,434 2,889 2012 9,391 7,101 2,245 661 22013 18,702 2,922 (2,922) 2,043 4,483 2,440 2013 7,446 6,787 2,237 685 22014 18,748 2,777 (2,777) 1,927 4,543 2,616 2014 7,615 7,118 2,237 540 12015 18,779 2,817 (2,817) 1,595 4,158 2,563 2015 7,895 6,731 2,237 580 12016 18,832 2,803 (2,803) 1,885 3,860 1,975 2016 8,221 4,819 2,245 558 12017 18,847 3,150 (3,150) 1,917 3,752 1,835 2017 7,997 3,902 2,532 618 12018 18,883 3,285 (3,285) 2,164 3,471 1,307 2018 7,656 3,725 2,606 680 22019 18,945 3,279 (3,279) 2,146 3,649 1,503 2019 7,685 3,869 2,606 674 22020 18,996 3,570 (3,570) 2,210 2,742 532 2020 6,573 3,993 2,911 659 22021 19,064 3,632 (3,632) 2,477 2,664 187 2021 6,821 3,342 2,975 657 22022 19,169 3,632 (3,632) 2,651 2,618 (33) 2022 6,868 3,253 2,975 657 22023 19,280 3,927 (3,927) 2,442 2,641 199 2023 6,749 2,962 3,270 657 22024 19,404 4,014 (4,014) 2,640 2,552 (88) 2024 6,463 3,008 3,355 659 22025 19,534 4,001 (4,001) 2,843 2,490 (353) 2025 6,839 2,556 3,343 657 2

2026 19,671 4,307 (4,307) 2,795 2,440 (355) 2026 6,602 2,656 3,639 668 2

2027 19,813 4,380 (4,380) 3,019 2,444 (575) 2027 6,905 606 3,712 668 3

2028 19,969 4,409 (4,409) 2,681 2,540 (141) 2028 6,589 644 3,725 683 2

2029 20,127 4,985 (4,985) 2,354 2,642 288 2029 6,543 664 4,303 682 22030 20,300 5,149 (5,149) 2,459 2,687 227 2030 6,500 664 4,450 699 22031 20,485 4,864 (4,864) 2,903 2,484 (418) 2031 7,312 653 4,165 699 2

2032 20,678 4,766 (4,766) 3,527 2,424 (1,103) 2032 7,438 662 4,065 701 32033 20,875 4,750 (4,750) 3,670 2,435 (1,235) 2033 7,518 653 4,051 699 32034 21,092 4,750 (4,750) 3,629 2,445 (1,184) 2034 7,779 647 4,051 699 32035 21,324 4,750 (4,750) 3,901 2,445 (1,457) 2035 7,711 647 4,051 699 32036 21,568 4,766 (4,766) 3,903 2,431 (1,472) 2036 7,893 647 4,065 701 3

2037 21,821 4,750 (4,750) 4,142 2,448 (1,694) 2037 7,947 642 4,051 699 42038 22,060 4,750 (4,750) 4,116 2,468 (1,648) 2038 8,238 633 4,051 699 42039 22,299 4,750 (4,750) 4,343 2,364 (1,979) 2039 8,122 630 4,051 699 42040 22,541 4,765 (4,765) 4,285 2,355 (1,930) 2040 8,382 628 4,064 701 4

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,445 11,306 15,086 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,382 12,430 13,462 4512013 4,102 4,904 0 4,904 19.6% 2013 21,440 11,786 11,730 4462014 4,109 4,902 0 4,902 19.3% 2014 22,575 12,124 12,247 4042015 4,099 4,902 0 4,902 19.6% 2015 19,484 11,895 11,860 5042016 4,094 4,691 0 4,691 14.6% 2016 10,328 10,603 8,101 5242017 4,083 4,697 0 4,697 15.0% 2017 6,749 9,811 6,881 5282018 4,079 4,697 0 4,697 15.1% 2018 6,232 9,461 6,678 6132019 4,081 4,697 0 4,697 15.1% 2019 6,759 9,615 6,831 4862020 4,078 4,708 0 4,708 15.4% 2020 6,737 9,103 5,863 6292021 4,091 4,708 0 4,708 15.1% 2021 5,670 8,709 5,746 5622022 4,105 4,708 0 4,708 14.7% 2022 5,652 8,613 5,620 4752023 4,117 4,721 0 4,721 14.7% 2023 4,979 8,530 5,592 5712024 4,130 4,497 236 4,733 14.6% 2024 4,986 8,464 5,590 6162025 4,156 4,497 0 4,733 13.9% 2025 4,245 8,208 5,332 5602026 4,179 4,508 236 4,979 19.1% 2026 4,242 8,180 5,288 6702027 4,204 4,048 466 4,985 18.6% 2027 47 6,887 3,824 6232028 4,225 4,050 0 4,987 18.0% 2028 52 7,050 3,537 6612029 4,253 4,069 0 5,006 17.7% 2029 54 7,082 3,552 6822030 4,284 4,071 0 5,008 16.9% 2030 54 7,084 3,715 6822031 4,318 3,803 236 4,975 15.2% 2031 54 7,097 4,073 6712032 4,348 3,803 0 4,975 14.4% 2032 55 6,985 4,278 6792033 4,390 3,803 236 5,211 18.7% 2033 54 7,036 4,473 6712034 4,427 3,803 0 5,211 17.7% 2034 54 7,156 4,529 6652035 4,471 3,803 0 5,211 16.5% 2035 54 7,165 4,615 6652036 4,511 3,803 0 5,211 15.5% 2036 54 7,252 4,717 6652037 4,565 3,803 0 5,211 14.1% 2037 54 7,295 4,778 6602038 4,611 3,803 236 5,446 18.1% 2038 54 7,433 4,874 6512039 4,657 3,803 0 5,446 16.9% 2039 54 7,413 4,898 6492040 4,691 3,803 0 5,446 16.1% 2040 54 7,543 5,097 646

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Early Carbon Pricing

Summary of Energy Purchases and Sales (Gwh) Summary of Energy Sources (Gwh)
PSO 2012 Integrated Reso

Table 30: Option 1 – 25 Year Early Carbon A 

Cash Flow ($

Market Market

Base Rate Impacts Value of Value of Tot

Fuel Contract Market Fuel & Carrying Incremental Total Allowances Grand Value of Grand Capital Allowances 

Cost Revenue/(Cost) Revenue/(Cost) Transactions Charges O&M Total Cost Consumed Total ICAP Total CPW Expenditures Purchased 

Annual 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) 

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 

2012 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 

2013 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 

2014 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 

2015 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 

2016 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 2017 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 

2018 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 

2019 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 2020 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 

2021 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 2022 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 2023 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 2024 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 2025 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 2026 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 2027 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 2028 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 2029 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 2030 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 

2031 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 2032 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 2033 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 2034 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 2035 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 2036 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 2037 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 2038 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 

2039 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 2040 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 

2011 Net Present Value

Period of 2011‐2040 6,809,637 (3,359,356) 1,339,903 8,829,090 1,392,507 766,912 2,159,419 10,988,509 1,337,714 12,326,223 260,239 12,065,984

Base Case O&M2011 ‐ 2040 1,146,811 1,146,811 1,146,811

Utility Cost Present Value 2011 ‐ 2040 3,306,230 13,473,034 13,212,795

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Early Carbon Pricing

Northeastern 3 and Northeastern 4 DFGD 25 Year Retrofit 3/1/2016

Optimal Plan Cost Summary ($000)
PSO 2012 Integrated Reso

Table 31: Option 1 – 25 Year Early Carbon B 

Net Net

Internal Contract Contract Contract Market Market Market Solid Other Eco

Sales Purchases Sales Transactions Purchases Sales Transactions Gas Fuel Wind Transactions Pur

2011 18,643 3,003 (3,003) 2,872 2,958 86 2011 8,454 7,272 2,123 880 2

2012 18,688 2,906 (2,906) 2,545 5,434 2,889 2012 9,391 7,101 2,245 661 2

2013 18,702 2,922 (2,922) 2,043 4,483 2,440 2013 7,446 6,787 2,237 685 2

2014 18,748 2,777 (2,777) 1,927 4,543 2,616 2014 7,615 7,118 2,237 540 1

2015 18,779 2,817 (2,817) 1,595 4,158 2,563 2015 7,895 6,731 2,237 580 1

2016 18,832 2,803 (2,803) 1,330 4,084 2,754 2016 7,556 7,327 2,245 558 1

2017 18,847 3,150 (3,150) 1,484 3,982 2,498 2017 7,486 6,871 2,532 618 1

2018 18,883 3,285 (3,285) 1,648 3,670 2,022 2018 6,794 7,005 2,606 680 1

2019 18,945 3,279 (3,279) 1,757 3,803 2,046 2019 7,177 6,710 2,606 674 1

2020 18,996 3,570 (3,570) 1,650 2,888 1,238 2020 5,988 6,964 2,911 659 1

2021 19,064 3,632 (3,632) 1,801 2,835 1,034 2021 6,038 6,706 2,975 657 1

2022 19,169 3,632 (3,632) 1,912 2,784 873 2022 5,867 6,850 2,975 657 1

2023 19,280 3,927 (3,927) 1,663 2,820 1,157 2023 5,813 6,463 3,270 657 1

2024 19,404 4,014 (4,014) 1,656 2,767 1,111 2024 5,419 6,836 3,355 659 1

2025 19,534 4,001 (4,001) 1,686 2,754 1,067 2025 5,637 6,732 3,343 657 1

2026 19,671 4,307 (4,307) 1,602 2,702 1,100 2026 5,487 6,748 3,639 668 1

2027 19,813 4,380 (4,380) 1,827 2,685 858 2027 5,775 6,283 3,712 668 1

2028 19,969 4,409 (4,409) 1,579 2,751 1,171 2028 5,624 6,856 3,725 683 1

2029 20,127 4,985 (4,985) 1,662 2,810 1,148 2029 5,785 6,272 4,303 682 1

2030 20,300 5,149 (5,149) 1,521 2,989 1,468 2030 5,634 6,754 4,450 699 1

2031 20,485 4,864 (4,864) 1,618 2,772 1,155 2031 6,033 6,514 4,165 699 1

2032 20,678 4,766 (4,766) 1,702 2,800 1,098 2032 5,881 6,887 4,065 701 1

2033 20,875 4,750 (4,750) 1,968 2,763 795 2033 6,143 6,547 4,051 699 1

2034 21,092 4,750 (4,750) 1,871 2,819 948 2034 6,205 6,846 4,051 699 1

2035 21,324 4,750 (4,750) 2,233 2,805 572 2035 6,266 6,648 4,051 699 2

2036 21,568 4,766 (4,766) 2,110 2,912 802 2036 6,497 6,871 4,065 701 2

2037 21,821 4,750 (4,750) 2,537 2,906 369 2037 6,566 6,638 4,051 699 2

2038 22,060 4,750 (4,750) 2,411 2,970 559 2038 6,685 6,951 4,051 699 2

2039 22,299 4,750 (4,750) 2,951 2,771 (181) 2039 6,663 6,474 4,051 699 2

2040 22,541 4,765 (4,765) 2,770 2,866 96 2040 6,922 6,706 4,064 701 2

PSO Reserve Margin - MW

Carbon

Case SO2 Dioxide NOX - OK NOX - TX

Existing Capacity Total Reserve Emissions Emissions Emissions Emissions

Demand Capacity Changes Capacity Margin - % (Tons) (kTons) (Tons) (Tons)

2011 4,072 4,561 0 4,561 12.0% 2011 22,445 11,306 15,086 697

2012 4,084 4,904 0 4,904 20.1% 2012 22,382 12,430 13,462 4512013 4,102 4,904 0 4,904 19.6% 2013 21,440 11,786 11,730 4462014 4,109 4,902 0 4,902 19.3% 2014 22,575 12,124 12,247 4042015 4,099 4,902 0 4,902 19.6% 2015 19,484 11,895 11,860 5042016 4,094 4,915 0 4,915 20.1% 2016 6,094 12,529 7,377 5352017 4,083 4,921 0 4,921 20.5% 2017 1,239 12,072 6,294 5372018 4,079 4,921 0 4,921 20.6% 2018 1,253 11,853 5,963 6082019 4,081 4,921 0 4,921 20.6% 2019 1,214 11,753 6,141 4902020 4,078 4,932 0 4,932 20.9% 2020 1,248 11,372 5,165 6092021 4,091 4,932 0 4,932 20.6% 2021 1,206 11,170 5,242 5582022 4,105 4,932 0 4,932 20.1% 2022 1,243 11,207 5,110 4652023 4,117 4,945 0 4,945 20.1% 2023 1,163 11,039 5,193 5522024 4,130 4,721 0 4,721 14.3% 2024 1,227 11,237 5,147 5882025 4,156 4,721 236 4,957 19.3% 2025 1,216 11,205 5,014 5052026 4,179 4,732 0 4,967 18.9% 2026 1,209 11,167 5,078 6042027 4,204 4,732 0 4,967 18.2% 2027 1,125 10,866 5,123 5652028 4,225 4,733 0 4,969 17.6% 2028 1,230 11,346 5,142 5902029 4,253 4,752 0 4,988 17.3% 2029 1,118 10,867 5,197 6162030 4,284 4,754 0 4,990 16.5% 2030 1,208 11,289 5,372 6182031 4,318 4,746 0 4,982 15.4% 2031 1,165 11,226 5,351 6082032 4,348 4,746 0 4,982 14.6% 2032 1,234 11,531 5,379 6112033 4,390 4,746 236 5,217 18.8% 2033 1,171 11,344 5,637 6112034 4,427 4,746 0 5,217 17.8% 2034 1,227 11,659 5,583 6052035 4,471 4,746 0 5,217 16.7% 2035 1,187 11,505 5,666 6112036 4,511 4,746 0 5,217 15.7% 2036 1,231 11,840 5,938 6132037 4,565 4,746 0 5,217 14.3% 2037 1,189 11,655 5,860 6112038 4,611 4,746 236 5,453 18.3% 2038 1,246 12,014 5,909 6062039 4,657 4,746 0 5,453 17.1% 2039 1,159 11,565 5,862 6072040 4,691 4,746 0 5,453 16.2% 2040 1,202 11,921 6,141 607

Public Service Company of Oklahoma

AEP Capacity Resource Optimization

Costs and Emissions Summary Under Early Carbon Pricing

Summary 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 Technical Conference Transcript before the Corporation Commission 

of the State of Oklahoma. 
PSOIRPtechconf.txt

 lw-1 

 1 BEFORE THE CORPORATION COMMISSION OF 

 THE STATE OF OKLAHOMA

 2 

 

 3 

 

 4 

 

 5 

 

 6 

 7 

 8 

 

 9 

 

 10 

 

 11 TRANSCRIPTION OF QUESTION AND ANSWER SESSION 

 12 PSO IRP STAKEHOLDER MEETING 

 13 SEPTEMBER 20TH, 2012 - 1:00 P.M.

 14 

 15 

 16 

 17 

 18 

 19 

 20 

 21 

 22 

 23 

 24 OFFICIAL REPORTER:

 25 LYNETTE H. WRANY, C.S.R.

 



 lw-2 

 1 

Page 1
PSOIRPtechconf.txt

 2 

 3 

 4 

 5 

 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:

 13 

 14 

 15 

 16 

 17 

 18 

 19 

 20 

 21 

 22 

 23 

 24 OFFICIAL REPORTER: 

 25 LYNETTE H. WRANY, C.S.R.



 lw-3 

 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 



 lw-12 

Page 10
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
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 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
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 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
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 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
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 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
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 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
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 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
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 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
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 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
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 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
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 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
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 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. 

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 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
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 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
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 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
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 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
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 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
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 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
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 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 

Page 29