Technical Support Document

for the

AEP/PSO BART Revision to the Oklahoma Regional Haze State 

Implementation Plan and Federal Implementation Plan

Prepared and Reviewed by:

Joe Kordzi

Erik Snyder

Terry Johnson

July 2013
i

Contents

I. Relationship of this TSD to our Proposal................................................................................................. 1

II. Background to Regional Haze................................................................................................................. 2

III. Evaluation of State Submittal ................................................................................................................ 5

A. Best Available Retrofit Technology (BART) Requirements: 40 CFR 51.308(e) ...............................5

A.1. SO2 BART.................................................................................................................................... 5

A.2. NOx BART ................................................................................................................................ 25

B. Federal Land Manager Coordination 40 CFR 51.308(i) ................................................................... 25

Tables

Table 1: Revised Dry Scrubber Cost Effectiveness.......................................................................15

Table 2: Summary of Revised DSI & Dry Scrubber Cost Effectiveness ......................................17

Table 3: ODEQ’s Baseline Minus the FIP SO2 Control Benefit ...................................................18

Table 4: ODEQ’s Baseline Minus ODEQ’s Revised BART.........................................................18

Table 5: Estimated Alternate Baseline Impairment for 0.6 lb/MMBtu for Units 3 & 4................20

Table 6: Revised Baseline Minus the FIP SO2 Control Benefit ....................................................20

Table 7: Revised Baseline Minus ODEQ’s Revised BART..........................................................21

Table 8: Summary of Results with Revised Baseline....................................................................22

Figures

Figure 1: Map of Class I Areas........................................................................................................3

Figure 2: Location of the Class I Area in Oklahoma .......................................................................3

Figure 3: Map of Regional Planning Organization Boundaries.......................................................4
1

Oklahoma Regional Haze Technical Support Document (TSD)

I. Relationship of this TSD to our Proposal

We are proposing to approve a revision to the Oklahoma’s Regional Haze (RH) State 

Implementation Plan (SIP) submitted on June 20, 2013. In our previous regional haze action for 

Oklahoma1

, (our “prior Oklahoma SIP/FIP action”), we partially approved, partially disapproved

and took no action on various portions of Oklahoma’s RH SIP revision submitted to us on 

February 19, 2010. We disapproved the SO2 BART determinations for Units 4 and 5 of the

Oklahoma Gas and Electric (OG&E) Muskogee plant; Units 1 and 2 of the OG&E Sooner plant; 

and Units 3 and 4 of the American Electric Power/Public Service Company of Oklahoma

(AEP/PSO) Northeastern plant. We also disapproved the LTS under section 51.308(d)(3). We 

finalized a FIP that imposed SO2 BART emission limits on these six sources at three facilities. 

In that FIP, we found that SO2 BART for each of these units was an SO2 emission limit of 0.06 

lb/MMBtu on a 30 boiler operating day average.

Our current proposal is in response to a settlement agreement reached between us, the U. S. 

Department of Justice, AEP/PSO, the State of Oklahoma, ODEQ, and the Sierra Club (the 

“settlement agreement”), attached as Appendix I to the SIP. 

In this action, we are proposing the following:

• Replacement of our SO2 BART determination for Units 3 and 4 of the AEP/PSO

Northeastern plant with ODEQ’s revised SO2 BART determination for these units

• Approval of an accelerated NOx BART compliance date for these same units

• Approval of monitoring, record- keeping, and reporting requirements to ensure

compliance with these emission limitations

• 51.308(i) - Federal Land Manager coordination

We are not proposing any other changes to our prior Oklahoma SIP/FIP action. 

Oklahoma has proposed to amend its long term strategy, as described in Chapter VII of its 

original RH SIP. Specifically, as required by subparagraph 26(E) of the First Amended Regional 

Haze Agreement, AEP/PSO will develop and propose a monitoring program to test various 

operating profiles and other measures required under subparagraph 26(D) to determine whether 

increased SO2 removal efficiencies can be achieved during normal operations. If the SO2

emission rate for the remaining coal-fired unit (either Northeastern Unit 3 or 4) is not reduced to 

0.30 lb/MMBtu after the implementation of the control requirements set forth in this revision and 

the incorporated First Amended Regional Haze Agreement, then ODEQ commits to obtain 

and/or identify additional SO2 reductions within the State of Oklahoma to the extent necessary to 

achieve the anticipated visibility benefits estimated in the CENRAP Base G 2018 regional haze 

modeling and attributable to reductions in SO2 emissions after installation of presumptive 

controls on AEP/PSO Northeastern Units 3 and 4. Additional details can be found in pages 8 to 

 

1

 76 FR 81728.
2

9 of the revised SIP. 

However, because we have not yet acted on Oklahoma’s long term strategy, which includes 

proposed reductions from more than the AEP/PSO Northeastern plant, we cannot propose to 

amend the long term strategy at this time. 

We note that AEP/PSO remains bound to the terms of the settlement agreement (unless it is 

amended), regardless of our proposed action. That settlement does require a monitoring program 

to test various operating profiles and other parameters to determine whether increased DSI SO2

removal efficiencies can be achieved during normal operations. We acknowledge that DSI 

performance is somewhat dependent on the particulars of the plant in question. As an aid to this 

analysis, we are placing a number of documents in the docket that attest to DSI control 

efficiencies at different plants and test environments.

This TSD is not meant to be a complete rationale for our decision. It merely provides additional 

information for some of the technical aspects of the basis for this action when needed. In some 

of the non-technical areas, our Federal Register notice(s) provides more detail than does this 

TSD. Lastly, the TSD attempts to refer the reader to the specific portions of the Oklahoma’s 

regional haze SIP that we relied upon for our analysis of particular portions of section 51.308.

Throughout this document, we may use language such as, “we find” or other similar phrases that 

on the surface would suggest a final determination has been made. However, all aspects of our 

TSD should be considered to be part of our proposal and are subject to change based on 

comments and other information we may receive during our public comment period.

II. Background to Regional Haze

In Section 169A of the 1977 Amendments to the Clean Air Act (CAA), Congress set forth a 

program for protecting visibility in Federal Class I areas which calls for the “prevention of any 

future, and the remedying of any existing, impairment of visibility in mandatory Federal Class I 

areas which impairment results from manmade air pollution.” Congress adopted the visibility 

provisions to protect visibility in 156 Federal Class I areas, which include certain national parks, 

memorial parks, and wilderness areas over a certain size, and all international parks. These areas 

are defined at 40 CFR 81.400, are listed by State at 40 CFR 81.401-81.437, and are depicted in 

Figure 1, with the Class I area within Oklahoma, the Wichita Mountains National Wildlife 

Refuge, depicted in Figure 2:
3

Figure 1. Map of Class I Areas

Figure 2. Location of the Class I Area in Oklahoma
4

On December 2, 1980, we promulgated regulations to address visibility impairment that is

“reasonably attributable” to a single source or small group of sources. (45 FR 80084). These 

regulations represented the first phase in addressing visibility impairment and deferred action on 

regional haze that emanates from a variety of sources until monitoring, modeling and scientific 

knowledge about the relationships between pollutants and visibility impairment improved.

In the 1990 Amendments to the CAA, Congress added Section 169B and called on us to issue 

Regional Haze rules. The RH rule that we promulgated on July 1, 1999 (64 FR 35713) revised 

the existing visibility regulations to integrate provisions addressing regional haze visibility 

impairment and establish a comprehensive visibility protection program for Federal Class I areas.

These regulations represented the second phase in addressing visibility impairment. States were

required to submit state implementation plans (SIPs) to us that set out each state’s plan for

complying with the RH Rule, including consultation and coordination with other states and with 

Federal Land Managers (FLMs). States were required to submit a Regional Haze SIP to us 

within three years after the date of designation of areas under the National Ambient Air Quality

Standard (NAAQS) for fine particulate matter (PM2.5). We promulgated PM2.5 designations on 

December 17, 2004, and thus, regional haze SIPs were to be submitted to us by December 17,

2007, which is also specified at 40 CFR 51.308(b).

The RH rule addressed the combined visibility effects of various pollution sources over a wide 

geographic region. Consequently, all 50 states, including those without Class I areas, 

Washington, D.C., and the Virgin Islands, were required to submit Regional Haze SIPs (40 CFR

51.300(b)(3)). We designated five Regional Planning Organizations (RPOs) to assist with the 

coordination and cooperation needed to address the visibility issue, as shown by Figure 3.

Figure 3. Map of Regional Planning Organization Boundaries
5

Oklahoma, through the ODEQ joined state air agencies from Arkansas, Iowa, Kansas, Louisiana, 

Minnesota, Missouri, Nebraska, and Texas in forming CENRAP, in 1999. CENRAP also 

includes federally recognized Indian tribes located within the geographic boundaries of its 

member states. The State of Oklahoma and it’s agency, the Oklahoma Department of 

Environmental Quality, chose to participate in CENRAP to develop the technical analyses

needed to fulfill the requirements of the RH Rule.

III. Evaluation of State Submittal

In evaluating the Oklahoma RH SIP, we reviewed all the parts of the document, including the 

body of the SIP itself, and all appendices (including the modeling files). In addition, we drew 

upon the following additional documents that may not have been specifically discussed in our 

TSD and/or the Federal Register publication(s) of our decision:

1. 40 CFR Part 51.

2. Appendix V to 40 CFR Part 51.

3. The “BART Guidelines” in Appendix Y to Part 51—Guidelines for BART Determinations 

Under the Regional Haze Rule, 70 FR 39104, July 6, 2005.

4. Guidance for Tracking Progress Under the Regional Haze Rule, EPA-454/B-03-004, 

September, 2003.

5. Guidance for Demonstrating Attainment of Air Quality Goals for PM2.5 and Regional Haze, 

January 2, 2001.

6. Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule, EPA454/B-03-005, September 2003.

7. The “Baseline Memo,” which is entitled, “2002 Base Year Emission Inventory SIP 

Planning: 8-Hour Ozone, PM2.5 and Regional Haze Programs, dated 11/18/2002, from 

Lydia Wegman to the Regional Air Directors.”

8. Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program, dated 

June 1, 2007.

9. Visibility Monitoring Guidance, EPA-454/R-99-003, June 1999.

10. Emissions Inventory Guidance for Implementation of Ozone and Particulate Matter National 

Ambient Air Quality Standards (NAAQS) and Regional Haze Regulations, EPA-454/R-05-

001, dated August, 2005.

11. Interim Air Quality Policy on Wildland and Prescribed Fires, April 23, 1998.

A. Best Available Retrofit Technology (BART) Requirements: 40 CFR 51.308(e)

A.1. SO2 BART

Herein, we review the SO2 BART determinations for Units 3 and 4 of the AEP/PSO Northeastern 

plant. We are not reviewing any other portions of our prior Oklahoma SIP/FIP action. Specifically, 

this proposal addresses Oklahoma’s duty to address the following sections of the RH rule:

• 51.308(e)(1)(ii)(A) - BART five factor determination

• 51.308(e)(1)(ii)(B) - BART for larger fossil fuel power plants

• 51.308(e)(1)(iv)-(v) – installation of BART
6

Section 51.308(e) addresses the Best Available Retrofit Technology (BART) requirements for

regional haze visibility impairment. Oklahoma must submit a SIP containing emission 

limitations representing BART and schedules for compliance with BART for each BART 

eligible source that may reasonably be anticipated to cause or contribute to any impairment of 

visibility in any mandatory Class I Federal area, unless it demonstrates that an emissions trading

program or other alternative will achieve greater reasonable progress toward natural visibility

conditions.

A.1.1 BART Five Factor Determination: 40 CFR 51.308(e)(1)(ii)(A)

ODEQ must make a determination of BART for each BART-eligible source in Oklahoma that emits 

any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of 

visibility in any mandatory Class I Federal area. All such sources are subject to BART. The 

determination of BART must be based on an analysis of the best system of continuous emission 

control technology available and associated emission reductions achievable for each BART-eligible 

source that is subject to BART within the State. In this analysis, Oklahoma must take into 

consideration the technology available, the costs of compliance, the energy and non-air quality 

environmental impacts of compliance, any pollution control equipment in use at the source, the 

remaining useful life of the source, and the degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such technology.

State Submittal

Pages, 5-10, Appendix II.

The AEP/PSO Northeastern Power Station is located in Rogers County, Oklahoma. Units 3 and 4 

are each 490 MW coal-fired steam electric generating units. 

ODEQ’s Five Factor SO2 BART Analysis

In assessing BART, ODEQ used the BART determination process described in the BART Guidelines 

in Appendix Y of 40 CFR Part 51, which are required to be followed for fossil-fuel-fired generating 

plants having a total generating capacity in excess of 750 MW. The BART determination process 

described in Appendix Y includes the following steps: 

• Step 1. Identify All Available Retrofit Control Technologies. 

• Step 2. Eliminate Technically Infeasible Options. 

• Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. 

• Step 4. Evaluate Impacts and Document the Results. 

• Step 5. Evaluate Visibility Impacts.

ODEQ summarizes the baseline control technologies and emissions for Units 3 and 4 as Table 

II-1 of its SIP, which is reproduced below:
7

Baseline Emissions (2004-2006)

Unit 3 Unit 4

Design Heat Input to Boiler 4,775 MMBtu/hr 4,775 MMBtu/hr

SO2

Control Low-Sulfur Coal Low-Sulfur Coal

Emission Rate (lb/MMBtu) 0.9 lb/MMBtu 0.9 lb/MMBtu

Combined Annual Emission Rate1 31,999 TPY

NOx

Control 1st Generation LNB w/ OFA21st Generation LNB w/ OFA2

Emission Rate (lb/MMBtu) 0.40 lb/MMBtu 0.40 lb/MMBtu

Combined Annual Emission Rate1 14,222 TPY

PM10

Control Electrostatic precipitator Electrostatic precipitator

Emission Rate (lb/MMBtu) 0.10 lb/MMBtu 0.10 lb/MMBtu

Combined Annual Emission Rate1 3,555 TPY 1

85% Capacity Factor

2

LNB = Low NOx Burners

OFA = Over-fired Air

In Step 1, ODEQ reviewed all SO2 control technologies in its original BART determination and 

did not repeat that exercise in this revision. Regarding Step 2, ODEQ did not identify any 

additional technically infeasible options from those it identified in its initial BART evaluation. 

However, ODEQ noted, “EPA concluded in the FIP that DFGD/SDA satisfied the BART review 

requirements; therefore, no further analysis of Wet Flue Gas Desulfurization is necessary.”2

 In 

Step 3, ODEQ then analyzed Dry Sorbent Injection (DSI) and Dry Flue Gas DesulfurizationSpray Dryer Absorber (DFGD/SDA, or “dry scrubber”) technologies. ODEQ concluded 

assuming a baseline emission rate of 0.9 lb/MMBtu on a rolling 30-day average basis that DSI 

and DFGD/SDA were capable of achieving SO2 emission rates of 0.40 and 0.06 lb/MMBtu (as 

rolling 30-day averages), respectively. Under Step 4, ODEQ did not identify any significant 

economic, environmental, and energy impacts associated with the two proposed control options. 

In evaluating cost, ODEQ stated that in general it followed EPA Air Pollution Control Cost 

Manual, Sixth Edition (“the Manual”). ODEQ based the capital and operating costs of the DSI 

control option on the Manual except as listed below:

• Purchased Equipment Costs, Site Preparation Costs, and Building Costs were based on an 

approximate six-month, site-specific, feasibility and conceptual engineering and design effort 

that resulted in a Class 4 AACE category budgetary estimate. 

• Operating Labor Costs, Maintenance Labor Costs, and Other Direct Operating Costs (e.g., 

for sorbent usage, electricity, and bag and cage replacement) were based on an evaluation of 

annual operating and maintenance cost project impact as part of the above-mentioned 

feasibility and conceptual design effort. 

• The Indirect Operating Costs of Overhead, Property Tax, and Insurance were based on the 

same calculation methodologies presented in our Technical Support Document (TSD) 

published with the RH FIP. These methodologies deviate from the Manual but were used for 

the purpose of consistency with the FIP3

. 

 

2

 Although we agree with the end result of this statement, some clarification is in order. In our FIP we analyzed 

both dry and wet scrubbers. We determined that SO2 emission rates of 0.06 and 0.04 lb/MMBtu, based on a 

rolling boiler- operating-day average, were appropriate for dry and wet scrubbers, respectively. We concluded that 

the additional cost of wet scrubbers was not worth the additional visibility benefit from them, so based our FIP 

emission rate of 0.06 lb/MMBtu on dry scrubbers. 3

 In our FIP, as directed by the RH rule, we took into account, “any site-specific design or other conditions 
8

The capital recovery factor used to estimate the annual cost of control of the DFGD/SDA option 

was based on a 7% interest rate and a control life of 30 years. Annual operating costs and annual 

emission reductions were calculated assuming a capacity factor of 85%. The capital costs for the 

DSI option were annualized over a 10-year period and then added to the annual operating costs to 

obtain the total annualized costs. ODEQ used an equipment life of 10 years because the controls 

will only be in operation from 2016 to 2026, when the unit will be shut down. ODEQ notes the 

capacity factor will decrease over the 10 year period, beginning in 2021. However, the cost 

analyses are based on an 85% capacity factor to be consistent with baseline actual capacity usage 

and with all previous evaluations. ODEQ summarizes the cost effectiveness of the DSI and 

DFGD/SDA in Table 8 of Appendix II, which is reproduced below:

Baseline DSI DFGD/SDA

SO2 Emission Rate (lb/MMBtu) 0.9 0.4 0.06

Annual SO2 Emission (TPY)1 31,999 7,111 2,880

Annual SO2 Reduction (TPY) 24,888 29,119

Total Annual Cost ($) $25,008,306 $44,969,595

Cost per Ton of Reduction $1,005/ton $1,544/ton

1

Baseline annual emissions were averaged based on annual emissions from 

2004- 2006. Projected annual emissions for DFGD/SDA option were 

calculated based on the controlled SO2 emissions rate (a 91% reduction from 

the baseline). Projected annual emissions for DSI option were calculated 

based on the controlled SO2 emissions rate, full load heat input of 4,775 

MMBtu/hr (30-day rolling average), and assuming a 85% capacity factor.

Having calculated the cost effectiveness of installing DSI versus dry scrubbers, ODEQ contrasts it 

with AEP/PSO’s proposed SO2 BART determination as reflected in the settlement agreement. The 

settlement agreement requires the following for SO2 control:

• Beginning on January 31, 2014, Units 3 and 4 will achieve a SO2 emission rate of 0.65 

lb/MMBtu on a 30-day rolling average, and beginning on December 31, 2014, Units 3 and 

4 will achieve a SO2 emission limit of 0.60 lb/MMBtu on a 12-month rolling average.

• Either Unit 3 or 4 will be shut down by April 16, 2016.

• DSI will be installed and operated on the remaining unit to meet an emission rate of 0.40 

lb/MMBtu or less from April 16, 2016 to December 31, 2026. 

• During the first year of operation of the controls, AEP/PSO will develop and propose a 

monitoring program to determine if additional SO2 reductions can be achieved.

• Beginning in calendar year 2021, the annual capacity factor for the remaining unit will be 

reduced to no more than 70 percent in 2021 and 2022; 60 percent in 2023 and 2024; and 50 

percent in 2025 and 2026.

• The remaining unit will be shut down no later than December 31, 2026.

ODEQ analyzed the fifth step in the BART analysis using the CALPUFF modeling system. 

 

identified above that affect the cost of a particular BART technology option.” 70 FR 39166.
9

ODEQ’s SO2 BART Modeling Analysis

The fifth step for a BART determination analysis, as required by 40 C.F.R. Part 51, Appendix Y, is 

to evaluate the degree of Class I area visibility improvement that would result from the installation 

of the various options for control technology. AEP/PSO submitted a modeling protocol to ODEQ 

October 3, 2012 and a modeling analysis, in November 2012, for the Northeastern Units 3 and 4 

that used the CALPUFF modeling system to predict the changes in Class I area visibility due to the 

different control levels evaluated in November 2012. The updated modeling analyses report and 

modeling protocol are included in Oklahoma Regional Haze SIP as Appendices 5A&5B and 5C 

respectively. The modeling files supporting the updated modeling analyses are also include in the 

available materials upon request from ODEQ or EPA Region 6 (The files are too large to post on a 

website or on EPA’s Federal Docket Management System). We are providing a real brief summary 

of pertinent information for our review. 

The modeling analysis evaluated impacts at four Class I areas (Wichita Mountain Wildlife Refuge, 

Caney Creek, Upper Buffalo and Hercules Glades). AEP/PSO evaluated three SO2 scenarios. They 

modeled Baseline emissions, the proposed SO2 limit of 0.4 lb/MMBtu with one unit shutdown, and 

the DFGD FIP SO2 emission level of 0.06 lb/MMBtu. They also included the pre-BART level NOx 

emission rates in the baseline and did a scenario based on the original RH sip assumptions of 0.15 

lb/MMBtu for NOx and SO2 emission rates for AEP’s boilers #3 and #4. AEP/PSO modeled NOx 

and SOx species but did not model PM2.5 species (primary PM2.5, VOCs, elemental Carbon, etc.). 

The emission rates and the lb/MMBtu were summarized by ODEQ in Table 9 of Appendix II, which 

is reproduced on the next page: 
10

Parameter Northeastern Unit 3 Northeastern Unit 4

Plant Configuration Coal-Fired Boiler Coal-Fired Boiler

Firing Configuration Tangentially-fired Tangentially-fired

Gross Output (nominal) 490 MW 490 MW

Design Input to Boiler 4,775 MMBtu/hr 4,775 MMBtu/hr

Maximum 24-hour Average Input 5,812 MMBtu/hr 5,594 MMBtu/hr

Primary Fuel Sub-bituminous coal Sub-bituminous coal

Existing NOX Controls 1st Generation LNB/OFA 1st Generation LNB/OFA

Existing PM10 Controls Electrostatic precipitator Electrostatic precipitator

Existing SO2 Controls Low-sulfur coal Low-sulfur coal

Baseline Emissions

Unit 3 Unit 4

lb/hr lb/MMBtu lb/hr lb/MMBtu

NOX 3,116 0.536 2,747 0.491

SO2 6,126 1.054 5,930 1.06

SIP Approved Emissions (Max 24-hour)

lb/hr lb/MMBtu lb/hr lb/MMBtu

NOX 872 0.15 839 0.15

Unit 4 Shut Down/Unit 3 NOX Controlled, SO2 Baseline (Max 24-hour)

lb/hr lb/MMBtu lb/hr lb/MMBtu

NOX 872 0.15 - -

SO2 6,126 1.054 - -

Unit 4 Shut Down/Unit 3 NOX Controlled, SO2 DSI Control (Max 24-hour)

NOX 872 0.15 - -

SO2 2,325 0.4 - -
11

AEP/PSO performed the CALPUFF modeling with the following versions of programs that make up 

the CALPUFF System:

Program Version Level

CALMET 5.53a 040716

CALPUFF 5.8 070623

POSTUTIL 1.52 060412

CALPOST 6.221 080724

AEP/PSO used the same CALMET files that were previously used in the earlier Oklahoma Regional 

Haze SIPs and our FIP. AEP/PSO did perform additional CALPUFF, POSTUTIL, and CALPOST 

modeling in performing the new modeling analysis. The source parameters were summarized by 

ODEQ in Table 11 of Appendix II, which is reproduced below:

Parameter

Baseline1

Coal-Fired

Unit 3

Coal-Fired

Unit 4

Heat Input (MMBtu/hr) 5,812 5,594

Stack Height (m) 183 183

Stack Diameter (m) 8.23 8.23

Stack Temperature (K) 424 415

Exit Velocity (m/s) 18.97 17.46

Baseline SO2 Emissions (lb/MMBtu) 1.054 1.060

Dry Sorbent Injection 0.4 -

Baseline NOX Emissions (lb/MMBtu) 0.536 0.491

LNB/OFA NOX Emissions (lb/MMBtu) 0.15 -

1

Baseline emissions data were provided by AEP/PSO. Baseline emission rates (lb/MMBtu) were calculated by dividing the 

maximum 24-hr lb/hr emission rate by the maximum heat input to the boiler at that emission rate.
12

AEP/PSO calculated visibility impacts using Method 8 in the CALPOST processing. ODEQ 

summarized the final visibility modeling results in Tables 12 and 13 of Appendix II , which is 

reproduced below:

Class I Area

2001 2002 2003 3-Year Average

98th

Percentile Value 

(Δdv)

98th

Percentile Value

(Δdv)

98th

Percentile Value 

(Δdv)

98th

Percentile Value 

(Δdv)

Baseline

Wichita Mountains 1.228 1.339 1.937 1.501

Caney Creek 1.927 1.290 1.664 1.627

Upper Buffalo 1.389 0.938 1.180 1.169

Hercules Glade 1.179 0.867 1.291 1.112

Unit 4 Shut Down and DSI on Unit 3 (NOX Baseline)

Wichita Mountains 0.417 0.356 0.618 0.464

Caney Creek 0.637 0.439 0.584 0.553

Upper Buffalo 0.534 0.293 0.379 0.402

Hercules Glade 0.408 0.291 0.298 0.332

Unit 4 Shut Down and DSI/LNB/OFA on Unit 3

Wichita Mountains 0.241 0.271 0.372 0.295

Caney Creek 0.346 0.240 0.297 0.294

Upper Buffalo 0.247 0.172 0.231 0.216

Hercules Glade 0.213 0.170 0.246 0.209
13

Class I Area

2001 2002 2003 3-Year Average

98th

Percentile Value

(Δdv)

98th

Percentile Value

(Δdv)

98th

Percentile Value

(Δdv)

98th

Percentile Value

(Δdv)

EPA FIP – DFGD/SDA Units 3 and 4

Wichita Mountains 0.187 0.163 0.257 0.202

Caney Creek 0.227 0.196 0.252 0.225

Upper Buffalo 0.238 0.129 0.139 0.169

Hercules Glade 0.197 0.129 0.119 0.148

ODEQ indicated that a DFGD/SDA solution would provide improvements in visibility above that 

achieved with a DSI system. ODEQ summarized the results that the FIP scenario would result in 

improvements of approximately 0.1dv over individual Class I areas and an average total 

improvement of 0.27 across the four nearest Class I areas during the time of control implementation

(by end of 2017). ODEQ concluded that factoring in the full settlement agreement, these 

incremental reductions in emissions of SO2 do not result in a perceptible improvement in visibility 

either on an individual Class I area basis or a cumulative Class I area basis. 

ODEQ’s SO2 BART Determination

ODEQ notes that in general, BART is considered to be a unit-by-unit evaluation. However, in 

order to more accurately compare the environmental benefits of one solution versus another, 

ODEQ contrasts the settlement agreement control strategy through the BART timeframe against the 

FIP scenario through the same time period. 

As noted above, ODEQ calculated the cost effectiveness in dollars per ton of SO2 removed for DSI 

as used in the settlement agreement to be $1,005 per ton, and for the level of SO2 control required 

in our FIP to be $1,544 per ton, with projected levels of emission reductions of 24,888 tons per year 

and 29,119 tons per year, respectively. Therefore, the incremental cost effectiveness of the FIP 

scenario is $4,718 per ton in the first year. ODEQ notes that this incremental cost effectiveness will 

worsen with decreased capacity utilization under the settlement agreement. ODEQ states that in 

comparison to the settlement agreement, the FIP would result in imperceptibly greater 

improvements of approximately 0.1 dv over individual Class I areas and an average total 

improvement of 0.27 dv across the four nearest Class I areas during the time of control 

implementation.

In addition, ODEQ notes that the settlement agreement requires the shutdown of either 

Northeastern Unit 3 or 4, and therefore the removal of NOx, SO2, PM, and CO2e emissions from 

that unit. These reductions will help to address local formation and interstate transport of ozone 

and reduce the contribution to greenhouse gases and mercury deposition from electricity generation 

in Oklahoma. In contrast, the FIP scenario provides no further improvement in ozone and ODEQ 

projects it would likely assure continued use of coal-fired electricity generation for an additional 20 

years beyond the settlement agreement scenario. ODEQ also states that the settlement agreement 
14

scenario, while achieving perceptively equivalent visibility improvements at the Class I areas, will 

not require water usage and in shutting down one of the two Northeastern Units rather than 

installing additional controls, energy consumption is half that of the control solution established by 

the FIP. 

ODEQ concludes that given the comparable visibility improvement, lower costs, and overall 

reduced environmental impact, the scenario described in the settlement agreement constitutes 

BART.

EPA Findings

Additional EPA Cost Effectiveness Analyses

We note that in performing its SO2 BART analysis, ODEQ assumes a SO2 baseline that is 

constructed on the basis of an emission limit of 0.9 lb/MMBtu. Although we believe that baseline 

was appropriate at the time ODEQ submitted its SIP and during our analysis and FIP, we believe it 

is no longer representative. Since the FIP, additional monitoring data has been acquired that 

indicates Units 3 and 4 are emitting well below this level4

. In fact, the annual SO2 emission 

averages for units 3 and 4 have been well below 0.60 lb/MMBtu in both 2011 and 2012. Also, as 

described elsewhere, AEP/PSO has entered into a settlement agreement with us and ODEQ that 

requires that beginning on January 31, 2014, Units 3 and 4 will achieve a SO2 emission rate of 0.65 

lb/MMBtu on a 30-day rolling average, and beginning on December 31, 2014, Units 3 and 4 will 

achieve a SO2 emission limit of 0.60 lb/MMBtu on a 12-month rolling average. We therefore 

propose that it is appropriate the SO2 baseline be based on an emission limit of 0.60 lb/MMBtu. 

In addition, although we believe that ODEQ makes several good points regarding some potential 

advantages of the settlement, ODEQ’s basic approach consists of comparing the cost effectiveness 

of the DSI based settlement control to the dry scrubber based FIP control. We believe it is more 

appropriate to approach the analysis by using the settlement shut down schedules for Units 3 and 4 

as the starting point, and then analyzing whether DSI or dry scrubbers are the more cost effective 

interim SO2 control. In other words, we believe it is appropriate to analyze both potential SO2

controls for the remaining unit on the basis of a 10 year life (approximated on the basis of the April 

16, 2016 to December 31, 2026 DSI installation and shut down schedules), in order to determine 

whether the incremental cost increase of dry scrubbers over DSI is cost effective in relation to the 

additional visibility improvement. 

We have therefore revised our FIP cost evaluation for dry scrubbing to incorporate a revised SO2

baseline based on an emission rate of 0.60 lb/MMBtu for one unit and a 10 year life. In so doing, 

we have retained the same heat input of 4,775 MMBtu/hr and 85% capacity factor as ODEQ.5 The 

revised spreadsheet containing this analysis is contained in the docket and a summary of this 

information is presented below in Table 1:

 

4

 See file, “AEP-PSO Monthly Emissions Units 3-4.xlsx,” which was downloaded from the CAMD Air Markets 

Program Data website, available at: http://ampd.epa.gov/ampd/ 5

 Baseline = (0.60 lb/MMBtu X 4,775 MMBtu/hr X 8760 hrs/yr X 0.85 capacity / 2000 lb/ton) X 2 units = 21,333 

tons SO2/yr. 

Note that in ODEQ’s cost effectiveness analyses, the baseline and the capital costs for both DSI and dry scrubbers 

are based on the totals for two units. This is fine, as the calculation of the cost per ton removed divides the total 

annual cost for both units by the total tons removed for both units, making the resulting figure applicable to either 

unit singly. We used the same approach to allow for an easier comparison.
15

Table 1 – Revised Dry Scrubber Cost Effectiveness

Revised Cost Effectiveness Analysis for

Flue Gas Desulfurization at

Northeastern Units 3 & 4

FIP EPA Notes

CAPITAL COST SUMMARY

Purchased Equipment Cost (PEC) 547,080,000 249,100,000 These costs are for both units

Landfill Construction 25,000,000 25,000,000

TOTAL CAPITAL INVESTMENT (TCI) 572,080,000 274,100,000

ANNUAL COST SUMMARY

DIRECT OPERATING COST

Lime Injection 6,178,600 6,178,600

Operating Electricity 3,022,200 3,022,200

Water 423,100

FGD Waste Disposal 479,988

Bag & Cage Replacement 572,000

Fixed O&M 4,116,350

TOTAL DIRECT COST (DC) 9,200,800 14,792,238

INDIRECT OPERATING COSTS

Administrative Charges (2% TCI) 11,441,600 5,482,000

Insurance (1% TCI) 5,720,800 28,781

Property Taxes (1% TCI) 5,720,800 2,329,850

Capital Recovery (CRF X TCI) 58,267,612 39,025,673

TOTAL INDIRECT COST (IC) 81,150,812 46,866,304

TOTAL ANNUALIZED COST (DC+IC) 90,351,612 61,658,542

COST EFFECTIVENESS SUMMARY

Annual Control Cost 90,351,612 61,658,542

SO2 to be Removed (ton/yr) 26,559 19,200 Tonnage removed is for both units

COST EFFECTIVENESS ($/ton) 3,402 3,211

Cost effectiveness applies to both 

units or either unit
16

INPUTS

DFGD Capital Cost ($/kW) 582 265

Net Rating (MW) 940 940

Landfill costs estimated by AEP ($) 25,000,000 25,000,000

Estimated Lime Usage (ton/yr) 30,893 30,893

Lime Cost ($/ton) 200 200

Estimated Electricity Usage (kW/hr) 6,900 6,900

Cost of Electricity ($/kW) 0.05 0.05

SO2 Removal Rate 0.83 0.90

Changed from 91% control to 90% 

control (0.6 to 0.06 lb/MMBtu)

Water (gal/MMBtu) 4.25

Water Cost ($1.40/1000 gal) 1.40

Solids Generated (lb solids/lb SO2) 5

Solids Disposal Cost ($/ton) 5

Baseline emissions (lb SO2/MMBtu) 0.90 0.60

Baseline emissions changed from 

0.90 to 0.60 lb/MMBtu to reflect 

current data and settlement 

agreement

Annual Average Firing Rate (MMBtu/hr) 4,775 4,775

Capacity Factor 0.85 0.85

Capital Recovery Factor 0.1019 0.1424

Interest Rate 0.08 0.07

Scrubber Lifetime (yr) 20 10.00 Revised to 10 years

In addition to revising the scrubber lifetime and the SO2 baseline, we also revised the SO2 removal 

rate. At the time we constructed our FIP, we noted that dry scrubbers were capable of 95% control. 

However, we also noted that in the SIP the capital and O&M costs for the Northeastern units were 

scaled from capital costs and utility demands for the OG&E Sooner and Muskogee scrubbers, which 

were based on 91% SO2 control. We chose to carry that 91% control forward in our FIP cost 

evaluation for the AEP/PSO facility as it did not alter our conclusion regarding cost effectiveness 

and was expedient to do so. Here, realizing that 91% control from a baseline emission rate of 0.60 

would result in a controlled level below what we found to be achievable in our FIP (0.06 

lb/MMBtu), we reduce the level of control to 90%, which results in a controlled emission rate of 

0.06 lb/MMBtu.

We therefore propose to find that recalculating as described above, a more appropriate cost 

effectiveness calculation for dry scrubbers is $3,211/ton, as opposed to the $1,544/ton ODEQ 

calculated.

We have found the capital costs for DSI to be acceptable. However, because ODEQ used the same 

SO2 baseline in its DSI cost analysis, we must similarly adjust ODEQ’s DSI cost per ton calculation 

to compensate for the revised SO2 baseline. We therefore accept ODEQ’s DSI total annual cost of 

$25,008,306 and annual SO2 emissions of 7,111 tons, but recalculate the tons removed to be 21,333

– 7,111 = 14,222. This results in a revised cost effectiveness calculation of $25,008,306 / 14,222 = 

$1,758/ton. Table 2 summarizes this information below:
17

Table 2 – Summary of Revised DSI and Dry Scrubber Cost Effectiveness

ODEQ EPA

SO2 Baseline (tons/yr) 31,999 21,333

Dry Scrubber Tons Removed 29,119 19,200

Dry Scrubber cost effectiveness $1,544/ton $3,211/ton

DSI Tons Removed 24,888 14,222

DSI cost effectiveness $1,005/ton $1,758/ton

As shown above, when the cost effectiveness is recalculated based on a 10 year operating life for 

both DSI and dry scrubbers, the cost effectiveness of dry scrubbers becomes less attractive. The 

incremental cost effectiveness of dry scrubbers is $7,362/ton when compared to DSI based on 

EPA’s recalculation. 

We note this analysis assumes a SO2 emission rate for DSI of 0.40 lb/MMBtu, based on a 30 day 

average. The settlement agreement requires that AEP/PSO “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.” 

Additional EPA Modeling Analyses

AEP/PSO’s modeling did not include PM or VOC species in any of the runs. While we would have 

typically included these species, they end up having a similar add-on to the estimated visibility 

impairment on all the modeling scenarios if they were modeled. Therefore, for the purpose of 

evaluating potential visibility improvements due to the different SO2 control levels, the change in 

impact is expected to be the same in magnitude as would be observed with these pollutants added to 

the CALPUFF modeling. Our review of the modeling information did not raise any other concerns 

with the actual modeling.

ODEQ’s analysis of modeling included data on the different scenarios (baseline, DSI and shutdown, 

and FIP). To assist in evaluating the analysis we created the following Tables that indicate the 

difference due to SO2 control in the FIP and due to the new BART determination utilizing DSI on 

Unit#3 and Shutdown of Unit #4 (for the sake of this exercise, we assumed that Unit #4 would be 

shut down and that Unit #3 would receive the additional DSI controls; because the two units are 

identical, the decision on which unit to shut down in 2016 will be left to AEP/PSO).
18

Table 3 – ODEQ’s Baseline Minus the FIP SO2 Control Benefit

Class I 

Area

2001 2002 2003

3-Year 

Average

98th 98th 98th 98th

Percentile 

Value 

Percentile 

Value

Percentile 

Value 

Percentile 

Value 

(Δdv) (Δdv) (Δdv) (Δdv)

ODEQ - AEP/PSO Baseline - FIP (DSGD w/SDA)

Wichita 

Mountains

1.041 1.176 1.68 1.299

Caney 

Creek 1.7 1.094 1.412 1.402

Upper 

Buffalo 1.151 0.809 1.041 1

Hercules 

Glade 0.982 0.738 1.172 0.964

TOTAL 4.874 3.817 5.305 4.665

Table 4 – ODEQ’s Baseline Minus ODEQ's Revised BART (Unit #3 DSI, Unit #4 Shutdown)

Class I 

Area

2001 2002 2003

3-Year 

Average

98th 98th 98th 98th

Percentile 

Value 

Percentile 

Value

Percentile 

Value 

Percentile 

Value 

(Δdv) (Δdv) (Δdv) (Δdv)

ODEQ - AEP/PSO Baseline - ODEQ's revised BART (Unit #3 

DSI, Unit #4 shut down)

Wichita 

Mountains

0.987 1.068 1.565 1.206

Caney 

Creek 1.581 1.05 1.367 1.333

Upper 

Buffalo 1.142 0.766 0.949 0.953

Hercules 

Glade 0.966 0.697 1.045 0.903

TOTAL 4.676 3.581 4.926 4.395
19

ODEQ indicated that the FIP scenario would result in trivial visibility improvements of 

approximately 0.1 dv above that of the proposed strategy over individual Class I areas and an 

average total improvement of 0.27 dv across the four nearest Class I areas during the time of control 

implementation. The difference between the 3 year average values for the sum of the four Class I 

area impacts is 4.665 dv – 4.395 dv, which confirms the 0.27 dv value ODEQ indicated.

ODEQ discussed this difference between DFGD controls and DSI controls (approx. 0.1 dv at a 

Class I area and 0.27 dv average cumulative difference) as not perceptible or significant and 

elsewhere as trivial. While less than 1 deciview may be referred to as ‘not perceptible’ in general, 

smaller differences are still important to estimate and can be weighed considering other pertinent 

issues. We agree that the levels are small and below the ‘cause’ or ‘contribute’ levels, but we do not 

consider them ‘trivial’. In the preamble to EPA’s BART Guidelines, “ [e]ven though the visibility 

improvement from an individual source may not be perceptible, it should still be considered in 

setting BART because the contributions to haze may be significant relative to other source 

contributions in the Class I areas.” Overall, the Regional Haze process envisions reductions that are 

both ‘perceptible’ and ‘not perceptible’ will be necessary as part of the overall path to obtain the 

necessary reductions to meet the Regional Haze goals.

We note that for baseline NOx emissions the maximum 24-hour lb/MMBtu emission rate was used 

and for the controlled levels a 30-day average emission rate level was used. This mix of 24-Hour 

maximum emission rate for the baseline and the 30-day average emission rate level tends to slightly 

overestimate the actual baseline to controlled level benefits. This does give a relative analysis as the 

same baseline is used in both NOx control levels of 0.23 lb/MMBtu and 0.15 lb/MMBtu emission 

rates.

We note that for baseline SO2 emissions the maximum 24-Hour lb/MMBtu emission rate was used 

and for the controlled levels a 30-day average emission rate level was used. This mix of 24-Hour 

maximum emission rate for the baseline and the 30-day average emission rate level tends to slightly 

overestimate the actual baseline to controlled level benefits. This does give a relative analysis as the 

baseline is used in both SO2 control levels of 0.4 lb/MMBtu and 0.06 lb/MMBtu emission rates. In 

the case of the SO2 baseline, the maximum emission rates were based on 1.054 and 1.06 lb/MMBtu 

for Units #3 and #4 respectively. This is higher than the 0.9 lb/MMBtu used in the cost analysis 

calculations for baseline. Furthermore, as discussed in the cost analysis section, an alternate 

baseline using 0.6 lb/MMBtu for SO2 emissions would also be appropriate for consideration.

Utilizing the existing modeling and assuming a linear nature to the benefits of SO2 reduction we can 

estimate a revised baseline using the 0.6 lb/MMBtu SO2 emission rate for Units #3 and #4. Based 

on some of the modeling included in previous Oklahoma and EPA actions this appears to be a 

reasonable assumption. In this analysis, we are using the baseline modeling that used the higher 

emission rates (1.054 and 1.06 lb of SO2/MMBtu) and the FIP modeling with 0.06 lb of 

SO2/MMBtu for Units #3 and #4 and extrapolating the amount of visibility impairment for the 

alternate baseline scenario.
20

Table 5 – Estimated Alternate Baseline Impairment for 0.6 lb of SO2/MMBtu for Units #3 and #4.

Class I 

Area

2001 2002 2003

3-Year 

Average

98th 98th 98th 98th

Percentile 

Value 

Percentile 

Value

Percentile 

Value 

Percentile 

Value 

(Δdv) (Δdv) (Δdv) (Δdv)

Alternate Baseline (0.6 lb/MMBtu SO2) 

Wichita 

Mountains 0.56 0.64 0.91 0.70

Caney 

Creek 0.92 0.59 0.76 0.76

Upper 

Buffalo 0.62 0.44 0.56 0.54

Hercules 

Glade 0.42 0.31 0.54 0.42

TOTAL 2.53 1.98 2.78 2.43

Based on this alternate baseline we can now estimate the difference between the alternate baseline 

and the two options of FIP and Revised BART.

Table 6 - Revised Baseline Minus the FIP SO2 Control Benefit

Class I 

Area

2001 2002 2003

3-Year 

Average

98th 98th 98th 98th

Percentile 

Value 

Percentile 

Value

Percentile 

Value 

Percentile 

Value 

(Δdv) (Δdv) (Δdv) (Δdv)

Alternate Baseline (0.6 lb/MMBtu SO2) - FIP (DSGD w/SDA)

Wichita 

Mountains 0.38 0.47 0.65 0.50

Caney 

Creek 0.69 0.40 0.51 0.53

Upper 

Buffalo 0.39 0.31 0.42 0.37

Hercules 

Glade 0.22 0.18 0.42 0.27

TOTAL 1.68 1.36 2.01 1.68
21

Table 7 - Revised Baseline Minus ODEQ's Revised BART (Unit #3 DSI, Unit #4 Shutdown)

Class I 

Area

2001 2002 2003

3-Year 

Average

98th 98th 98th 98th

Percentile 

Value 

Percentile 

Value

Percentile 

Value 

Percentile 

Value 

(Δdv) (Δdv) (Δdv) (Δdv)

Alternate Baseline (0.6 lb/MMBtu SO2) - ODEQ's revised 

BART (Unit #3 DSI, Unit #4 shut down)

Wichita 

Mountains 0.32 0.37 0.54 0.41

Caney 

Creek 0.57 0.35 0.47 0.47

Upper 

Buffalo 0.38 0.27 0.33 0.33

Hercules

Glade 0.20 0.14 0.29 0.21

TOTAL 1.48 1.13 1.63 1.41

Both of these comparisons also include the benefits of the NOx controls and the respective SO2

controls. As can be seen in comparing Tables 6 and 7, the differences in the average impacts at 

each Class I are still 0.1 or less and the cumulative average is 0.27 dv (1.68 dv -1.41 dv). The 

additional controls from the FIP only net approximately 20% more net visibility impairment benefit 

for a much larger cost and do not consider the other benefits of the limited life with shutdown in 

2026 which should net more overall benefit on the Reasonable Progress Goals at the four Class I 

areas eventually. 

ODEQ assessed the cost effectiveness of the two scenarios in the Revised BART determination.

They concluded that these small improvements would be achieved at a much greater cost.

In Table 8 below the results are summarized and improvement results from the new baseline are 

also included for a scenario estimated for one unit operating with a Dry Scrubber and one unit 

shutdown. This is included for comparison purposes with the one unit operating with DSI. It is 

based on the one unit having half the impairment of the FIP scenario. This scenario shows that 

there are somewhat significant visibility improvements over one unit operating with DSI. The 

maximum visibility benefit is 0.19 at Wichita Mountains and 0.64 cumulatively. It should be noted 

that this scenario was not presented by the State and if the company were to invest in a Dry 

Scrubber, it likely would want to operate the scrubber much longer than 10 years and the visibility 

benefits of the second unit shutdown would not be realized.
22

Table 8 – Summary of Results with Revised Baseline

Baseline 

Average 

Impairment

Improvement 

Shutdown 

and DSI

2 Dry 

Scrubber 

Improvement

Shutdown 

and Scrubber

Improvement

(Δdv) (Δdv) (Δdv) (Δdv)

Wichita 

Mountains 0.70 0.41 0.50 0.6

Caney 

Creek 0.76 0.47 0.53 0.65

Upper 

Buffalo 0.54 0.33 0.37 0.46

Hercules 

Glade 0.42 0.27 0.27 0.35

TOTAL 2.43 1.41 1.68 2.06

Overall, in looking both at ODEQ’s analysis and the alternate baseline analysis, it can be 

determined that only a small percentage improvement in visibility impairment (compared to 

DSI/Shutdown option) would be gained by the FIP but the costs are significantly higher and would 

also result in more impairment in the long run. Furthermore, a Dry Scrubber on the remaining unit 

would cost significantly more and while it would achieve somewhat more visibility benefit, we 

would agree that the State’s decision not to require it is reasonable considering the long term 

benefits of the Regional Haze Agreement.

We note that the modeling files supporting this analysis and SIP submittal are very large (over 1 

Terabyte). EPA is not able to load these on an ftp or web site due to their size, but we will copy 

the files onto a hard drive if someone would like the files to review. Please contact either Erik 

Snyder (snyder.erik@epa.gov or 214-665-7305) or Michael Feldman (feldman.michael@epa.gov

or 214-665-9793) for arrangements on what size portable hard drive the requestor will need to 

provide, where to ship the drive and what files are desired.

EPA Cost Effectiveness Conclusions

We propose to find that our revised cost analysis has confirmed that ODEQ has adequately 

addressed the requirements in section 51.308(e)(1)(ii)(A). 

A.1.2. BART for Larger Fossil Fuel Power Plants: 40 CFR 51.308(e)(1)(ii)(B)

A determination of BART is required for each BART-eligible source in Oklahoma that emits 

any air pollutant which may reasonably be anticipated to cause or contribute to any impairment 

of visibility in any mandatory Class I Federal area. All such sources are subject to BART. The 

determination of BART for fossil-fuel fired power plants having a total generating capacity 

greater than 750 megawatts must be made pursuant to the guidelines in appendix Y of this part 

(Guidelines for BART Determinations under the Regional Haze Rule).
23

State Submittal

Appendix II

The AEP/PSO Northeastern Units 3 and 4 are located at a fossil-fuel fired steam electric

generating plants with heat inputs greater than 250-MMBtu/hr, and with a total generating 

capacity in excess of 750 MW. ODEQ has stated it followed the requirements in Section 

51.308(e)(1)(ii)(B) in preparing the BART determinations for these facilities.

EPA Findings

We propose to find that ODEQ made its determination of SO2 BART for Units 3 and 4 pursuant to 

the guidelines in appendix Y, as required by 51.308(e)(1)(ii)(B). ODEQ evaluated the visibility 

impacts and the costs of controls. As described above, we believe the costs of controls were not 

estimated as we believe is most appropriate and there were differences in the visibility modeling 

from how we believe the modeling would best be performed. However, we believe these differences

do not change the overall outcome that Oklahoma reached a reasonable conclusion regarding BART 

for SO2 and the FIP is no longer appropriate.

A.1.3. Installation of BART: 40 CFR 51.308(e)(1)(iv) – (v)

Each source subject to BART must (1) install and operate BART as expeditiously as practicable, but 

in no event later than 5 years after approval of the SIP revision, and (2) maintain the control 

equipment required by this subpart and establish procedures to ensure such equipment is

properly operated and maintained.

State Submittal

ODEQ summarizes the implementation of the BART determination as Table II-2 of its SIP, which is 

reproduced below:
24

Preliminary/BART Control Steps (Prior to Unit 4 Shutdown1)

By December 31, 2013 Unit 3 Unit 4

NOX

Control LNB w/ Separated OFA2 LNB w/ Separated OFA2

Emission Rate (lb/MMBtu) 0.23 lb/MMBtu

(30-day rolling average)

0.23 lb/MMBtu

(30-day rolling average)

Hourly Emission Rate 1,098 lb/hr

(30-day rolling average)

1,098 lb/hr

(30-day rolling average)

Combined Annual Emission Rate 9,620 TPY (12-month rolling)

By January 31, 2014 Unit 3 Unit 4

SO2

Control Low Sulfur Coal Low Sulfur Coal

Emission Rate (lb/MMBtu) 0.65 lb/MMBtu3

(30-day rolling average)

0.65 lb/MMBtu

(30-day rolling average)

Hourly Emission Rate 3,104 lb/hr

(30-day rolling average)

3,104 lb/hr

(30-day rolling average)

By December 31, 2014 Unit3 Unit 4

SO2

Control Low Sulfur Coal Low Sulfur Coal

Emission Rate (lb/MMBtu) 0.60 lb/MMBtu

(12-month rolling average)

0.60 lb/MMBtu

(12-month rolling average)

Combined Annual Emission Rate 25,097 TPY (12-month rolling)

BART Control (with Unit 4 Shutdown1)

By April 16, 2016 Unit 31

SO2

Control Dry Sorbent Injection (DSI) with Activated Carbon Injection

Emission Rate (lb/MMBtu) 0.4 lb/MMBtu (30-day rolling average)

Hourly Emission Rate 1,910 lb/hr (30-day rolling average)

Annual Emission Rate 8,366 TPY

NOx

Control LNB w/ Separated OFA (and Further Control System Tuning)

Emission Rate (lb/MMBtu) 0.15 lb/MMBtu (30-day rolling average)

Hourly Emission Rate 716 lb/hr (30-day rolling average)

Annual Emission Rate 3,137 TPY 1

For simplicity, the table reflects AEP/PSO’s indication that Unit 4 is the likely unit to be shut down in 2016, but 

there is no requirement as to which of the two units is shut down first.

2

LNB = Low NOx Burners

OFA = Over-fired Air 3

An alternative operating scenario is provided in paragraph 12 of the First Amended Regional Haze Agreement, 

Case No. 10-025, that addresses potential disruption of coal supplies during the time period from January 31, 2014 

through April 16, 2016.

EPA Findings

We propose to find that ODEQ has demonstrated it has the authority and enforceable mechanisms 

in place to ensure each source subject to BART will (1) install and operate BART as

expeditiously as practicable, but in no event later than 5 years after approval of the SIP revision, 

and (2) maintain the control equipment required by this subpart and establish procedures to 

ensure such equipment is properly operated and maintained.
25

A.2. NOx BART

We previously approved ODEQ’s NOx BART emission limit applicable to Units 3 and 4 as 0.15 

lb/MMBtu, based on a 30-day rolling average, in our prior Oklahoma SIP/FIP action. This 

determination required compliance within 5 years of the SIP approval, or by January 27, 2017. In 

this action, we are not proposing to re-evaluate ODEQ’s NOx BART technology determination for 

these units. However, we are proposing to approve ODEQ’s determination, as reflected in the 

settlement agreement, that an earlier compliance schedule is appropriate. We propose the 

following:

• Units 3 and 4 are required to comply with an initial emission limit of 0.23 lb/MMBtu, based

on a 30-day rolling average, beginning on December 31, 2013 until April 16, 2016. These 

NOx reductions will occur earlier than required by our prior Oklahoma SIP/FIP action. 

• After April 16, 2016, either Unit 3 or 4 will be shut down and the remaining unit must 

comply with an emission limit of 0.15 lb/MMBtu, based on a 30-day rolling average. This 

is also earlier than required by our prior Oklahoma SIP/FIP action. 

Although not modeled, we anticipate this early implementation schedule will provide additional

improvements in visibility, and will reduce the local formation and transport of ozone.

B. Federal Land Manager Coordination 40 CFR 51.308(i)

Oklahoma must provide the Federal Land Manager with an opportunity for consultation, in 

person and at least 60 days prior to holding any public hearing on a SIP (or plan revision) for

regional haze required by this subpart. This consultation must include the opportunity for the

affected Federal Land Managers to discuss their:

(i)Assessment of impairment of visibility in any mandatory Class I Federal area; and

(ii)Recommendations on the development of the reasonable progress goal and on the 

development and implementation of strategies to address visibility impairment.

In developing any SIP (or plan revision), Oklahoma must include a description of how it 

addressed any comments provided by the Federal Land Managers.

The SIP (or SIP revision) must provide procedures for continuing consultation between 

Oklahoma and Federal Land Manager(s) on the implementation of the visibility protection 

program required by this subpart, including development and review of SIP revisions and 5-year 

progress reports, and on the implementation of other programs having the potential to contribute

to impairment of visibility in mandatory Class I Federal areas.
26

State Submittal

Pages 117-119, Appendix 10-2.

Under Section 51.308(i)(2), the Oklahoma was obligated to provide the Fish and Wildlife 

Service with an opportunity for consultation, in person and at least 60 days prior to holding a 

public hearing on it RH SIP. In practice, state environmental agencies have usually provided all 

FLMs – the Forest Service, the Park Service, and the Fish and Wildlife Service, copies of their 

RH SIP, as the FLMs collectively have reviewed these RH SIPs. ODEQ followed this practice 

and sent its draft of this implementation plan revision to the federal land manager staff on 

March 20, 2013 and notified the federal land manager staff of the public hearing held on May

20, 2013. In its letter dated April 15, 2013, transmitting its comments, the Fish and Wildlife 

Service acknowledged having received Oklahoma’s draft RH SIP. Likewise, The U.S. Forest 

Service acknowledged receiving the draft RH SIP in its letter dated April 30, 2013, transmitting 

its comments.

Section 51.308(i)(3) requires that ODEQ provide in its RH SIP a description of how it addressed 

any comments provided by the FLMs. ODEQ has provided that information in Appendix VII of 

its RH SIP.

Lastly, Section 51.308(i)(4) specifies the RH SIP must provide procedures for continuing 

consultation between the State and Federal Land Manager on the implementation of the visibility 

protection program required by section 51.308, including development and review of 

implementation plan revisions and 5-year progress reports, and on the implementation of other 

programs having the potential to contribute to impairment of visibility in the mandatory Class I 

Federal areas. ODEQ has stipulated in its RH SIP it will continue to coordinate and consult

with the FLMs as required by section 51.308(i)(4). ODEQ states it intends to consult the FLMs 

in the development and review of implementation plan revisions; review of progress reports; and 

development and implementation of other programs that may contribute to impairment of 

visibility at the Wichita Mountains and other Class I areas. 

EPA Findings

We find that ODEQ has satisfied section 51.308(i).