December 16, 2009

Before the

OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY

COMMENTS

of

OKLAHOMA GAS AND ELECTRIC COMPANY

on

REGIONAL HAZE IMPLEMENTATION PLAN REVISION

Proposed by

The State of Oklahoma

Department of Environmental Quality

Draft of November 13, 2009
I. Executive Summary

On November 13, 2009, the State of Oklahoma issued its Draft Regional Haze 

Implementation Plan Revision (the "Revised SIP"). The Revised SIP requires, among other 

things, that Oklahoma Gas and Electric Company ("OG&E") install dry flue gas desulfurization 

technology with a spray absorber system ("Dry FGD" or "scrubbers") to control certain 

visibility-impairing emissions on four coal-fired generating units at OG&E's Muskogee and 

Sooner Generating Stations. Such a requirement is contrary to applicable law as scrubbers 

would not be cost effective on these units under Section 169A of the Clean Air Act. 

Installation of scrubbers also would have a severe financial impact on OG&E, its 

customers and the Oklahoma economy. The installation of scrubbers is projected to cost more 

than $1 billion, which OG&E believes would be among the largest privately funded capital 

investments ever in Oklahoma. Operation and maintenance of the scrubbers would cost even 

more. OG&E estimates that the largest rate increase in its history would be required to recover 

from its customers the capital and operating costs of the scrubbers. Moreover, compelling 

OG&E to install scrubbers is also contrary to a national trend toward reducing carbon dioxide 

(“CO2

The State of Oklahoma should instead implement the alternative proposal submitted by 

OG&E in September 23, 2009 to achieve compliance with regional haze targets for the four 

OG&E units. OG&E’s alternative proposal will ultimately achieve the same visibility 

improvement as set forth in the Revised SIP but in a cost effective manner. OG&E’s proposal 

will also give OG&E the flexibility to generate its power in the future using cleaner energy, such 

as natural gas and wind, that can be obtained from sources within the State of Oklahoma.

”) emissions from these types of facilities. Once OG&E expends more than $1.0 billion to 

install scrubbers, OG&E will be locked economically into maximizing the use of its coal-fired 

units for the foreseeable future.
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II. Introduction

OG&E submits these comments on the Revised SIP, which was drafted by the Oklahoma 

Department of Environmental Quality (“ODEQ”) on behalf of the State of Oklahoma. The 

Revised SIP is fundamentally flawed as it relates to four of OG&E’s coal-fired units located at 

the Muskogee and Sooner Generating Stations. Use of Dry FGD to control sulfur dioxide 

(“SO2

Using first the federally required methodology and, later, a more unit-specific approach, 

OG&E has demonstrated that the costs of Dry FGD at these units is unreasonably high in light of 

the low emission reductions achieved. OG&E urges ODEQ to implement OG&E’s alternative 

proposal for regional haze compliance in the Revised SIP. (OG&E Alternative Regional Haze 

Proposal (September 23, 2009) ("Alternative Proposal"), attached hereto as Ex. 1.)

”) emissions from the four affected units, as called for in the Revised SIP, is not cost 

effective and is not the Best Availability Retrofit Technology (“BART”) for these units.

OG&E’s proposal will ultimately achieve the same improvement in visibility as Dry FGD 

and gives the company flexibility to consider innovative ways to address air emissions from 

these units in the future, including the use of more natural gas and wind derived from sources 

within Oklahoma. 

A. BACKGROUND ON THE REGIONAL HAZE RULE AND BART

Under the authority of the Clean Air Act, the United States Environmental Protection 

Agency (“EPA”) issued the “Regional Haze Regulations and Guidelines for Best Available 

Retrofit Technology Determinations” on July 6, 2005 (the “Regional Haze Rule”). 70 Fed. Reg. 

39,104 (July 6, 2005). The Regional Haze Rule requires that certain states, including Oklahoma, 

develop programs to assure “reasonable progress” toward a national goal of preventing any 

future, and remedying any existing, visibility impairment at nearly 156 federally protected parks 
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and wilderness areas (called “Class I areas”) over an approximately fifty-year period. 42 U.S.C. 

§ 7491.

The Regional Haze Rule further requires that certain sources of air pollutants install 

BART to control regulated emissions. 40 C.F.R. § 51.302. Individual states must submit 

implementation plans to eliminate, by 2064, man-made impacts on visibility in affected Class I 

Areas from sources within that state. The Revised SIP identifies sources that contribute to 

visibility impairment in Class I areas, identifies BART for certain of these units, and develops a 

set of rules for the installation of BART.

Under the Regional Haze Rule, sources that may be required to install BART are those 

sources: (i) that were in existence between August 7, 1962 and August 7, 1977; (ii) that have the 

potential to emit 250 tons or more of a visibility-impairing air pollutant; and (iii) whose 

operations fall within one or more of twenty-six listed categories, including electric power 

generation. 40 C.F.R. §51.302(c)(4)(iii). OG&E has nine sources located at its Seminole, 

Horseshoe Lake,1

B. OG&E’S MUSKOGEE AND SOONER GENERATING STATIONS

Muskogee and Sooner Generating Stations that meet these criteria and were 

therefore subject to BART review. The four coal-fired units at the Muskogee (Units 4 and 5) and 

Sooner (Units 1 and 2) Generating Stations are the primary subjects of this comment.

OG&E’s Muskogee Generating Station is located at 5501 Three Forks Road near 

Muskogee, Oklahoma. This facility has a total of four electric generating units. The two subject 

units, designated as Units 4 and 5, are nominal coal-fired units. Construction of these units 

commenced in the early 1970s with Unit 4 coming on line in 1977 and Unit 5 in 1978. Both of 

these units are dry bottom tangentially-fired pulverized coal boilers and both fire sub-bituminous 

 1

 As set forth in the Revised SIP, air dispersion modeling showed that the BART-eligible units at the 

Horseshoe Lake Generating Station, Units 7 and 8, were exempt from BART. OG&E agrees with this assessment.
- 4 -

coal as their primary fuel. Units 4 and 5 are equipped with electrostatic precipitators ("ESPs") 

for particulate control.

OG&E’s Sooner Generating Station is located at 10800 County Road 230 near Red Rock, 

Oklahoma. The Sooner station includes two nominal coal-fired units designated as Units 1 and 2. 

Both of these units began construction in the mid-1970s with Unit 1 coming on line in 1979 and 

Unit 2 in 1980. Both of these units are dry bottom tangentially-fired pulverized coal boilers. 

Like the Muskogee units, these units fire sub-bituminous coal as their primary fuel and both are 

equipped with electrostatic precipitators for particulate control.

C. OG&E’S COMMENTS ON THE REVISED SIP

As a preliminary matter, BART evaluations conducted for affected units at OG&E’s 

Muskogee, Seminole and Sooner Generating Stations address three types of emissions that have 

the potential to affect visibility—nitrogen oxide (“NOx”), sulfur dioxide (“SO2

OG&E agrees with the Revised SIP on several points. First and with respect to NO

”), and particulate 

matter (“PM”). The Revised SIP contains a number of requirements that address emissions of 

these substances from the various OG&E facilities, but not all of these requirements are the 

subject of this comment. 

x

emissions, ODEQ concludes in the Revised SIP that the installation of low NOx combustion 

technology to minimize the creation of NOx during combustion is BART for affected units at the 

Muskogee, Seminole and Sooner Generating Stations. (Revised SIP, App. 6-4 at lxiv, cxxx, 

clxvi.) Second and with respect to SO2 emissions associated with the three natural gas-fired 

boilers at the Seminole Generating Station (Units 1, 2 and 3), ODEQ concludes that “[b]ecause 

the units fire natural gas, emissions of sulfur dioxide (SO2) and particulate matter (PM) are 

minimal. There are no SO2 or PM post-combustion control technologies with a practical 

application to natural-gas fired boilers. BART is good combustion practices.” (Id., App. 6-4 at 
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cxi.) Third, and with respect to SO2

The Revised SIP, however, also concludes that SO

emissions associated with the four coal-fired boilers at the 

Muskogee (Units 4 and 5) and Sooner (Units 1 and 2) Generating Stations, ODEQ determined 

that wet flue gas desulfurization technology was even more costly than Dry FGD, would achieve 

minimal incremental visibility reductions and was therefore not BART for these units. (Id., App. 

6-4 at lxv, clxviii.) OG&E agrees with the Revised SIP on these points. 

2

In addition to OG&E’s comments with respect to Dry FGD, OG&E also has comments, 

among others, with respect to the following items: (i) PM emissions for the four affected units at 

the Muskogee and Sooner Generating Stations in the absence of Dry FGD; (ii) ODEQ’s 

inclusion in the Revised SIP of a presumptive limit of 0.10 lbs/mmBTU for SO

from four coal-fired units at the 

Muskogee (Units 4 and 5) and Sooner (Units 1 and 2) Generating Stations impair visibility at 

Class I areas and that BART for these units is the installation of Dry FGD. While OG&E does 

not dispute that these units are subject to BART, Dry FGD is not a cost effective control option 

and is therefore not BART for these units. As set forth below, the data shows that Dry FGD is 

extremely expensive and use of this technology on the four affected units will yield low actual 

emission reductions and minimal overall visibility improvement.

2

III. BART Evaluations Show that Dry FGD is Not Cost Effective and Therefore is Not 

BART for the Four Coal-Fired Units at Muskogee and Sooner

control at the 

Muskogee and Sooner units; and (iii) ODEQ's use of an incorrect measure of baseline emissions 

when calculating cost effectiveness at Seminole Generating Station and recent changes in its 

assessment of modeled visibility impacts.

BART evaluations show that Dry FGD is not cost effective and is not BART for SO2

control at the four coal-fired units located at OG&E’s Muskogee (Units 4 and 5) and Sooner 

(Units 1 and 2) Generating Stations. As detailed below, cost effectiveness must be considered in 
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any BART determination and EPA requires that the cost effectiveness analysis be done in 

accordance with the methodology set forth in Appendix Y to 40 C.F.R. Part 51. 

OG&E conducted BART evaluations in May 2008 (the "May 2008 BART Evaluations") 

and in September 2009 (the "September 2009 BART Evaluations") using EPA’s required 

methodology. (See Muskogee Generating Station Best Available Retrofit Technology 

Evaluation (May 6, 2008)2

; Sooner Generating Station Best Available Retrofit Technology 

Evaluation (May 9, 2008)3

; Best Available Retrofit Technology Determination Report for 

Sooner/Muskogee Generating Stations (Sept. 17, 2009), attached hereto as Ex. 2.) Using the 

proper baseline for emissions, these evaluations show that Dry FGD on the Muskogee and 

Sooner units will cost in excess of $10,000 per ton of SO2

Even when OG&E revised its cost calculation methodology in December 2009 to address 

ODEQ’s comments regarding unit-specific costs associated with Dry FGD, the revised 

evaluations show that this technology is expected to cost at least $6,300 per ton of SO

removed. (Ex. 2.) 

2 removed. 

(December 2009 Budget Cost Estimates, attached hereto as Ex. 3.) Either way, these costs are 

unreasonable and far exceed the EPA estimated cost for this technology.4

 2

 Available at http://www.deq.state.ok.us/aqdnew/permitting/applications/2005-271-TVR_M-1/index.htm 

(last visited on December 14, 2009).

3

 Available at http://www.deq.state.ok.us/aqdnew/permitting/applications/2003-274-TVR_M-2/index.htm 

(last visited on December 14, 2009).

4

 In its original draft SIP, circulated on October 5, 2009, ODEQ acknowledged a “maximum cost of 

$5,000 per ton of SO2 or NOx emissions reduced as the upper limit of cost effectiveness” when assessing reasonable 

progress for Wichita Mountains. (Draft Regional Haze Implementation Plan, State of Oklahoma at 102 (Oct. 5, 

2009).) OG&E’s estimated costs for Dry FGD at all four affected units are well above this threshold regardless of 

whether such costs were calculated using EPA’s OAQPS Cost Control Manual or whether they were calculated 

using the more recent unit-specific approach. Moreover, even as to the $5,000 threshold, ODEQ has never 

explained how it arrived at that number, especially in light of EPA’s prior guidance on this issue identifying much 

lower expectations for costs.
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A. ODEQ MUST CONSIDER COST EFFECTIVENESS IN ITS BART DETERMINATION

Before making a BART determination, ODEQ must consider the cost effectiveness of 

any proposed control technology. Section 169A of the Clean Air Act requires that states 

determine the appropriate level of BART control by considering: (i) the costs of compliance; (ii) 

the energy and non-air quality environmental impacts of compliance; (iii) any existing pollution 

control technology in use at the source; (iv) the remaining useful life of the source; and (v) the 

degree of improvement in visibility that may reasonably by expected as a result of such 

technology. The implementing EPA rule is identical. See 40 C.F.R. § 51.308(e)(1)(ii).

EPA’s “Guidelines for BART Determinations Under the Regional Haze Rule” are set 

forth in Appendix Y to 40 C.F.R. Part 51 (“Appendix Y”). The purpose of these Guidelines is to 

help states “identify those sources that must comply with the BART requirement and . . . 

determine the level of control technology that represents BART for each source.” 69 Fed. Reg. 

25,184, 25186 (May 5, 2004). Appendix Y sets out the five basic steps to a BART analysis: (1) 

identify all available retrofit control technologies; (2) eliminate technically infeasible options; (3) 

evaluate control effectiveness of remaining control technologies; (4) evaluate impacts and 

document the results; and (5) evaluate visibility impacts. 40 C.F.R. Pt. 51, App. Y(II)(A).

Step four in the BART analysis establishes the methods to be used in evaluating cost 

impacts. Id. These methods specifically require a cost effectiveness calculation using estimates 

based on EPA’s Office of Air Quality Planning and Standards (“OAQPS”) Cost Control Manual 

“where possible” so that states can “maintain and improve consistency” in making BART 

determinations. 40 C.F.R. Pt. 51, App. Y(IV)(D); 70 Fed. Reg. at 39,166. EPA recently 

affirmed the use of the OAQPS Cost Control Manual for these purposes, stating that: “[t]he Air 

Pollution Cost Control Manual provides guidance and methodologies for developing accurate 

and consistent estimates of cost for air pollution control devices.” 74 Fed. Reg. 44313, 44318 
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(August 28, 2009). Oklahoma incorporates Appendix Y into its visibility protection standards. 

See OAC §§ 252:2-100-8-73; 252:100-8-75.

Not only does Appendix Y establish Guidelines for cost effectiveness determinations, it 

also sets forth “presumptive” BART limits for electrical generating units based on their type and 

size. 40 C.F.R. Pt. 51, App. Y (IV)(E)(4). EPA established presumptive BART for the coalfired units at Muskogee and Sooner as 95% SO2 removal or an emission rate of 0.15 pounds of 

SO2 emissions per million BTUs of heat input (0.15 lb/mmBTU). This presumptive emission 

rate can be achieved with the installation of Dry FGD. For units that are the size of OG&E’s, 

EPA estimates that sources could install Dry FGD at an average cost of $919 per ton of SO2

removed annually with an estimated cost range from $400 to $2,000 per ton of SO2 removed 

annually, and that this would be cost effective under the BART analysis.5

B. BART EVALUATIONS CONDUCTED IN MAY 2008 AND SEPTEMBER 2009 IN 

ACCORDANCE WITH APPENDIX Y SHOW THAT DRY FGD IS NOT COST EFFECTIVE

 See 70 Fed. Reg. at 

39,132. For OG&E’s units, however, the cost of achieving the presumptive rate using Dry FGD 

is at least seven times greater than EPA's projected average cost of installing these controls. 

In accordance with Appendix Y, OG&E followed the Cost Control Manual when 

evaluating the cost effectiveness of Dry FGD in May 2008 and September 2009. In those 

evaluations, OG&E clearly demonstrated that Dry FGD is not a cost effective option for 

controlling SO2

 5

 The emission limit of 0.10 lb/mmBTU for SO2 included in the Revised SIP is significantly more stringent 

than the presumptive limit established for these units by EPA and is not justified. The presumptive limit for these 

units should be 0.15 lbs/mmBTU and this is the subject of the additional comment below in Section VI.

emissions at the Sooner and Muskogee Generating Stations. ODEQ's own cost 

estimates for OG&E's units in the Revised SIP are arbitrary and capricious because they rely on 

general data, such as industry magazines and qualified studies, instead of EPA’s Cost Control 

Manual or even unit-specific information presented by OG&E.
- 9 -

As mentioned above, EPA's Cost Control Manual identifies the procedures and data 

necessary to calculate the cost effectiveness of control technologies on the basis of dollars per 

ton of pollutant removed. Pursuant to Appendix Y, annual emissions resulting from the use of a 

particular control device are subtracted from baseline emissions to calculate tons of pollutant 

controlled per year. See, e.g., OAQPS Cost Control Manual at 2-34 through 2-37. Under EPA's 

Cost Control Manual, total annual cost is calculated by adding annual operation and maintenance 

costs to the annualized capital cost of an option with capital costs consisting of direct costs + 

indirect costs (including capital recovery costs) – recovery credits. See OAQPS Cost Control 

Manual at 2-7. In developing its costs for the Muskogee and Sooner units, OG&E followed the 

procedures established in the Cost Control Manual and also relied on detailed engineering 

estimates, vendor quotations for similar projects and equipment, and data from Sargent and 

Lundy's internal cost database.6

1.

The May 2008 BART Evaluation for Muskogee Units 4 and 5 estimated that the average 

cost effectiveness of Dry FGD at these units was $4,554 per ton of SO

The May 2008 BART Evaluations 

2

 6

 It has been suggested in meetings with EPA and ODEQ that the use of this database is somehow 

questionable because the confidentiality of the information it contains prevents its examination by the agencies and 

the public. As OG&E explains in these comments, numerous public sources of information corroborate the 

estimates derived from the database. In contrast, at a meeting with OG&E on November 3, 2009 and in a 

subsequent letter dated December 9, 2009, EPA representatives mentioned the existence of a recent government 

survey that developed average cost effectiveness information for BART evaluations. As shown in Exhibit 4 of these 

comments, OG&E made several requests to obtain this survey. To date, the survey has not been provided, nor has 

any explanation of the EPA's inability to provide the survey been given.

removed. (May 2008 

BART Evaluation for the Muskogee Generating Station at 51.) These estimated costs are nearly 

five times the average cost projected by EPA for this technology and over twice as much as the 

upper limit of EPA’s projected cost range. The May 2008 BART Evaluation was performed in 

accordance with the requirements of Appendix Y and used the emission factors and cost 
- 10 -

estimates set forth in EPA’s OAQPS Cost Control Manual. The annual cost of Dry FGD at 

Muskogee was estimated to be $142,600,600 for both units. (Id.) Dry FGD was estimated to 

cost approximately $111,900,000 per deciview ("dv") of improvement. (Id. at 55.)

The May 2008 BART Evaluation for Sooner Units 1 and 2 estimated the annual cost of 

Dry FGD to be $4,797 per ton of SO2

2.

removed for both units. (May 2008 BART Evaluation for 

Sooner Generating Station at 49.) These estimated costs are five times the average costs 

projected by EPA for this technology and over twice as much as the upper limit of EPA’s 

projected cost range. This BART Evaluation was done in accordance with the requirements 

prescribed by EPA in Appendix Y and used the emission factors and cost estimates set forth in 

EPA’s OAQPS Cost Control Manual. The annual cost of Dry FGD at Sooner was estimated to 

be $147,045,200 for both units. (Id.) The cost effectiveness of Dry FGD there was estimated to 

be $125,700,000 per dv of improvement. (Id. at 54.)

On September 18, 2009, OG&E submitted the revised BART Evaluations for the affected 

units at Muskogee and Sooner. (September 2009 BART Evaluations, Ex. 2.) These evaluations 

showed average cost effectiveness for Dry FGD to be in the range of $9,842 to $10,004 per ton 

of SO

The September 2009 BART Evaluations

2 removed at Muskogee and $9,625 to $10,843 per ton of SO2 removed at Sooner. (Id.) 

The revised evaluations use actual emissions data to establish an emissions baseline for cost 

effectiveness calculations in accordance with a determination that had recently been made by 

EPA. See 74 Fed. Reg. at 44,321. In August 2009 and in connection with EPA’s review of the 

cost effectiveness analyses for the Salt River Project (“SRP”) Navajo Generating Station in 

Arizona, EPA found that SRP’s use of “the same 24-hour average actual emission rate from the 

highest emitting day used for its modeling inputs” was incorrect. Id. EPA revised SRP’s 
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calculations accordingly “by starting with baseline emission rates for NOX

Using actual baseline emissions instead of the highest modeled baseline emissions in the 

BART Evaluation calculation leads to a more accurate—and higher—cost effectiveness estimate 

for the four coal-fired units at Muskogee and Sooner. In the May 2008 BART Evaluations for 

both Muskogee and Sooner, the baseline emissions were developed from the visibility model that 

uses the highest 24-hour block emissions reported during the baseline period pursuant to the 

Acid Rain Program. As pointed out by EPA, however, using this methodology to calculate 

baseline annual emissions for BART cost effectiveness overestimates actual emissions and does 

not provide a realistic estimate of anticipated annual emissions from each source. In the 

September 2009 BART Evaluations, OG&E instead used its actual annual baseline emissions for 

2004-2006. 

averaged over 2004–

2006 . . . .” Id. EPA’s determination in the SRP context is in line with the agency’s requirement 

that baseline emissions “represent a realistic depiction of anticipated annual emissions for the 

source.” 70 Fed. Reg. at 39,167.

The cost per ton of SO2 removal at Muskogee is high primarily due to OG&E’s use of 

sub-bituminous coal as its main fuel source for Units 4 and 5. This low-sulfur coal (0.20-0.37%) 

already has a low potential for uncontrolled SO2 emissions (0.50-0.86 lb/mmBTU). For Unit 4, 

the average actual annual baseline emissions of SO2 was determined to be 9,113 tons per year, 

with an average SO2 emission rate of 0.507 lb/mmBtu. For Unit 5, the average actual annual 

baseline emissions of SO2 was determined to be 9,006 tons per year, with an average SO2

emission rate of 0.514 lb/mmBtu. This compares with the visibility model values of 17,282 and 

18,362 tons per year, respectively, used for these units in the 2008 report. The combination of 

relatively low baseline SO2 emissions, low baseline visibility impacts (less than 1.5 Δ-dv at all 
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Class I areas), and the distance to the Class I areas all contribute to the high cost effectiveness 

values associated with these units.

OG&E also utilizes sub-bituminous coal as its primary fuel source for Units 1 and 2 at 

the Sooner Generating Station. The average actual annual baseline emissions of SO2 for Unit 1 

was determined to be 9,394 tons per year, with an average SO2 emission rate of 0.509 lb/mmBtu. 

The average actual annual baseline emissions of SO2 for Unit 2 was 8,570 tons per year, with an 

average SO2 emission rate of 0.516 lb/mmBtu. This compares with the visibility model values 

of 17,344 tons per year used for both of these units in the 2008 report. The low baseline 

emissions of SO2

Using Appendix Y and the actual emissions baseline endorsed by EPA results in cost 

effectiveness values for Dry FGD at OG&E’s Muskogee and Sooner units of approximately 

$10,000/ton. This is more than ten times the average cost expected by EPA for this technology 

and nearly five times as much as the upper limit of EPA’s expected cost range. 

at Sooner Units 1 and 2, coupled with the high annualized capital cost for Dry 

FGD, causes the cost effectiveness values for these units to be high in much the same way it did 

for the Muskogee units.

3.

ODEQ acknowledges in the Revised SIP that OG&E's cost estimation methodology 

generally follows EPA's Cost Control Manual. (See Revised SIP, Appendix 6-4 at xlviii, clii.) 

ODEQ also acknowledges the recent guidance from EPA clarifying that sources should use 

actual annual baseline emissions, rather than peak 24-hour emissions from visibility monitoring. 

(See id. at 77-78.) Nonetheless, ODEQ has rejected OG&E's estimates of the cost effectiveness 

of Dry FGD in favor of its own estimates, which are arbitrary and capricious. 

ODEQ Cost Effectiveness Determinations Are Arbitrary and Capricious
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ODEQ inappropriately relies on data from a 2003 National Lime Association Report, 

entitled "Economics of Lime and Limestone for Control of Sulfur Dioxide," and an article in 

Power Magazine, to estimate the capital costs of Dry FGD for OG&E's units. (See Revised SIP, 

App. 6-4 at xlix, cliii.) However, neither resource was designed for use in developing budgetary 

cost estimates for particular units. (See Abstract: Economics of Lime and Limestone for Control 

of Sulfur Dioxide at 1.)7

 As more specifically detailed in Section 2.5 of the December 2009 

Budget Cost Estimate, the National Lime Association Report was not intended to provide the 

basis for a project-specific capital cost estimate. Rather, the purpose of the report is to "compare

costs of leading lime and limestone-based flue gas desulfurization (FGD) processes utilized by 

power generating plants in the United States." (Id.) Moreover, the 2003 National Lime 

Association Report is too outdated to provide useful data for estimating costs in 2009 or beyond. 

Likewise, the Power Magazine article that ODEQ relies on provides only average cost 

information but does not provide any information on cost distribution about the average. (See 

Update: What’s That Scrubber Going to Cost? at 2.) The article explicitly states that that 

“average total installed costs reported by the survey respondents were expected to have wide 

variation . . .”8

Even more importantly, ODEQ's reliance on such materials completely disregards the 

requirements of Appendix Y, which requires states to use EPA’s Cost Control Manual in making 

BART determinations “where possible.” 70 Fed. Reg. at 39,104. OG&E's estimates, on the 

other hand, were developed in accordance with EPA’s Cost Control Manual, as tailored 

specifically to the affected units. It is arbitrary and capricious for ODEQ to disregard these 

 

 7

 Available at http://www.lime.org/FGD/DePriest503.pdf (last visited on December 14, 2009).

8

 Available at http://www.powermag.com/environmental/Update-Whats-That-Scrubber-Going-toCost_1743.html (last visited on December 14, 2009).
- 14 -

estimates and instead rely on general information in industry reports and magazine articles in 

support of its BART determination for the four affected units.

4. The Federal Land Manager's Cost Effectiveness Estimates Are Similarly 

Flawed

Comments on the Revised SIP submitted by the Federal Land Managers ("FLM") on 

December 4, 2009 are similarly flawed. (See U.S. Fish and Wildlife Service (“USFWS”) and 

National Park Service ("NPS") Comments Regarding Oklahoma Draft Regional Haze SIP 

(“FLM Comments”) (Dec. 4, 2009).) The FLM inappropriately relies on a 2007 National Lime 

Association Report and the same Power Magazine article in support of its unfounded assertions 

that Dry FGD is cost effective for OG&E’s affected units. (Id. at Attach., 2.) The FLM’s 

reliance on this material is also arbitrary and capricious and also disregards Appendix Y. 

Like the 2003 National Lime Association Report relied on by ODEQ, the 2007 National 

Lime Association Report that FLM cites was not intended to provide information for the cost of 

Dry FGD at any particular unit. Indeed, the author of that report explicitly "cautions the reader 

that the costs provided herein are not indicative of any cost you may actually achieve." (FGD 

Technology Evaluation: Dry Lime v. Wet Limestone FGD at 2 (March 2007).)9

Not only does the FLM inappropriately rely on generalized data instead of EPA-required 

methodology in reaching its own cost effectiveness numbers, but it also makes unsupportable 

assertions about the data provided by OG&E. In particular, the FLM argues that: (i) 

construction costs will be lower in 2012 than they were from 2007-2008; (ii) Dry FGD will be 

able to achieve a higher reduction efficiency than OG&E recognizes; and (iii) OG&E should 

 The Power 

Magazine article that FLM relies on is likewise inappropriate for the reasons discussed above.

 9

 Available at http://www.lime.org/FGD/FGDTechEvalDryLimevWetLimestoneFGD11311001.pdf (last 

visited on December 14, 2009).
- 15 -

consider whether FGD can be implemented without replacing the existing ESPs with a fabric 

filter to save money. (FLM Comments at Attach., 2-4.) Each of these arguments is problematic.

First, FLM’s conclusion that future construction costs will be lower in 2012 is based 

exclusively on speculation about generalized trends in construction prices. In support of this 

assertion, FLM makes the unsubstantiated claim that "[a]ll of the reasons that caused [FGD] 

construction costs to dramatically escalate in the 2007-2008 period are abating." (Id. at Attach., 

1.) OG&E has developed unit-specific cost estimates that account for fluctuating costs of 

various FGD components. These estimates, which are based on actual data, show that scrubbers 

are not cost effective. 

Second, the removal efficiency presented by FLM is not achievable because FLM has 

failed to account for the already-low sulfur content of OG&E's fuel. The guaranteed efficiency 

of Dry FGD depends on inlet sulfur and the lowest SO2 emission (floor) that will be guaranteed 

by the FGD supplier. FGD suppliers typically have not guaranteed below 94% SO2 removal 

efficiency, or 0.08 lb/mmBtu, whichever is achieved first, at existing units. The low sulfur coal 

used by OG&E makes the lb/mmBtu value the applicable guarantee value. OG&E used 0.10 

lb/mmBtu as the floor for a retrofit application to encompass all FGD suppliers with an 

additional margin of 0.02 lb/mmBtu to overcome system upsets and changes of atomizers. These 

were appropriate measures for estimating the removal efficiency of Dry FGD at OG&E's units, 

and they demonstrate that the removal efficiency presented by FLM is not achievable.10

Third, the use of a baghouse downstream of a Dry FGD system has several advantages 

over using the existing ESPs in conjunction with a Dry FGD, as suggested by FLM. 

 Dry 

FGD suppliers will not guarantee the removal efficiency suggested by FLM.

 10 As discussed later in these comments, OG&E believes the appropriate SO2 emission rate under BART 

for a facility that is required to install a scrubber is 0.15 lb/mmBTU.
- 16 -

Specifically, a Dry FGD/baghouse combination would remove more sulfur and reduce more 

emissions of HC1 and HF than Dry FGD with the existing ESPs. A new baghouse also could be 

completely installed without any tie-in outage. The modifications needed to tie in the existing 

ESPs, on the other hand, would need to take place during an outage, which would increase tie-in 

outage duration and increase power replacement costs. Adding Dry FGD upstream of the 

existing ESP would have yet another disadvantage—the amount of dust loading would increase 

in the ESP and the character of the dust would change, raising concerns about whether Sooner 

and Muskogee could continue to meet emissions limits for particulate matter without major ESP 

modifications.

5. The U.S. Forest Service Lacks Support for its Comment Regarding 

Visibility Improvement Cost Effectiveness at OG&E's Units

The U.S. Forest Service recently submitted comments on the Revised SIP asserting that 

"[a]ll Class I areas within 300 km should be used in the cost analysis to determine the cost per 

deciview of visibility improvement." (Comment Letter from N. Wagoner and J. Henry (Dec. 10, 

2009).)11

As an initial matter, OG&E's units do not cause or contribute to visibility at "all four 

Class I areas" within 300 km, as the Forest Service suggests in its comments. EPA has 

determined that an individual source will be considered to “cause visibility impairment” if

emissions from the source result in a change in visibility, measured as a change in dv's, that is 

 According to the Forest Service, OG&E "did not consider all four Class I areas where 

the Muskogee and Sooner Generating Stations are causing or contributing to visibility 

impairment." (Id.) The FLM also made this same point in its comments. (See FLM Comments, 

at Attach., 3.) In both cases, the comments are flawed.

 11 The Forest Service's comments are available on ODEQ's website at the following address: 

http://www.deq.state.ok.us/aqdnew/RulesAndPlanning/Regional_Haze/us001.pdf. The copy available online 

appears to be incomplete. These responses to the Service's comment are based upon OG&E's interpretation of the 

incomplete copy that is available online.
- 17 -

greater than or equal to 1.0 dv on the visibility in a Class I area. See 70 Fed. Reg. at 39,120. An 

individual source is considered to “contribute to visibility impairment” if its emissions result in a 

dv impairment of greater than or equal to 0.5 dv in a Class I area. Id.

OG&E conducted visibility impact modeling to determine the baseline predicted 

maximum 98th

OG&E calculated average visibility improvement cost effectiveness (in dollars per dv per 

year) for its Muskogee units using the modeled visibility improvement from Dry FGD at the 

Caney Creek Wilderness Area. (See May 2008 BART Evaluation, Muskogee, Table 4-10.) 

OG&E relied on the Caney Creek improvement estimates because modeling indicated that the 

largest dv improvement from scrubbing would occur at Caney Creek. (Id.) When calculating 

average visibility improvement cost effectiveness for the Sooner units, OG&E relied on 

estimates for the nearest Class I area, and the only Class I area where Sooner units cause an 

impact equal to or greater than 0.5 dv—the Wichita Mountains Area.

percentile dv improvement impact from the Muskogee and Sooner units. This 

modeling showed that the Muskogee Station exceeded the 0.5 dv threshold only for the Upper 

Buffalo, Caney Creek, and Wichita Mountains Class I Areas. (May 2008 BART Evaluation, 

Muskogee Generating Station, at 4.) The maximum predicted visibility impact associated with 

the Sooner Station exceeded the 0.5 dv threshold only at the Wichita Mountains Class I Area. 

(May 2008 BART Evaluation, Sooner Generating Station, at 2.)

Providing separate estimates for other Class I areas would not change the ultimate 

conclusion that scrubbers are not cost effective for the Muskogee units. Furthermore, the Forest 

Service and the FLM fail to cite any regulation directing OG&E to combine the visibility 

improvements at numerous Class I areas when calculating average visibility improvement cost 

effectiveness for its units. There is no such requirement. In fact, BART Guidelines specifically 
- 18 -

allow for sources to analyze visibility improvement for the highest-impacted Class I area only. 

40 C.F.R. pt. 51 App. Y(IV)(D)(5) ("If the highest modeled effects are observed at the nearest 

Class I area, you may choose not to analyze the other Class I areas any further . . . ."). Other 

facilities have recognized this and calculated visibility improvement cost effectiveness in a 

manner that is consistent with OG&E's methodology. (See, e.g., Revised BART Analysis for 

GGS, 44 (noting that incremental visibility impairment improvement costs were calculated 

"based on a modeled improvement of visibility impairment . . . at the worst-base Class I area, 

which is the Badlands of South Dakota").)12

C. ADDITIONAL COST ESTIMATES USING MORE SITE-SPECIFIC INFORMATION ALSO 

SHOW DRY FGD IS NOT COST EFFECTIVE

Neither EPA nor ODEQ questioned OG&E’s methodology or its use of EPA’s Cost 

Control Manual between the time OG&E submitted its 2008 reports and the time it filed revised 

emissions baseline information in September 2009. It was only after EPA and ODEQ 

recognized that OG&E’s BART evaluations clearly showed that scrubbers were not cost 

effective that they asked for vendor quotations and other information to validate the 2008 cost 

estimates. Although OG&E’s May 2008 and September 2009 BART Evaluations are valid and 

consistent with EPA requirements, OG&E agreed (at significant cost) to commission a detailed 

engineering study to provide site-specific budget cost estimates for installing scrubbers at the 

four affected units. (December 2009 Budget Cost Estimates, Ex. 3.) These revised cost 

estimates address ODEQ’s and EPA’s concerns that the Cost Control Manual’s factors overstate 

the actual costs of Dry FGD at the Muskogee and Sooner units and confirm that Dry FGD is not 

a cost effective control technology on these units. 

 12 Even if visibility improvements at all Class I areas were included when calculating costs per dv 

improvement, scrubbers still would not cost effective on a dollars-per-dv basis. This is because OG&E's facilities 

are relatively distant from the relevant Class I areas, compared to other facilities, and the costs of scrubbers are high. 

(See Dec. 2009 Budget Cost Estimates, Ex. 3 at 15.)
- 19 -

The December 2009 Budget Cost Estimates again show that Dry FGD is not cost 

effective. Costs range from $6,348 to $7,147 per ton of SO2 removed for Sooner Units 1 and 2 

and from $7,221 to $7,324 per ton of SO2 removed for Muskogee Units 4 and 5.13

The December 2009 Budget Cost Estimates were established using an approach whereby 

OG&E considered over seven hundred individual cost factors associated with the installation of 

Dry FGD at each of the affected units, ranging from the cost of the foundation for a lime storage 

silo to projected overtime for laborers. Operation and maintenance costs as well as 

administrative costs associated with Dry FGD were re-calculated using this approach as well. As 

more specifically set forth in the December 2009 Budget Cost Estimates, OG&E developed its 

estimates for each of these factors using project-specific vendor quotations and through the 

performance of preliminary project engineering. In addition, the December 2009 Budget Cost 

Estimates are based on current and projected capital cost estimates and also take into account 

 (Ex. 3 at 12.) 

For Sooner, the total capital costs of installing Dry FGD at Units 1 and 2 is estimated to be 

$584,589,400. (Id. at 4.) The combined annual cost of Dry FGD for both units at Sooner is 

estimated at $93,664,600 with an average estimated cost of $80,055,214 per dv of improvement. 

(Id. at 15.) For Muskogee, the total capital costs of Dry FGD are expected to be similar to the 

Sooner estimates. Total annual costs of Dry FGD at Muskogee are estimated at $100,280,200 

for both units. (Id.) Even as revised using a unit-specific approach, the estimated costs per ton 

of Dry FGD at these units are roughly seven times the average cost estimated by EPA for this 

technology and three times higher than the upper range of EPA’s estimates.

 13 Although OG&E believes that the Muskogee capital estimates are accurate, a complete estimate for 

these units had not been completed as of the date of this comment. OG&E is working with Sargent & Lundy to 

develop cost estimates for Muskogee in the same level of detail as it did for Sooner. OG&E will provide those 

estimates to ODEQ once they are available.
- 20 -

changed economic conditions since the original estimates were made in May 2008.14

IV. OG&E's Cost Effectiveness Estimates Are Consistent With Other BART Submittals

 Even as 

revised using a unit-specific calculation methodology, the calculations establish that Dry FGD is 

not BART for the affected units at OG&E’s Muskogee and Sooner Generating Stations.

Comparing OG&E’s cost effectiveness estimates for Dry FGD to those of other, similarly 

situated facilities reveals that OG&E’s estimates are correct and that there are numerous 

differences between OG&E’s BART-affected units and those of other facilities. As noted, the 

basic equation for calculating average annual cost effectiveness is to divide the total annual cost 

of a given control technology by the tons per year ("TPY") of SO2 removed through the use of 

that technology (Total Annual Cost / TPY Removed). In this calculation, a higher number for 

TPY removed lowers the cost per ton of SO2

OG&E’s estimates of the costs per ton of installing Dry FGD at Sooner and Muskogee 

Generating Stations are higher than those of facilities operated by other companies. This is so 

largely because a variety of factors combine to increase the TPY removed from Dry FGD at 

other facilities well beyond the TPY removed at OG&E’s units. Furthermore, the total annual 

costs estimated by OG&E in its BART Evaluations and subsequent site-specific budget cost 

estimate were appropriate for OG&E's units and are consistent with similar estimates for other 

removed, thereby improving cost effectiveness. 

Moreover, unique and facility-specific conditions can lead to differences in the total annual costs 

portion of the cost effectiveness equation.

 14 Although OG&E’s December 2009 Budget Cost Estimates reflect ODEQ’s (and the FLM’s) assumption 

that the costs associated with installing Dry FGD have decreased since 2008, construction costs are difficult to 

predict. For example, on November 25, 2009, American Municipal Power Inc. announced that it was suspending 

development of a coal-fired generating station in Ohio based on a recent and unexpected 37% increase in 

engineering, procurement and construction costs associated with the project. See

http://www.cleveland.com/business/index.ssf/2009/11/american_municipal_power_will.html (last visited on 

December 15, 2009). Furthermore, if a revised CAIR regulation is released in 2010, the Dry FGD market could see 

escalations based on increased market demand.
- 21 -

facilities. Like other facilities' estimates, the OG&E estimates were based on the OAQPS Cost 

Control Manual. Even as supplemented with the site-specific Budget Cost Estimates in 

December 2009, OG&E's Evaluations show the costs of Dry FGD per ton of SO2

A. DRY FGD RESULTS IN LOWER TPY REMOVED FOR OG&E’S UNITS COMPARED TO 

OTHER FACILITIES WITH LOWER COSTS PER TON

reduced at 

OG&E's units far exceed the costs per ton accepted by other facilities.

At least four factors affect any calculation of TPY removed through the use of a 

particular control technology on an electric generating unit: (1) the size of the unit; (2) the sulfur 

content of its fuel; (3) the unit's actual SO2-emitting history; and (4) the measure used for 

calculating the unit’s baseline annual emissions. Units with larger MW ratings and heat input 

capacities burn more coal per hour, which means there is more SO2 to remove through the use of 

Dry FGD at those units. The same is true for the next two factors—more SO2 is produced from 

the combustion of coal with higher sulfur content, and a unit's dispatch requirements will 

determine how often it operates and thus how much SO2

In OG&E’s case, all four factors contribute to the TPY removed from scrubbing at 

Sooner and Muskogee being roughly 35% to 75% lower than the estimated TPY removed 

through scrubbing at other facilities. Exhibit 5 shows how some of these factors relate to the 

TPY removed and the cost effectiveness of Dry FGD for OG&E's units, as compared with White 

Bluff Units 1 and 2, Nebraska City Station ("NCS") Unit 1, Gerald Gentleman Station ("GGS") 

Units 1 and 2, Boardman Power Plant Unit 2, and AEP's Northeastern Power Plant. In preparing 

Exhibit 5, OG&E selected facilities that were of roughly the same size as OG&E’s units and that 

do not already use scrubbers as an existing control technology.

is actually emitted. Finally, using an 

emissions baseline that overstates actual baseline emissions also will overestimate the TPY 

removed from Dry FGD.
- 22 -

The first factor affecting TPY removed is the size of a unit. Compared to OG&E’s units, 

all of the other facilities shown in Exhibit 5 except Northeastern burn more coal per hour as 

evidenced by their higher MW ratings and heat input capacities. Not surprisingly, these other 

facilities also have higher estimates of the TPY removed from Dry FGD.15

The second factor affecting TPY removed is the sulfur content of the fuel utilized by a 

unit. The facilities shown in Exhibit 5 use coal with higher sulfur content than the coal used by 

OG&E. OG&E uses coal with a sulfur content ranging from 0.5 to 0.86 lb/mmBtu (0.20 - 0.37% 

sulfur by weight). White Bluff, for example, used a much higher sulfur content for its coal—2.0 

lb/mmBtu for Dry FGD (0.87% sulfur by weight). (See Revised BART Analysis for the White 

Bluff Steam Electric Station (Aug. 2008), at 3-5.) Using fuel with higher sulfur content 

contributes to more TPY removed.

 

The third factor contributing to higher TPY removed at other facilities is higher 

utilization. In its BART analyses, OG&E used actual, measured SO2 emissions from its units to 

estimate TPY removed and, ultimately, the cost effectiveness of Dry FGD. These emissions 

necessarily reflect the actual dispatch requirements for a unit over the course of an entire year, 

including outages for repair and maintenance. NCS Unit 1 and GGS, on the other hand, assumed 

100% utilization when calculating TPY removed even though the BART determinations for NCS 

Unit 1 and GGS expressly note that a capacity factor of 100% overstates TPY removed. (See

Revised BART Analysis for GGS at 15 (Table 3); BART Analysis for NCS 1 at 12 (Table 2).)16

 15 Note that any differences in assumed control efficiency for Dry FGD are not large enough to 

significantly affect the overall cost effectiveness comparison for OG&E. The FLM, for example, recently 

recommended that a BART limit of 0.065 lb/mmBtu should be assumed for scrubbing at OG&E's Muskogee units, 

rather than 0.10 lb/mmBtu as assumed by OG&E, on the grounds that Dry FGD can achieve a higher control 

efficiency than OG&E recognizes. As noted above, the control efficiency recommended by FLM is not appropriate 

for OG&E's units. Even if it were, however, the difference between 0.10 lb/mmBtu and 0.065 lb/mmBtu would 

account for just a few additional TPY removed at OG&E's units. Even with the FLM's limit, Dry FGD would still 

result in much lower TPY removed for OG&E's units and much higher costs per ton compared to other facilities.

16 Available at http://www.deq.state.ne.us/AirDivis.nsf/Pages/Haze (last visited on December 14, 2009).
- 23 -

Finally, using the wrong measure of baseline emissions can overstate TPY removed, 

thereby leading to unrealistically low estimates of cost per ton removed. As explained above, 

federal regulations and EPA’s own practice establish that cost-effectiveness should be based on 

actual emissions. In the preamble to the BART Guidelines at Appendix Y, 40 C.F.R. Pt. 51, 

EPA explained that a “baseline emissions rate should represent a realistic depiction of 

anticipated annual emissions for the source.” 70 Fed. Reg. at 39,167. Therefore, EPA noted that 

“in general, . . . you will estimate the anticipated annual emissions based upon actual emissions 

from a baseline period.” Id. EPA recently again made this point when revising cost 

effectiveness calculations for the SRP's Navajo Generating Station to incorporate baseline 

emission rates averaged over a three year period. See 74 Fed. Reg. at 44,321. 

In addition to these differences and contrary to EPA’s regulations and clearly stated 

practice, all of the facilities shown in Exhibit 5 relied on some type of inflated measure of 

baseline emissions. OG&E also made this error in its original BART Evaluations for Sooner and 

Muskogee in May 2008. OG&E has since corrected the error by submitting the revised 

September 2009 BART Evaluations that rely on average actual emissions from the baseline 

period (as did EPA for the Navajo Generating Station). Other facilities have not made this same 

adjustment.

Overall, it makes sense that OG&E’s estimates of the TPY removed from scrubbing are 

significantly less than the estimates developed for other facilities with larger units that are 

running harder, burning higher sulfur-content coal and using inflated measures of baseline 

emissions. The higher estimates of TPY removed at those other facilities also drives down their 

estimates of the cost per ton of Dry FGD.
- 24 -

B. IN ITS MAY 2008 AND SEPTEMBER 2009 BART EVALUATIONS, OG&E FOLLOWED 

THE SAME GENERAL APPROACH FOR ESTIMATING THE TOTAL ANNUAL COSTS OF 

DRY FGD AS OTHER FACILITIES

The May 2008 BART Evaluations contain reasonable estimates of the total annual cost of 

Dry FGD at Muskogee and Sooner. The same is true of the September 2009 BART Evaluations, 

which also reflect the appropriate measure of baseline emissions. As described previously, 

OG&E developed its cost estimates based on the EPA Cost Control Manual, engineering 

estimates, vendor quotes from similar projects and equipment, and Sargent and Lundy's internal 

cost database. Data was selected from these sources based on its appropriateness for use in 

estimating OG&E’s costs for Dry FGD. 

Other facilities used this same basic approach to estimate the total annual costs of 

installing and operating Dry FGD on their BART-eligible units. (See, e.g., BART Analysis for 

NCS Unit 1 at 7-8 (Aug. 2007) (estimates were generally based on data from EPA’s Cost 

Control Manual, with supplemental information provided from 2003 vendor-supplied quotations 

and general engineering estimates)17; Revised BART Analysis for GGS at 8-9 (Feb. 2008) 

(estimates based on EPA's data as refined through site-specific conceptual layouts and vendor 

budgetary quotes for major equipment costs).)18

Neither EPA nor ODEQ has suggested that OG&E's methodology in calculating cost 

effectiveness based on EPA's Cost Control Manual was incorrect. Instead, ODEQ has made the 

more general assertion that OG&E’s costs seem high in comparison to the cost estimates offered 

by other facilities. (See Revised SIP, Appendix 6-4 at xlix, cliii.) These general assertions serve 

 

 17 Available at 

http://www.deq.state.ne.us/AirDivis.nsf/23e5e39594c064ee852564ae004fa010/c03ae6a45b1e105286257443006512

d5/$FILE/BART%20Analysis%20for%20NCS%20Unit%201.pdf (last visited December 15, 2009).

18 Available at 

http://www.deq.state.ne.us/AirDivis.nsf/23e5e39594c064ee852564ae004fa010/c03ae6a45b1e105286257443006512

d5/$FILE/Revised%20BART%20Analysis%20for%20GGS%20Units%201%20and%202.pdf (last visited on 

December 15, 2009).
- 25 -

little purpose. As shown in Exhibit 5, OG&E’s total annual costs from its May 2008 Evaluations 

are only $3,000,000 to $6,000,000 higher than the estimated total annual costs of installing and 

operating Dry FGD on Units 1 and 2 at White Bluff. This difference can be accounted for 

through the combination of a variety of source-specific factors. It is clear that the costs projected 

by OG&E for its units are in the same general range as the costs actually projected at other 

facilities. As shown by the site-specific budget cost estimates, variations in the total annual cost 

of as much as 25% will not change the cost effectiveness determination.

C. NEW SITE-SPECIFIC BUDGET COST ESTIMATES VALIDATE THE CONCLUSION THAT 

SCRUBBERS ARE NOT COST EFFECTIVE.

To address comments from ODEQ and EPA, OG&E obtained the site-specific Budget 

Cost Estimates in December 2009. (Ex. 3.) Those estimates depart significantly from the 

methods in EPA's Cost Control Manual for determining costs associated with projected 

operations at the four coal-fired units at Sooner and Muskogee Generating Stations. While 

OG&E believes that ODEQ and EPA lacked any basis to require OG&E to depart from the 

published methodology for calculating costs, the site-specific Budget Cost Estimates nonetheless 

confirm that Dry FGD is not a cost effective option for OG&E's units. Exhibit 5 shows the costs 

per ton of Dry FGD are still significantly higher than the costs per ton accepted by other facilities. 

According to the site-specific estimates, the costs per ton of Dry FGD at OG&E's units exceed 

the costs per ton of Dry FGD at the other facilities shown in Exhibit 5 by roughly $3,000 -

$5,000 per ton.

V. OG&E’s Alternative Proposal Offers a Cost Effective and Better Way to Achieve 

the Same SO2 Emission Reductions
- 26 -

In September 2009, OG&E offered a cost effective Alternative Proposal to achieve 

compliance with the Regional Haze Rule as it relates to the four coal-fired units at OG&E’s 

Muskogee and Sooner Generating Stations. (Ex. 1.) The Alternative Proposal offers a cost 

effective approach to achieving the same level of emission reductions as would the installation of 

Dry FGD. Moreover, OG&E’s September 2009 Proposal gives the company the flexibility to 

implement innovative technologies to control emissions from these units and meet future air 

standards. For these reasons, ODEQ should adopt OG&E’s September 2009 Alternative 

Proposal in the Revised SIP.

A. OG&E’S ALTERNATIVE PROPOSAL

On September 23, 2009, OG&E submitted its Alternative Proposal for achieving 

“reasonable progress” in Oklahoma under the Regional Haze Rule. (Ex. 1) This proposal, which 

would be implemented in three steps, is based on incremental lowering of SO2 emissions from 

the four affected units at the Muskogee and Sooner Generating Stations. Upon implementation

of the first step, the affected units would not “cause” a visibility impact in a Class I area. Upon 

implementation of the second step, the units would not “contribute” to such an impact. 

Ultimately, OG&E proposes to lower its SO2

As more specifically detailed in Exhibit 1, the three steps that OG&E proposes to achieve 

these emission reductions are as follows:

emissions to achieve the same level of visibility 

improvement as would be achieved by the installation of Dry FGD. OG&E believes that, if 

adopted, this proposal would demonstrate compliance with the Regional Haze Rule in a cost 

effective manner.

1. OG&E proposes to limit its SO2 emissions to levels such that operation of 

the affected units will not “cause” a visibility impact in a Class I area beginning on the earlier of 
- 27 -

January 1, 2016, or four years after SIP approval. By this time, OG&E would limit SO2

emissions from all four affected coal-fired units to 0.65 lb/mmBtu on a 30-day rolling average 

basis and 0.55 lb/mmBtu on a 365-day rolling average. In addition, OG&E would accept 

enforceable annual SO2 emission limits from the Sooner and Muskogee units (combined) as set 

forth in the table below. These limits represent an emissions decrease from emissions used in the 

visibility model of up to 46% for Sooner and of up to 65% for Muskogee. 

Muskogee 4 and 5 

Combined Annual 

SO2 Limit 

(tons/year)

Sooner 1 and 2 

Combined Annual 

SO2 Limit 

(tons/year)

Year 1 18,096 19,736

Year 2 16,635 19,318

Year 3 15,174 18,900

Year 4 13,713 18,482

Year 5 12,252 18,064

2. OG&E proposes to limit its emissions consistent with modeled emission 

impacts that do not cause or “contribute to” visibility impairment in a Class I Area beginning on 

the earlier of January 1, 2021, or nine years after SIP approval. By this time, OG&E would limit 

SO2 emissions from the combined units at Sooner and Muskogee to 17,646 and 12,064 tons per 

year, respectively. These limits represent an emissions decrease of 48% for Sooner and 66% for 

Muskogee compared to the emissions used for visibility modeling. OG&E would also continue 

the SO2

3. Beginning on the earlier of January 1, 2026, or fourteen years after SIP 

approval, OG&E would limit annual SO

rolling average emission rates. 

2 emissions from the combined units at Sooner and 

Muskogee to 6,000 tons per year and 4,40019

 19 The limit of 4,400 tons per year is a slight increase over the limit of 4,000 tons per year included in the 

September 2009 Alternative BART Proposal. The limit originally stated in the proposal was not consistent with the 

emission rate suggested in the May 2008 BART Evaluation for the installation of Dry FGD. The revised limit is 

consistent with the May 2008 BART Evaluation.

tons per year, respectively. This limit represents an 
- 28 -

emissions decrease of 82% for Sooner and 88% for Muskogee compared to the emission rates 

used for visibility modeling—the same limit as would be achieved by installing Dry FGD on all 

four units.

OG&E’s Alternative Proposal also offers the company flexibility for cost effective 

compliance. OG&E would have the ability to propose alternative emission limits that achieve 

the same improvement in modeled visibility impacts as the proposed limits. If OG&E believes 

the emission limits cannot be achieved cost effectively, OG&E could then ask ODEQ to approve 

alternate limits. In the absence of such explicit approval, however, OG&E would be obligated to 

comply with the already established limits.

B. OG&E’S ALTERNATIVE PROPOSAL GIVES OG&E FLEXIBILITY TO MEET FUTURE 

AIR STANDARDS

The approach proposed by OG&E in September 2009 would also give the company 

flexibility to employ innovative technologies developed over the life of OG&E’s compliance

obligations to control emissions from the four affected units and to meet future air standards. 

OG&E’s proposal would allow the company the option to reduce SO2

OG&E believes that it is prudent to anticipate that state and federal requirements 

regulating air emissions from coal fired electrical generating stations—including Maximum 

Achievable Control Technology standards and climate change legislation—will become effective 

in the next five to ten years. It is likely that these requirements will impact the economic and/or 

technical feasibility of particular emission controls on the affected units. OG&E’s proposal will 

not only meet the requirements of the Regional Haze Rule for SO

emissions in a variety of 

ways, including by the increased use of natural gas and wind generation, the installation of 

emission controls, or reducing coal combustion. The flexibility offered by this approach will 

allow OG&E the option to use local sources of energy thereby benefiting the State economy.

2 emissions, but will give 
- 29 -

OG&E the flexibility to employ innovative technology (including the use of alternative fuels) to 

meet future air requirements with respect to other emissions as well. 

In addition, if Dry FGD is required, OG&E anticipates that it will be difficult for the

company to obtain a construction permit for the scrubbers under the Prevention of Significant 

Deterioration (“PSD”) tailoring rule for greenhouse gas emissions. It will take a significant 

amount of additional power to operate any scrubbers installed at the affected units. This power 

would be generated by burning additional fuel, which would likely increase greenhouse gas 

emissions (including CO2

Moreover, at a time when so much effort and attention in the environmental community 

is focused on reducing the use of coal, ODEQ’s approach effectively compels OG&E to continue 

using coal to fuel these units for the foreseeable future. The installation, operation and 

maintenance of Dry FGD involves such a large capital investment—more than $1 billion within 

five years—that OG&E will have no choice but to continue to utilize coal as its primary source 

of fuel for a long time to come. Currently, OG&E fuels its units at Muskogee and Sooner with 

coal that is mined in Wyoming and shipped via rail. The State of Oklahoma has excellent 

resources for generating electricity with natural gas and wind. OG&E should have the flexibility 

to utilize these local energy sources at its plants in the future, while achieving the same reduction 

in impact on visibility.

emissions) from the unit being scrubbed. It is unclear whether EPA 

would even issue OG&E a PSD permit under the current rules to cover these emissions. 

OG&E’s alternative proposal does not present this issue.

OG&E’s economic interests would arguably be better served by acquiescing to the 

Revised SIP. Under state law, OG&E would be entitled to charge its customers for its operating 

costs and capital costs for the scrubbers and to earn a return on the capital costs of the scrubbers. 
- 30 -

However, this would require the largest rate increase in history for OG&E’s customers. If 

ODEQ adopts OG&E’s alternative proposal, any increased costs associated with using natural 

gas to generate electricity rather than coal will be recovered by OG&E on a dollar for dollar 

basis under its various fuel adjustment clauses and OG&E would not earn a return on these 

additional costs.

VI. Other Comments

A. IF SCRUBBERS ARE NOT REQUIRED, ESP IS BART FOR PARTICULATE MATTER 

EMISSIONS

The affected units at the Muskogee and Sooner Generating Stations are currently 

equipped with ESPs, and assuming that scrubbers are not required, the continued use of ESP is 

BART for PM control at these units. In the Revised SIP, ODEQ concludes that PM emissions 

are to be controlled by a fabric filter that is “integral to the design of the Dry FGD.” For the 

reasons set forth herein, however, Dry FGD is not BART for these units. In the absence of Dry 

FGD, ESPs offer a cost effective approach to PM control.

In its May 2008 BART Evaluations for both Muskogee and Sooner, OG&E determined 

that baghouses would provide only an incremental reduction in PM/PM10 control compared to 

the existing ESP control systems.20

 20 This discussion assumes that scrubbers are not installed. As discussed above, scrubbers would create 

additional particulate emissions compared to current operations and baghouses would be needed to achieve effective 

control if scrubbers are installed.

 Even without operation and maintenance costs and using 

higher baseline emissions, OG&E estimated the total capital costs of a retrofit baghouse system 

to be $104,000,000 per unit. Due to the high capital cost and the very low particulate emission 

reduction over ESP, the cost effectiveness for such a system would be well over $18,000 per ton 

of PM removed even without considering operations and maintenance costs. Adjusted to 

account for EPA’s guidance on the use of average baseline emissions, this number would 
- 31 -

inevitably rise even higher. Accordingly, continued use of ESP for PM control is BART for 

these units assuming that scrubbers are not required, and currently permitted PM emission limits 

should apply.

B. THE REVISED SIP SHOULD REFLECT A PRESUMPTIVE LIMIT OF 0.15 LBS/MMBTU

FOR SO2

As discussed above, OG&E has presented an Alternative Proposal for making reasonable 

progress to address regional haze in a cost effective manner. Even if ODEQ ultimately does not 

accept that proposal, ODEQ must at least apply the EPA-established BART presumptive 

emission limit of 0.15 lb/mmBTU—and not its own significantly lower limit of 0.10 

lb/mmBTU—for the Muskogee and Sooner units in its Revised SIP. Appendix Y sets forth the 

“presumptive standards [for these units that] were developed through a formal rulemaking 

process.” 70 Fed. Reg. at 44,159. EPA has established that states “must require owners and 

operators of greater than 750 MW power plants to meet these BART emission limits.” 70 Fed. 

Reg. at 39,131. Indeed, these “presumptive standards are ‘mandatory’ [and] must be applied” 

unless a source demonstrates that it would not be cost effective to apply these standards. 71 Fed. 

Reg. at 60,619; see also EPA Regulatory Impact Analysis for the Final Clean Air Visibility Rule, 

EPA-452/R-05-004 (June 2005).

CONTROL

EPA’s perspective on the use of these presumptive limits is informed by Congressional 

intent. In discussing Section 169A(b)(1) of the Clean Air Act, which required the establishment 

of presumptive BART, the agency notes: “This statutory requirement clearly requires us to 

promulgate [presumptive] BART guidelines that the States must follow in establishing BART 

emission limitations for [over-750MW] power plants. ... [T]he Act indicates that Congress 

intended the guidelines to be mandatory ... with respect to 750 megawatt powerplants.” 70 Fed. 

Reg. at 39,108. Hence, the Act’s “unambiguous language leaves little room to dispute that the 
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[presumptive BART] guidelines EPA is required to promulgate must be used by the states when 

making BART determinations for this class of sources.” Id.

Presumptive limits of 0.15 lb/mmBTU established by EPA apply to each of the four coalfired units at the Muskogee and Sooner Generating Stations. Accordingly, any BART 

determination for these units must be evaluated against this benchmark and not against the more 

stringent 0.10 lb/mmBTU benchmark used by ODEQ in the Revised SIP.21

C. OG&E RESERVES THE RIGHT TO COMMENT ON OUTSTANDING ISSUES 

CONCERNING THE BART DETERMINATION FOR SEMINOLE AND ODEQ'S 

ASSESSMENT OF VISIBILITY IMPACTS AT OG&E FACILITIES

On October 27, 2009, ODEQ issued Draft Permit to Operate No. 2003-400-TVR (M-1) 

for the Seminole Generating Station ("Draft Permit") along with a Memorandum explaining 

ODEQ's analysis of the corresponding permit application submitted by OG&E. OG&E 

submitted comments on the Draft Permit and ODEQ's Memorandum on November 5, 2009. 

OG&E's comments, attached hereto as Exhibit 6, raise two important issues that have not yet 

been resolved.

First, the current cost effectiveness estimates for the Seminole Generating Station are 

based on an incorrect measure of baseline emissions. (Ex. 6 at 21.) The May 2008 BART 

Evaluation for Seminole calculated baseline emissions according to the highest 24-hour actual 

emissions reported under the Acid Rain Program, rather than the annual average of actual 

emissions over the baseline period as required by EPA. As noted, OG&E made this same error 

 21 ODEQ proposed a BART limit of 0.15 lb/mmBTU for AEP/PSO Northeastern Power Station Units 3 

and 4 which are also coal-fired. There is no rational basis for applying limits to OG&E’s units that are different 

from the limits proposed for the AEP/PSO Northeastern Power Station units. (Revised SIP at p. 73.) With respect 

to PM10, the Revised SIP proposes an emission limit of 0.1 lb/mmBTU for the AEP/PSO Northeastern Power 

Station units in contrast to a proposed emissions rate of 0.015 lb/mmBTU for OG&E’s units. OG&E believes that 

ODEQ does not have any rational basis for proposing different limits for these units. (Id.)
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in its May 2008 BART Evaluations for Sooner and Muskogee Generating Stations but corrected 

the error when submitting the September 2009 BART Evaluations. 

OG&E has not made a second, revised submission of cost effectiveness estimates for the 

Seminole Generating Station because ODEQ arrived at a reasonable BART determination for 

Seminole, notwithstanding the use of an incorrect emissions baseline. Nevertheless, OG&E 

continues to believe that the BART Determination for Seminole is contrary to EPA's regulations 

and guidance concerning the appropriate measure of baseline emissions when calculating the 

cost effectiveness of a control option. BART determinations should be made according to the 

EPA-required methodology.22

The second issue raised in connection with ODEQ's Draft Permit for Seminole deals with 

ODEQ's assessment of visibility impacts from Seminole. In its Memorandum accompanying the 

Draft Permit, and without prior discussions with OG&E on the topic, ODEQ provided estimates 

of visibility improvements expressed in Δ-dv and percentages that did not match the estimates in 

OG&E's May 2008 BART Evaluation. (Ex. 6 at 24.) ODEQ apparently decided at some point 

to use a different method for averaging modeled visibility impacts over the three-year baseline 

period based. Further consultation with ODEQ on this point is needed, and OG&E reserves the 

right to comment on ODEQ's new assessments for Seminole and any of the other facilities for 

which ODEQ has revised its assessments, once sufficient information on those revisions is made 

available to OG&E. 

D. ODEQ’S ADOPTION OF THE REVISED SIP RAISES QUESTIONS REGARDING 

COMPLIANCE WITH THE OKLAHOMA ADMINISTRATIVE PROCEDURES ACT

 22 The data needed to develop the correct emissions baseline for the Seminole Generating Station is 

available on EPA's Clean Air Markets webpage at 

http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=emissions.wizard (last visited on December 15, 2009).
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ODEQ proposes to adopt the Revised SIP for the purpose of implementing the BART 

rule (OAC 252:100-8, Part 11). See Regional Haze Implementation Plan Revision, dated 

11/13/09, at 1-3. However, in doing so, ODEQ apparently does not intend to comply with the 

Oklahoma Administrative Procedures Act (“OAPA”). OG&E urges ODEQ to consider carefully 

whether its intended process effectively complies with the OAPA in implementing and revising 

an existing Rule and in prospectively setting policy for the State of Oklahoma that goes beyond 

determining BART controls for individual facilities. See, e.g., 75 O.S. § 250.3(15); 75 O.S. § 

302(D). The procedural requirements of the OAPA are designed to protect the due process rights 

of citizens who may be affected by agency actions, either through rulemaking procedures or 

individual proceedings where an affected party may present evidence and argument, and to the 

extent ODEQ adopts the Revised SIP and imposes the substantial costs on OG&E contemplated 

therein without the procedural safeguards contemplated by the OAPA, OG&E’s rights would 

unquestionably be prejudiced. In the event ODEQ desires a specific request for an individual 

proceeding, OG&E requests such a proceeding prior to the final adoption of Dry FGD as the 

BART requirement applicable to the Muskogee and Sooner units.

VII. Conclusion

For the reasons set forth above, the State of Oklahoma should modify the Revised SIP by 

removing the requirement that OG&E install Dry FGD on four coal-fired units at its Muskogee 

and Sooner Generating Stations. The State should instead adopt the alternative proposal 

submitted to ODEQ by OG&E on September 23, 2009. The alternative proposal ultimately 

achieves the same degree of visibility reduction as Dry FGD, is cost effective, and offers OG&E 

the flexibility to use local, cleaner energy sources to generate electricity in the future.

Respectfully Submitted,
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______________________________________

Ford Benham

Air Quality Supervisor

Oklahoma Gas and Electric Company

321 N. Harvey

Oklahoma City, Oklahoma 73102