Response to Technical Comments for Sections E. through H. of the 

Federal Register Notice for the Oklahoma Regional Haze and Visibility 

Transport Federal Implementation Plan 

Docket No. EPA-R06-OAR-2010-0190 

12/13/2011 
Table of Contents 

Introduction ....................................................................................................1 

I. Comments Related to our SO2 BART Cost Evaluation ..............................................1 

II. Comments Relating to Our SO2 BART Emission Limit ..........................................91 

III. Comments Related to the SO2 BART Compliance Timeframe ................................107 

IV. Visibility Improvement Analysis Comments .....................................................111 

List of Tables 

Table 1 - Economies Of Scale Fabric Filter Baghouse Capital, Engineering & Construction 

Costs Estimated by S&L IPM Model for SDA/FF ........................................... 4 

Table 2 - Average Entergy Day-Ahead Price for On-Peak and Off-Peak ........................... 44 

Table 3 - Average Capacity Factor for OG&E Units ................................................... 61 

List of Figures 

Figure 1 – Sooner Plant, OK, Average Sulfur Content Per Coal Fuel Receipt, 

Jan 2004 – Dec 2010 .......................................................................... 50 

Figure 2 – Muskogee Plant, OK, Average Sulfur Content Per Coal Fuel Receipt, 

Jan 2004 – Dec 2010 ........................................................................... 50 

Figure 3 – Muskogee Unit 4 Monthly Average SO2 Emissions and Coal Sulfur .................. 51 

Figure 4 – Muskogee Unit 5 Monthly Average SO2 Emissions and Coal Sulfur .................. 52 

Figure 5 – Sooner Unit 1 Monthly Average SO2 Emissions and Coal Sulfur ...................... 52 

Figure 6 – Sooner Unit 2 Monthly Average SO2 Emissions and Coal Sulfur ...................... 53 

Figure 7 – TS Power Plant (NV) SO2 Emission Rate lb/MMBtu .................................... 96 

Figure 8 – Wygen II (WY) SO2 Emission Rate lbs/MMBtu ..........................................97 

Figure 9 – Weston Unit 4 (WI) SO2 Emission Rate lb/MMBtu ....................................... 98 

List of Attachments 

Attachment 1 - Sargent & Lundy Fabric Filter IPM Model Study 

Attachment 2 - Sargent & Lundy SDA IPM Model Study 

Attachment 3 -Revised Cost Effectiveness Analyses for Dry Flue Gas Desulfurization at Sooner 

Units 1 and 2 and Muskogee Units 4 and 5 

i 
Introduction 

This document contains a partial listing of responses to comments received as a result of 

our proposed Oklahoma Regional Haze and Visibility Transport Federal Implementation Plan 

(76 FR 16168), published in the Federal Register on March 22, 2011. It is intended as a 

supplement to our final rule. The responses to comments contained herein represent those issues 

that were deemed to be too complex or lengthy for direct inclusion into our final rule. Those 

issues include our SO2 BART Cost Evaluation, our SO2 BART Emission Limit, and our SO2

BART Compliance Timeframe for the six Oklahoma Gas and Electric (OG&E) and American 

Electric Power/Public Service Company of Oklahoma (AEP/PSO) units. Of these, those 

comments and responses that impacted our final decision have been summarized in our final 

rule. Although we responded to all the comments we received, some groups expressed support 

for or otherwise endorsed the comments submitted by the utility owners, OG&E and AEP/PSO, 

who are subject to the BART SO2 FIP. In those cases, although we attribute the comment to the 

utility commenter, both the comment and our response apply to all parties. 

I. Comments Related to our SO2 BART Cost Evaluation 

Comment: OG&E states that we incorrectly suggest that the OG&E BART analysis 

"made no apparent effort to minimize costs and overlooked many obvious opportunities to lower 

costs, including factoring in capital cost reductions due to multiple identical units, use of 

common facilities, use of existing equipment, and consideration of other scrubbing options." 

According to OG&E, to attempt to account for these supposed opportunities to lower costs, we 

arbitrarily assumed that: (1) vendors would offer a 5% discount on equipment costs for multiple 

identical units and large unit operations, thereby incorrectly reducing the capital costs by 5%; 

and (2) designing the control system to use common facilities (e.g., single lime preparation and 

ash handing systems, and/or a single fabric filter) would reduce equipment, material, and labor" 

costs by an additional 5%, thereby reducing the costs by an extra 5%. EPA' provides no support 

that these cost savings could be achieved. 

OG&E states that the vendor quotes already include any potential discounts on capital 

costs for multiple units. Sargent and Lundy (S&L) based the 2009 Cost Estimate on budgetary 

quotes supplied by equipment vendors for the major pieces of equipment - the scrubber vessel 

fabric filter baghouse, reactant handling and preparation system, and ash handling systems. To 

obtain those budgetary quotes, equipment vendors were provided with plant design data sheets 

for all of the generating units, which included a general description of each unit, boiler size, fuel 

specifications mass balances, flue gas volumes and temperatures. Therefore, states OG&E, 

vendors providing estimates were already aware of opportunities for quantity and size discounts 

and of the general design that, to the extent supported by the engineering data, could allow the 

potential use of common facilities. 

In conclusion, OG&E claims we had no basis to assume the budgetary quotes in the 

December 2009 Budget Cost Estimates did not already reflect the multiple units or to arbitrary 

reduce capital costs by 5% for an unsupported "multiple unit discount" and therefore we cannot 

reduce the capital costs by 5%. 
With regard to us reducing the costs by an additional 5% because of the supposed failure 

to consider common facilities, OG&E states that site-specific general arrangements were 

prepared for each station, which could be used to speculate regarding opportunities to use 

common facilities. However, they claim that significantly more engineering would have been 

needed to optimize the control system layout and determine if, and to what extent OG&E could 

take advantage of potential opportunities to use common facilities, which was beyond the scope 

of a study level or even a scoping-level cost estimate. OG&E states that such an analysis is not 

required for a BART analysis. OG&E states that lack of engineering makes our reduction of 

equipment, material, and labor costs by an additional 5% for common facilities arbitrary. In 

addition, OG&E claims that we provide no documentation that any savings would be realized by 

designing the scrubber to use common facilities. 

Response: Our reduction in costs to consider multiple unit discounts and common 

facilities discounts was not arbitrary and without basis, but rather based on standard cost 

estimating practices and further supported by vendor quotes supplied by OG&E.1

 

 The subject scrubbers are not off-the-shelf technology, but are rather designed and 

fabricated from scratch. It is common sense and a well established principle of cost estimating 

that considerable savings can be achieved by designing, fabricating, and constructing multiple 

identical units simultaneously. Fabricating multiple units would save the cost of creating an 

additional design, drafting an additional set of plans, and an additional shop setup. 

 The vendor quotes relied on by OG&E’s contractor, Sargent & Lundy were provided for 

a single generating unit at Sooner and a single generating unit at Muskogee. Sargent & Lundy 

doubled the single-unit estimates without taking into consideration economies of scale or 

common facilities. Further, in many cases, the single unit specification requested two 50% 

systems or equipment, rather than a more economical system designed to handle 100% of the 

flow. Thus, the there is no evidence that any of these vendor quotes considered multiple unit 

discounts. Based on common industry practice, we expected to see vendor discounts for multiple 

units in OG&E’s site specific cost estimates. Because as we discuss above, OG&E specified that 

single unit quotes be provided, the vendors did not provide multiple unit discounts. 

 

1

 At our request, OG&E provided us with supporting documentation for its cost numbers for ODEQ’s BART 

determination for OG&E’s Sooner and Muskogee units. OG&E submitted vendor quotes for the fans and scrubber 

system. marked as confidential business information: (1) Howden Variax, Inc., Proposal for Axial Booster Draft 

Fans, No. N21110, dated December 2, 2009; (2) Babcock & Wilcox Power Generating Group, Inc. Price Estimate 

for Spray Dry Absorber and Pulse Jet Fabric Filter Systems, dated December 12, 2009; (3) Alstom Power 

Environmental Control Systems. Price Estimate for Spray Dry Absorber and Pulse Jet Fabric Filter Systems, dated 

November 20, 2009; and (4) Siemens Energy, Inc. Environmental Systems & Services. Price Estimate for Spray Dry 

Absorber and Pulse Jet Fabric Filter Systems, dated December 9, 2009. It appears as if we were provided with 

abbreviated vendor quotations and not the entire vendor quotation. In addition, OG&E provided us with copies of 

the spreadsheets that were utilized by OG&E to develop their annualized cost estimates which are provided and 

marked as releasable in our Administrative Record. Upon development of our BART FIP for OG&E’s Sooner and 

Muskogee Units, we adopted the spreadsheet capital costs in our cost effectiveness analysis and used the provided 

vendor quotations to confirm our cost effectiveness calculations, with the exception of those items expressly 

outlined herein.

2 
 Sargent & Lundy's request for budgetary quotes went to three vendors. A portion of the 

Sargent & Lundy request for budgetary quote was submitted with one of the vendor quotes. The 

portion of the request available to us specified the technical data the vendors were to quote on as 

a "per unit" basis, e.g., one unit at each of the stations. The data provided in the request specified 

each piece of equipment and its capacity. A summary of the resulting vendor quotes are 

provided in the 12/28/09 S&L FollowUp Report, in a table captioned "DFGD Budgetary 

Proposal Pricing." Therefore, it is clear that the vendors were tasked to provide quotes based 

upon consideration of single units, not upon consideration of multiple units. Furthermore, these 

prices are exactly double the per-unit prices in the vendor quotes. Moreover, one vendor noted 

that the cost of the equipment and the design could be optimized to provide more economical 

operation. This vendor’s statement shows that costs could be reduced by considering multiple 

units rather than single units. 

 Our 5% discount on equipment for multiple identical units is therefore reinforced by this 

vendor’s statement. A search of the literature revealed a range of 4% to 10% savings from 

optimized equipment.2

 We picked 5%, which is at the lower end of this range. We provide 

examples later in this response showing the appropriateness of our choice. 

 For example, the technical data that Sargent & Lundy included in its Request for 

Budgetary Quote specified two baghouses, each sized to handle 50% of the flow The baghouses 

or fabric filters comprise about one-third of the capital cost of an Spray Dryer Absorber/Fabric 

Filter (SDA/FF) system,3

 rather than a single baghouse that could serve both SDA vessels at the 

unit. Because there is no information showing there is anything unique about OG&E’s facilities, 

we used the common industry practice of using one baghouse to handle 100% of the load – that 

one baghouse is used by similar facilities. We incorporated the algorithm from the fabric filter 

baghouse model developed by Sargent & Lundy for EPA's IPM Model4

 into a spreadsheet to 

explore the savings from building one large baghouse to serve each unit, rather than two half size 

or 50% baghouses as included in the Request for Quote and vendor proposals. The full 

spreadsheet, along with a copy of the report from which it was derived, has been added to the 

docket for our final action, and a screen copy of the spreadsheet and information on the model is 

reproduced as Attachment 1 to this document. The results of our analysis are summarized in 

 

2

 See, e.g., National Energy Technology Laboratory (NETL), Coal-fired Power Plants in the United States: 

Examination of the Costs of Retrofitting with CO2 Capture Technology, Revision 3, January 4, 2011, p. 14: (“Apply 

economies of scale discount for multiple units at the same plant (4% applied to all costs), p. 19 ("A total CAPEX 

discount of 4 percent was given to plants with multiple units to account for reduced engineering costs and economy 

of scale. The discount was determined by assuming a 50 percent reduction in engineering costs for the first 

successive unit at a site and was calculated based upon engineering costs in the Conesville Study relative to total 

investment costs."), Available at: http://www.netl.doe.gov/energy-analyses/pubs/GIS_CCS_retrofit.pdf 

Also, Burns and Roe Enterprises, Inc., Capacity Expansion Study for the Gowanus and Narrows Generating 

Stations, October 19, 2006, p. 10 ("To develop a baseline discount factor, BREI developed a list of balance of plant 

equipment that can be readily shared by multiple units (air compression, water treatment, tankage and piping 

systems) with dedicated CEMS, gas compression, and electrical systems for each individual CTG. The estimated 

savings that may be realized with this level of equipment sharing plus engineering and construction economies is on 

the order of 7% to 10%."), Available at: http://www.dec.ny.gov/docs/permits_ej_operations_pdf/ncapacity.pdf 3

 12/28/09 S&L FollowUp Report, DFGD Budgetary Proposal Pricing, Sooner Units1&2. 

4

 IPM Model – Revisions to Cost and Performance for APC Technologies, Particulate Control Cost Development 

Methodology, Final, March 2011, Project 12301-009, Systems Research and Applications Corporation, Prepared by, 

Sargent & Lundy 

3 
Table 1. 

 Table 1 

Economies Of Scale 

Fabric Filter Baghouse 

Capital, Engineering & Construction Costs 

Estimated by S&L IPM Model for SDA/FF 

 

Sooner Muskogee 

MW 570 285 572 286 

Btu/KW 8975 8975 9580 9580 

A/C Ratio 4 4 4 4 

Cost $73,904,917 $42,154,024 $78,136,443 $44,567,610 

Cost Ratio 0.88 0.88 

 Note the cost ratio is calculated as the cost of a single 100% baghouse divided by the cost 

of two 50% baghouses. Thus, the analysis in Table 1 shows that one large baghouse designed to 

serve each unit, rather than two 50% baghouses, would reduce baghouse capital costs by about 

12% (100 X (1-0.88). As baghouse costs are about 36% of total equipment costs, this one item 

alone would result in a 4% discount in total capital costs, very close to the 5% we assumed. As 

noted previously, we chose 5% savings from optimizing equipment. The entire FGD/FF system 

was costed to handle only 50% of the flow to two units at each station, rather than 100%. Thus, 

the cost estimate contains more opportunities for optimization. 

 Another vendor first quotes the capital cost and erection man hours (380,000 hrs) to 

design and construct one standalone SDA/FF system for each unit, based on the specifications in 

the Request for Budgetary Quote. This vendor then quotes the price to design and supply two 

duplicate SDA/FF systems, assuming both designs are the same, a common lime preparation and 

recycle system, and the same schedule. The resulting capital cost for both systems is double the 

per unit cost at each station, i.e., the costs were not optimized. However, the erection man hours 

were reduced by 10% (700,000 hrs rather than 760,000 hrs) to supply two duplicate SDA/FF 

systems. As the erection costs are about half of the total system costs (ranging from 48% to 52% 

for the three vendors),5

 the reduction in the total price of the system for one station to supply two 

duplicate SDA/FF systems is about 5% off of the total cost. This is the basis of our second 5% 

reduction cited in this comment. 

 

 As another example, the Sargent & Lundy Dry FGD Design and Cost Estimate Basis 

Document6 states, “A common lime handling system will be installed at each station.” The 

vendor quotes confirmed that OG&E required a separate lime handling system be built at each 

 

5

 12/28/09 S&L FollowUp Report, DFGD Budgetary Proposal Pricing, December 11, 2009, pdf 94. We note that 

the date on this table is the day before the vendor proposals were submitted. 

6

 Sooner Units 1&2 Muskogee Units 4 & 5, Dry FGD, Design And Cost Estimate Basis Document, December 28, 

2009, attached to the 12/28/09 S&L FollowUp Report, Design and Cost Estimate Basis Document, pdf 67. 

4 
unit when these systems can be shared successfully between the units. However, in the cost 

estimate, Sargent & Lundy merely doubled the per unit cost for these systems, ignoring its own 

design basis that common facilities were to be used, thus double counting some of the cost of the 

lime handling system that was meant to be shared between the two units. 

 

Consequently, we find that our initial assumptions that (1) vendors would offer a 5% 

discount on equipment costs for multiple identical units and large unit operations; and (2) 

designing the control system to use common facilities (e.g., single lime preparation and ash 

handing systems, and/or a single fabric filter) would reduce equipment, material, and labor" costs 

by an additional 5%, are adequately justified. 

Comment: OG&E states that other control options that we identified as potential cost 

saving measures, including reuse of the ESPs and use of a single pass dry scrubber, would not 

reduce costs or are not technically feasible. OG&E claims we incorrectly adjusted OG&E’s 

capital costs because of this. 

Response: We merely noted areas for potential cost savings that could have been 

investigated. We, however, did not make any adjustments to our proposed cost estimates for any 

of these options. Therefore, the possible reduction of costs from, or technical feasibility of these 

particular measures, is not relevant. 

Comment: OG&E states we incorrectly stated there was a mismatch between OG&E’s 

scrubber design that assumed an SO2 inlet rate of 1.176 lb/MMBtu SO2, and its annual emission 

reductions assumption, which was based on an average inlet SO2 loading of 0.51 lb/MMBtu. 

OG&E states our Option 1 cost estimate remedy in which we raised the emission baseline 

emissions to match the scrubber design assumption (i.e., 1.176 lb/MMBtu) was incorrect. 

OG&E states this approach was based on a misunderstanding of how emission reductions are 

properly calculated and our own requirements for calculating baseline emissions, as expressed in 

the BART Guidelines, and other BART determinations. As a result, OGE states our approach 

significantly overestimates baseline SO2 emissions from the subject units. 

OG&E notes the BART Guidelines in Appendix Y to 40 CFR Part 51 state that “[t]he 

baseline emissions rate should represent a realistic depiction of anticipated annual emissions for 

the source. In general, for the existing sources subject to BART, you will estimate the 

anticipated annual emissions based upon actual emissions from a baseline period.” OG&E states 

we reiterated this approach to calculating baseline emissions in our Advanced Notice of 

Proposed Rulemaking for the Four Corners and Navajo Generating Station BART 

determinations. 

OG&E also states that our observation that the size of the scrubber could have been 

minimized to match the sulfur content of the coal being fired is incorrect, and redesigning the 

scrubber, as we suggest, would result in an undersized and ineffective control system. 

Response: We disagree with this comment. First, the use of the lower estimate of 

emission reductions, based on OG&E’s historical baseline emissions, would not change our 

conclusion that dry scrubbers are cost effective. We explored this option in our proposal as 

5 
Option 2. As discussed elsewhere in our response to comments, we have revised Option 2 due to 

comments we have received. In summary (but discussed in greater detail later), the use of the 

lower estimate of emission reductions results in a revised cost effectiveness for Option 2 of 

$2,747/ton to $3,032/ton (Exhibit 2) and remains cost effective. 

 Regardless, OG&E cites to 70 FR 39167, column 1, in support of its position that the 

lower, historic baseline emissions should have been used to estimate cost effectiveness. In 

calculating baseline emissions, the BART Guidelines assume the source in question is otherwise 

unchanged in the future, except for the addition of BART controls, as can be seen from an 

examination of the full quote: 7

 

The baseline emissions rate should represent a realistic depiction of anticipated 

annual emissions for the source. In general, for the existing sources subject to 

BART, you will estimate the anticipated annual emissions based upon actual 

emissions from a baseline period. When you project that future operating 

parameters (e.g., limited hours of operation or capacity utilization, type of fuel, 

raw materials or product mix or type) will differ from past practice, and if this 

projection has a deciding effect in the BART determination, then you must make 

these parameters or assumptions into enforceable limitations. In the absence of 

enforceable limitations, you calculate baseline emissions based upon continuation 

of past practice.

 The Regional Haze Rule (RHR) provides that the baseline emissions used in the BART 

cost analysis “should represent a realistic depiction of anticipated annual emissions for the 

source.” OG&E’s cost analysis does not do this. Instead, as discussed elsewhere in our response 

to comments, it employs substantially different operating and design characteristics to project the 

units’ pre- and post-control emissions and costs. Cost aside, this under estimates reductions that 

may be reasonably anticipated to result from the controls’ installation. The discussion in the 

RHR regarding baseline emissions, contemplates a situation in which a change in future 

operations makes the historical baseline emissions effectively too high. However, we find it is 

reasonable to conclude the RHR’s desire to realign baseline emissions with potential future 

changes in operations applies equally to this situation as well. 

In addition, the RHR states that when differences from "past practice," as here, have "a 

deciding effect in the BART determination, you must make these parameters or assumptions into 

enforceable limitations." The OG&E analysis does not propose making the basis of their 

emission reductions enforceable. In fact, the scrubbers are designed to allow the station to burn 

higher sulfur coals than historically used at the station. Therefore, we affirm our position taken 

in Option 1, that our decision to raise the baseline to match the SO2 removal potential of the 

overdesigned scrubber was correct. 

We took a similar approach in deviating from historical emissions in calculating the 

baseline for BART when we proposed to approve the SO2 BART determination for Unit 1 of the 

Stanton Station in North Dakota.8

 In that case, the Stanton Station Unit 1 historically burned a 

 

7

 70 FR 39167 

8

 76 FR 58585 

6 
mix of lignite and Powder River Basin coal. Since Stanton was permitted to burn both lignite 

and Powder River Basin (PRB) coal and wanted the flexibility to burn 100% of each, in its 

BART determination, North Dakota changed the baseline emissions to reflect the future emission 

potential of Stanton under either scenario. North Dakota then analyzed the SO2 BART 

determination on the basis of each coal. In so doing, they used different baseline emissions that 

did not reflect their historical emissions but rather were calculated on the basis of either 100% 

lignite or 100% PRB. 

 The scrubbers that were costed were designed to treat the exhaust gases from a coal that 

contains much higher amounts of sulfur than coals that were burned in the baseline period (2004-

2006). As we discuss elsewhere in our response to comments, this design thus "anticipates" 

much higher SO2 emissions than experienced in the baseline. 

 OG&E cites our position in the Advanced Proposed Rulemaking for Navajo and Four 

Corners (74 FR 44321) as support for its position that historic baseline emissions must be used. 

The example of our position in the Advanced Proposed Rulemaking for Navajo and Four 

Corners (74 FR 44321) for adjusting historic baseline emissions is not relevant to this case as 

there was no issue of anticipated change in fuel quality in the Navajo/Four Corners cases. In 

those cases, we adjusted the historical baseline emissions because the company, “used the same 

24-hour average actual emission rate from the highest emitting day used for its modeling inputs, 

rather than an annual average rate.”9

. Thus, in those cases, we revised the company's estimated 

NOx emissions to use the average annual emissions over the same period. Therefore, this 

example is not pertinent. Furthermore, we did not assume a 24 hour maximum emission rate for 

OG&E. Rather, in Option 1, we recognized that OG&E specified in its vendor request for quote 

that the SO2 scrubbers be designed on the basis of a higher sulfur coal than the facilities have 

previously burned in any appreciable quantities. We therefore raised our emission baseline to 

match this overdesigned scrubber and demonstrated such a situation would be cost effective. 

However, we did not base our proposed decision solely on this outcome. In Option 2, we based 

our emissions baseline on annualized data, just as ODEQ did and costed the installation of 

scrubbers designed to address a coal with a sulfur content the OG&E units historically burned. 

Taken together, Options 1 and 2 demonstrate that whether OG&E continues to burn its historical 

coal, or decides to burn a higher sulfur coal that actually matches the capability of its scrubber, 

both results are cost effective. We agree with ODEQ that coal sulfur content will fluctuate and 

that a facility must be in compliance with its BART emission limits at all times. Elsewhere in 

our response to comments, we demonstrate that OG&E and AEP/PSO can meet our SO2

emission limit of 0.06 lbs/MMBtu on the basis of a 30 day BOD average. 

Comment: OG&E states that the December 2009 Budget Cost Estimates were prepared in 

accordance with the BART Guidelines and are consistent with the cost estimating methodology 

described in the Control Cost Manual.10 OG&E further states that the December 2009 Budget 

Cost Estimates were meant to supplement, not replace, the prior May 2008 BART evaluations. 

Response: We disagree with this comment. As explained in our proposal, ODEQ did not 

follow the Control Cost Manual. The Control Cost Manual uses the overnight method of cost 

 

9

 74 FR 44321. 

10 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002 

7 
estimation, widely used in the utility industry.11 This is the cost of a construction project if no 

interest is incurred during construction, as if the project is completed "overnight." As explained 

in our proposal, OG&E’s December 2009 cost estimates did not follow the overnight method 

used in the Control Cost Manual. 

There are only very limited situations under which an analyst can depart from the Control 

Cost Manual methodology under the RHR12: 

The basis for equipment cost estimates also should be documented, either with 

data supplied by an equipment vendor (i.e., budget estimates or bids) or by a 

referenced source (such as the OAQPS Control Cost Manual, Fifth Edition, 

February 1996, EPA 453/B–96–001). In order to maintain and improve 

consistency, cost estimates should be based on the OAQPS Control Cost Manual, 

where possible. The Control Cost Manual addresses most control technologies in 

sufficient detail for a BART analysis. The cost analysis should also take into 

account any site-specific design or other conditions identified above that affect 

the cost. 

This section of the RHR makes it clear that the Control Cost Manual is the intended 

methodology for conducting a BART cost determination. It also states why—to maintain and 

improve consistency. However, the Control Cost Manual does state that site-specific conditions 

should be incorporated. Site-specific conditions could include space constraints, or a design 

feature that could complicate installing a control. However, a footnote at the bottom of the same 

page of the RHR makes it clear that the analyst should document any deviations from the Control 

Cost Manual: 

You should include documentation for any additional information you used for 

the cost calculations, including any information supplied by vendors that affects 

your assumptions regarding purchased equipment costs, equipment life, 

replacement of major components, and any other element of the calculation that 

differs from the Control Cost Manual. 

In fact, the record does not point to any "unusual circumstance" that explains why 

OG&E's scrubber costs are higher than costs of scrubbers at other similar facilities, other than 

the use of a different cost methodology. The RHR also provides the following explanation, 

which makes it clear that other cost methods are supplemental, not replacements for the Control 

Cost Manual cost method13 14: 

We believe that the Control Cost Manual provides a good reference tool for cost 

calculations, but if there are elements or sources that are not addressed by the 

Control Cost Manual or there are additional cost methods that could be used, we 

believe that these could serve as useful supplemental information. 

 

11 See Cost Control Manual, Section 2.3 to 2.4. 

12 70 FR 39166. 

13 70 FR 39127. 

14 70 FR 39169 

8 
The ‘‘remaining useful life’’ of a source, if it represents a relatively short time 

period, may affect the annualized costs of retrofit controls. For example, the 

methods for calculating annualized costs in EPA’s OAQPS Control Cost Manual 

require the use of a specified time period for amortization that varies based upon 

the type of control. 

Although the focus in the second quote is ensuring the remaining useful life is 

incorporated into the amortization schedule, this passage affirms that the Control Cost Manual's 

annualized cost methodology should be followed. The following quote from the same page of 

the RHR sheds light on the type of costing methodology employed by the Control Cost Manual, 

“capital and other construction costs incurred before controls are put in place can be rolled into 

the first year, as suggested in EPA’s OAQPS Control Cost Manual.” Although this passage is 

again focused on the remaining useful life, the text we reproduce is a reference to the basic 

Control Cost Manual cost methodology—the overnight method. That is what is meant with the 

reference of rolling future costs into the first year. The "all in" method that OG&E used does not 

do that—it projects costs to a future date. Although the Control Cost Manual does not use the 

term, overnight cost,” it is widely used in industry. 

The U. S. Energy Information Administration (EIA) defines “overnight cost” as “an 

estimate of the cost at which a plant could be constructed assuming that the entire process from 

planning through completion could be accomplished in a single day. This concept is useful to 

avoid any impact of financing issues and assumptions on estimated costs.”15 EIA presents all of 

its projected plant costs in terms of overnight costs. The overnight cost is the present value cost 

that would have to be paid as a lump sum up front to completely pay for a construction project.16 

The Control Cost Manual does, however, use the same method. For instance, the Control 

Cost Manual discusses how cost should be annualized using Net Present Value (NPV)17: 

To evaluate alternative pollution control devices, the analyst must be able to 

compare them in a meaningful manner. Since different controls have different 

expected useful lives and will result in different cash flows, the first step in 

comparing alternatives is to normalize their returns using the principle of the time 

value of money discussed in section 2.4.1. The process through which future cash 

flows are translated into current dollars is called present value analysis. When the 

cash flows involve income and expenses, it is also commonly referred to as net 

present value analysis. In either case, the calculation is the same: adjust the value 

of future money to values based on the same (generally year zero of the project), 

employing an appropriate interest (discount) rate and then add them together. 

 OG&E, on the other hand, states that cost effectiveness should be based on the "all-in" 

cost method, which includes all of the costs of a financial transaction, including interest, 

 

15 EIA, “Updated Capital Cost Estimates for Electricity Generation Plants,” November 2010, footnote. 2. Available 

at: http://www.eia.gov/oiaf/beck_plantcosts/?src=email 

16 Steven Stoft, Power Economics: Designing Markets for Electricity, 2002. 17 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002, pdf 32. 

9 
commissions, and any other fees from a financial transaction up to the date that the projects goes 

into operation, as of the commercial operating date of the scrubbers, 2014 and 2015. This is an 

entirely different method than that prescribed in the Control Cost Manual. Many of the 

categories of cost that OG&E included in its cost analyses are valid under the all-in approach. 

However, as the BART Guidelines explain, cost effectiveness is a relative determination, 

based on comparing the cost of a project with the cost borne by other similar projects.18 If costs 

are outside of the range at other similar facilities, the control can be rejected as not being cost 

effective. This comparison requires the cost effectiveness of a subject project to be estimated in 

same way as the projects included in the comparison range. It would not be fair, for example, to 

reject or adjust a cost reported in year 2015 dollars based on a comparison range reported in year 

2000 dollars due to the impact of inflation on costs. Similarly, it would not be fair to compare 

the costs estimated using, for instance, mixed current dollars including interest during 

construction, with the overnight cost. However, this is what OG&E has done. 

 OG&E states that scrubbers are not cost effective at Sooner and Muskogee, based on allin costs reported in 2014 to 2015 dollars, compared to costs estimated at other similar facilities 

based on overnight costs and 2009 and earlier dollars. This is an entirely different method than 

that prescribed in the Control Cost Manual. OG&E concludes that dry scrubbers are not cost 

effective at Sooner and Muskogee, based on all-in costs reported in 2014 to 2015 dollars, 

compared to costs estimated at other similar facilities based on overnight costs and 2009 and 

earlier dollars. This is an invalid comparison, because OG&E’s 2014 and 2015 all-in costs are 

much higher than the corresponding overnight costs, as prescribed by the Control Cost Manual. 

This makes the estimated cost of scrubbers at Sooner and Muskogee appear to be higher than 

scrubbers required at other similar facilities costed using the overnight method. 

 Finally, as to the 2008 cost analysis, we based our determination about the adequacy of 

the BART determinations for the six OG&E and AEP/PSO units on the information contained in 

the Oklahoma RH SIP. This SIP contained BART analyses performed by the ODEQ. These 

analyses considered both the 2008 and 2009 revisions cited by OG&E, including the use of 

vendor quotes. Regardless, both analyses contain many of the same fundamental methodological 

flaws, such as including escalation and Allowance for Funds Used During Construction 

(AFUDC). These 2008 costs are not valid under the overnight costing method. The cost of 

scrubbers would not be substantially higher than those reported for other similar projects if 

OG&E had used the costing method and basis, i.e., overnight costs in current dollars, prescribed 

by the Control Cost Manual. 

Comment: OG&E presents its position on the costing methodologies used in the Control 

Cost Manual. OG&E then states that the Control Cost Manual allows deviations from the 

standard approach for FGD (flue gas desulfurization). OG&E states the Control Cost Manual

provides a road map for estimating capital costs, annual operating costs, and total annual costs 

associated with an air pollution control system. OG&E states the Control Cost Manual also 

provides flexibility, and is not so prescriptive as to explicitly exclude from a cost estimate actual 

tangible costs that an applicant will incur as part of an air pollution control project. For example, 

 

18 70 FR 39168, “A reasonable range [cost-effectiveness] would be a range that is consistent with the range of cost 

effectiveness values used in other similar permit decisions over a period of time.” 

10 
continues OG&E, the Control Cost Manual states that “the user has to be able to exercise 

‘engineering judgment’ on those occasions when the procedures may need to be modified or 

disregarded;” and that “the application of an appropriate [indirect capital cost] factor requires the 

subjective application of the analyst’s best judgment. OG&E states that since the Control Cost 

Manual does not provide cost information for the FGD technology when the Control Cost 

Manual is explicit in providing cost information for other technologies, it is reasonable to 

incorporate site specific design and conditions in the cost calculation for the FGD. They state 

the December 2009 estimates provided significantly more detail than required by the Control 

Cost Manual by establishing reasonable design parameters for the control system, obtained 

budgetary equipment costs from vendors for the major equipment, and provided a reasonable 

basis for all line items included in the cost estimate. OG&E concludes the level of detail is more 

than is required by our Control Cost Manual and departs from its default factors to identify the 

true site-specific costs, but it still follows the Control Cost Manual’s methodologies. 

Response: We disagree with this comment's characterization of what is required by the 

Control Cost Manual. The Control Cost Manual contains two types of information: (1) a generic 

costing methodology and (2) study level capital cost estimates for certain general types of 

pollution control equipment. The Cost Manual does not include study level capital cost 

estimates for any type of SO2 scrubbing. This means scrubber capital costs must be based on 

site-specific vendor quotes or other sources. We do not dispute the vendor quotes. Rather, we 

dispute how these vendor quotes were represented by OG&E. 

 The absence of a study level chapter on scrubbers in the Control Cost Manual does not 

mean that the standard costing methodology, i.e., the overnight costing approach, can be 

disregarded. See the previous response to comments on the overnight cost method versus the all 

in cost method. The overnight costing methodology converts the capital cost estimates into an 

annual cost in current real dollars without any inflation. This methodology must be used 

regardless of the source of the capital cost data to evaluate cost effectiveness. The Control Cost 

Manual offers no alternative costing methodology to the overnight methodology but does offer 

alternative study-level cost estimating methods. 

 In evaluating cost effectiveness, it is important that a consistent set of rules be used. 

Otherwise, one runs the risk of comparing apples with oranges when making the cost 

effectiveness determination, i.e., when comparing an estimated site-specific cost effectiveness 

value for the project at hand with the costs borne by other similar sources. The BART 

Guidelines stipulate: "In order to maintain and improve consistency, cost estimates should be 

based on the OAQPS Cost Control Manual, where possible."19 OG&E used vendor estimates 

for equipment costs but did not follow the generic costing method, i.e., the overnight method. 

 This comment also suggests that "engineering judgment" can be substituted for the 

procedures stipulated in the Control Cost Manual "when the procedures may need to be modified 

or disregarded and that "the application of an appropriate [indirect capital cost] factor requires 

the subjective application of the analyst's best judgment." These arguments are taken out of 

context. 

 

19 70 FR 39166 (July 6, 2005). 

11 
 The first citation to the use of "engineering judgment" to modify or disregard portions of 

the Control Cost Manual is made with reference to the use of study level capital cost estimating 

procedures, not the general overnight costing methodology. The second citation, to the statement 

"the application of an appropriate [indirect capital cost] factor requires the subjective application 

of the analyst's best judgment," refers to cost estimating factors for freight, sales tax, and 

instrumentation, not to the general overnight costing methodology. 

 Comment: OG&E states the BART guidelines do not limit the analyst to using studylevel costs and default factors found in the Control Cost Manual. Rather, states OG&E, the 

BART Guidelines require that the cost analysis should take into account site-specific design or 

other conditions that affect the cost of a particular control technology, provided that the cost 

estimate includes documentation of any additional information that was used for the cost 

calculations, including any information supplied by vendors that affects assumptions regarding 

purchased equipment costs, equipment life, replacement of major components, and any other 

element of the calculation that differs from the Control Cost Manual.

OG&E states that the May 2008 BART Evaluations and the December 2009 Budget Cost 

Estimates were both prepared in accordance with the BART Guidelines and the Control Cost 

Manual methodology. OG&E states the December 2009 Budget Cost Estimates were developed 

using refined capital cost estimates, budgetary costs from equipment vendors, site-specific 

balance-of-plant costs, and specific indirect cost factors. This level of detail, states OG&E, is 

more than what is required by the Control Cost Manual and only departs from default factors to 

achieve its site specific purpose, but the December 2009 Budget Cost Estimates still follow the 

Control Cost Manual’s methodology. OG&E goes on to list a number of items such as plant 

design data, general arrangement drawings, a motor list, mass balance calculations, an 

installation schedule, and a design and cost basis document that it claims provides a greater cost 

estimation accuracy than the default factors used in the Control Cost Manual. 

OG&E claims the methodology used in the December 2009 Budget Cost Estimates is 

consistent with the approach described in the Control Cost Manual and provides a conceptual 

capital cost estimate, or scoping-level estimate, with accuracy in the range of ±20%. OG&E 

states that cost estimates using default factors in the Control Cost Manual, like those contained in 

the May 2008 BART Evaluations, are directed toward a study-level estimate with a nominal 

accuracy of ±30%. The Control Cost Manual, cites OG&E states that “[s]tudy-level estimates 

are acceptable for regulatory development because they represent a compromise between the less 

accurate order-of-magnitude and the more accurate, but more costly, estimate types.” OG&E 

claims the methodology used by it to prepare the December 2009 Budget Cost Estimates 

provides more detailed and robust estimates of the capital costs associated with installing the 

DFGD and baghouse control systems on a large subbituminous coal-fired boiler and more 

specific estimates of the actual costs that OG&E would incur to install these control systems at 

the Sooner and Muskogee Stations. 

Therefore, concludes OG&E, the Control Cost Manual is not the exclusive or primary 

source of costs when there is better source-specific information available. Consequently, OG&E 

claims we improperly discarded OGE’s December 2009 Budget Cost Estimates on the grounds 

of their lack of conformity with the Control Cost Manual. 

12 
Response: The May 2008 study level BART cost estimate and the December 2009 

budget cost estimate do not follow the cost methodology in the Control Cost Manual. These two 

cost estimates are based on the all-in costing approach and thus deviate from the Control Cost 

Manual which is based on the overnight cost approach, as discussed elsewhere in our response to 

comments. Both the 2008 and 2009 cost estimates contain many of the same methodological 

flaws including, for example, excessive contingencies, double counting, allowance for funds 

during construction (AFUDC), and reliance on the Electric Power Research Institute (EPRI) cost 

model, CUECost. These deviations, occurring because of the reliance upon the all-in cost 

methodology, erroneously increase the cost of scrubbing at Sooner and Muskogee, compared to 

the cost at other similar facilities using the overnight cost methodology. 

 The December 2009 budget cost estimates relied on vendor quotes and site specific 

estimates for certain additional costs. We support the use of vendor quotes and site specific 

estimates but only as used within the parameters of the overnight cost methodology. However, 

the Guidelines, cited in this comment, are clear that "[y]ou should include documentation for any 

additional information you used for the cost calculations, including any information supplied by 

vendors that affects your assumptions regarding purchased equipment costs, equipment life, 

replacement of major components, and any other element of the calculation that differs from the 

Control Cost Manual."20 

 Much of the documentation OG&E cites to support deviations from the Control Cost 

Manual, were not provided to us. For instance, although OG&E provided two spreadsheets that 

listed their cost line items, these spreadsheets, each over 600 lines in length (and including line 

items such as seeding and fertilizing the grass at the plant sites), were stripped of all cell 

calculations, preventing any meaningful review. In addition to not providing the necessary 

required supporting documentation, OG&E did not follow the overnight cost methodology. 

Thus, OG&E has failed to meet the test that is required to support deviations from the Cost 

Manual. 

Comment: OG&E states we improperly found that the December 2009 Budget Cost 

Estimates failed to follow the Control Cost Manual guidelines by including escalation, bond 

costs, AFUDC, and excessive contingency, and by annualizing the capital costs using an 

overstated capital recovery factor. OG&E states that the constant dollar approach described in 

the Control Cost Manual only requires the analyst to establish a baseline year from which total 

annual costs can be equalized (in constant dollars) over the life of the control system. The 

Control Cost Manual, claims OG&E, does not dictate any specific baseline year and allows the 

analyst to establish the commercial operating date (“COD”) of the control system as the baseline 

year. OG&E states that construction of an FGD control system can take from approximately 32 

to 40 months from start of construction to COD; thus, it is reasonable to establish the COD as the 

baseline year from which future maintenance and O&M costs are calculated. Thus, states 

OG&E, it is acceptable for them to escalate costs to 2014 and 2015 dollars. OG&E states that 

annual O&M and auxiliary power costs in 2009 dollars were also escalated to the respective 

baseline years. From those baseline years, explain OG&E, the O&M and auxiliary power costs 

were calculated using the constant dollar approach over the operating life of the control 

 

20 70 FR 39166, footnote 15. 

13 
equipment. Inflation was removed from the discount rate and from the O&M and auxiliary 

power costs with respect to the baseline year and the 20-year operating life of the control 

equipment. This approach, claims OG&E, is consistent with the constant dollar approach 

described in the Control Cost Manual, and we have not shown it is inconsistent with the Control 

Cost Manual. 

Response: This approach suggested by OG&E of escalating costs to future dates is 

inconsistent with our long standing practice, articulated in the Control Cost Manual, of reporting 

cost effectiveness values in current dollars.21 The Control Cost Manual does not allow the 

analyst to define year zero as the commercial operating date. Table 2.1 and Figure 2.5 show year 

zero to be prior to operation of the project. 

 The overnight cost method is the cost of a construction project as if the project is 

completed overnight in current dollars. Thus, escalation of current dollars to future dollars is 

never valid under the Control Cost Manual overnight cost approach. We recognize that “[t]he 

cost analysis should also take into account any site-specific design or other conditions identified 

above that affect the cost of a particular BART technology option.” 22 However, escalation is not 

one of these “site specific design or other condition[s]”23 that can be considered under the 

Control Cost Manual and the RH rule. It is our position that the Control Cost Manual only 

allows the overnight cost method for a BART analysis for scrubbers. 

 A dollar per ton value is considered to be cost effective if it falls within a reasonable 

range, based on the range of cost effectiveness values in other similar permit decisions over a 

period of time.24 Thus, while it is theoretically possible to report costs relative to any future 

year, the cost range used to determine if the result is cost effective must be adjusted to the same 

future year. 

 In making a cost effectiveness determination, values from past permit decisions must be 

adjusted to current dollars to compare with the project of interest. This is done to assure an 

apples to apples comparison. It would be inappropriate to compare a cost effectiveness value 

reported in future dollars with a range reported in historic dollars. 

 OG&E estimated cost effectiveness values in 2014 and 2015 dollars. However, 

comparison data in 2014 and 2015 dollars were not provided. If the cost-effectiveness of 

scrubbers at the OG&E plants is stated in 2014 or 2015 dollars per ton, the historical comparison 

data would need to be escalated to 2014 or 2015 dollars. OG&E does not provide any such 

comparison. Thus, there is no basis for concluding that scrubbers reported in 2014 to 2015 

dollars are not cost effective. We adjusted Sargent & Lundy's costs to current dollars in our 

original analysis and demonstrated that the resulting values are cost effective. 

 In principle, the cost-effectiveness of controls could be compared in any year’s dollars—

 

21 Cost Manual, p. 2-20 ("EUAC works best when the [sic] is only one capital investment to incorporate and annual 

cash flows are constant or normalized to one year, typically year zero."). 22 70 FR 39104, at 39166, 

23 Id. 24 70 FR 39168. 

14 
1990, 2009, 2015, 2050, or any other year—so long as all the costs are in the same year’s dollars. 

Since historical data are generally available in earlier years’ dollars, it is simpler and has long 

been standard practice to make the comparison in current year dollars. In this case, the 

comparison would be conducted in 2009 dollars rather than some hypothetical future year. We 

made the comparison in 2009 dollars in our proposal and our revised cost estimates, based on the 

overnight costing approach, demonstrate that scrubbers are cost effective at Sooner and 

Muskogee. 

 Cost effectiveness is a relative determination based on current dollars that requires the 

application of a consistent methodology to a set of facts. A level playing field requires that all 

historic costs used to evaluate reasonableness be adjusted to the same basis. The Sooner and 

Muskogee costs appeared to be high, in part, because they were compared to costs from 2000 to 

2009, rather than from 2014 or 2015. 

 The commenter argues in a footnote that the example on page 2-36 of the Cost Manual is 

not evidence that future escalation should be excluded. We disagree. The Cost Manual states 

that "[t]his [referring to excluding inflation] is the preferred way to approach this kind of 

analysis, since it relies on the most accurate information available (current prices) and does not 

try to extrapolate those prices into the future." This is the overnight approach described 

elsewhere. This statement is not specific to the example cited in Table 2.6, but rather is our 

standard practice in performing regulatory cost analysis under the Cost Manual approach. This 

method is based on current prices and real dollars without any inflation. Escalating vendor 

quotes in current dollars to future operating dates and comparing the cost with the cost in historic 

dollars is inappropriate. Overnight costs in current dollars should not be compared with 2014 - 

2015 all-in costs. 

 Comment: OG&E states that the Control Cost Manual explicitly includes AFUDC as a 

cost component based on several lines of evidence. First, it explains that AFUDC is a cost that 

will be incurred and on this basis, it should be included. OG&E states AFUDC is more than an 

accounting method and is a way of measuring the cost of interest over the construction period 

and is a real cost. Furthermore, states OG&E, the Control Cost Manual specifically allows 

AFUDC costs in the total capital investment (TCI) costs (see Table 1.4 and Table 2.5). Second, 

it states that the Control Cost Manual cites two reports that include AFUDC and that AFUDC 

was historically required: The Shattuck report, published in connection with cost estimating 

software for FGD software; and the Kaplan report, published in collaboration with major utility 

companies. Third, OG&E states that the two examples we cited as evidence that AFUDC should 

be excluded were for controls with a short construction periods, SNCR and SCR, where AFUDC 

would not apply. They feel the zero adjustment is not appropriate for a FGD because of its long 

construction period of 42 months. Moreover, they state, we have allowed AFUDC costs in 

several coal-fired BART determinations and AFUDC is included as a line item in EPA’s 

CUECost worksheets for FGD control systems. Consequently, concludes OG&E, we improperly 

disallowed the AFUDC costs on the grounds that AFUDC costs are not allowed under the 

Control Cost Manual. 

Response: We disagree. It has long been EPA's practice to exclude AFUDC from 

regulatory cost effectiveness analysis, because the overnight costing methodology used in these 

15 
analyses, does not include AFUDC. See a previous discussion in our response to comments. 

 First, the comment states that the Control Cost Manual includes "all" costs required to 

purchase and install a control system, citing to Section 2.3.1 of the Manual, Elements of Total 

Capital Investment, and stating that AFUDC is one of these costs. However, AFUDC is not 

mentioned anywhere in this section of the Control Cost Manual. In particular, Figure 2.2 of the 

Control Cost Manual, which diagrams the "elements of total capital investment," does not list 

AFUDC. AFUDC costs are not included because the Control Cost Manual costing methodology 

is based on overnight cost as explained previously in our response to comments. 

 AFUDC is the cost of capital that is incurred to finance the project during the 

construction period. The overnight cost method is the cost of a construction project if no interest 

is incurred during construction, as if the project is completed overnight. Thus, AFUDC is never 

valid under the Control Cost Manual overnight cost approach. Neither is AFUDC a “site specific 

design or other condition[s]25” that can be considered under the RHR and the Control Cost 

Manual. Further, if an alternate costing approach is used, based on all-in costs, the range of costs 

used to assess the reasonableness of the resulting estimate must be adjusted to the same basis, 

i.e., AFUDC and other all-in costs must be added to the projects that make up the range used to 

determine reasonableness. Nevertheless, it is our position that the Control Cost Manual only 

allows the overnight cost method for a BART analysis for scrubbers. 

 Second, the comment suggests that the Control Cost Manual anticipates the inclusion of 

AFUDC by including "working capital," which is underlined. While the manual is not clear 

what is meant by that phrase, previous versions of the Manual defined working capital as a fund 

set aside to cover the initial costs of fuel, chemical, labor and maintenance to build the project.26 

Thus, we believe the appropriate interpretation is that the Control Cost Manual intends that the 

cost estimate include an allowance for suppliers’ and contractors’ materials, supplies and the 

cash needed to pay wages before the facility owner reimburses the contractor. 

 In accounting and financial management, working capital generally refers to current 

assets (e.g., cash, accounts receivable, inventories), while net working capital is a measure of the 

operating liquidity of a firm, computed as the difference between current assets and current 

liabilities (e.g., accounts payable). None of these concepts leads to a cost item that resembles 

AFUDC. Therefore, the inclusion of an allowance for “working capital” does not change our 

position that the Control Cost Manual does not allow the inclusion of AFUDC. 

 Third, this comment also states that the inclusion of zero AFUDC in the sections of the 

Control Cost Manual dealing with SCR and SNCR implies that non-zero AFUDC can be applied 

to the scrubber costs. OG&E asserts that the SNCR and SCR tables in the Control Cost Manual

(Section 4, Tables 1.4 and Table 2.5) “are simplified examples of cost estimates ... include a line 

item for AFUDC, but zero out AFUDC for the example.” 

 OG&E suggests that the zero AFUDC in these tables may be due to the fact that these 

technologies have shorter construction periods and lower AFUDC (18 months and 5%, for SCR) 

 

25 70 FR 39166 

26 OAQPS Control Cost Manual, 4th Edition, Report EPA 450/3-90-006, January 1990, p. 2-6. 

16 
than do FGD systems (42 months and 12%, according to OG&E), and thus are not worth 

considering. However, in estimating the costs of SCR for other purposes, OG&E has estimated 

that SCR would have AFUDC of 6%.27 OG&E provides no basis for asserting that the Control 

Cost Manual would ignore a 5%–6% cost adder, if that were intended to be part of the cost 

methodology. Table 2.5 includes two 5% cost adders and a 2% adder. Further, as AFUDC 

accounts for the cost of capital to finance a project during the construction period, there would 

always be a finite financing charge for any length of construction. It would never be zero under 

the all-in cost method. The fact that it is explicitly set equal to zero for SCR and SNCR is clear 

evidence that the Control Cost Manual is following the overnight costing method. 

 In fact, the Control Cost Manual indicates that the zero AFUDC is included for clarity, 

not for simplification. The Control Cost Manual reference to SCR AFUDC occurs in a section 

entitled “Indirect Capital Costs,” the text of which states: 

Indirect installation costs are those associated with installing and erecting the 

control system equipment but do not contribute directly to the physical capital of 

the installation. This generally includes general facilities and engineering costs 

such as construction and contractor fees, preproduction costs such as startup and 

testing, inventory capital and any process and project contingency costs. As 

explained in the Manual Section 1 Introduction, average values of indirect 

installation factors are applied to the direct capital cost estimate to obtain values 

for indirect installation costs. These costs are estimated as a percentage of the 

TCI. The equations for indirect installation costs are presented in Table 2.5.28

 Each of the costs enumerated in the text has a non-zero adder in Table 2.5; the cost items 

that are set to zero in the table (including AFUDC) are not included in the text. Contrary to 

OG&E’s assertion, the Control Cost Manual does not describe Table 2.5 as a “simplified 

example” with AFUDC “zeroed out for the example.” Table 2.5 presents the” equations for 

indirect installation costs,” including the “average values of indirect installation factors” to be 

“applied to the direct capital cost estimate to obtain values for indirect installation costs.” The 

discussion of Table 1.4 is essentially the same as for Table 2.5. 

 The Control Cost Manual also defines and enumerates indirect costs in Section 1, p. 2-5, 

as follows: 

Indirect installation costs include such costs as engineering costs; construction 

and field expenses (i.e., costs for construction supervisory personnel, office 

personnel, rental of temporary offices, etc.); contractor fees (for construction and 

engineering firms involved in the project); start-up and performance test costs (to 

get the control system running and to verify that it meets performance 

guarantees); and contingencies. 

 The same list appears in Section 1, Figure 2.2. The Control Cost Manual discusses the 

 

27 IPM Model – Revisions to Cost and Performance for APC Technologies, SCR Cost Development Methodology, 

August 2010, p. 3. 

28 Control Cost Manual, Section 4, p. 2-43. 

17 
scope of indirect costs at least eleven times (Section 1, p. 2-5 and Figure 2.2; Section 2, Table 3-

14; Section 3.2, p. 1-27 and Table 2.8; Section 4, p. 1-32, Table 1.4, p. 2-43, and Table 2.5; 

Section 5.2, Table 1.3; Section 6, Table 3.20). None of these lists of indirect costs includes 

AFUDC. 

 Thus, the intent of the Control Cost Manual is to compute and compare cost-effectiveness 

on the basis of overnight costs, and OG&E’s assertion that "In cases where the time value of 

money during the construction period would be significant (e.g., projects with longer 

construction periods such as the installation of DFGD), the Control Cost Manual clearly allows 

inclusion of AFUDC" (OG&E, Ex. B, p. 22) is not correct. 

 Finally, the comment states the Control Cost Manual allows the inclusion of AFUDC 

because it cites to two reports, by Shattuck and Kaplan, that it states include the use of AFUDC. 

The comment goes on to state that the Kaplan report was published by us, that both reports are 

the foundation for the Control Cost Manual, and that we included AFUDC in the years leading 

up to publication of the Control Cost Manual. We disagree that these reports or the practice 

leading up to publication of the Cost Control Manual provide a basis for including AFUDC in 

cost estimates under the Regional Haze Rule. 

 First, although these two reports are included in the references to Chapter 2, they are not 

specifically cited in the text of the Control Cost Manual as to the appropriateness of any 

particular matter. There are no footnotes in Chapter 2 that specifically cite to these two reports 

and tie them to any narrative; the narrative does not provide any information on how these two 

reports are to be used in a regulatory cost analysis; and there is nothing to tie them to AFUDC. 

As they cover a wide range of topics, there is no basis for concluding that listing them in the 

references supports any specific fact in the Control Cost Manual. 

 Second, the Shattuck report is the foundation for the CUECost model and some of the 

costing algorithms for specific control methods, but not for the general overnight costing 

methodology used in the Control Cost Manual. CUECost is a model that estimates control costs 

using the levelized cost method developed by EPRI. Although portions of it may shed some 

light on particular aspects of cost determinations it is not an appropriate stand-alone cost model 

for BART determinations because it does not follow the overnight cost methodology prescribed 

by the Control Cost Manual. 

 Third, OG&E explains that the all-in costing approach is recognized in publications by 

other agencies (EIA, EPRI). As noted, AFUDC is valid cost under the all-in method, and all-in 

method is a valid approach in other settings. Other agencies, including us, use this all-in cost 

method for purposes other than regulatory cost analysis. For purposes of implementing the 

RHR, the Control Cost Manual requires the use of the overnight cost method. 

Finally, this comment claims that "the EPA clearly followed this approach in its studies 

of retrofit costs of SO2 and NOx in the years leading up to its publication of the Control Cost 

Manual." Although we did not check the accuracy of this statement, it is irrelevant. As we have 

discussed elsewhere in our response to comments, the RHR states the Control Cost Manual 

should be followed where possible, and the Control Cost Manual uses overnight costing 

18 
methodology. 

 In sum, while AFUDC is a valid cost under the all-in cost estimating, it is not a valid cost 

under the Control Cost Manual methodology, which is based on the overnight costing method. 

The Control Cost Manual "relies on the most accurate information available (current prices) and 

does not try to extrapolate those prices into the future."29 

Comment: OG&E states that we improperly set OG&E’s bond costs to zero in the capital 

cost estimate on the premise that bond costs are similar to AFUDC costs in that they are transfer 

payments and not allowed under the constant dollar approach in EPA’s Control Cost Manual. 

The comment states that bond costs are distinct from AFUDC costs and should not be set to zero. 

They claim AFUCD costs are tangible expenses paid to a bond underwriter for actual services 

associated with financing a large capital project and thus should be included in the total capital 

expenditure. OG&E states Bond costs are an indirect tangible cost paid to a bond underwriter 

for actual services, which is an allowed TCI cost. 

Response: The 2009 OG&E cost estimates include bond cost estimated as 1% of total 

project cost with escalation and contingency, but without AFUDC.30 While OG&E is correct 

that utilities incur some costs in issuing debt, this cost is normally included in the interest rate. 

Here, it is impossible to determine whether the interest rate Sargent & Lundy uses in its 

computations (6.03% nominal) includes those costs. Neither the S&L FollowUp Report nor the 

Comments provide any derivation or source for the assumed bond cost interest rate. 

 In most cases, the issuer of corporate debt does not pay the underwriters directly for their 

service, but instead sells the bonds to the underwriters at a discount. The underwriters’ 

compensation comes from the difference between the price they pay for the bonds and the price 

at which they can sell them. Hence, the debt issuance costs do not represent a cash payment at 

the time the plant is built, but a small increment in the repayment at maturity, twenty or thirty 

years in the future. 

 Thus, bond costs are usually included as part of the cost of debt, rather than the capital 

cost of the project. Therefore, we exclude these costs from our revised cost analyses. 

 Regardless looking at the bond costs as they pertain to the cost of debt, the scrubbers may 

be financed in part with Pollution Control Bonds, at very low tax-exempt interest rates (currently 

under 4%).31 Thus, the average cost of debt for these projects, even including the small 

increment necessary to cover the costs of issuing debt, should be substantially less than assumed 

by OG&E. 

 Comment: OG&E claims that we improperly rejected the range estimating process used 

by them that provides a better estimate of an appropriate project contingency (14%). They state 

our 3% estimate used in our revised cost analysis is arbitrary, not supported by the Control Cost 

Manual, and ignores site-specific information. OG&E states a larger contingency is generally 

 

29 Cost Manual, Chapter 2, p. 2-36. 

30 12/28/09 S&L FollowUp Report, Attach. A, pdf 41, 56. 

31 OG&E FERC Form 1, p. 256. 

19 
needed if the project is not well-defined and/or if a high level of confidence is needed. They 

state the December 2009 Budget Cost Estimate used to range estimating technique to determine 

that a 14% contingency was needed to provide a 95% confidence level in the cost estimate. 

According to OG&E, this level of contingency is typical for a scoping-level cost estimate. 

Further, they state that range estimating is a commonly used technique to determine the level of 

contingency needed in a cost estimate to achieve the desired level of confidence. In addition, 

OG&E states our Control Cost Manual does not specify any particular methodology for 

estimating an appropriate level of contingency and allows both process and project contingencies 

in an estimate of the indirect capital costs. 

Response: We disagree. Under the overnight cost estimating method in the Cost Control 

Manual, contingency has a specific definition: "A contingency factor should be reserved (and 

applied to) only those items that could incur a reasonable but unanticipated increase but are not 

directly related to the demolition, fabrication, and installation of the system. For example, a 

hundred year flood may postpone delivery of materials, but their arrival at the job site is not a 

problem unique to a retrofit situation."32

 In contrast, OG&E urges a definition of "contingency" based on a different authority, 

Perry's Chemical Engineers' Handbook, which defines contingency in different terms: 

"unforeseeable elements of cost, particularly in fixed investment estimates, which previous 

experience has shown to be statistically likely to occur." These definitions conflict. The Control 

Cost Manual method, required by the RHR, specifically excludes from the definition of 

contingency: “A contingency factor should be reserved (and applied to) only those items that 

could incur a reasonable but unanticipated increase but are not directly related to the demolition, 

fabrication, and installation of the system.”33 In contrast, OG&E applies a 14% contingency to 

all project costs, including demolition, fabrication, and installation, in direct contradiction to this 

fundamental definition in the Control Cost Manual. This inappropriately inflates the OG&E cost 

estimate for scrubbers at Sooner and Muskogee, compared to costs estimated for other similar 

facilities using the Control Cost Manual methodology. 

 We estimated contingency based on the Control Cost Manual definition for the 

equipment included in the Manual that is most similar to the proposed controls —a wet scrubber 

for acid gases (similar to the spray dryer absorber) and a baghouse (included in a spray dryer 

absorber system). In both of these cases, the Control Cost Manual specifies the contingency as 

3% of the purchased equipment cost.34 Thus, in our revision to OG&E's cost estimate, we 

estimated the contingency as 3% of the vendor quotes, which represent the purchased equipment 

cost. 

 OG&E notes that a higher contingency than our 3% is specified in the Control Cost 

Manual for SNCR and SCR and states if we had used it (a process contingency of 5% of direct 

capital cost and a project contingency of 15% of direct capital cost + indirect installation costs), 

 

32 Control Cost Manual, Sec. 2.5.4, p. 2-30. 

33 Cost Manual, Section 2.5.4.2 Retrofit Cost Considerations, Chapter 2: Cost Estimation: Concepts and 

Methodology. 

34 Control Cost Manual, Section 5.2, Post-Combustion Controls, Chapter 1: Wet Scrubbers for Acid Gas, Table 1.3 

and Section 6, Chapter 1: Baghouses and Filters, Table 1.9. 

20 
contingencies would be "significantly higher" than estimated using OG&E's 14% of total capital 

investment. 

 First, these controls (SCR and SNCR) are not similar to the proposed scrubbers. The 3% 

contingency we used is for the same type of equipment as proposed at Sooner and Muskogee. 

Second, even if the SNCR and SCR factors had been used, they would have resulted in a 

contingency that is only about one-third of the OG&E estimate,35 i.e., much less, not 

significantly more. 

 This comment claims that a 14% contingency based on total project cost is required to 

provide a 95% confidence level in the cost estimate. However, cost estimates for purposes of 

determining cost effectiveness are not based on a 95% confidence level. They need only be 

accurate to 30%.36 OG&E claims their cost estimate is accurate to within +/-20%,37 which is 

more than adequate for a cost effectiveness analysis. The overnight cost methodology in the 

Manual does not contemplate changes in fixed investment estimates that are statistically likely to 

occur in the future because the costs are based on current prices. 

 The comment also states the range estimating process used to determine contingency 

provides a more detailed estimate of contingency. However, the underlying calculations, cost 

probabilities, and Monte Carlo analysis38 are not supported in the record, preventing any 

meaningful review of this claim. 

 Finally, we note that the cost estimates prepared by Trinity for the AEP/PSO 

Northwestern plant, nearly identical units, included a contingency of only 0.7%. The owner, 

AEP/PSO, in comments on contingency, note that "[m]ultiple capital cost estimating examples 

provided in the EPA Cost Manual use a 3% contingency factor, more than four times greater 

than the contingency allowance of 0.7% (line item 41 divided by line item 32) used as the basis 

for the estimates in Appendix 2. 

 Comment: OG&E states that crew wage rates did not include contractor's general and 

administrative expenses and profit, otherwise known as Balance of Plant (BOP) profits. Thus, 

states OG&E, contractor profit was included as a separate line item, and therefore we improperly 

rejected it from the capital cost estimate on the premise that profits are embedded in labor rates, 

supplies, and materials. 

 Response:. The commenter misunderstood our approach. This does not require any 

modification to our cost analysis as we did not make any adjustments for contractor profits. 

 Comment: OG&E states that we incorrectly downgraded OG&E’s labor rates on the 

belief that OG&E overestimated the rate in the December 2009 Budget Cost Estimates, it 

 

35 Sooner contingency based on SCR/SNCR: 0.05(70,500,000) + 0.15(70,500,000 + 48,090,100) = $21,313,515 

(compared to $58,673,400 estimated by OG&E). Muskogee contingency based on SCR/SNCR: (0.05)(71,200,000) 

+ 0.15(71,200,000 + 49,601,900) = 21,680,285 (compared to $63,104,100 estimated by OG&E). 

36 Control Cost Manual, p. 1-4. 

37 12/28/09 S&L FollowUp Report, p. 2. 

38 See, e.g., AACE International, Risk Analysis and Contingency Determination Using Range Estimating, Available 

at: http://www.wsdot.wa.gov/NR/rdonlyres/BAB31979-0B6F-4AB7-841E-5666289A8021/0/RangeEstimating.pdf. 

21 
included a man-hour estimate and a crew wage rate for the installation of each major piece of 

equipment. OG&E states it based nonunion craft labor rates were developed from the 

publication “Merit Shop Wage and Benefit Survey,” published by Personnel Administration, Inc. 

(PAS), for Region 6, which includes average Journeyman rates for Arkansas, Louisiana, New 

Mexico, Oklahoma, and Texas. OG&E states costs were added to the labor rates to cover FICA, 

workmen’s compensation, federal and state unemployment insurance, and all applicable taxes. 

The resulting burdened craft rates, states OG&E, were used to develop crew rates applicable to 

the tasks being performed. In developing the crew rates, additional allowances were included to 

cover construction equipment, site overheads, small tools, and jobsite consumables and 

incidentals. OG&E believes that burdened labor rates more accurately reflect the labor costs 

associated with a large construction project. OG&E states it would be incorrect and inaccurate to 

arbitrarily remove these additional costs from the Labor Rate calculation. 

 Response: In our proposal, we noted that the labor rates used in OG&E’s cost estimates 

($40/hr – $80/hr) were excessive for an open shop project in Oklahoma and the general region, 

based on published statistics.39 However, we did not make any adjustments to Sargent & 

Lundy’s calculations because we did not have access to the electronic spreadsheets containing 

the respective calculations and Sargent & Lundy provided no supporting information. Ibid. 

 OG&E's comment explains the labor rates are actually “crew rates” that include FICA, 

workmen’s compensation, federal and state unemployment insurance, all applicable taxes, 

construction equipment, site overheads, small tools, and jobsite consumables and incidentals. 

OG&E further explains that these “crew rates” more accurately reflect the labor costs associated 

with a large construction project than “craft rates”. In its comments, OG&E suggests that the 

difference between the wage rates cited in the TSD and those used by them may have been due 

to OG&E’s inclusion of additional costs: “Costs were added to the labor rates to cover FICA, 

workmen’s compensation, federal and state unemployment insurance, and all applicable taxes. 

(OG&E comments, p. 24).” The resulting costs are referred to as “burdened craft rates.” 

However, these and other cost adders were also included in the publicly available labor rates that 

we reported in the TSD. Thus, they are not the source of the discrepancy. 

 The wages from the Bureau of Labor Statistics and FMI Management Consulting 

references we cited in the TSD include fringe benefits, including employer-provided or 

employer-paid housing, group insurance (health, dental, life etc.), disability income protection, 

retirement benefits, daycare, tuition reimbursement, sick leave, vacation (paid and non-paid), 

social security, profit sharing, funding of education, and other specialized benefits. 

 Further, FICA and unemployment insurance amount to only about 7.5% of OG&E’s 

payroll40. OG&E does not report workmen’s compensation separately, but even with that cost, 

these adders would increase wage rates by 10% or less. Additionally, as noted above, the labor 

rates that we quoted in the TSD include all fringe benefits and FICA, workmen’s compensation, 

federal and state unemployment insurance, and all applicable taxes. 

 

39 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, pages.15-18. 

40 OG&E FERC Form 1, page 264. 

22 
 The labor rates that Sargent & Lundy used are higher by a factor of two or more than 

those quoted in publicly available sources. A comment we received on behalf of a Labor 

Coalition commented on the excessive costs reported for the scrubbers and noted: "By way of 

example, such exaggerated costs apparently include OG&E wage rates for journeymen 

pipefitters which we understand were calculated at $100 per hour. GCELC [Gulf Coast 

Environmental Labor Coalition] notes for the record that the current prevailing wage rate for the 

local pipefitters union in Oklahoma is $40.80 per hour."41

 Prevailing wages is a term used in a legislative effort to provide organized labor a fair 

chance to bid for government contracts.42 Prevailing wages are defined the same way as the 

Bureau of Labor Statistics wages, i.e. they include employee's taxes, employee's portion of FICA 

and Social Security but exclude benefits. Federal law requires all employers engaged in the 

performance of federal contracts to pay "prevailing" wages to their workers. This ensures that 

nonunion employers cannot gain an unfair bidding advantage by paying wages far below the 

union rate and passing the savings on to the government in lower bids. A prevailing wage is a 

rate of pay determined by the U.S. Department of Labor based upon the particular geographic 

area for a given class of labor and type of project. The Davis-Bacon Act, the McNamara-O'Hara 

Service Contract Act, and the Walsh-Healy Act are the primary laws governing federally funded 

construction projects in the private sector.43

 Thus, the large discrepancy between S&L labor rates and publicly available information 

cannot be explained by FICA, workmen’s compensation, federal and state unemployment 

insurance, and all applicable taxes, which adds only about 10% to the base rate. Rather, it 

appears that other costs have been added to the labor rates. 

 This comment explains that certain “additional allowances” were added to the burdened 

craft rates (wage + FICA, workmen’s compensation, federal and state unemployment insurance, 

and all applicable taxes), including “construction equipment, site overheads, small tools, and 

jobsite consumables and incidentals.” The record contains no support for these adders, which 

appear to have elevated craft labor rates far above those reported elsewhere. The addition of 

construction equipment, site overheads, small tools, and jobsite consumables and incidentals to 

the labor rates is double-counting as these items are separately accounted for elsewhere in 

OG&E’s cost estimates. See, for example, line items in Conceptual Cost Spreadsheets 

captioned: "spare parts, special tools and consumables" and "temporary facilities and 

construction utilities during construction." 

 Finally, OG&E states that its craft labor rates were developed from the publication: 

“Merit Shop Wage and Benefit Survey.” However, it does not disclose the date of the survey 

that it relied on nor provide a copy of the subject survey or excerpts there from supporting its 

choices. This survey is updated yearly and is only available for a fee of $450. Thus, it is not in 

the record and cannot be reviewed. 

 We find that OG&E has failed to support its labor rates and significantly overestimated 

 

41 Comment received from Joseph M. Santarella, Counsel for GCELC, May 20, 2011. 42 http://definitions.uslegal.com/p/prevailing-wages/ 

43 http://definitions.uslegal.com/p/prevailing-wages/ 

23 
them. However, we did not make any changes to OG&E's cost estimates based on this 

conclusion, but it is one of several factors that supports our opinion that our revised costs are 

probably high. 

Comment: OG&E, states we incorrectly adjusted downward the per diem expense used 

by them in the December 2009 Budget Cost Estimates on the grounds it was excessive for the 

Oklahoma market and additionally our statement that per diem is not being paid for by “open 

shop jobs in today’s soft labor market” is similarly incorrect. OG&E states per diem costs will 

be incurred to attract and retain a skilled labor force for major construction projects as well as to 

attract the traveling labor force. OG&E states Per diem rates are not included in the wage rates, 

and thus there is no double counting. Per diem is an indirect construction cost. OG&E states 

that based on its experience with large construction projects with the current low unemployment 

in Oklahoma, a per diem allowance will be needed to attract skilled trade labor to the job sites. 

 Response: The commenter is incorrect, our proposed cost analysis did not adjust the 

OGE cost estimate downward based on excessive per diem expense. We did note a per diem 

expense of $10/hr was added to the already high labor rates for every single hour (1,790,700 

hours for Sooner and 1,854,271 hours for Muskogee) required to build the project. We further 

pointed out that per diem is not being paid for open shop jobs in today's soft labor market. This 

comment responds that per diem is required to attract and retain a skilled labor force for major 

construction projects and is required to cover a "travelling" labor force. We agree that per diem 

would be required for a portion of the workforce. However, in our opinion, per diem at the rate 

of $10/hr for a 50 hour workweek for every single worker is excessive for this general area. It 

effectively assumes that none of the workers would be drawn from the local area. Nevertheless, 

we did not make adjustments to our proposed cost analysis for per diem. 

 Comment: OG&E states we incorrectly identified the construction man-hour adjustment 

used to account for labor productivity as another form of contingency, rather than as an 

appropriate cost that is not a contingency. As a consequence, we specifically disallowed this 

cost under the Control Cost Manual, and we incorrectly deleted this cost as double counting on 

the basis that a general contingency was included elsewhere in the cost analysis. As a result, 

OG&E argues, we incorrectly deducted the 15% productivity contingency from the estimated 

capital costs. OG&E further states that applying a factor to account for labor productivity is 

common practice on large construction projects, is specifically recognized in the Cost Control 

Manual, and is necessary to address regional differences in wages. OG&E states it used the U.S. 

Productivity Factors published in the 2008 Front-End/Conceptual Estimating Year Book 

published by Compass International. Based on the available historical data from the past 20 to 

30 years, OG&E states the productivity factor for Open Shop/Non-Union labor for Oklahoma 

was listed as 1.05 in the Compass International publication. OG&E states it included an 

additional 10% factor to account for the fact that the DFGD/FF construction projects are back-fit 

projects that would require a significant amount of work in tight site conditions. In OG&E’s 

opinion, industry experience shows that back-fit projects that would require a significant amount 

of work in tight site conditions adversely affect labor productivity. 

Response: Sargent & Lundy increased the estimate of man-hours to install equipment by 

24 
15% to account for “productivity”.44 We discussed how this increase was 

unprecedented/inappropriate in a cost-effectiveness analysis, because it is another form of 

contingency, and double-counting.45 This comment states that applying a factor to account for 

labor productivity “is common practice on large construction products...” is specifically 

recognized in the Cost Manual, is consistent with certain published factors, and is necessary to 

address regional differences in wages. 

The Sargent & Lundy Design and Cost Estimate Basis Document in the 12/28/09 S&L 

FollowUp Report specifically states that “no allowances have been made to cover items such as 

the loss in productivity.”46 in direct contradiction of what it did. A labor productivity adjustment 

is not warranted based on this comment for at least five reasons. 

 First, the OG&E does not define “labor productivity.” Generally, labor productivity is 

defined relative to a defined set of work conditions.47 The labor productivity index is then 

calculated as the ratio of the job-site labor productivity under a different set of work conditions 

to the base labor productivity and is a measure of the relative labor efficiency of a project under 

this new set of work conditions. Neither this comment nor the underlying Sargent & Lundy cost 

analyses define the job-site conditions reflected in the base labor rates or the job-site conditions 

at Sooner and Muskogee that would warrant a 15% increase. Further, they provide no evidence 

that any of the citations refer to the same index of labor productivity. It is reasonable to assume 

that the vendors who quoted the erection man-hours/costs were aware of the site conditions and 

would have taken them into account in their estimates. Thus, no further adjustments are 

warranted. 

 Second, the comment claims that the Control Cost Manual recognizes “the need to adjust 

labor costs to local conditions,” citing Table 4-11 and page 4-27 (“the default values can be 

modified if location specific or vendor specific information is available”).48 This section of the 

Manual is summarizing a “CEMS Cost Model” that is used to estimate the cost of monitoring 

equipment, not pollution control equipment. The cited material does not relate to the Control 

Cost Manual methodology, but rather a methodology used in a separate model. There is no 

“default” value that should be adjusted based on a specific location or vendor information. The 

OG&E labor rates are local (Sec. 4.2.4, p. 24, labor rates) and, thus, do not need to be adjusted to 

a different location. Rather, the subject adjustment addresses the productivity of the local labor. 

Labor productivity is not addressed anywhere in the Control Cost Manual. In addition, these 

costs are included elsewhere in OG&E’s costs as overtime inefficiency. 

 Third, the comment claims the productivity factor for “open shop/non-union labor for 

Oklahoma” is 1.05, based on a report called: “2008 Front-End/Conceptual Estimating Year 

Book” published by Compass International. This claim cannot be confirmed as the subject 

report was not provided by the commenter and is not publically available on the internet or in 

 

44 12/28/09 S&L FollowUp Report, Attach. A, pdf 28 - 56. 

45 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, page 18. 

46 12/28/09 S&L FollowUp Report, Attach. A, pdf 66. 

47 See, e.g., http://pmbook.ce.cmu.edu/04_labor,_material,_and_equipment_utilization.html. 48 Control Cost Manual, Section 2, Chapter 4, pages 4-26 - 4-27. 

25 
U.S. university libraries. Furthermore, there is evidence that some productivity adjustments are 

considered to be unreliable.49

 Fourth, the comment discloses that an additional 10% was added to the 1.0550 Compass 

factor “to account for the fact that the OG&E DFGD/FF construction projects are back-fit 

projects that would require a significant amount of work in tight site conditions.” The basis for 

this further adjustment is cited to in another Compass report, The 2010 Global Construction Cost 

and Reference Yearbook, pages 527 - 529, in footnote 90. 

 This report does not support the additional 10% due to the claimed conditions. Rather, it 

notes that a "merit shop," which is not proposed here, could average the productivity factors for 

open shop (1.05) and union (1.15),51 which for Oklahoma would result in factor of 1.10, not 

1.15. Regardless, a merit shop has not been proposed and the cited material does not support the 

adjustment for backfit projects and tight site conditions.52 

 Fifth, the 2010 Compass Report explains that the productivity factors that Sargent & 

Lundy used are benchmarked for the Texas Gulf Coast. In other words, if you have a labor 

estimate based on Texas Gulf Coast hours, you could, for example, adjust it to Oklahoma by 

multiplying it by a factor of 1.05. The Sooner and Muskogee cost estimates are based on local 

Oklahoma data.53 Thus, there is no basis to adjust Oklahoma data based on the Texas Gulf 

Coast. 

 Sixth, the record contains no support for the claim that the subject work involves “backfit projects that would require a significant amount of work in tight site conditions.” In fact, the 

12/28/09 S&L FollowUp Report states that “[i]n degree of difficulty, the retrofits at Sooner and 

Muskogee could be described as average.”54 We are not aware of cost-effectiveness analyses of 

average retrofit difficulty that increased labor costs in this manner. 

 Finally, this comment points to the Kaplan report as justification for including a 

productivity factor, claiming that it includes a list of cost multipliers that include regional cost 

factors and access/congestion factors that are derived from empirical data for specific conditions 

and are necessary to adjust reference prices to local conditions. The Kaplan report cited in 

footnote 91 does not contain any “labor productivity factors” including regional cost factors and 

access/congestion factors. Further, based on this list, even if it did, none of these are “labor 

productivity factors,” the subject of this comment. 

 

49 R. Brunies and Z. Emir, Calculating Loss of Productivity Due to Overtime Using Published Charts -- Fact or 

Fiction, The Revay Report, v. 20, no. 3, November 2001, Available at: http://www.danzpage.com/ConstructionManagement-Resources/Calculating_Loss_of_Productivity_Due_to_OT_Using_Charts_-_Nov_2001.pdf. 50 1.05 + 0.1 = 1.15 or a 15% increase in the number of hours to perform all tasks. 

51 See Compass International Consultants, The 2010 Global Construction Cost and Reference Yearbook, pp. 527-

529, cited in footnote 90. See Compass International Consultants, The 2010 Global Construction Cost and 

Reference Yearbook, pp. 527-529, cited in footnote 90. 52 See Compass International Consultants, The 2010 Global Construction Cost and Reference Yearbook, pp. 527-

529, cited in footnote 90. 

53 12/28/09 S&L FollowUp Report, p. 6 (Labor cost estimates were developed using Oklahoma area wage rates, 

installation quantities, and installation rates taken from the S&L database."). 54 12/28/09 S&L FollowUp Report, pdf 6. 

26 
 Comment: OG&E states we incorrectly stated that the overtime inefficiency adjustment 

was “another form of contingency, specifically disallowed by the Control Cost Manual, and that 

it should also be considered double counting as a general contingency was included elsewhere in 

the cost analysis. OG&E states we incorrectly assumed that the new scrubbers would be 

installed during normal maintenance outages by working five 10 hour days and that the efficient 

scheduling of the labor pool should not result in an overtime inefficiency. OG&E stated a 50 

hour work week would be needed to attract and retain the construction labor force necessary to 

complete the DFGD/FF construction projects. According to OG&E, numerous publications 

support these overtime and labor productivity assumptions. OG&E states it’s overtime 

inefficiency line-item accounted for scheduled overtime that would be incurred when a 

construction project extends over a 3 to 4 year period. OG&E calculated overtime inefficiency 

costs as a loss of labor productivity based on hours worked per week and assuming an overtime 

cost equal to 1.5 times the base pay rate. Therefore, states OG&E, we incorrectly set overtime 

inefficiency equal to zero. 

Response: The OG&E cost analyses contains another contingency in the "other costs" 

portion of its spreadsheets, called "cost due to overtime inefficiency working 5x10s."55 It 

amounts to an additional $10 million at each station. We eliminated this cost as another form of 

contingency, specifically disallowed by the Control Cost Manual and found that it double counts 

other contingencies. The new scrubbers would be installed during normal maintenance outages. 

Efficient upfront planning and scheduling of the labor pool should not result in an overtime 

inefficiency.56 Therefore, there is no reason to plan for inefficiency. The 12/28/09 S&L 

FollowUp Report contains no support for overtime inefficiency. 

 This comment explains that a 50-hour work week would be required to attract and retain 

construction labor necessary to complete the projects. The comment further explains the 

resulting longer work week would adversely affect labor productivity. This was included in the 

cost analyses as about 8.75% of the total manhours costed at $66/hr-$67/hr. 

 

First, we cannot determine whether the claimed loss in productivity due to a 50-hour 

work week is captured in the 1.15 labor productivity factor discussed above because none of the 

cited references to support the 1.15 productivity factor were produced by the commenter nor are 

they publicly available. 

 Second, the references cited in footnotes 92 - 96 in support of the overtime inefficiency 

adjustment also were not produced and are not publicly available.57 However, information that 

we independently found indicates that overtime productivity estimates, such as those cited in this 

 

55 12/28/09 S&L FollowUp Report, Attach. A, pdf 40, 55. 

56 See discussion of "Overtime and Productivity" at http://www.delmar.com/Templates/Overtime%20and%20Productivity.pdf. 

57 The cite in footnote 92 to the 2010 RS Means report, "Labor Rates for the Construction Industry 2010" costs 

$380.00. The second cite in this footnote, RS Means Engineering, December 2009, p. 316, is an incorrect cite. The 

report itself is also available at a cost. The cite in footnote 93 to the June 18, 2009 Engineering News-Record, p. 60, 

is incorrect. The MCAA bulletins cited in footnotes 95 and 96 are not publically available, online, or otherwise for 

sale. 

27 
comment, are sometimes considered to be unreliable.58 

 Third, the commenter has presented no evidence that a 50-hr workweek must be offered 

to attract and retain construction labor necessary to complete the scrubber projects. Although 

some offered 50 hour work weeks, many recent ads for construction workers posted on an online merit-shop jobs listing site59 and the Zachry Construction (major nonunion construction 

firm) website,60 offered only 40 hours of work per week at the time we examined the site. Longterm work, such as required for the scrubber projects, would be more likely to offer 40 hours, 

compared to short-term shutdown or turnaround work. Therefore, considering the large amount 

of additional labor costs involved and the failure of OG&E to demonstrate that a overtime 

inefficiency adjustment was necessary, we find this should be set to zero in the cost estimate. 

 Comment: OG&E states we incorrectly removed the owner’s cost, which was estimated 

at 5% of the total capital expended in its December 2009 Budget Cost Estimates on the grounds 

it double counted certain indirect capital costs associated with financing and constructing the air 

pollution control systems and was excessive. OG&E states that based on a review of its cost 

estimates, we incorrectly concluded that owner’s costs have been double counted in the cost 

estimates for the Sooner and Muskogee units. OG&E states owner’s costs are project specific 

and include costs incurred by the owner to manage the project, hire and retain staff to support the 

project, and costs associated with third party assistance associated with project development and 

financing. OG&E states our Coal Quality Environmental Cost model includes model costs in its 

air pollution control system cost estimating workbook of a factor of 10% of the total installed 

cost to estimate owner’s costs and engineering costs for limestone forced oxidation and lime 

spray dryer control systems. 

Response: In our proposal, we stated61 that owner's costs were double counted, i.e., they 

are included in two places, as a separate line item of 5% of TCI and under indirect capital cost. 

This comment ignores our argument that they are double counted and instead argues that owners 

costs are real costs and are included in the CUECost model. We agree that owners costs are real, 

are part of the cost of building a scrubber, and thus are valid costs under the overnight costing 

method. However, here, they have been included twice. The Sargent & Lundy cost analyses 

include owner's costs as a separate indirect capital cost, estimated as 5% of total capital 

expended. The costs that owners incur are also included under "indirect capital cost," which also 

includes engineering/procurement estimated at 6.5% of total direct costs and construction 

management, estimated as 2% of total direct costs. These factored costs (which are not site 

specific, but rather based on general factors) are high compared to costs that result when using 

the factors in the Control Cost Manual (both engineering and construction/field expenses are 

estimated as 10% of purchased equipment costs). Owner's cost is part of the factored estimate 

 

58 R. Brunies and Z. Emir, Calculating Loss of Productivity Due to Overtime Using Published Charts -- Fact or 

Fiction, The Revay Report, v. 20, no. 3, November 2001, Available at: http://www.danzpage.com/ConstructionManagement-Resources/Calculating_Loss_of_Productivity_Due_to_OT_Using_Charts_-_Nov_2001.pdf; 

H. R. Thomas, Effects of Scheduled Overtime on Labor Productivity, Available at: 

http://cmdept.unl.edu/drb/Reading/overtime2.htm. 

59 http://www.industrialprojectsreport.com/site/links.aspx 

60 http://zhi-craft.jobs.net/. See, e.g., postings for pipefitters. 

61 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, page 19. 

28 
for engineering, procurement, and construction management. The Control Cost Manual does not 

provide that Owner's costs are separately included in BART cost effectiveness analyses, and they 

have been more than double counted here 

 This comment supports the use of 5% of TCI for owners costs by pointing to the 

CUECost model, which estimates owners cost as 10% of total installed cost. However, using the 

CUECost model is not an appropriate stand-alone cost model for BART determinations because 

it does not follow the overnight cost methodology of the Control Cost Manual. Further, we note 

that OG&E estimated owners costs as 2% of total capital expended in other BART analyses.62 It 

has long been EPA's policy to exclude owners costs when estimated as a percent of the TCI as 

these costs are included in indirect installation costs. In its May 10, 2010 formal comments to 

the North Dakota Department of Health, for example, EPA rejected the inclusion of "owner's 

costs" in a cost analysis for the Milton R. Young facility63 and likewise omitted these costs in the 

recently proposed North Dakota FIP.64

 Comment: OG&E states we incorrectly attributed a portion of their 

engineering/procurement costs as double counted. OG&E states our assumption that “vendor 

proposals that Sargent & Lundy relied on include the cost to both design and supply the dry 

scrubber and baghouse” is incorrect. Thus, argues OG&E, because they also separately 

calculated engineering/procurement, our assumption that the engineering and procurement costs 

for the vendor-supplied portion of the capital costs were double counted are incorrect. 

OG&E states that major equipment engineering and procurement costs are included as 

part of the vendor equipment costs; however, there are significant engineering and procurement 

costs associated with balance-of-plant (BOP) equipment and integrating the control system into 

the existing facility. OG&E states major equipment suppliers, including those who supplied 

estimates in connection with the December 2009 Budget Cost Estimates, furnish their equipment 

with no foundations or other support structures and do not integrate the control systems into the 

existing facility for functional operation. OG&E states the Engineering/Procurement line item 

includes the costs for engineering and procuring all BOP equipment, including ID fans, dampers, 

expansion joints, pumps, air compressors, and electrical equipment (high voltage power 

transformers, switchgear, motor control centers). OG&E also states the 

Engineering/Procurement also includes the engineering design and detailed drawings for 

buildings, support steel, foundations, ductwork, BOP piping, BOP compressed and instrument air 

systems, electrical design (including auxiliary power requirements, raceway, conduits, cabling, 

controls, and instrumentation), resolving interferences, and preparing a general work installation 

specification. 

Response: OG&E estimated engineering and procurement as 6.5% of the total direct 

 

62 See, e.g., Sargent & Lundy, Dry FGD and ID Fan & Auxiliary Power Conceptual Design Costs, Conceptual Cost 

Estimate, Prepared for Nebraska Public Power District, Gerald Gentleman Station, Units 1&2, February 7, 2008. 63 Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry O'Clair, Director, 

Division of Air Quality, North Dakota Department of Health, Re: EPA's Comments on the North Dakota 

Department of Health's April 2010 Draft BACT Determination for NOx for the Milton R. Young Station, May 10, 

2010. 

64 76 FR 58570. 

29 
costs, which amounts to $21,144,700 for Sooner and $21,784,400 for Muskogee.65 We reduced 

these costs as the vendor proposals indicated a portion of these costs were double counted. The 

vendor proposals include the cost to both design and supply the dry scrubbers and baghouses, 

which include the cost of engineering and procurement. Sargent & Lundy also separately 

calculated engineering/ procurement costs on top of the vendor-supplied portion of the capital 

costs and thus double counted them. We applied Sargent & Lundy's 6.5% 

engineering/procurement factor only to the balance of plant materials and labor, excluding the 

scrubber system, fabric filter, and the scrubber contractor's scope for the ash recycling system 

since these items already included engineering and procurement costs. This adjustment 

eliminated the double counting. 

 This comment agrees that major equipment engineering and procurement costs are 

included as part of the vendor equipment costs. However, it notes "there are significant 

engineering and procurement costs associated with balance-of-plant (BOP) equipment and 

integrating the control system into the existing facility." We agree and therefore estimated BOP 

engineering and procurement costs based on the total direct cost of only balance of plant 

equipment and other costs not otherwise included in the vendor quotes. 

 This comment additionally claims that the major equipment suppliers, including those 

who provided the estimates for the Sooner and Muskogee scrubbers "furnish their equipment 

with no foundation or other support structures and do not integrate the control systems into the 

existing facility for functional operation." This is partially incorrect. Although the Division of 

Responsibility table in the requests for quote sent to the vendors lists foundations as the owner’s 

responsibility, it specifically required that "all steel integral to support the FGD and Baghouse 

vendor's equipment and ducts" be included in the FGD vendor's scope. The vendor quotes 

specifically identified support steel for the SDA, baghouse and connecting ducts and detailed 

arrangement and erection drawings. The vendor quotes also included estimates for erection. 

 This comment goes on to explain that the "engineering/procurement" line item includes 

the costs for engineering and procuring all BOP equipment including ID fans, dampers, 

expansion joints, pumps, air compressors, and electrical equipment as well as engineering design 

and detailed drawings for buildings, support steel, foundations, ductwork, BOP piping, BOP 

compressed and instrument air systems, electrical design, resolving interferences, and preparing 

a general work installation specification." We agree these are valid costs, but some of them were 

included in the vendor quotes, such as support steel, ductwork between the absorber and 

baghouse, and FGD electrical work, and thus they were double counted. 

 This comment additionally states that 6.5% of total direct cost is reasonable for the 

installation and integration of the DFGD and FF control systems. We agree if the total direct 

cost that this factor is applied to exclude the costs of the FGD, fabric filter, and ash handling 

system, which were fully costed in the vendor proposal, i.e., the cost for engineering and 

procurement were already accounted for. Thus, we find that our original revision remains 

appropriate. 

 Comment: OG&E states we incorrectly attributed double counting to BOP construction 

 

65 12/28/09 S&L FollowUp Report, pdf 40, 56. 

30 
management costs in two places in their Cost Estimate: first, under “total indirect costs” where 

construction management was estimated as 2% of the total direct costs; and second under “other 

costs” where the BOP contractor’s general and administrative costs were estimated as 5% of 

BOP materials and labor costs. OG&E explains that BOP contractor’s general and 

administrative (“G&A”) costs and the construction management cost shown as an indirect capital 

cost in its December 2009 Budget Cost Estimates are two distinct line items and do not double 

count the construction management costs. As OG&E discusses elsewhere, crew wage rates in 

the cost estimate included base pay for skilled crafts, fringe benefits, worker’s compensation, 

federal and state unemployment insurance, and applicable taxes, but do not include contractor 

G&A expenses or profit. Therefore, per OG&E, contractor G&A was included as a separate line 

item in the cost estimate. 

Response: In our proposal, we revised the cost estimate to remove double counting of the 

balance of plant (BOP) construction management costs. This comment explains that crew wage 

rates do not include contractor G&A expenses or profit and that construction management is the 

cost of third-party construction management, different from the BOP contractor and different 

from the owner. Based on this explanation, we have restored the construction management costs 

in our revised Options 1 and 2 cost estimates in Exhibits 1 and 2. 

 Comment: OG&E states we incorrectly attribute double counting to the vendor proposals 

relied on to prepare the December 2009 Budget Cost Estimates on the ground they included the 

cost to commission the units; thus, including a line item for startup and commissioning resulted 

in double counting. 

OG&E states that equipment suppliers, including those who provided estimates in 

connection with the December 2009 Budget Cost Estimates, provide very limited field support 

during control system startup and commissioning. The Start-up & Commissioning line item, per 

OG&E, accounts for the craft support required by the general work contractor (as opposed to the 

equipment suppliers) during the duration of start-up and commissioning (which can take several 

months). OG&E states that project schedules developed for the Sooner and Muskogee DFGD 

projects included a five-month startup/commissioning duration for the first unit and an additional 

five-months for the second unit, but not at the same time. OG&E asserts that the 10 months of 

craft support will require extended mobilization, supervision, and labor costs to help the owner 

during the startup/commissioning period. OG&E concludes that cost estimates provided by the 

equipment suppliers include limited field support during startup, but do not include all of the 

craft support needed during startup and commissioning; thus, there is no double counting, and it 

is incorrect and inaccurate for us to exclude these costs from the cost estimate. 

Response: Sargent & Lundy estimated startup and commissioning craft support, an 

indirect line item cost, as 2% of an unidentified capital sum about 8% less than the vendor 

portion of equipment, materials and labor costs (e.g., $163,695,000 for Sooner). These costs 

amounted to $3,273,900 for Sooner and $3,417,600 for Muskogee.66 However, the vendor 

proposals that Sargent & Lundy used include those cost to commission the units. Thus, these 

costs are double counted and are eliminated in Exhibit 1, Line 36. 

 

66 12/28/09 S&L FollowUp Report, pdf 40, 56. 

31 
 This comment states that equipment suppliers provide very limited field support during 

control system startup and commissioning and that the Start-up and Commissioning line item 

accounts for "the craft support required by the general work contractor (as opposed to the 

equipment suppliers) during the duration of start-up and commissioning (which can take several 

months). This comment also states that this support will require 10 months of craft support for 

extended mobilization, supervision, and labor costs. However, one of the vendor quotes 

specifically states that their scope of supply is to "design, supply and commission" the SDA/FF 

system. Another vendor states in a section captioned Site Service: "Field Service Personnel will 

be supplied for startup and check-out assistance as well as for plant personnel training. [This 

bidder] will also provide an erection advisor to be on-site during equipment installation." 

 The schedule that OG&E prepared for these projects shows that it assumed that the 

startup and commissioning of each unit would take 140 hours over about a 2 month period as 

opposed to the 10 months it stated it required in their comment to EPA’s proposal.67 Therefore, 

it appears that OG&E overstated the installation time as well as double counted startup & 

commissioning craft, given the vendor quotes. Thus, we find that startup and commissioning 

was double counted and no adjustment in our Options 1 and 2 cost estimate in Exhibits 1 and 2 

are required. 

 Comment: OG&E states that we incorrectly assumed the vendor proposals relied on to 

prepare the December 2009 Budget Cost Estimates included operator training and manuals, thus 

incorrectly removed these costs. OG&E states that including a line item for operating training 

and manuals is not double counting. OG&E states that operator training costs are not generally 

included in budgetary proposals received from equipment vendors and were not included in the 

proposals received in connection with the December 2009 Budget Cost Estimates. Furthermore, 

argues OG&E, because of the staggered start-up schedule for each station discussed above, 

separate operator training will be required. OG&E states that operator training and manuals 

costs included in the December 2009 Budget Cost Estimates were based on its contractor’s 

previous experience for similar type and size applications and include manuals for major FGD 

equipment as well as all BOP equipment. In addition, according to OG&E, budgetary proposals 

from the equipment vendors do not include costs for operating manuals. Because these costs are 

not included in the vendor quotes, per OG&E, there is no double counting, and it is incorrect to 

exclude these costs from the cost estimate. 

Response: OG&E estimated operator training and manuals, an indirect cost, as 0.55% of 

the total construction & erection cost portion of total equipment, material and labor. These costs 

amounted to $900,300 for Sooner and $939,800 for Muskogee.68 We eliminated these costs in 

the TSD as they were included in the vendor proposals and thus double counted. 

 This comment states that operator training costs are not generally included in budgetary 

proposals and were not included in the proposals for this job. However, as noted –elsewhere in 

our response to comments, one vendor specifically stated that "personnel training" was included. 

 This comment also states that budgetary proposals from equipment vendors do not 

 

67 12/28/09 S&L FollowUp Report, Attachment 6, Project Schedule. 

68 12/28/09 S&L FollowUp Report, pdf 40, 56. 

32 
include operating manuals. It is standard practice to include the cost of an operating manual with 

the cost of an expensive piece of complex pollution control equipment, such as the subject 

SDA/FF. The basic manual is the same for all similar models of an SDA/FF; only minor 

modifications are required to tailor a manual to a site specific application. These costs are minor 

and are generally included in categories such as "other" noted in all the vendor quotes. They are 

generally too small to break out as a separate line item. We note that Sargent & Lundy's IPM 

cost models prepared for the EPA for fabric filters and SDA FGD69 do not separately breakout 

commissioning, personnel training or manuals. These costs are imbedded in the costs of the 

controls, which calculated under the Sargent & Lundy IPM cost models are less than the costs 

claimed by Sargent & Lundy for Sooner and Muskogee. Thus, we find our decision to eliminate 

the operator and training manual costs remains appropriate. 

 Comment: OG&E states that under the Control Cost Manual methodology, total capital 

costs are annualized by calculating an annual payment sufficient to finance the investment over 

its entire life. OG&E asserts we incorrectly found they did not follow the Control Cost Manual

when they calculated the annual capital recovery cost, and that their O&M cost estimates 

required adjustments. 

OG&E further states that the "Control Cost Manual does not limit the analyst to using 

that method [CRF], nor does the Cost Control Manual dictate using a 7% social discount interest 

rate in the calculation. In support of this, OG&E references Section 2.4.2 of the Control Cost 

Manual (Interest Rates) and states that the social discount rate of 7.0% may be used when "State, 

local, Tribal, and other governmental authorities assess pollution control costs;" however, "the 

social rate of interest is probably not appropriate for industry." OG&E goes on to claim that 

"[b]ecause OG&E is an investor-owned utility company and not a governmental agency, the 

Control Cost Manual suggests that it use an appropriate discount rate that more accurately 

reflects OG&E's capital structure." OG&E notes that "capital investment costs for an investorowned utility such as OG&E are recovered by annual revenue requirements after the facility 

becomes operational and placed into the rate base. These revenue requirements consist of capital 

recovery, debt return, equity return, and income taxes." 

OG&E states the CRF includes not only recovery of principal but also a return on the 

principal, with the rate of return equal to the discount rate. OG&E asserts that for an investor 

owned utility such as OG&E, which is financed by a mix of debt and equity, the discount rate is 

equal to the weighted average of the equity return and debt return. OG&E alleges that the use of 

the CFR in the Cost Control Manual provides only a simplified derivation of the annual capital 

charge rate for entities that do not pay income taxes, such as a municipality or governmental 

agency and is inaccurate if applied to investor-owned utility companies such as OG&E. OG&E 

states that a more complete derivation of the annual capital costs based on OG&E's companyspecific capital structure is included in Attachment B, Table B-5 of the 12/29/2009 S&L 

FollowUp Report. 

Response: The calculation of capital costs in the Control Cost Manual includes two 

 

69 IPM Model – Revisions to Cost and Performance for APC Technologies, Particulate Control Cost Development 

Methodology, Final, March 2011, Project 12301-009, Systems Research and Applications Corporation. Prepared by 

Sargent and Lundy 

33 
separate steps. First, the TCI is determined based on overnight costs with no inflation or interest 

during construction. Second, the TCI is turned into an annual cost by multiplying it by a 

carrying charge that in normal utility practice would include the interest, equity return, recovery 

of the initial investment, and taxes, plus operating and maintenance expenses of the plant, once 

built. However, the Control Cost Manual does not seek to duplicate normal utility practice. 

Section 2.4.2 of the Manual states: 

[T]he industrial planner must . . . understand how the cost of each device fits into 

the financial structure of their business . . . . [T]he source may find it useful to 

apply their own interest rate to the calculation of control costs. Common interest 

rates used by industry and accepted by the EPA for source petitions include the 

business’ current borrowing rate, the current prime rate, and other acceptable 

industrial rates of return. 

 Only debt is specifically listed in the allowed carrying costs. "Industrial rates of return" 

might include the utility's debt and equity, but there is no reference to taxes. However, taxes are 

a significant component of the cost in levelized interest rate of 10.36% used in 12/28/09 S&L 

FollowUp Report, Table B-5, which OG&E holds up as the proper method for calculating its 

annualized capital costs. 

 The Control Cost Manual states "this Manual methodology does not consider income 

taxes."70 Thus, even assuming OG&E’s levelized capital recovery method, the Control Cost 

Manual itself prohibits the inclusion of income taxes as a cost. Furthermore, OG&E does not 

offer any precedent for inclusion of income taxes in the capital recovery factor (or elsewhere in 

the cost-effectiveness computation). OG&E also does not offer any cost effectiveness values for 

other similar facilities calculated in the same way as it proposes in Table B-5, including taxes. 

Thus, for comparability with other cost-effectiveness computations and consistency with the 

Control Cost Manual, income taxes must be excluded from the levelized capital recovery factor, 

along with AFUDC and inflation to arbitrary years (discussed elsewhere in our response to 

comments). 

 

 OG&E states that the nominal return on equity of 10.75%, the "levelized capital recovery 

factor (LCRF)," used to annualize total capital investment, was calculated from a real interest 

rate of 8.05% determined from: {[(1.1075)/1.025)]-1}X 100 = 8.05%, which compares with our 

7% social cost of interest. The real discount rate was then determined as (0.557 X 8.05%) + 

[(0.443 X 3.44%) X (1-0.3812)] = 5.43%. (p. 32). The tax, not allowed under the Control 

Manual method, is the quantity in the last set of parentheses or (1-0.3812). Thus, the weighted 

real cost of capital for OG&E, revised to exclude taxes, is (0.557 X 8.05%) + (0.443 X 3.44%) = 

6.01%. 

 This is less than the 7% social-cost default rate that we used to annualize total capital 

investment. Substituting 6.01% and a 20 year life into the CRF formula in Eq. 2.8a of the 

Manual yields a CRF of 8.72%, rather than the LCRF of 10.36% used by OG&E. The 7% social 

discount rate would yield a 9.44% CRF. Thus, the site-specific calculation for the OG&E units, 

using its method, corrected to exclude taxes, yields a lower CRF than the default values of 7% 

 

70 Chapter 2, p. 2-9. 

34 
that we used in our revised cost analyses. The CRF would be even lower if a 30 year life is used, 

as discussed below. 

 Thus, we have revised our cost effectiveness analysis in Exhibits 1 and 2 for Options 1 

and 2, to use the levelized interest rate of 6.01% as reported by OG&E, adjusted to remove 

income taxes. This is consistent with OG&E's real average cost of capital and falls within the 

range of 3% to 7% recommended by OMB for regulatory cost analyses.71

Regardless, we note that OG&E's calculation of interest rate as included in the levelized 

cost recovery factor in the 12/28/09 S&L FollowUp Report, Table B-5, is incorrect and 

overstated. 

 OG&E makes two serious errors in its development of the levelized cost recovery factor. 

First, OG&E assumes straight-line tax depreciation of the scrubber cost, at 5% annually over 

twenty years. In fact, the Internal Revenue Code allows the amortization of “atmospheric 

pollution control facilities” acquired and placed in service after April 11, 2005, in connection 

with an electric generation plant or other property placed in operation after December 31, 1975, 

that is primarily coal fired, to be amortized over 84 months.72 Hence, the scrubbers could be 

amortized over 7 years, at 14.3% annually. 

 Realistic treatment of the tax depreciation would generate large deferred taxes, starting 

with 14.3% – 5% = 9.3% X 38% tax rate = 3.5% of the original plant investment at the end of 

year one, and 24.8% of the original investment (about 37% of the remaining investment) at the 

end of year seven. OG&E includes a line for deferred taxes, but sets them to zero, incorrectly 

assuming that there are no tax depreciation benefits. Including the seven-year tax depreciation 

schedule would reduce OG&E’s estimate of the carrying charge by about 1.3%, to 9.1%. 

 Second, OG&E uses a mixture of real and nominal rates in Table B-5. The debt rate 

appears to be expressed in real terms, but the equity return is expressed in much higher nominal 

terms. Having produced a revenue-requirement cash flow in mixed dollars, OG&E presents 

values that result in an after-tax real discount of 5.43% (see OG&E comments, Exhibit B, p. 32), 

producing a much higher cost than if it had discounted at the mix of real and nominal returns it 

used in the computations. The rate was 10.75% for 55.7% equity, and 3.44% for 44.3% debt, 

with a 31% tax shield, or 6.93% overall. If OG&E had levelized its estimates of the annual 

revenue requirements at 6.93%, and then properly levelized at the real discount rate, the result 

would be a levelized carrying charge of 9.35%, a full point lower than their estimate. 

 Combining these corrections, results in a levelized carrying charge of 8.1%. We believe 

it is possible that a properly computed analysis, using nominal rates throughout, converting the 

annual revenue requirements to real dollars, and levelizing in real terms, would result in an even 

lower rate. 

 Comment: OG&E states we incorrectly calculated the CRF because we assumed a 

scrubber life of 30 years. OG&E states that our use of a 30-year scrubber lifetime to calculate 

 

71 http://evans.washington.edu/files/bca_center/BCA_PG_Final_10_31_08.doc. 72 IRS Publication 535 (2010), Business Expenses, Chapter 8. 

35 
the CRF is arbitrary. OG&E also argues that "useful life" used in the Control Cost Manual is not 

the same as actual service life, that "economic life" is sometimes appropriate, and thus actual age 

of existing scrubbers is not the appropriate measure. OG&E further state that our examples of 

other facilities use of a 30 year lifetime is not appropriate, is not supported by the Control Cost 

Manual, and have not been demonstrated to be operational for the full 30 years. 

AEP/PSO states that the capital recovery charges we employ in our SO2 BART analysis 

of the Northeastern units are understated by over $32 million, as a result of increasing the service 

life to 30 years, reducing the interest rate from 8 to 7%, and using a PEC that is $258 million 

below realistic estimates. AEP/PSO states we attempt to justify the use of a 30-year service life 

by identifying units that were built in the late 1970s and early 1980s and originally equipped 

with FGD systems that are still operating. However, states AEP/PSO, the TSD cites no 

examples of units that were over 30 years old and then retrofit with FGD systems, and operated 

for an additional 30 years. AEP/PSO states the operating lives of electric generating units are 

highly variable, and the 20-year remaining life of the Northeastern units was based on a realistic 

assessment of the units’ operating characteristics and economic value. AEP/PSO states we 

presented no basis why 30 years might be more appropriate than 20 years (for example: EPA 

guidance, ODEQ experience, BART guidelines, etc.). 

In other comments, AEP/PSO takes issue with our statements in the TSD73: 

Scrubber vendors indicate that the lifetime of a scrubber is equal to the 

lifetime of the boiler, which might easily be over 60 years. There are, for 

example, many scrubbers that were installed between 1975 and 1985 that 

are still in operation today (e.g., Coyote Station, H.L. Spurlock Unit 2, 

East Bend Unit 2, Laramie River Unit 3,48 Cholla 5, Basin Electric, 

Mitchell Unit 33). Standard cost estimating handbooks74 and published 

papers75 report 30 years as a typical life for a scrubber. 

Further, many utilities routinely specify 30+ year lifetimes in requests for 

proposal and to evaluate proposals. The original Sargent & Lundy cost 

estimate, for example, assumed a 25 year lifetime, which was lowered to 

20 years in the revised 2009 analysis without comment. The BART 

determination for Big Stone Unit 1, on-line in 1974, assumed a 30 years 

scrubber life. Thus, I used 30 years in my revised cost estimates. 

AEP/PSO states these statements lack support. 

Response: In the section of the Control Cost Manual on the capital recovery factor, the 

subject of this comment, control equipment lifetime is clearly defined as the entire life of the 

control. For example, on page 2-19, the Control Cost Manual states: “For each alternative: 

calculate a discounting factor each year over the life of the equipment....” and on page 2-21: “In 

 

73 Ibid., TSD page 14. 

74 William M. Vatavuk, Estimating Costs of Air Pollution Control, Lewis Publishers, 1990, p. 198. 

75 J. Warych and M. Szymanowski, Optimum Values of Process Parameters of the “Wet Limestone Flue Gas 

Desulfurization System, Chemical Engineering & Technology, v. 25, 2002, pp. 427-432. 

36 
essence, annualization involves establishing an annual "payment" sufficient to finance the 

investment for its entire life, using the formula...[CFR]...where PMT is the equivalent uniform 

payment amount over the life of the control, n, at an interest rate, i.”76 The variable n in the 

CRF equation used to annualized total capital investment is thus the actual life of the control, as 

we used in our revised cost analysis, and not the economic life as argued in this comment. 

 While Table 2.3 in the Control Cost Manual does mention an "economic life," the text 

proceeding the table defines "economic life" as "useful life."77 The term "useful life" as used in 

the Control Manual is the same as the actual service life, at the end of which the equipment is 

replaced. See, for example, page 2-18: “While payback considers both projects to be equal, the 

second project would actually cost more over the ten year period because it would have to be 

replaced at the end of its useful life.” See also page 2-20: “So, instead of paying up front for all 

the future costs of installation, maintenance, and operation of a pollution control device (NPV 

analysis), what if the payment could be equalized (in constant net present value dollars) over the 

life of the control?”78 Thus, under the Control Manual definition, equipment is replaced at the 

end of its useful life and is synonymous with service life or equipment life. 

 The comment also states that our use of 30 years for the service life of the scrubber is 

"arbitrary." We disagree. We supported our estimate. First, we noted that scrubber vendors 

indicate that the lifetime of a scrubber is equal to the lifetime of the boiler, which might easily be 

well over 60 years. Second, we identified specific scrubbers installed between 1975 and 1985 

that are still in operation today.79 Third, we cited to standard cost estimating handbooks80 and 

published papers81 that report 30 years as a typical life for a scrubber. Fifth, we noted that 

Sargent & Lundy's 2008 cost estimate assumed a 25 year lifetime, but lowered it to 20 years in 

the revised 2009 analysis without explanation. Sixth, we pointed to the BART determination for 

Big Stone Unit 1, on-line in 1974, which assumed a 30 years scrubber life. Finally, we note that 

the Kaplan report, cited by Sargent & Lundy in its comments in a number of places for the truth 

of various matters (e.g., inclusion of AFUDC at 21, cost of auxiliary power at 35), reported the 

"book life" of scrubbers as 30 years and the "tax life" as 20 years.82 Further, we have assumed a 

30-year lifetime for scrubbers since at least 1981.83

 

76 Control Cost Manual, pp. 2-19, 2-21, emphasis added. 

77 Control Cost Manual, p. 26. 

78 Control Cost Manual, pp. 2-18, 2-20. 

79 See, for example, EPRI, A Review of Literature Related to the Use of Spray Dryer Absorber Material: Production, 

Characterization, Utilization Applications, Barriers, and Recommendations, December 6, 2006, Table 1-2. 80 William M. Vatavuk, Estimating Costs of Air Pollution Control, Lewis Publishers, 1990, p. 198. 81 J. Warych and M. Szymanowski, Optimum Values of Process Parameters of the “Wet Limestone Flue Gas 

Desulfurization System, Chemical Engineering & Technology, v. 25, 2002, pp. 427-432. 82 Kapland et al., Retrofit Costs of SO2 and NOx Control at 200 U.S. Coal-Fired Power Plants, Presented at the 1990 

Pittsburgh Coal Conference, September 11, 1990. 

83 EPA/TVA (T.A. Burnett and K.D. Anderson,), Technical Review of Dry FGD Systems and Economic Evaluation 

of Spray Dryer FGD Systems, Prepared for U.S. EPA, Report EPA-600/7-81-014, TVA EDT-127, February 1981, 

pp. xxvii, xxxiv, 84 (30-year economic and tax life for a dry FGD/FF). 

http://nepis.epa.gov/Exe/ZyNET.exe/20006OVC.TXT?ZyActionD=ZyDocument&Client=EPA&Index=1981+Thru

+1985&Docs=&Query=600781014&Time=&EndTime=&SearchMethod=1&TocRestrict=n&Toc=&TocEntry=&Q

Field=pubnumber%5E%22600781014%22&QFieldYear=&QFieldMonth=&QFieldDay=&UseQField=pubnumber

&IntQFieldOp=1&ExtQFieldOp=1&XmlQuery=&File=D%3A%5Czyfiles%5CIndex%20Data%5C81thru85%5CT

xt%5C00000000%5C20006OVC.txt&User=ANONYMOUS&Password=anonymous&SortMethod=h%7C-

&MaximumDocuments=10&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&D

37 
 In quoting the Control Cost Manual, OG&E asserts that “In general, useful life varies 

according to the type of control system and with the severity of the environment in which the 

control system is installed.” We agree. The subject application, the use of a scrubber to remove 

SO2 from low sulfur coal, is a mild environment for a scrubber, compared to high sulfur 

applications, which have already demonstrated 30 year lifetimes. The corrosion potential and 

bag plugging issues in a low sulfur application are much lower than in a comparable high sulfur 

application.84

 OG&E also asserts that the Control Cost Manual assumes a 20 year useful life for other 

large air pollution control systems, citing 20 years for a fabric filter baghouse and 20 years for 

SCR. The cite of 20 years for the baghouse actually says: "For fabric filters, the system lifetime 

varies from 5 to 40 years, with 20 years being typical," citing to a 1980 report.85 Significant 

advances have been made in the material of construction and baghouse design since this 

publication.86 Further, the 1981 EPA/TVA report cited above, "Technical Review of Dry FGD 

Systems and Economic Evaluation of Spray Dryer FGD System" assumes a 30 year economic 

and tax life for an SDA/FF, which includes the fabric filter. Regardless, our 30 year estimate for 

a scrubber, which includes a baghouse, is well within the reported range. 

 OG&E points to two State BART determinations that assumed a 20 year useful life. In 

adopting a FIP, we owe no deference to any state’s BART determination. Our only requirement 

here is to follow the Clean Air Act and our federal regulations. In so doing, we make a well 

reasoned determination, documenting our analysis as appropriate. 

In response to questions from us, OG&E attempted to justify the 20 year life as the 

"estimated remaining depreciable life for Sooner and Muskogee Stations as of 2014/2015 

according to OG&E's depreciation studies of those plants."87 The depreciable life is not used in 

capital recovery calculations, but rather the actual service life as noted above. 

Also, the OG&E 2011 Integrated Resource Plan (IRP) says "OG&E will not assume any 

retirements through the study period. This assumption reflects the results of the retirement study 

OG&E performed in the past."88 The "study period...ends in 2041." 89 Thus, OG&E appears to 

be saying that it does not plan any retirements through 2041, suggesting the remaining useful life 

of the Sooner and Muskogee units is at least 30 years according to OG&E internal planning. 

Similarly, we note that AEP's 2009 Integrated Resource Plan projects the installation of FGD at 

Northeastern in 2016 and the addition of carbon capture at Northeastern Unit 3 in 2030, implying 

 efSeekPage=x&SearchBack=ZyActionL&Back=ZyActionS&BackDesc=Results%20page&MaximumPages=1&Zy

Entry=1&SeekPage=x&ZyPURL# 

84 EPA/TVA, 1981, p. 5 ("Expensive corrosion-resistant materials are unnecessary and the operating expenses 

associated with high corrosion rates and plugging are eliminated."). 

85 Control Cost Manual, Section 6, Chapter 1, p. 1-48 and reference [26] on p. 1-58. 

86 John D. McKenna et al., Fine Particle (2.5 microns) Emissions: Regulations, Measurement and Control, Wiley, 

2008, Chapter 4.1; NDEP, Tocquop BACT Analysis, Appendix 10, pdf 28, Available at: 

http://ndep.nv.gov/bapc/projects/toq/Appendix10.pdf, Table 10-5, pdf 8 (30 year life for baghouse). 

87 2/8/10 S&L Memorandum, Question 1. 

88 Oklahoma Gas & Electric Co., Integrated Resource Plan, Redacted, May 2011, Appx. D, p. 9. 89 Oklahoma Gas & Electric Co., Integrated Resource Plan, Redacted, May 2011, p. 37 

38 
they intend to operate at least Unit 3 long past 2030.90 

Lastly, when the lifetime of the scrubber effects the BART determination, as here, we 

would require a federally-enforceable restriction preventing further operation after a date certain, 

i.e., the requested 20 years.91 Such a date has not been adopted and submitted by the State as 

part of the BART determination. 

Thus, we find that our original determination that the scrubbers for the six OG&E and 

AEP/PSO units should have a 30 year useful life remains correct. 

Comment: OG&E states annual O&M costs include both fixed and variable costs and 

indirect operating costs. According to OG&E, variable O&M costs are items that generally vary 

in proportion to the plant capacity factor, and variable costs associated with DFGD control 

include lime reagent costs, water costs, FGD waste disposal costs, bag and cage replacement 

costs, ash disposal costs, and auxiliary power costs. OG&E states we incorrectly stated that S&L 

overestimated the amount of lime necessary for the 80% SO2 removal case because the cost 

estimate was based on a stoichiometric ratio of 1.5 moles of calcium/mole of SO2 entering the 

system rather than using the “rule of thumb” value of 1.2. They state the stoichiometry required 

for a specific application is a function of several design parameters including, but not limited to, 

the spray-down temperature (i.e., the difference between the spray dryer inlet and outlet 

temperatures), the approach to the adiabatic saturation temperature in the scrubbing vessel, and 

the degree of recycle possible within the physical limits of the control system. OG&E states for 

the OG&E dry scrubbers it was determined, based on the unit-specific design parameters and 

unit-specific SO2 removal efficiencies developed in connection with the December 2009 Budget 

Cost Estimates, that a stoichiometric value of 1.5 was most appropriate for the process 

conditions. OG&E states it is incorrect for us to recalculate the lime consumption rate based on 

a rule of thumb value of 1.2 without taking into account the specific design parameters for the 

OG&E scrubbers and ignoring the site-specific nature of the December 2009 Budget Cost 

Estimates. 

Response: We disagree with this comment. We did not recalculate lime costs based on a 

different stoichiometric ratio. Rather, we pointed out that OG&E’s contractor, Sargent and 

Lundy, had used a lower stoichiometric ratio in other similar work (1.2 compared to 1.5). 

 Our comment is consistent with the vendor quotes, which also used a lower stoichiometic 

ratio than used by OG&E. The net effect of this issue is a 30% overestimate of lime costs in 

OG&E's analysis, compared to the vendor quotes they relied on. Lime cost is one of the major 

operational costs for a dry scrubber. However, we did not modify any costs based on these 

differences. 

 

 

90 American Electric Power, Integrated Resource Plan, 2009 AEP-SPP (Public Service Company of Oklahoma & 

Southwestern Electric Power Company), 2010 - 2019, July 2009. Available at: 

http://occeweb.com/pu/PSO%202011%20IRP.pdf. 91 70 FR 39169 (July 6, 2005). Where the date that a facility permanently stops operation affects the BART 

determination, "this date should be assured by a federally- or State-enforceable restriction preventing further 

operation.". 

39 
 Rather, as we explained in the TSD, Appendix C, we actually increased lime costs using 

OG&E’s high sulfur case (named as Option 1 in our proposal) rather than its average sulfur case. 

In other words, our lime costs were higher than those used by OG&E to estimate cost 

effectiveness. This had the effect of increasing the annual costs, but this was not due to changes 

in the stoichiometric ratio. 

 However, in response to OG&E's comment that the average sulfur case should be used to 

estimate O&M cost, we have revised our Option 2 lime costs to use OG&E’s average sulfur case 

and stoichiometric ratio, adjusted accordingly to use a baseline capacity factor of 78.5%, as we 

discuss in response to another comment. 

 Further, OG&E estimated lime costs based on $118.50 per ton at Sooner and $105.53 at 

Muskogee.92 In its response in Section 4.2.6, Variable Operating and Maintenance (O&M) 

Costs, OG&E indicates that it applied an inflation rate to its auxiliary power cost to adjust it to 

the anticipated year of startup of the controls. It appears that OG&E has escalated other O&M 

costs to the anticipated year of startup (2014, 2015). As we state in our response to other 

comments, this does not comport with the Control Cost Manual’s methodology of calculating 

costs on the basis of the overnight method, and thus overestimates these costs. 

 For example, OG&E assumed a lime cost of $95/ton in 2009 dollars in its dry scrubber 

model prepared for the EPA.93 The Utility Air Regulatory Group reported this IPM estimate was 

high in 2010 based on historical prices of lime at $60/ton.94 Other sources report $101.48 per 

ton for 2009.95 Thus, it appears that Sargent & Lundy also escalated its lime costs to the year of 

startup. As inflation to future years is not allowed in the overnight costing method used in the 

Cost Manual, lime costs are overestimated. We did not revise our cost analyses for this 

overestimate. 

 Our revised lime calculations for Options 1 and 2 are shown in Exhibits 1, and 2. 

However, we continue to note that these costs are overestimated as they are based on a lime 

stoichiometric ratio higher than assumed in the site-specific vendor quotes and future lime costs. 

Comment: OG&E states we incorrectly stated that the water consumption rate used in the 

December 2009 Budget Cost Estimates of 5.3 gallons/MMBtu heat input was beyond the upper 

end of the range of 3.6 to 4.4 gal./MMBtu for other similar dry scrubbers. They state the water 

consumption in a DFGD control system is calculated based on the amount of water needed to 

cool the flue gas from the spray dryer inlet temperature to the spray dryer outlet temperature (the 

spray-down temperature); thus, water consumption is fixed by thermodynamics. According to 

OG&E, units that have a higher air heater outlet temperature and units with more air in-leakage 

 

92 12/28/10 S&L FollowUp Report, Tables B-1 to B-4. 

93 Sargent & Lundy, IPM Model - Revisions to Cost and Performance for APC Technologies, SDA FGD Cost 

Development Methodology, Final, August 2010, Tables 2 and 3. Available at: 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Appendix51B.pdf 

94 J. Edward Cichanowicz, Overview of Information on Projected Control Technology Costs and Performance as 

Developed for EPA's Integrated Planning Model (IPM), Prepared for the Utility Air Regulatory Group, October 15, 

2010, p. 6. 

95 USGS, Mineral Industry Surveys, Lime in the United States 1960 to 2009. 

http://minerals.usgs.gov/minerals/pubs/commodity/lime/lime-1960-2009.pdf 

40 
will require more water than similar units with different design and operating parameters. 

OG&E notes that a 10°F change in the air heater outlet temperature will result in a 7% - 8% 

change in the amount of water needed to achieve the design approach-to-saturation temperature. 

OG&E states the water consumption rate used in S&L’s December 2009 Budget Cost Estimates 

was based on unit specific design and operating parameters, consistent with the purpose of those 

estimates. OG&E states we incorrectly adjusted the water consumption rate based on “rule of 

thumb” water consumption rates. 

Response: We disagree with this comment. We did not adjust the water consumption 

rate based on a "rule of thumb" estimate. Rather, we used the site-specific water consumption 

rate quoted by a vendor for the subject units.96 

 The typical range of water consumption rates was mentioned to confirm that the vendor's 

quote fell within the usual range for similar installations. This typical range also confirms that 

OG&E’s stated water consumption rate is outside of the usual range of water consumption rates. 

We noted that the accuracy of OG&E’s estimate "cannot be evaluated as the basis is not in the 

documents . . ." OG&E does not provide any further unit specific design and operating 

parameters to support its proposed water consumption rate. Therefore, we find that our original 

determination remains correct. 

Comment: OG&E stated that we incorrectly revised the FGD waste disposal cost by 

increasing the quantity of waste generated in the FGD (based on the higher inlet SO2 loading 

rate). OG&E also states we were wrong to state the unit cost to dispose of the FGD solids was 

high compared to other similar BART cost analyses. OG&E states we incorrectly calculated the 

quantity of FGD waste generated based on an inlet loading rate of 1.176 lb/MMBtu as it is 

inconsistent with the rest of the variable O&M cost estimate. OG&E reiterates that it does not 

believe there was an inconsistency between the capital cost estimate and the annual O&M cost 

estimate. OG&E states capital costs were based on the flue gas flow rate, while variable O&M 

costs and the quantity of SO2 removed from the flue gas were calculated based on the average 

SO2 loading to the scrubber. This approach, according to OG&E, provides a consistent basis for 

estimating capital costs, O&M costs, and SO2 removal. In OG&E’s opinion, revising the 

variable O&M costs based on the maximum inlet SO2 loading rather than average SO2 loading to 

the scrubber would overestimate the quantity of FGD waste generated and would be inconsistent 

with the rest of the variable O&M cost estimates. 

Response: We agree that the average sulfur case should be used to estimate O&M cost 

for Option 2 based on OG&E's explanation elsewhere in its comments. Because, as explained 

elsewhere in our response to comments, we continue to increase the SO2 emission baseline to 

correspond to the overdesigned scrubber in Option 1, we did not make a correction to the FGD 

waste disposal cost for Option 1. Our revised calculations are shown in Exhibits 1 and 2. 

However, we note, for the following reasons, that these revised costs likely remain high. 

 

96 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March, 2011; Revised BART Cost-Effectiveness Analysis for Flue Gas Desulfurization at 

Coal-Fired Electric Generating Units in Oklahoma: Sooner Units 1 & 2 Muskogee Units 4 & 5 Northeastern Units 3 

& 4 Appendix C, page 29. 

41 
 First, OG&E assumes the unit disposal cost for Sooner is $39.60/ton and for Muskogee 

$40.59/ton for on-site disposal.97 Other similar BART cost analyses, as summarized by OG&E, 

show a range from $5/ton to $24.33/ton.98 The cost for FGD waste disposal at Sooner and 

Muskogee should be at the lower end of this range as on-site disposal will be used,99 e.g., 

transportation costs will be low. 

 Second, in its response in Section 4.2.6, Variable Operating and Maintenance (O&M) 

Costs, OG&E indicates that it escalated auxiliary power cost to the anticipated year of startup of 

the controls. It appears that OG&E has likewise escalated other O&M costs to the anticipated 

year of startup (2014, 2015), thus overestimating them. These inflated O&M costs may well 

include waste disposal, as it is outside of the usual range. 

 The basis for OG&E's high estimate for Sooner and Muskogee was not provided, even 

though this discrepancy was pointed out in the TSD. We did not adjust the unit disposal cost as 

no information was provided about the on-site landfilling operations. Therefore, FGD waste 

disposal costs likely remain significantly overestimated. Finally, as we noted previously,100 in 

some cases FGD wastes can be reused, thus reducing disposal costs. However, this option was 

not considered by OG&E. 

Comment: OG&E states we incorrectly lowered OG&E’s auxiliary power costs for the 

DFGD/FF control systems on the premise that the unit cost of electricity used in the cost estimate 

was “much higher than the cost to OG&E to produce electricity.” OG&E states we mixed 

terminology by equating busbar costs to energy charges. Further, they claim our price quotations 

completely ignore the summer on-peak period, which has significantly higher rates. OG&E 

notes that by definition, busbar costs are the all-in cost to produce electricity, including capital 

charges, fixed O&M, variable O&M, and fuel. OG&E alleges we selectively chose only offpeak energy charges, which generally cover only variable O&M and fuel costs. In the long run, 

auxiliary power has a cost for both energy and capacity. OG&E also states that auxiliary power 

requirements also reduce the installed net plant capacity, which is a lost value to OG&E, as may 

be measured by the $/kW cost of base load replacement capacity, or the $/kW cost of required 

capacity reserve margins. OG&E states they used average year-round market retail rates of 

$85.93/MWh (2015$) for Sooner and $83.83/MWh (2014$) for Muskogee as the best long-run 

measure of auxiliary power capacity and energy costs. OG&E cites to a previously cited report 

by the EPA, Air and Energy Engineering Research Laboratory, which was developed in 

collaboration with EPRI, the U.S. Department of Energy, and an industry technical advisory 

committee, which uses a value of $50/MWh in constant 1988 dollars. OG&E states that on the 

basis of an estimated inflation rate of 2.5%/year, this would be equivalent to a value of 

$95/MWh (2014 $) and $97/MWh (2015 $). OG&E concludes their approach is therefore 

 

97 12/28/09 S&L FollowUp Report, Attach. B, pdf 102-104. 

98 12/28/09 S&L FollowUp Report, Attach. C, pdf 109 (Gerald Gentleman - $5/ton; White Bluff - $8.58/ton; 

Boardman - $10/ton; Naughton - $24.33/ton; Nebraska City - $9/ton). 

99 12/28/09 S&L FollowUp Report, Attach. B, Tables B-1 to B-4, FGD Waste Disposal Costs, Basis Column. 100 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March, 2011; Revised BART Cost-Effectiveness Analysis for Flue Gas Desulfurization at 

Coal-Fired Electric Generating Units in Oklahoma: Sooner Units 1 & 2 Muskogee Units 4 & 5 Northeastern Units 3 

& 4 Appendix C, page 30. 

42 
justified as this study accounted for both energy and capacity, as did OG&E in its December 

2009 Budget Cost Estimates. 

Response: OG&E states that the cost of power used in the S&L December 2009 cost 

analysis is the average year-round market retail rates including inflation to the anticipated year of 

startup of the controls. This is inappropriate for three reasons. 

 First, as we have discussed elsewhere in our responses, regulatory cost effectiveness 

analyses performed under the Control Cost Manual methodology, are based on current annual 

dollars, excluding inflation and escalation for generation-only service, to replace lost output. 

OG&E escalated power prices to 2014/2015. We find that this is an incorrect approach for 

auxiliary power costs, similar to our finding for capital costs, explained elsewhere in these 

responses. Regardless, as demonstrated below, power prices are currently low and are expected 

to remain low through at least 2015. The Department of Energy's 2010 Annual Energy Outlook 

(the supplemental tables for the 2011 AEO have not been released), Supplemental Table 17 for 

the West South Central region (including OK) forecasts only about 1.5% real escalation in 

industrial power rates for 2015 to 2035.101 Thus, even if future power prices were used to 

estimate auxiliary power costs, they would be much lower than assumed by OG&E in the Sooner 

& Muskogee cost estimates. 

 Second, OG&E uses an average retail rate as if it were a proxy for the cost of generating 

or buying power to replace the power used in the scrubbers. OG&E states that “S&L used 

average year-round market retail rates of $85.93/MWh (2015$) for Sooner and $83.83/MWh 

(2014$) for Muskogee as the best long-run measure of auxiliary power capacity and energy 

costs.” It is not clear what OG&E means by “market retail rates,” since there is no retail 

electricity market in Oklahoma; competitive market prices exist only at the wholesale level. 

 It appears that OG&E estimated the cost of wholesale replacement generation-only 

energy and capacity102 at a 90% capacity factor103 from the average retail rate (including 

transmission, distribution, metering, billing, customer service, and a host of costs not required for 

the replacement power) at OG&E’s average 54% load factor.104 The average OG&E retail rate 

in 2008 was $70.7/MWh.105 Assuming 2.5% inflation, this would be $84/MWh in 2015 dollars, 

close to the rates quoted by OG&E in this comment.106 The 2008 rate for the retail class most 

like a power plant, the Large Power and Light (LPL) class, was $49/MWh in 2008. This value 

includes transmission, distribution, metering and other non-generation charges that should not be 

included in generation-only prices. Thus, the retail price for generation-only service to replace 

 

101US DOE, 2010 Annual Energy Outlook, Available at: 

http://www.eia.gov/oiaf/archive/aeo10/supplement/sup_t2t3.xls. 

102 Capacity is the power plant's maximum possible output under specified conditions, e.g., at typical winter peak 

temperature, generally measured in MW. 

103 Capacity factor is average output divided by capacity, or (energy output divided by hours) divided by capacity. 104 For example, the IRP projects 2012 retail energy of 27,501 GWh and peak of 5,823 MW or 5.823 GW 

(Oklahoma Gas & Electric Co., Integrated Resource Plan, Redacted, May 2011, p. 11). 27,501 GWh ÷ ( 5.823 GW 

× 8,784 hours) = 54% load factor. 

105 OG&E FERC Form 1, 2008, p. 304. 106 OG&E may have started with a different year’s price, or used different escalation rates. 

43 
lost output from Sooner and Muskogee would be even lower than $49/MWh. 

 Wholesale market prices are even lower than the industrial retail price. OG&E’s average 

market price for energy was a little over $30/MWh in 2010, down from about $50/MWh in 

2011.107 According to Megawatt Daily108, the forward price for on-peak energy delivered to 

Entergy (which borders on OG&E, and is the closest hub with regular price reporting) is about 

$40/MWh in 2012, $44/MWh in 2013, $47/MWh in 2014 and $49/MWh in 2015. Off-peak 

prices are much more stable, and not so widely traded in the forward markets, but are clearly 

much lower than the on-peak prices. The following Table 2 shows the average day-ahead price 

in on-peak and off-peak hours over each of the last twelve months, the monthly price ratio and 

the average ratio over the year.109 Note that none of the monthly prices, even the on-peak 

summer prices, are anywhere near the $85/MWh range claimed (without basis) by OG&E. 

Table 2 

Average Entergy Day-Ahead Price for On-Peak and Off-Peak 

Average price 

month-to-date 

Off/On 

ratio 

Report 

date 

On 

peak 

Off 

peak 

10/29/2010 29.66 18.29 62% 

11/30/2010 31.01 21.11 68% 

12/30/2010 38.32 28.56 75% 

1/31/2011 39.32 30.45 77% 

2/28/2011 33.33 26.24 79% 

3/31/2011 33.51 24.85 74% 

4/29/2011 36.35 24.95 69% 

5/31/2011 40.46 25.98 64% 

6/30/2011 45.40 22.73 50% 

7/29/2011 47.18 26.24 56% 

8/31/2011 44.64 26.99 60% 

9/22/2011 35.80 24.68 69% 

Average 67% 

 About half the hours in each month are off-peak, so assuming that the off-peak prices are 

67% of the on-peak price, the average price would be about 84% of the on-peak price, or roughly 

$40/MWh in 2014 and $41/MWh in 2015.110 In constant 2009 dollars, these would be 

$35.8/MWh and $36.5/MWh respectively.111 Thus, in revising OG&E’s cost estimate (Exhibits 

1 and 2), we assume the 2014/2015 forward energy cost of $36/MWh as a proxy for replacement 

 

107 Southwest Power Pool 2010 State of the Market, SPP Market Monitoring Unit May 10, 2011, p. 39. 108 Megawatt Daily, September 16, 2011. 109 Megawatt Daily October 29, 2010 to September 30, 2011. 110 0.5 *100% + 0.5 *67% = 83.5%. 84% of $47/MWh = $39.5/MWh, 84% of $49/MWh = $41/MWh. 111 $39.5/MWh ÷ 1.025

 = $35.8/MWh; 111 $41/MWh ÷ 1.026 = $36.5/MWh. Dividing by 1.02^5 deflates the 2014 

price 5 years. Dividing by 1.02^6 deflates the 2015 price 6 years. 

44 
power costs. As explained below, we assume capacity costs are zero as capacity costs are 

currently zero, are likely to remain zero for several years, and will be very small thereafter. This 

is consistent with an overnight cost analysis. 

 The Southwest Power Pool (SPP) does not have that any separate capacity market and is 

not proposing to create one in the planned Integrated Marketplace.112 Thus, capacity is likely 

included in the on-peak energy prices available through 2015. Even if the value of capacity is 

not fully reflected in the market cost of energy, any additional cost of peaking capacity is likely 

to be minimal, since OG&E and the SPP region are awash in capacity. 

 The cost of capacity would be zero until OG&E needs new capacity to meet its 12% 

required capacity margin. Table 14 of the OG&E IRP indicates that OGE currently has a 12.9% 

capacity margin in 2021 without the scrubbers. If one removes the relatively small amount of 

electricity necessary to power the scrubbers, the capacity margin would still be approximately 

12.5%. Thus, no additional capacity would be needed until 2022 with existing resources. 

OG&E has been adding wind that reduces costs: "OG&E also will have over 700 MW of 

renewable wind energy, which will result in more than $1 billion in estimated customer 

savings..."113 Additional such resources, as explained in the Langston testimony,114 (or energy 

efficiency) will push back the date of capacity need. 

 The most recent NERC assessment reports an anticipated 2019 reserve margin of 23%, 

even higher than OG&E’s margin.115 The SPP section of the NERC assessment describes the 

excess in greater detail: 

The SPP RE’s minimum capacity margin requirement is 12 percent, which translates to a 

reserve margin of 13.6 percent. For 2010-2019 assessment period, ...[a]fter considering 

Deliverable Capacity Resources, the SPP RE’s reserve margin is 28.3 percent in 2010, which 

drops to 19.7 percent in 2019. With the addition of Prospective Capacity Resources, the SPP 

RE’s reserve margin is 38.9 percent in 2010 and drops to 28.9 percent in 2019. No known 

reliability concerns are identified for the 2010-2019 assessment period, as the targeted reserve 

margin is above the required level.116

 Since the reserve margin declines only about 1% annually, the SPP region appears to be 

in surplus until at least 2030 or so, with the exact date depending on whether resources are at the 

Anticipated or Prospective level. Thus, OG&E should be able to purchase cheap excess capacity 

(which can be peaking units, as the energy is already accounted for) to 2030 or beyond. Thus, 

for an overnight cost estimate, a capacity charge of zero is defensible. Therefore, an energy 

price of $36/MWh should cover all power costs, including any capacity charges. 

 

112 Southwest Power Pool 2010 State of the Market, SPP Market Monitoring Unit May 10, 2011. pp. 34-47 and 88–

91. 

113 In the Matter of the Application of Oklahoma Gas and Electric Company for an Order of the Commission 

Authorizing Applicant to modify its Rates, Charges, and Tariffs for Retail Electric Service in Oklahoma, Cause No. 

PUD 201100087, Direct Testimony of Jesse B. Langston, July 28, 2011, Chart 2 and p. 11. 

114 Ibid. 115 North American Electric Reliability Corporation, 2010 Long-Term Reliability Assessment, October 2010, Table 

5e. Available at: http://www.nerc.com/files/2010_LTRA_v2-.pdf 

116 North American Electric Reliability Corporation, 2010 Long-Term Reliability Assessment, October 2010, p. 157. 

45 
 While OG&E never fully explains how they derived their auxiliary electricity costs or 

provides any supporting data, the comment does compare the power-cost assumption to the 

results of escalating a $50/MWh value assumed in a 1990 national study, which notes that the 

inflation rates and other “economic bases used in this study are not necessarily those that would 

be used currently or by a utility company....These parameters are from the 1986 EPRI Technical 

Assessment Guide...” (Kaplan, N., et al., “Retrofit Costs of SO2 and NOx Control at 200 U.S. 

Coal-Fired Power Plants,” Pittsburgh Coal Conference, 1990, p. 4. Thus, the comment defends 

OG&E’s estimate of its current replacement generation costs on the basis of 1986 national 

average prices (a quarter of a century ago), that includes such high-cost areas as the Northeast 

and California, back when oil was the marginal fuel in those regions. 

 This same 1988 value, unescalated, is still used today in many BART analyses as the 

default cost of auxiliary power. Note, for example, as discussed above, that it is reported by 

OG&E itself as the upper end of the range for auxiliary power costs. Thus, we find that 

escalation of a 1988 price to 2014 to 2015 dollars is incorrect. 

 The claim that we mixed up terminology by equating busbar costs to energy charges is 

incorrect. If the Muskogee 5 scrubber were powered by more generation from Muskogee 5, the 

auxiliary power cost would be the busbar variable cost of the unit. If the scrubber were powered 

by more generation from Muskogee 6, or Muskogee 3, or some other OG&E plant, the cost is the 

busbar variable cost of that unit. If OG&E is short of capacity and purchases from the regional 

surplus described above, it would be the market price for that energy plus perhaps some cost of 

capacity. 

 OG&E's summary of auxiliary power costs in the FollowUp Report indicates the range 

used for other similar facilities is $30/MWh to $50/MWh.117 As explained previously, our 

estimated upper bound is no more than $36/MWh. However, because we arrived at this figure 

due to independent research that we do not view as being a logical outgrowth of the comment we 

received, we have not revised our cost effectiveness analysis to use $36/MWh. Instead, we 

retain the $50/MWh figure we proposed. We view this, however, as evidence buttressing our 

position that OG&E’s scrubber costs are high. 

Comment: OG&E claims we selectively picked factors from the Control Cost Manual, 

using default Control Cost Manual factors when they yielded lower results, but otherwise 

ignored them. OG&E states we did not adjust the lower site-specific factors used for property 

taxes, insurance, and administrative charges in the December 2009 Budget Cost Estimates. 

OG&E states that fixed O&M costs are recurring annual costs that are generally independent of 

the plant capacity factor. According to OG&E, these consist of operating labor, supervisor labor, 

maintenance materials, and maintenance labor. OG&E states indirect operating costs are 

recurring annual costs for the DFGD/FF control systems that are not part of the direct O&M, 

consisting of property taxes, insurance, and administration. OG&E states that if we argue that 

the Control Cost Manual mandates the use of other factors, for consistency, we should have 

revised these factors upwards, as well. OG&E accuses us of selectively using updated, site-

 

117 12/28/09 S&L FollowUp Report, Attach. C, pdf 109 (Gerald Gentleman - $45.65/MWh; White Bluff - 

$47/MWh; Boardman/Northeastern/Naughton - $50/MWh; Nebraska City - $30/MWh). 

46 
specific numbers where they lower overall costs and “rule of thumb” numbers from the Control 

Cost Manual where that approach lowers cost. 

Response: We disagree with this comment. We used the Control Cost Manual 

methodology (overnight costs, no inflation, no AFUDC, no income taxes, etc.) and site-specific 

values when they were available and correct. We reviewed the basis of all of OG&E's cost 

estimates, to the extent feasible, based on publicly available information. These site-specific 

values were accepted when reasonable and adequately supported. We did not challenge sitespecific capital or O&M costs based on the generic factors in the Cost Manual unless we had 

documentation that demonstrated OG&E’s costs were inappropriate. 

 For instance, we accepted OG&E's estimate of property tax and insurance, based on their 

representation that they are based on OG&E records and our own research.118 The 12/28/09 

FollowUp Report itself characterizes property tax and insurance as site specific and notes they 

are lower than reported in the Manual:119 

• Property Taxes. “Calculated as 0.60% of total capital investment at Sooner and 0.85% of 

total capital investment at Muskogee, according to OG&E property tax rates. These rates 

are significantly lower than those used in the EPA Air Pollution Control Cost Manual 6th 

Ed., page 2-34. 

• Insurance. "Calculated as 0.0105% of total capital investment at both Sooner and 

Muskogee, according to OG&E insurance rates.” 

Comment: OG&E states we incorrectly argued that variable costs (as well as emission 

reductions) in their December 2009 Budget Cost Estimates were based on “Option 2” (i.e., 

reducing SO2 emissions from an uncontrolled rate of 0.509 lb/MMBtu to a controlled rate of 0.10 

lb/MMBtu), while the scrubber sizing and capital costs were based on “Option 1” (i.e., reducing 

SO2 emissions from an uncontrolled rate of 1.176 lb/MMBtu to a controlled rate of 0.10 

lb/MMBtu). OG&E states we incorrectly concluded that this mismatch results in underestimating 

emission reductions and fixed O&M costs, while overestimating capital costs. 

OG&E states there was no “mismatch” between the capital cost estimate and the annual 

O&M cost estimate included in its December 2009 Budget Cost Estimates. OG&E states capital 

costs were based on sizing the DFGD/FF control systems to handle the full load flue gas flow 

rate associated with firing subbituminous coal. OG&E states annual O&M costs, and annual SO2

emission reductions, were calculated based on the average actual baseline SO2 loading to the 

scrubber. This approach, claims OG&E, is consistent and provides a more specific estimate of 

the annual O&M costs. 

 

118 See, e.g., http://muskogee.oklahoma.usassessor.com/Shared/base/Levys/Levys.php 

http://muskogee.oklahoma.usassessor.com/Shared/base/Levys/TaxCalc.php 

http://www.tax-rates.org/oklahoma/noble_county_property_tax 

http://www.tax-rates.org/oklahoma/property-tax 

http://www.tax.ok.gov/publicat/copos/copo3Q11.pdf. 

119 12/29/09 S&L FollowUp Report, p. 11, pdf 13 (emphasis added). 

47 
OG&E states that the cost estimates developed for “Option 2” in the Fox Report and in 

Tables 5 and 6 of the proposed rule are invalid because this option is technically infeasible. 

OG&E’s comments summarize the BART costing report provided by their contractor, Sargent 

and Lundy, as Exhibit B. Under “Option 2”, the scrubber size and capital costs were reduced by 

approximately 50% to address that the December 2009 Budget Cost Estimates “assumed that the 

Sooner and Muskogee plants burned coal with a higher sulfur content [1.172 lb/MMBtu 

uncontrolled SO2 emissions] than they are currently burning [0.51 lb/MMBtu uncontrolled SO2

emissions].” OG&E claims that the scrubber design for “Option 2” does not account for the 

sulfur content of the coal that OG&E actually uses at these units. OG&E continues that the 

“Option 2” scrubber would be grossly undersized, ineffective, and not able to handle the flue gas 

flow rates at these units if they were fired at full load. 

 OG&E states that capital costs should be based on a scrubber designed to be capable of 

controlling the highest sulfur coal that could be delivered to OG&E and that the “Option 2” 

scrubber could not handle half of the coal that OG&E actually uses. OG&E provides tables of 

the annual minimum, maximum and average sulfur content of the coal delivered to the 

Muskogee and Sooner units for 2006 through 2010, and states that a functional system must be 

designed to handle the maximum sulfur content. OG&E and their consultant state that the size of 

the reactant and ash handling systems cannot be designed for an average fuel sulfur content (as 

suggested by EPA’s consultant), but must be sized based on a reasonable estimate of the 

maximum fuel sulfur content expected at the facility. Sizing the reactant handling system for an 

“average” coal would result in the lime supply being inadequate for coals with sulfur contents 

higher than the average, which, by definition, would be approximately one-half of all the coal 

fired. OG&E states that designing the scrubber based on the average coal content could greatly 

limit fuel supply options. 

Response: We disagree, as explained in our responses to these issues in the next 

comment. However, we address here OG&E’s use of a coal that is not typically burned, as the 

basis for its scrubber designs. OG&E presents sulfur content data for coal delivered to the 

OG&E units during the previous five years to support its coal sulfur design basis. The 

company's analysis calculates emission reductions based on average sulfur content in the 

baseline years 2004-2006, while the scrubber was designed to accommodate a much higher 

sulfur coal that was never burned at the stations in any appreciable quantities. 

 The coal sulfur data in OG&E’s Table IV.2 includes minima, maxima, and averages for 

each year during the period 2006 to 2010 for Sooner and Muskogee. However, the underlying 

data and its source were not provided. OG&E’s scrubber was designed based on a maximum 

sulfur content of 0.48%. 

 We obtained sulfur content data (fuel receipts data) reported by OG&E to the Energy 

Information Agency (EIA) for the period January 2004 to November 2010 on forms EIA-423, 

FERC-423, EIA-923 Sch 2.120 This data is summarized below in Figure 1 for Sooner and Figure 

 

120 2008-2010 data is from: "2010: EIA-923 Schedule 2, January - December, Excel Format." Data Released: June 

2011. U.S. Energy Information Administration. EIA-923 (Schedule 2) - Monthly Utility and Nonutility Fuel 

Receipts and Fuel Quality Data, 2008 and Beyond (http://www.eia.gov/cneaf/electricity/page/eia423.html). 

Accessed September 16, 2011. 

48 
2 for Muskogee. These figures show that sulfur content varied within a very tight band 

throughout this period. There were only two excursions in which sulfur content strayed outside 

of this band. According to this data, they occurred at the same sample date at each station. 

 These figures also show that the maxima in Table IV-2 are higher and more frequent than 

in the fuel delivery data reported to the EIA. In fact, only two data points over the six year 

period shown are greater than 0.40% for each facility. Therefore, the EIA data suggest that the 

design basis coal sulfur content of 0.48% is an outlier and thus should not be used as a basis for 

designing OG&E’s scrubbers. 

 "2009: EIA-923 Schedule 2, Excel Format." Data Released: June 2011. U.S. Energy Information Administration. 

EIA-923 (Schedule 2) - Monthly Utility and Nonutility Fuel Receipts and Fuel Quality Data, 2008 and Beyond 

(http://www.eia.gov/cneaf/electricity/page/eia423.html). Accessed September 16, 2011. 

"2008: EIA-923 Schedule 2, Excel Format." Data Released: June 2011. U.S. Energy Information Administration. 

EIA-923 (Schedule 2) - Monthly Utility and Nonutility Fuel Receipts and Fuel Quality Data, 2008 and Beyond 

(http://www.eia.gov/cneaf/electricity/page/eia423.html). Accessed September 16, 2011. 

2007 and earlier data is from: "2007: FERC-423, January - December, Excel Format." Data Released: U.S. Energy 

Information Administration. FERC Form No.423: "Monthly Report of Cost and Quality of Fuels for Electric 

Plants." (http://www.eia.gov/cneaf/electricity/page/ferc423.html). Accessed September 16, 2011. 

"2006: FERC-423, Excel Format." Data Released: U.S. Energy Information Administration. FERC Form No.423: 

"Monthly Report of Cost and Quality of Fuels for Electric Plants." 

(http://www.eia.gov/cneaf/electricity/page/ferc423.html). Accessed September 16, 2011. 

"2005: FERC-423, Excel Format." Data Released: U.S. Energy Information Administration. FERC Form No.423: 

"Monthly Report of Cost and Quality of Fuels for Electric Plants." 

(http://www.eia.gov/cneaf/electricity/page/ferc423.html). Accessed September 16, 2011. 

"2004: FERC-423, Excel Format." Data Released: U.S. Energy Information Administration. FERC Form No.423: 

"Monthly Report of Cost and Quality of Fuels for Electric Plants." 

(http://www.eia.gov/cneaf/electricity/page/ferc423.html). Accessed September 16, 2011. 

49 
Figure 1 

Sooner Plant, OK, Average Sulfur Content Per Coal Fuel Receipt, Jan 2004 - Dec 2010

0.00

0.05

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Apr-08

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Apr-09

Aug-09Nov-09

Mar-10

Jul-10

Nov-10

Month

Sulfur Content (% by weight)

Figure 2 

Muskogee Plant, OK, Average Sulfur Content Per Coal Fuel Receipt, Jan 2004 - D

0.00

0.05

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ec 2010 Nov-09

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Sulfur Content (% by weight)

50 
 The EIA data in these figures is also consistent with sulfur content data presented by 

OG&E in the initial, May 28, 2008 BART analyses, which reported a range of 0.27% to 0.37% 

for typical coal.121 Furthermore, we also validated the EIA data by comparing it to SO2 emission 

data reported by OG&E to CAMD, as required by the Acid Rain program. 

 The monthly average SO2 emissions in lb/MMBtu are compared with monthly average 

sulfur data in weight percent in Figures 3 to 6. Average monthly sulfur content was calculated 

by multiplying each sample's sulfur content by its corresponding tonnage, adding up all of the 

sulfur tons and dividing by the total tons of coal from all loads for each month to obtain a 

monthly average sulfur content. Monthly average sulfur content for each of the four units is 

below 0.30% for the period from January 2004 through November of 2010. 

Figure 3 

 

 

121 Sargent & Lundy, Muskogee Generating Station, Best Available Retrofit Control Technology Evaluation, May 

28, 2008, Table 4-1 and Sargent & Lundy, Sooner Generating Station, Best Available Retrofit Control Technology 

Evaluation, May 27, 2008, Table 4-1. 

51 
Figure 4 

Figure 5 

 

52 
Figure 6 

 These plots demonstrate that the average monthly fuel sulfur content closely tracks the 

average monthly SO2 emissions, confirming the conclusion from the EIA data in Figures 1 to 2 

that coals burned over the January 2004 to November 2010 period are contained in a narrow 

band well below the design sulfur level used for the scrubbers. This is consistent with the 

12/28/09 OG&E FollowUp Report at pdf 62 which states that the design basis fuel was 

developed based on the PRB coal fired at the station "and potential future PRB coal sources." 

This suggests the scrubbers were overdesigned to accommodate coals that have not been burned 

in appreciable quantities by these units. 

 These plots also show that both the coal sulfur content and the SO2 emissions are 

trending up over time. One potential strategy to reduce SO2 emissions is to reduce the amount of 

sulfur contained in the coal. However, rather than maintaining baseline sulfur contents, the 

OG&E units have been increasing coal sulfur content. The spreadsheets for these plots are 

present in the docket. 

Comment: OG&E states we incorrectly argued that the BART cost-effectiveness 

calculation requires that costs for the control technology are consistent with the calculated 

emission reductions, and that in performing their BART analysis, OG&E assumed that the 

Sooner and Muskogee plants burned coal with a higher sulfur content than they are currently 

burning. OG&E states we incorrectly argued that this assumption led to OG&E costing a much 

bigger scrubber than is necessary for the coal currently being burned, and resulted in a 

“mismatch” between annual costs and emission reductions. OG&E states we incorrectly scaled 

down the capital cost of the scrubber by approximately 50% in our Option 2 approach. OG&E 

53 
argues that there is no mismatch between the cost calculation and emission reductions. OG&E 

further argues that the Option 2 scrubber is undersized resulting in an ineffective control system. 

Response: We noted in the TSD that in performing its BART analysis, OG&E assumed 

that the Sooner and Muskogee plants burned coal with a higher sulfur content than currently 

burned but the emission reductions used to calculate cost effectiveness were based on a lower 

sulfur coal. The scrubbers were costed to remove 95% of the SO2 from a coal containing 0.48% 

sulfur (1.176 lb SO2/MMBtu) while the boiler operated at 100% capacity. ODEQ calculated 

annual emissions assuming a 90% capacity factor. In comparison, during the years that 

established the emission baseline, the units burned coal containing an average of 0.51 lb/MMBtu 

of SO2 and operated only 78.5% of the time. This means that (1) not only was the scrubber over 

designed to treat the coal that OG&E historically burned, (2) it was designed to operate at a 

capacity that exceeds that level at which the facilities have historically operated, and (3) future 

emissions were over predicted compared to the facilities’ past capacity. As we have stated 

previously, we do not in principle object to this overdesign, as it provides operational flexibility 

to burn cheaper coals (with higher sulfur contents) and allows the facilities to operate at higher 

capacities than they have in the past, should the need arise. However, we do object to OG&E not 

considering these mismatches in their SO2 BART cost analyses, as it does not comport with the 

requirements of the RHR. 

This mismatch between the design of the scrubber system and historical practices resulted 

in an erroneous calculation that made SO2 scrubbers appear less cost effective. Thus, we 

explored the range in cost effectiveness by both raising the historical emission baseline to match 

the potential reductions from the higher sulfur content of the coal the scrubber was designed to 

clean (Option 1), and by scaling down the scrubber to match the emissions corresponding to the 

lower sulfur coal the facilities have historically burned (Option 2).122 The following discussion 

separately addresses the baseline mismatch issue, the scrubber sizing issue in Option 2, and the 

capacity issue in Option 2. 

Baseline Mismatch

 The BART cost basis must match the BART emission reductions expected to occur from 

compliance with the prescribed BART limit, or 0.06 lb/MMBtu. 

 Section 169A(g)(7) of the CAA and section 51.308(e)(1)(ii)(A) requires States to 

consider the costs of compliance in making BART determinations. We have interpreted cost of 

compliance in terms of “cost effectiveness,”123 and defined average cost effectiveness as: 

Average cost effectiveness means the total annualized costs of control divided by annual 

emissions reductions (the difference between baseline annual emissions and the estimate of 

emissions after controls) . . . . 124 

 Therefore the units of cost effectiveness are annualized dollars per ton of SO2 ($/ton). 

 

122 76 FR 16183, Tables 4 - 6. 123 70 FR 39129. 124 70 FR 39167. 

54 
However, the OG&E cost effectiveness analyses contain two mismatches. The cost and 

emission reductions are mismatched, and components of emission reductions — the baseline and 

future controlled emissions — are mismatched. These mismatches contribute to OG&E’s 

erroneous conclusion that scrubbers are not cost effective. We treat each mismatch separately, 

below. 

Emissions Baseline

 As discussed elsewhere in our response to comments, OG&E directed its vendors to 

provide bids on a SO2 scrubber system that was designed to remove 95% of the SO2 from a coal 

that has a significantly higher amount of sulfur than the coal that has typically been historically 

burned. However, as it admits itself, it assumed a baseline that corresponds to its historical 

emissions. Thus, the scrubber system was overdesigned and more expensive than necessary in 

order to treat the coal the company has historically burned. This effectively results in both 

increasing the numerator (annualized cost) and decreasing the denominator (tons of SO2

removed) in the $/ton cost effectiveness, thus greatly increasing the result of this calculation and 

erroneously making SO2 scrubbers appear to be much less cost effective, i.e., have a higher 

dollar per ton value due to dividing a higher cost by a lower emission reduction. 

We have treated the problem of the erroneously high annualized cost elsewhere in our 

response to comments, and now turn to the problem of the erroneously low baseline SO2

emissions. In calculating baseline emissions, the BART Guidelines assume the source in 

question is otherwise unchanged in the future, except for the addition of BART controls. The 

Guidelines state: 125

The baseline emissions rate should represent a realistic depiction of 

anticipated annual emissions for the source. In general, for the existing 

sources subject to BART, you will estimate the anticipated annual 

emissions based upon actual emissions from a baseline period. When you 

project that future operating parameters (e.g., limited hours of operation or 

capacity utilization, type of fuel, raw materials or product mix or type) 

will differ from past practice, and if this projection has a deciding effect in 

the BART determination, then you must make these parameters or 

assumptions into enforceable limitations. In the absence of enforceable 

limitations, you calculate baseline emissions based upon continuation of 

past practice.

 Clearly, the RHR assumes the baseline emissions used in the BART cost analysis “should 

represent a realistic depiction of anticipated annual emissions for the source.” OG&E’s cost 

analysis does not do this. Instead, as discussed elsewhere in our response to comments, it 

employs substantially different operating and design characteristics to project the units’ pre- and 

post-control emissions and costs. Cost aside, this under estimates reductions that may be 

reasonably anticipated to result from the controls’ installation. The baseline example discussed 

above in the RHR, contemplates a situation in which a change in future operations makes the 

historical baseline emissions effectively too high. However, we find it is reasonable to conclude 

 

125 70 FR 39167 

55 
the RHR’s desire to realign baseline emissions with potential future changes in operations cuts 

both ways. 

In addition, the RHR states that when differences from "past practice," as here, have "a 

deciding effect in the BART determination, you must make these parameters or assumptions into 

enforceable limitations." The OG&E analysis does not propose making the basis of their 

emission reductions enforceable. In fact, the scrubbers are designed to allow the station to burn 

higher sulfur coals than historically used at the station. 

Therefore, we affirm our position taken in Option 1, that our decision to raise the baseline 

to match the SO2 removal potential of the overdesigned scrubber was correct. Elsewhere in our 

response to comments we discuss corrections we have made to Option 1. The full spreadsheet, 

Exhibit 1, has been added to the docket for our final action, and a screen copy of the spreadsheet 

is reproduced as Attachment 3 to this document. 

Costs: 

 Moreover, even assuming the use of high-sulfur coals, Sargent & Lundy’s estimate of the 

costs of compliance are over-stated. The use of a higher sulfur coal will reduce the operating 

costs of the stations. The cost of coal is the major operating expense at a coal-fired electric 

generating unit. Higher sulfur coals cost less. The resulting reduction in operating costs from 

using higher sulfur coal was not included in the cost effectiveness analysis.126

 The OG&E units currently burn ultra low sulfur coal or "SA" coal, which results in 

uncontrolled SO2 emission rates of 0.58 to 0.62 lb/MMBtu.127 The 2012 delivered price for this 

coal is $1.44/MMBtu.128 The highest sulfur coal that the IPM model129 currently anticipates 

OG&E will burn is "SB" coal, with an uncontrolled SO2 emission rate of 0.94 lb/MMBtu, well 

below the OG&E design basis of 1.175 lb/MMBtu. The IPM model's projected 2012 delivered 

price for SB coal is $1.36/MMBtu. We expect the delivered cost of the OG&E design basis coal 

would be even lower as its sulfur content is greater than the SB coal. Thus, at a minimum, the 

scrubber design would allow the stations to reduce their operating costs by at least 6% and 

perhaps more. This reduction in costs was not included in Sargent & Lundy's analysis. 

Although we do not incorporate it into our SO2 BART determination cost analysis for the six 

OG&E and AEP/PSO units, we did include this information in a supplemental cost analysis as 

Exhibit 3, in order to illustrate its effect. The full spreadsheet has been added to the docket for 

 

126 EPA has established that costs estimated for purposes of assessing cost-effectiveness must include recovery 

credits, where, as here, a control method allows a source to “save on raw materials.” New Source Review Manual 

(Draft October 1990) at b.7. That principle governs BART determinations. 69 Fed. Reg. at 25,218 (“The process for 

a BART analysis is very similar to the BACT review as described in the New Source Review Workshop Manual 

Draft (October 1990)”). 

127 2012 coal choices for Sooner Units 1 and 2 and Muskogee Units 4 and 5 and corresponding lbs SO2/MMBtu 

content of fuel: Model plants FTA, FTB, and FTC in file "TR_Remedy_Final.rpe," available for downloading by 

clicking hotlink "TR Remedy Final" at: www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html 128 Delivered coal prices: 2012 results for coal demand region MWR3 in the "Coal Demand" section of file 

EPA410FINAL_BC_58S.rpt (Transport Rule Remedy RunEPA410FINAL_BC_58), available upon request from 

CAMD. 

129 Integrated Planning Model, available at: http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html 

56 
our final action, and a screen copy of the spreadsheet is reproduced as Attachment 3 to this 

document. 

 The cost effectiveness analysis anticipates significant changes in the plant’s operation. 

These changes include burning a higher sulfur coal and operating at a high capacity factor. The 

baseline used by Sargent & Lundy – which reflects the use of lower-sulfur coals, and a lower 

capacity factor – does not permit a reasonable assessment of the reductions that will result from 

compliance with BART. In order to provide that reasonable assessment, future anticipated 

conditions should be used as the common baseline for estimating emission reductions. 

 Thus, the emission reductions used by Sargent & Lundy to calculate cost effectiveness 

minimize emission reductions by subtracting a high post-BART controlled emission rate inflated 

with a high capacity factor from a low historic baseline that has not been adjusted for anticipated 

changes in coal sulfur content. The result is an underestimate in emission reductions, an 

overestimate in scrubber cost, and a significant overestimate in cost effectiveness. 

Scrubber Sizing in Option 2

 OG&E comments that the exhaust gas flow rate, rather than the sulfur content, is the 

primary variable that affects scrubber sizing. Thus, the use of a higher sulfur coal would not 

significantly affect the size and hence the cost of a scrubber. The comment states that our Option 

2 scrubber is undersized and thus technically infeasible as we reduced the cost of the scrubber in 

Option 2 based on coal sulfur content. 

 We agree that the sulfur content of the fuel, taken by itself, will not significantly affect 

the size (or cost) of the gas path portions of the FGD system. We also agree that the Option 2 

scrubbers were undersized based on OG&E’s design basis. We advised in our initial analysis 

that OG&E did not supply any cost data for a smaller scrubber option, requiring that we provide 

an estimate. We disclosed that the six-tenth rule approximation we used to estimate the cost of a 

smaller scrubber was an "oversimplification." TSD, Ex. B, p. 7. OG&E still has not provided 

any cost information for a smaller scrubber. However, as explained below, a smaller scrubber is 

technically feasible and cost effective. 

 The subject scrubbers only need to be costed to satisfy BART, not to accommodate 

OG&E's future plans. While it may be prudent to overdesign for many reasons, the cost of 

overdesign should not be attributed to BART, especially when the emission reductions do not 

consider the overdesign. 

 We have revised our Option 2 cost analysis to address the sulfur content/sizing issue 

raised in this and other comments. Our revised Option 2 analysis relies on certain design 

algorithms in the dry scrubber absorber (SDA) cost model developed by Sargent & Lundy for 

EPA.130 This model does not consider changes in flue gas volume due to changes in coal 

composition. The design coal, for example, has a higher heat content than currently burned coal 

and would thus generate less flue gas, reducing costs. Further, this model does not optimize 

 

130 Sargent & Lundy, IPM Model - Revisions to Cost and Performance for APC Technologies, SDA FGD Cost 

Development Methodology, Final, August 2010, Table 1. 

57 
mass transfer to account for the smaller amount of SO2 that would have to be removed by the 

Option 2 scrubber. We used it only to establish a floor. The actual cost of a smaller scrubber 

could be much less. 

 We used this model to estimate the difference in the capital cost of dry scrubbers for 

Sooner and Muskogee when burning coal containing the two sulfur contents that we analyzed in 

the TSD, 0.48% sulfur (1.176 lb SO2/MMBtu) and 0.22% sulfur (0.509 lb SO2/MMBtu), 

assuming a 100% capacity factor. The results of this analysis indicates that the use of the lower 

sulfur coal alone would reduce the capital cost of the scrubber by about $7 million or 3%.131 The 

full spreadsheet, along with a copy of the report from which it was derived, has been added to the 

docket for our final action, and a screen copy of the spreadsheet and information on the model is 

reproduced as Attachment 2 to this document. The 3% reduction is incorporated into the revised 

Option 2 cost analysis in Exhibit 2. Elsewhere in our response to comments we discuss 

corrections we have made to Option 2. The full spreadsheet has been added to the docket for our 

final action, and a screen copy of the spreadsheet is reproduced as Attachment 3 to this 

document. 

 While we agree with the conclusion that the Option 2 scrubber was undersized, we 

disagree with OG&E’s characterization of our initial analysis and many of OG&E’s related 

arguments. 

 Our analysis did not adjust costs based on the sulfur content of the coal, but rather based 

on the amount of SO2 removed. Our analysis also did not make any assumptions about reactor 

vessel sizes or sizing of lime storage, preparation, and slurry injection system, but rather adjusted 

lump sum scrubber cost using the six-tenth rule, a standard method used in cost engineering to 

adjust the capital cost of equipment.132 The six-tenth rule is commonly used in cost estimating 

and has been specifically recommended for dry scrubbers using an exponent similar to the one 

we used.133 We explained that the use of this rule "is an oversimplification as the actual values 

[of the exponent] ranges from less than 0.2 to greater than 1.0."134

 The design and sizing of a scrubber is generally divided into two major systems: (1) flue 

gas path and (2) reactant handling system. The flue gas path includes the scrubbing vessel, duct 

work, fabric filter, foundations, support structure and fans. The reactant handling system 

includes lime receiving, lime slurry preparation, reactant recycle, and ash handling systems. The 

following responds within this framework to statements by Sargent & Lundy with which we 

disagree. 

 

131 Using the formula in Table 1 of the 8/2010 S&L SDA FGD Report, Table 1, the total cost with AFUDC for a 

single unit at Sooner when burning 1.176 lb SO2/MMBtu coal is $229,122,268 and when burning 0.509 lb 

SO2/MMBtu coal, it is $221,885,381. The total cost with AFUDC for a single unit at Muskogee when burning 

1.176 lb SO2/MMBtu coal is $236,228,452 and when burning 0.509 lb SO2/MMBtu coal, it is $228,861,061. 132 See, e.g., Lawrence K. Wang, Norman C. Pereira, and Yung-Tse Hung (Eds.), Air Pollution Control Engineering, 

2010, p. 227 (recommends the six-tenth rule using a sizing exponent of 0.73). 

133 Ibid., page 227. 134 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March, 2011; Revised BART Cost-Effectiveness Analysis for Flue Gas Desulfurization at 

Coal-Fired Electric Generating Units in Oklahoma: Sooner Units 1 & 2 Muskogee Units 4 & 5 Northeastern Units 3 

& 4 Appendix C, page 7. 

58 
 First, the lime slurry, recycle slurry, and ash handling systems were designed for the 

maximum fuel sulfur content expected in the future, 0.48% sulfur.135 OG&E argues these 

systems cannot be designed for an average fuel sulfur content, but must be sized based on a 

reasonable estimate of the maximum fuel sulfur content expected at the facility. However, the 

design sulfur is higher than the range of coal sulfur burned historically. OG&E cites a Babcock 

& Wilcox book, as the authority for the reactant handling design basis. However, that reference 

does not state that the reactant and ash handling system must be sized based on a reasonable 

estimate of the maximum fuel sulfur content expected at the facility. 

 OG&E oversized the reactant and ash handling system to accommodate "anticipated" 

future increases in coal sulfur content. As we state elsewhere in our response to comments, this 

affects the baseline used in cost effectiveness analyses. The costs to process this higher sulfur 

coal should not be included in the BART cost analysis unless the increase in emission reductions 

it allows is used to calculate cost effectiveness. 

 Second, OG&E’s contractor, Sargent and Lundy, claims that the primary design 

parameter for sizing a dry scrubber is the flue gas flow rate. This claim does not comport with 

Sargent & Lundy's statements elsewhere. In the scrubber model developed for EPA, Sargent & 

Lundy explains: "Several input variables are required in order to predict future retrofit costs [for 

a spray dryer absorber]. The gross unit size in MW (equivalent acfm) and sulfur content of the 

fuel are the major variables."136 Also, in the initial BART analyses for Sooner and Muskogee, 

Sargent & Lundy explains: "Various process parameters affect the efficiency of the SDA process 

including: the type and quality of the additive used for the reactant, reactant stoichiometric ratio 

[lime to sulfur ratio], how close the SDA is operated to saturation conditions, and the amount of 

solids product recycled to the atomizer...High SO2 removal efficiencies in a SDA are also 

dependent upon good gas-to-liquid contact."137

 Third, OG&E cites the same Babcock & Wilcox book referenced above as the source for 

the claim that "The primary design parameter for sizing a dry scrubber is flue gas flow rate."138 

This book does not support the claim that flue gas flow rate is the primary design parameter. 

Rather, it explains that the "SDA chamber is sized to provide sufficient gas-phase residence time 

for drying of the reagent slurry to produce free-flowing solids in the particulate collector. The 

required residence time depends on the inlet flue gas temperature, feed slurry solids loading, 

degree of atomization, and exit gas temperature."139 

 Fourth, scrubber performance depends on many more factors than the flue gas flow rate, 

some of which are determined by the amount of SO2 that must be removed. Scrubber 

 

135 12/28/09 S&L FollowUp Report, Dry FGD Design and Cost Estimate Basis Document, Table 2.1-1. 136 Sargent & Lundy, IPM Model -- Revisions to Cost and Performance for APC Technologies, SDA [spray dryer 

absorber or dry scrubber] Cost Development Methodology, Final, Prepared under contract to Perrin Quarles Assoc., 

Inc. for U.S. EPA, August 2010, p. 1. 

137 Sargent & Lundy, Sooner Generating Station, Best Available Retrofit Control Technology Evaluation, May 27, 

2008, p. 43 and Sargent & Lundy, Muskogee Generating Station, Best Available Retrofit Control Technology 

Evaluation, May 28, 2008, p. 45. 

138 See footnote 22 in OG&E Appendix B, which cites "Steam: It's Generation and Use," 41st Edition, page 35-13. 139 Babcock & Wilcox, Steam: It's Generation and Use, 41st Edition, 2005, pp. 35-12 to 35-19. 

59 
performance, for example, depends on the diffusion of SO2 gas into the scrubber liquid. This 

process is referred to as mass transfer. The higher the mass transfer, the higher the SO2 removal. 

Option 1 assumed 91.5% removal of 43,428 ton/yr to 46,458 ton/yr of SO2 while Option 2 

assumed only 80% removal of 13,799 ton/yr to 13,930 ton/yr of SO2. Thus, Option 2 involves 

much less mass transfer and should thus be less expensive. TSD, Ex. B, Table 1. 

 Fifth, mass transfer is directly related to the surface area provided by water droplets 

containing the reagent lime sprayed into the flue gas. The scrubbing fluid is sprayed into the 

SDA chamber using an atomizer, which creates the required surface area. The design and cost of 

this atomizer does not depend solely on the exhaust gas flow rate, but also on the amount of SO2

that must be removed. Thus, the cost of the absorber island, which includes the SDA chamber 

and atomizer, is not independent of the amount of SO2 that is removed, as suggested by Sargent 

& Lundy. 

 The amount of surface area can be increased by changing the type of nozzles to spray a 

larger number of smaller droplets, by increasing the amount of slurry that is injected, or by 

improving the efficiency of contact.140 Thus, under Option 2, flow rates and absorber vessel size 

can remain constant while lump sum costs decline due to reductions in mass transfer area 

required to remove smaller amounts of SO2, e.g., modifications in the design of the atomizer, 

required to achieve a lower SO2 removal efficiency or remove lesser amount of SO2. 

Capacity in Option 2

In addition, OG&E presents information that is material to the costing of the operating 

costs in Option 2: "Sargent & Lundy, on the other hand, estimated capital costs for a scrubber 

that was designed to be capable of controlling the highest sulfur coal that could be delivered to 

OG&E but estimated operating costs using the coal’s average sulfur content.” Because OG&E 

states the operating costs were based on the average sulfur content of the coal that has 

historically been burned, we further examined the historical operating practices at the Sooner and 

Muskogee facilities. 

Operating costs include lime, water, FGD disposal, bag and cage replacement, and 

auxiliary power. These operating costs vary according to the amount of coal that is burned. In 

conducting its Muskogee SO2 BART analyses, ODEQ calculated annual emissions based on the 

controlled SO2 emissions rate, full load heat input of 5,480 MMBtu/hr, and assuming 7,884 

hours/year per boiler (90% capacity factor)141. ODEQ similarly assumed a future capacity factor 

of 90% in conducting the Sooner SO2 BART analysis. However, OG&E’s baseline SO2

emissions, were estimated from actual emissions in 2004-2006 when the units ran at an average 

capacity factor of 78.5%.142 The actual capacity factors for the four units in 2004–2006, based 

 

140 See, e.g., Eui-Kyung Oh et al., Effect of Initial Droplet Size Distribution on Sulfur Removal Efficiency in 

FGD/SDA, Korean Journal of Chemical Engineering, v. 16, no. 3, pp. 292-297, 1999; C.J. King, Separation 

Processes, 2nd Ed., McGraw Hill, New York, 1980, pp. 558-570, A.L. Hines and R.N. Maddox, Mass Transfer 

Fundamentals and Applications, Prentice-Hall, 1985, Chapter 5; Barbara Toole-O'Neil (Ed.), Dry Scrubbing 

Technologies for Flue Gas Desulfurization, Kluwer Academic Publishers, 1998. 141 Oklahoma Department of Environmental Quality, Air Quality Division, BART Application Analysis, January 

15, 2010, Oklahoma Gas and Electric Muskogee Generating Station, p. 18. 

142 BART Analysis Follow-Up Report, pp. 12-13. 

60 
on fuel input from the Clean Air Markets database, were as shown in Table 3: 

Table 3 

Average Capacity Factor for OG&E Units 

2004 2005 2006 average 

Muskogee 4 86.0% 73.7% 79.5% 79.7% 

Muskogee 5 75.4% 75.1% 82.4% 77.7% 

Sooner 1 85.5% 92.4% 69.4% 82.4% 

Sooner 2 74.3% 75.7% 72.4% 74.1% 

Average 78.5% 

 Thus, the emission reduction calculation compares uncontrolled 2004-2006 baseline 

emissions at a 78.5% capacity factor to controlled emissions when burning a higher sulfur coal at 

90% capacity factor. This results in two errors in Option 2: The future emissions were 

overestimated, and certain operating costs were underestimated. However, because we arrived at 

these errors due to independent research that we do not view as being a logical outgrowth of the 

comment we received, we have not revised our cost effectiveness analysis in Option 2. Instead, 

we view this as further evidence buttressing our conclusion that OG&E’s scrubber costs are high. 

Comment: AEP/PSO states that as part of its BART submittal, it determined that the 

average cost effectiveness for dry scrubbing at Northeastern Units 3 and 4 is $3,294/ton, in 2009 

dollars. However, according to AEP/PSO, Appendix C (SO2 BART Cost Effectiveness Analysis 

for the Federal Implementation Plan) of EPA’s Technical Support Document (TSD) for the 

Oklahoma Regional Haze SIP and FIP calculates an average cost effectiveness for dry scrubbing 

of $1,544/ton, in 2009 dollars based on the assumption that the “corrections” developed for the 

cost analysis performed for OG&E’s BART-eligible units should also be applied to AEP/PSO’s 

Northeastern Units. AEP/PSO claims that no justification is given for this “one-size-fits-all” 

approach. AEP/PSO incorporates by reference the critique of EPA’s cost-effectiveness analysis 

in OG&E’s comments, which demonstrate that significant errors and unjustified assumptions 

were made, and artificially reduce the costs of FGD installations at all units. AEP/PSO states 

that the Total Capital Investment (TCI) for retrofitting dry FGD/fabric filter systems at 

Northeastern Units 3 and 4 as contained in Appendix 2 of the TSD is $274,100,000 and, per page 

35 paragraph 3 under Unit Capital Cost, is based on the average of the Fox calculated cost/kW 

for the OG&E units or $265/kW, presumably in 2010 dollars. AEP/PSO concludes that there is 

no site-specific estimate for the work at Northeastern, the cost estimate in the TSD is 

considerably understated, and this calculated value drives the entire cost effective analysis. 

Response: See our response to the OG&E comments AEP/PSO references, elsewhere in 

our response to comments. As to the “one size fits all” comment, the TSD explains that the six 

units consist of nearly identical pulverized coal fired boilers installed around the same time that 

burn similar low sulfur PRB coal.143 We do not see where ODEQ has identified any site-specific 

differences, such as retrofit issues or space constraints, that would significantly affect the cost to 

 

143 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, page 23 and Table 4. 

61 
retrofit scrubbers on any one of these units compared to any other. Thus, absent any 

distinguishing factors, we find that the unit cost in $/kW to retrofit these units should be roughly 

equal. The TSD's estimate to retrofit scrubbers at Northeastern is within the range reported by 

others for similar facilities.144 As we discuss elsewhere in our response to comments, the cost to 

install scrubbers at these units, $555/kW - $582/kW, is not supported in the record. This value is 

substantially higher than unit costs for similar facilities based on independent studies.145 146 

Comment: AEP/PSO states that its cost-effectiveness value was based on a detailed sitespecific cost estimate, and is supported in the materials compiled by ODEQ and submitted to 

EPA with the proposed SIP. AEP/PSO claims that the calculations found in EPA’s Technical 

Support Document Appendix C have no site-specific analyses, incorporate generic estimates and 

vendor information without regard to its suitability for this site, and omit critical project 

components. According to AEP/PSO, the calculations from Appendix C therefore lack the 

fundamental attributes required of a site-specific BART cost estimate and provide no 

justification for rejecting the Oklahoma SIP. 

Response: The ODEQ SO2 BART evaluation of AEP/PSO Northeastern units 3 and 4 

does not provide any support for its assumption that the cost of scrubbers is $555/kW to 

$582/kW. We are not aware of a detailed site-specific cost estimate in the materials compiled by 

ODEQ and submitted to EPA with the proposed SIP. In fact, ODEQ notes in its BART 

determination (at pdf 14): 

The engineering estimates and possible vendor quotations AEP-PSO relied on to develop 

base $/kW Total Capital Investment assumptions were not provided to substantiate the capital 

costs for installation. In reviewing BART submittals to other states, AEP-PSO’s estimated costs 

were found to be somewhat higher than those reported for similar projects. However, the 

evaluations in neighboring states are known to underestimate present day costs and the analysis 

submitted by AEP-PSO is in line with the more detailed and recent analyses submitted by 

OG&E.147

However, the Northeastern units are very similar to the Sooner and Muskogee units, for 

which this information was available. We used these vendor quotes to support our cost analysis 

for the Northeastern units. Thus, absent any supporting information from AEP/PSO for any of 

the capital costs it presents, we find our BART SO2 cost evaluation to be well founded, 

representative of the AEP/PSO units in question, and based on the best information available to 

us. 

Comment: AEP/PSO states that the purchased equipment costs (PEC) provided in 

Appendix 2 of the TSD, which includes installation and commissioning labor costs, for a dry 

FGD/fabric filter for the Northeastern 3 and 4 units is $249,100,000 ($265/kW). AEP/PSO 

 

144 Ibid., TSD, pp. 33-35 and Fig. 2. 145 See, e.g., J. Edward Cichanowicz, Overview of Information on Projected Control Technology Costs and 

Performance As Developed for EPA's Integrated Planning Model (IPM), Prepared for the Utility Air Regulatory 

Group, October 15, 2010, pp. 5-7 and Fig. 2. 

146 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, pp. 33-35 and Fig. 2. 

147 ODEQ, BART Application Analysis, January 19, 2010, pdf. 14. 

62 
believes that the cost estimate does not appear to include the cost of a new stack, which was 

included in the costs supplied by AEP/PSO to ODEQ in 2009. 

Response: The record contains no evidence that a new stack would be required for a 

retrofit dry scrubber at Northeastern. A new stack is not specified for similar retrofits at Sooner 

and Muskogee. Existing stacks are generally used for dry scrubbers due to the dry condition of 

the flue gas. However, if the units are cycled frequently, acid condensation could form on the 

chimney shell. Thus, acid-resistant coating of the top 100 feet on the outside of the stack is 

typically included in dry scrubber costs. The unit cost estimates for both Sooner and Muskogee, 

which were extrapolated to Northeastern, include $1.4 million for coating the top 100 feet of 

stack.148 Thus, the cost for stack modifications is included in our Northeastern cost estimates. 

Comment: AEP/PSO states that the estimate provided in the TSD is not consistent with 

the actual vendor estimates secured by it. As a basis for estimating total installed capital costs, 

AEP/PSO states it solicited firm first quarter 2009 material design and supply pricing from an 

FGD/fabric filter equipment manufacturer for both Northeastern 3 and 4. This cost totaled 

approximately $76,000,000, and included a multiple purchase discount, as suggested in the TSD. 

Response: The ODEQ BART evaluation for the Northeastern units does not include any 

vendor estimates from AEP/PSO in support of the Northeastern cost effectiveness analysis. 

Nevertheless, our cost estimate for Northeastern is based on vendor quotes for similar units at 

Sooner and Muskogee. The Sooner and Muskogee quotes average $72,000,000149 compared to 

$76,000,000 stated by AEP for Northeastern (without any record support). 

Comment: AEP/PSO states that based on historical analysis of actual costs for 

retrofitting air pollution technology at several AEP coal fired generating stations, the base cost of 

material design and supply of the FGD/fabric filter system typically represents 15% of the total 

installed project capital cost. AEP/PSO states this method of estimating total installed project 

capital cost is corroborated by Table 4, page 164 of Plant Design and Economics for Chemical 

Engineers, Peters and Timmerhaus, 3rd edition. AEP/PSO states that using this methodology 

and the base costs supplied by the equipment manufacturer, the total installed capital costs for 

dry FGD/fabric filter technology at Northeastern 3 and 4, in 2009 dollars, therefore approaches 

$506,000,000 ($544/kW), which is within 2% of the $555/kW estimate in the Trinity report 

submitted to the ODEQ. AEP/PSO states that nothing in the TSD demonstrates that these costs 

are unreliable, or provides any basis for rejecting these site-specific estimates in favor of the 

costs derived for different units in the TSD. 

Response: Based on our review of the 4th edition of the cited reference, the cited table 

reports that purchased equipment typically ranges from 15% to 40% of the total direct costs. 

However, as we have discussed elsewhere in our response to comments, we do not see any 

support for any of the capital costs for the AEP/PSO Northeastern scrubber cost estimates. The 

makeup of the differential between the purchased equipment cost and the installed project cost 

(the 15% cited in this comment) must be broken out to determine if it includes costs such as 

 

148 Excel Spreadsheets: (1) Cost 30352A, Muskogee Unit 1&2 Dry FGD Systems Conceptual Cost Estimate, Lines 

271-276 and (2) Cost 30351A, Sooner Units 4 & 5 Dry FGD Systems Conceptual Cost Estimate, Lines 260 - 265. 

149 12/28/09 S&L FollowUp Report, DFGD Budgetary Proposal Pricing. 

63 
AFUDC, bond cost, escalation and inflation, which are not allowed in the overnight method used 

in the Control Cost Manual. This breakout has not been provided for the Northeastern units. 

This calculation adjusts the vendor quote of $74 million to total installed capital costs of 

about $506 million by dividing the vendor quote by AEP's unsupported rule of thumb of 0.15 

(74/0.15 = 493) and increasing the result to $506 to match $544/kW, without explaining the $13 

million differential (506-493 = 13), which cannot be attributed to rounding. 

The components included in the difference, or $432 million (506-74 = 432) are not 

identified and quantified. Thus, they cannot be reviewed. However, the Sargent & Lundy cost 

analysis for Sooner and Muskogee indicates that the vendor quotes are about 12% of the total 

project cost, or roughly equivalent to those claimed by AEP/PSO. The TSD and our response to 

comments indicate many of the components in this differential are not allowed in the overnight 

costing method used in cost effectiveness analyses, as required by the Control Cost Manual. 

These include AFUDC, owners cost, bond costs, inflation, taxes, and escalation. We cannot 

comment specifically on these additional costs for the Northeastern units (the $432 million 

differential) because AEP/PSO has not produced any support for them, including any of the 

assumptions used to derive them. The record only identifies the total sum, which prevents us 

from engaging in any meaningful analysis. 

Comment: AEP/PSO states the unrealistically low assumed PEC we employ in our SO2

BART analysis of the Northeastern units in Appendix 2 for the dry FGD/fabric filter results in a 

cascading reduction of Indirect Operating Costs (Administrative Charges, Insurance, Property 

Taxes and Capital Recovery) as they are calculated as a percentage of Total Capital Investment 

(TCI). AEP/PSO states the understated PEC results in an understated cost in line item 12 in 

Appendix 2 for administrative, insurance and property taxes of over $13 million. 

Response: As we state elsewhere in our response to comments, we see no support for 

AEP/PSO’s PEC. Our PEC is consistent with our detailed analysis of the OG&E SO2 scrubber 

cost evaluation, and the range reported in other studies, as summarized in the TSD.150 

Comment: AEP/PSO states that since the Northeastern analysis included in the TSD is 

based, in large part, on the analysis conducted for the OG&E Sooner and Muskogee plants, 

comments on the methods used for OG&E facilities are appropriate. 

AEP/PSO objects to our statement in the TSD that “escalation is a contingency and is 

double counted....” and was set to zero for the analysis. AEP/PSO states that categorizing 

escalation as a contingency and setting it to zero is not appropriate, as it is a real cost associated 

with expected increases for labor and materials that occur over time, and must be accounted for 

when projects extend over a period of years. AEP/PSO states that contingency, per the EPA 

Cost Manual, is a reserve that is applied to items that could incur a reasonable but unanticipated 

increase but are not directly related to the demolition, fabrication and installation of the system. 

They state that our assertion on escalation is in direct conflict with page 2-30 of the Control Cost 

 

150 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, pp. 33-35 and Fig. 2. , Appx. C, pp. 33-34. 

64 
Manual, 6th Ed., and unrealistically decreases the estimated costs of completion of a multi-year 

project. 

AEP/PSO states that as recently as March 29, 2011, the U.S Bureau of Labor Statistics 

published information concerning the Producer Price Index, which is typically used by 

Contractors to calculate project escalation. According to AEP/PSO, this critical index is 

approaching an all time high and has increased 8% since January 2009. AEP/PSO concludes that 

in light of such circumstances, eliminating an escalation factor is unreasonable and artificially 

understates the cost of a major capital project. 

Response: The escalation referred to in this comment is the escalation of current year 

dollars to the future, when the costs are incurred. In our analysis of OG&E’s costs, this included 

escalation of equipment (2.5% for 2010 and 4% for 2011 - 2014), material (3% for 2011 and 5% 

for >2012), labor (3% for 2010 and 4% for 2011-2014), and indirects (3% for 2010 and 4% for 

2011-2015) to the year of expenditure. The Cost Control Manual approach explicitly excludes 

future escalation as cost comparisons are made on a current real dollar basis. Escalation costs 

expressed in prior year dollars, before the year of the cost estimate, to current year dollars using 

an appropriate cost index is allowed under the overnight costing approach used in the Control 

Cost Manual methodology. However, this is a different concept than escalating current dollars to 

a future year of operation dollars, which is not allowed under the Control Cost Manual approach 

as it involves speculation. Historical escalation, which is allowed under the overnight costing 

approach in the Control Cost Manual, is based on known cost indices. Escalation to future years, 

beyond 2009, is not allowed under the overnight costing approach used in the Control Cost 

Manual. See elsewhere in our response to comments for more information regarding the concept 

of escalation as it relates to a BART cost analysis. 

Comment: AEP/PSO states that the most accurate estimate (+/- 5%), as defined in the 

EPA Control Cost Manual, requires complete drawings, specifications and site surveys. These 

were not used in either the Trinity analysis or the TSD, nor do they exist for the Northeastern 

unit retrofits. Multiple capital cost estimating examples provided in the EPA Cost Manual use a 

3% contingency factor, more than four times greater than the contingency allowance of 0.7% 

(Line item 41 divided by line item 32) used as the basis for the estimates in Appendix 2. Given 

the lack of precision in the estimates developed for the Northeastern units, a contingency factor 

is warranted, and the factor used in the TSD is unrealistically low. 

Response: The contingency factor most commonly used in the Control Cost Manual for 

similar equipment to SO2 scrubbers at a similar stage of design (e.g., vendor quotes,) is 3% of 

total purchased costs.151 The contingency factor noted in this comment (0.7%) is expressed 

relative to total capital investment, not total purchased cost [e.g., 100 (2,136,000/289,791,940) = 

0.74%]. The 3% contingency specified in the Cost Manual and cited in this comment was used 

in the revised cost estimate for Northeastern.152 Thus, we find that no modification of our 

contingency factor is warranted. 

 

151 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, p. 13 and footnote 44. 

152 Ibid., TSD, Appx. C, Appx. 1. 

65 
Comment: AEP/PSO states that we indicate in the TSD that costs could also be reduced 

by combining processing units, e.g., a single lime preparation system, a single ash handling 

system, a single fabric filter or similar common equipment sized for multiple units. However, 

states AEP/PSO, we subsequently indicate that a precise estimate could not be made as required 

information was not provided by Sargent & Lundy. AEP/PSO states we applied, without 

apparent basis, a reduction of 5% to the costs associated with these process units, that also 

impacts the Northeastern cost analysis. According to AEP/PSO, no such reduction is justified in 

the case of the Northeastern units, because site-specific vendor equipment estimates were used to 

generate the costs associated with these units. 

Response: The request for quote and vendor equipment estimates AEP/PSO mentions 

have not been provided for the Northeastern units. Thus, the design basis and opportunity for 

discounts and economies of scale cannot be assessed. However, the Northeastern units are very 

similar to the Sooner and Muskogee units, for which this information was available. We used 

these vendor quotes to support our cost analysis for the Northeastern units, and we have (as 

discussed elsewhere in our response to comments) concluded these discounts are justified for the 

OG&E units. Thus, absent any supporting information from AEP/PSO for any of the capital 

costs it presents for its SO2 BART analysis, we find that this 5% discount is similarly justified 

for the AEP/PSO units. 

Comment: AEP/PSO states that we assumed the Northeastern units will shift to a higher 

sulfur fuel than is currently burned, thus inflating the baseline emissions by over 300%, thereby 

reducing the cost-effectiveness of FGD installation. AEP/PSO states this is contradicted by the 

RH rule, 70 Fed. Reg. 39167, and by prior EPA analyses. See 74 Fed. Reg. 44321. They 

conclude the TSD cost-effectiveness analysis for AEP/PSO’s Northeastern units is biased and 

provides no basis for rejecting the ODEQ SO2 BART determination for these units. 

Response: The issues discussed do not apply to the Northeastern units. We did not make 

any assumptions about AEP/PSO switching to a higher sulfur coal. AEP/PSO's consultant 

estimated SO2 emission reductions of 26,559 ton/yr. We revised this estimate to 29,119 ton/yr, a 

10% increase in emission reductions, which adjusted the scrubber control efficiency from 85% to 

91%, as a result of meeting the BART limit of 0.06 lb/MMBtu.153 Thus, there is no 300% 

inflation of baseline emissions due to a shift to higher sulfur fuel in our revised cost estimate for 

the Northeastern units. 

Comment: AEP/PSO states that we improperly discarded insurance costs for 

Northeastern and instead used Sooner and Muskogee’s insurance costs as a basis for lowering 

Northeastern’s insurance costs by a factor of ten. They state we do not provide a basis for why 

we deviated from our Control Cost Manual and why the insurance costs for the Sooner and 

Muskogee plants are applicable to Northeastern. They state that the value for insurance is 

generally calculated as 1% of the TCI. However, they note that the assumed TCI in Appendix 2 

is the sum of Landfill Construction ($25M) provided by them and purchased equipment estimate 

of $249.1M. AEP/PSO claims that line item 32 is calculated as $28,781, but should be at least 

$2.741M based on the assumed cost of the FGD/fabric filter technology. 

 

153 Ibid., ITSD, Appx. C, p. 38. 

66 
Response: This is not a mathematical error in our calculation of insurance, but rather a 

correction to ODEQ’s analysis. As explained elsewhere in our response to comments, we used 

certain OG&E costs in our cost calculation for AEP/PSO because of the similarities of the units 

owned by both companies. We find it is appropriate to use OG&E’s site specific costs to 

calculate insurance costs for the AEP/PSO units because of the similarity of these units to the 

OG&E units. The TSD154 explains that insurance is not 1% of TCI as assumed in AEP's 

analysis, but rather 0.015% of TCI, based on OG&E’s analysis for Sooner and Muskogee. Thus, 

we revised Appendix 2, Line 32. The parenthetical (1% TCI) shown in Appendix 2 is from 

AEP/PSO’s contractor’s report and does not represent the calculations made in Appendix 2. 

Therefore, we find that the calculation of insurance in the TSD, Appendix 2, Line 32, is correct 

as stated. 

Comment: AEP/PSO states that there is a mathematical error in the TSD in our 

calculation of property tax and we improperly discarded the property tax estimate for 

Northeastern and instead used Sooner and Muskogee’s property tax rate as a basis for lowering 

Northeastern’s property taxes. They state the value for property tax is generally calculated as 1% 

of the TCI, which is $2.741 million based on the assumed cost of the FGD/fabric filter 

technology assumed in the TSD. AEP/PSO concludes that line item 33 is $2.329 million, not 

$2.741 million. 

AEP/PSO states that the TSD provides no basis for why change out rate and costestimates applied to the Sooner and Muskogee units are applicable to the Northeastern units. 

AEP/PSO states that if indeed the Control Cost Manual is the source of the value, then this is 

contradictory to the criticism in Section III of the Technical Support Document that the Control 

Cost Manual should play a greater role in such an analysis. 

Response: This is not a mathematical error in our calculation of property tax, but rather a 

correction to AEP/PSO's analysis. The TSD155 explains that property tax for Northeastern was 

estimated as 1% of TCI, based on the Cost Manual default. The Sargent & Lundy analysis for 

Sooner and Muskogee indicates that property taxes in Oklahoma are lower, estimated as 0.6% of 

TCI at Sooner and 0.85% of TCI at Muskogee. We confirmed Sargent & Lundy's estimate 

elsewhere in our response to comments and used the upper end of the range (0.85%) for 

Northeastern. Thus, we revised AEP/PSO’s insurance costs in Appendix 2, Line 33. The 

parenthetical (1% TCI) shown in Appendix 2 is from AEP/PSO’s contractor’s report and does 

not represent the calculations made in Appendix 2. The TSD explains why property tax rates are 

similar for Sooner, Muskogee, and Northeastern. The six units consist of nearly identical 

pulverized coal fired boilers installed around the same time that burn a similar low sulfur coal. 

Thus, an upper-bound site-specific estimate for four of these six units is more representative than 

a generic factor from the Cost Manual. We specifically researched Oklahoma property tax and 

concluded that 0.85% is a reasonable upper bound for Northeastern, located in Rogers County. 

This comment does not explain why a site-specific estimate of property tax was not used in the 

Trinity cost analysis, given the claims throughout the AEP comments that the Northeastern cost 

analysis is site-specific and the fact that AEP would have had ready access to this information. 

We find that the calculation shown in the TSD, Appendix 2, Line 33, is correct as stated. 

 

154 Ibid., TSD Appendix C, p. 37. 155 Ibid., TSD Appendix C, p. 38 

67 
Comment: AEP/PSO states that many of the assertions in the TSD are unsupported and 

inconsistent with actual operating experience at retrofit FGD installations. As a utility provider 

and the owner of the units at issue, AEP/PSO states that it has direct experience with the costs 

associated with installing FGD retrofits, and the specific conditions and constraints at this 

location, and is in the best position to calculate the costs to retrofit its own units. Thus, we 

should accept the analysis and estimates submitted by ODEQ as the basis for BART 

determinations in the Oklahoma SIP. 

Response: These comments have not identified any errors in our report. We could not 

approve ODEQ’s BART determination for AEP/PSO in part because it is not supported in the 

record. The capital cost is based on an unsupported unit cost estimate of $555/kW, which is 

inconsistent with analyses presented for other similar facilities, including AEP's BART analysis 

for its White Bluff station.156 As discussed elsewhere in our response to comments, the unit cost 

that AEP's analysis is based on includes cost elements, such as AFUDC, inflation and escalation, 

that are not allowed under the overnight Control Cost Manual approach. Since ODEQ’s BART 

cost effectiveness analysis does not provide supporting documentation and overestimates the 

costs for installation of a dry FGD at AEP/PSO’s Northeastern units, it is not approvable. 

AEP/PSO’s comments frequently allude to various site specific estimates for the 

Northeastern unit, including vendor quotes. However, none of this material has been provided to 

us. The BART Guidelines specifically require "documentation for any additional information 

you used for the cost calculations, including any information supplied by vendors that affects 

your assumptions regarding purchased equipment costs, equipment life, replacement of major 

components, and any other element of the calculation that differs from the Control Cost 

Manual."157 The TSD, Appendix C, on the other hand, provides the basis for each modification 

that was made by us to the Northeastern cost estimate. As demonstrated in our response to 

comments, the allegation that the TSD analysis is unsupported is incorrect. 

Comment: AEP/PSO states that the following statements from our TSD are unfounded 

and that we have not presented citations to similar facilities that would support these statements: 

(From Page 1-2 of Technical Support Document) 

When these errors are corrected, the average cost effectiveness for dry 

scrubbing declines at Sooner from $6,747/ton to $1,291/ton; at Muskogee 

from $7,435/ton to $1,317/ton; and at Northeastern from $3,294/ton to 

$1,544/ton, in 2009 dollars. Actual costs could be even lower as I was 

unable to correct all of the overestimates that I identified due to lack of 

support and underlying calculations. My revised cost effectiveness values 

are within the range of values found to be cost effective at other similar 

facilities. In addition, my analysis indicates that a dry scrubber at any of 

these units could achieve a BART emission limit of 0.06 lb/MMBtu, based 

on 30-day rolling average, when burning low sulfur coal. 

 

156 Ibid., TSD, Appendix C, pp. 33-34 & 38, footnote 147. 157 70 FR 39,166, col. 3, footnote 15 (emphasis in original). 

68 
(From Page 1-2 of Technical Support Document) 

BART analyses performed for many similar facilities nationwide indicate 

that the cost effectiveness of a wet scrubber is about 9% higher than for a 

dry scrubber. 

Response: This material is quoted from the summary and conclusions. The detailed 

support is found elsewhere in the report. See the table of contents. For instance, the cost 

effectiveness information for "similar facilities" is found in Table 7 of Appendix C of the TSD. 

The support for the fact that the cost effectiveness of a wet scrubber is about 9% higher than for 

a dry scrubber is found in the TSD158. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 1-2 of Technical Support Document) 

In cases where an existing electrostatic precipitator can be used instead of 

a new fabric filter baghouse, the cost effectiveness of wet scrubbing is 

lower than dry scrubbing and the incremental cost effectiveness is zero. 

This is likely the case for the subject units, but this option was not 

evaluated by the companies. 

AEP-PSO disagrees with us that an existing electrostatic precipitator (ESP) can be used 

instead of a new fabric filter baghouse, which we claim will lower the cost effectiveness 

calculation for wet scrubbing to below the cost effectiveness of dry scrubbing and eliminates the 

incremental cost effectiveness. AEP/PSO states that a fabric filter baghouse is integral to the 

design and performance of a dry FGD. No examples or citations are provided to support the idea 

that an ESP is being used in practice or is sufficient to support dry FGD operations. 

Response: This material is quoted from the summary and conclusions. The detailed 

support is found elsewhere in the report. See table of contents. The support for the use of an 

existing electrostatic precipitator in the design of a dry FGD system is found in the TSD159at 

pages 25-26. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 25 of Technical Support Document) 

As noted above, a dry scrubbing system consists of a spray chamber 

followed by a dust collection device. These two devices together are 

referred to as a dry scrubber or dry flue gas desulfurization unit (DFGD). 

The costs for the Sooner and Muskogee dry scrubbers include a new fabric 

filter baghouse at each unit. This baghouse accounts for about one-third 

of the purchased equipment cost. However, all of the BART-subject, coalfired units are currently equipped with electrostatic precipitators, a dust 

collection device that could be used instead of the new baghouse. The 

 

158 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, Table 8. 

159 Ibid., TSD, Appendix C, pages 25-26. 

69 
costs for a new baghouse, when an acceptable dust control device is 

already present, could make a significant difference in an incremental cost 

comparison with a wet scrubber, which does not require a downstream 

baghouse. 

AEP/PSO states that we have not provided a basis for this statement. They state that a 

fabric filter baghouse is integral to the design and performance of a dry FGD. They state that no 

examples or citations are provided to support the idea that an ESP is being used in practice or is 

sufficient to support dry FGD operations. 

Response: A particulate control device is an integral part of a dry FGD. This device 

does not have to be a fabric filter, particularly when an existing ESP is present. We provide 

support for this statement in the TSD.160 It should be noted that we did assume a fabric filter 

would be purchased as part of our cost estimate for all six OG&E and AEP/PSO units. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 35 of Technical Support Document) 

The Northeastern analysis starts with an assumed unit capital cost, 

expressed in dollars per kilowatt of capacity ($/kW), that is not supported, 

but simply stated. It is reported as $555/kW in the Trinity Report and as 

$582/kW in the ODEQ BART analysis. As explained above, capital costs 

of this magnitude are outside of the range of actual costs for similar sized 

plants with no serious retrofit issues. These elevated values correspond to 

smaller units with significant retrofit issues. AEP, the owner of 

Northeastern, has publicly reported the capital cost of scrubber technology 

is about $262/kW. 

AEP/PSO states that the reference cited is to an “average” capital cost of retrofit FGD 

projects and is not specific to the Northeastern units. They state their retrofit program is 

designed to prioritize the installation of FGD units to achieve the most cost-effective SO2

reductions for the AEP fleet. AEP/PSO states the FGD retrofit projects represented by the 

average $262/kW value are for larger units (800 to 1,300 MW) that utilize bituminous coals with 

a higher sulfur content, which have different FGD design variables and associated cost 

considerations compared to the Northeastern units, that are smaller in size (490 MW) and utilize 

lower sulfur subbituminous coal. In fact, states AEP/PSO, the report in the TSD alludes to the 

benefits of such a system-wide approach to retrofit projects on page 8 by noting: “... it would be 

in the owner’s interest to build the larger scrubber based on the higher sulfur coal as it is not only 

more cost-effective, but it provides greater flexibility in future operations. ....this is a good 

business strategy....” Therefore, states AEP/PSO, the average value utilized by us has no 

relevancy for accurately estimating the cost of an FGD at Northeastern Plant. AEP/PSO 

concludes the $555/kW value is based on evaluation of site-specific factors and is more accurate 

for accessing the cost-effectiveness of an FGD project at the Northeastern Plant. 

 

160 Ibid., TSD, Appendix C, pages 25-26, footnotes 89 and 91. 

70 
Response: ODEQ’s RH SIP submittal contains no support for the cited unit cost of 

$555/kW, which is very high compared to other publicly reported estimates.161 As explained 

elsewhere in our response to comments, this value includes costs such as AFUDC, escalation, 

and inflation that are not allowed in the overnight cost analysis used to estimate cost 

effectiveness in the Control Cost Manual. 

This comment states that the AEP-reported value of $262/kW is for larger units, 800 to 

1300 MW, that use higher sulfur coal and different design variables, which may be wet FGD 

installations. However, AEP did not analyze wet scrubbing for Northeastern. It is feasible and 

more cost effective (i.e., dollars per ton lower as emission reductions are higher for roughly the 

same cost) to build a single wet scrubber to serve the two 490 MW Northeastern units (980 

MW), designed to remove 98% of the SO2 from the combined flue gas. 

A wet FGD system has a significant cost advantage for a large system, such as the 980 

MW combined Units 3 and 4. Single absorbers have been built up to 1000 MW.162 A single 

large wet scrubber significantly reduces the capital cost of controlling SO2 emissions. One large 

wet scrubber designed to service 980 MW may be more cost effective than two smaller dry 

scrubbers, each designed to service a 490 MW unit, as the latter would require two 50% absorber 

vessels to serve each 490-MW unit while the former would require only a single 980 MW 

absorber. AEP/PSO does not explain why this potentially lower cost option was not evaluated 

for Northeastern. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 35 of Technical Support Document) 

The information I reviewed does not identify any retrofit issues or unusual 

circumstances that would lead to such a high unit capital cost. 

AEP/PSO states this is an unfounded statement with no reference to specific citations that 

would support this statement. 

Response: This statement is based on our examination of the complete record that 

Oklahoma produced to support its BART determination. The record does not identify any 

retrofit issues or unusual circumstances that would justify a high unit capital cost—higher than 

those found in other similar analyses, as summarized in the TSD.163 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 35 of Technical Support Document) 

 

161 Ibid., TSD, Appendix C, pages 33-34, Figure 2. 162 Wet Flue Gas Desulfurization Technology Evaluation, Project number 11311-000, Prepared for National Lime 

Association, January 2003, prepared by Sargent & Lundy, Available here: 

http://www.graymont.com/technical/Wet_Flue_Gas_Desulfurization_Technology_Evaluation.pdf 163 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, pages 33-34, Figure 2, Table 7. 

71 
The unit capital cost for the two coal-fired Northeastern units should be 

about the same as for Sooner and Muskogee. These six units are similarsized, tangentially-fired boilers that burn similar low sulfur PRB coal and 

were built about the same time (Table 4). They all use electrostatic 

precipitators for particulate control. Thus, absent a demonstration to the 

contrary, the unit capital cost for the Northeastern units should be about 

the same as for the Sooner and Muskogee units. 

AEP/PSO states that although similarities exist, accurate cost-estimates for any retrofit 

project are based on variety of site- and project-specific variables. According to AEP/PSO, these 

include site-specific unit integration considerations; current unit disposition and condition; 

available footprint at the project site to support the control equipment; available water supply, 

water treatment, and coal combustion by-product disposal options; as well as the availability and 

cost of capital and labor. AEP/PSO states the analysis performed by its consultant considered 

project variables specific to the Northeastern Project. AEP/PSO concludes that to generalize 

such an analysis with a one-size-fits-all approach as proposed would yield unrepresentative 

results. 

Response: We based our analysis on the RH SIP submitted to us by the State of 

Oklahoma. This SIP was constructed by ODEQ, who performed its own BART analyses, 

including the SO2 BART analysis we reviewed for units 3 and 4 of the AEP/PSO Northeastern 

facility However, we also reviewed an earlier draft BART analysis performed by AEP/PSO and 

Trinity Consultants 164 and other material. We did not see the kind of site specific information 

discussed in this comment in the official BART analysis we received from Oklahoma, nor did we 

see it in any of the other material we reviewed. The BART Guidelines specifically require 

"documentation for any additional information you used for the cost calculations, including any 

information supplied by vendors that affects your assumptions regarding purchased equipment 

costs, equipment life, replacement of major components, and any other element of the calculation 

that differs from the Control Cost Manual."165 We cannot review and approve an unsupported 

cost analysis, particularly when it deviates substantially from those prepared for other similar 

facilities.166 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 35 of Technical Support Document) 

Thus, I revised the Trinity capital cost estimate using the average capital 

cost from my revised Sooner and Muskogee analysis in Appendix 1, Line 

65. This value is $265/kW, without escalation, AFUDC, bond costs, and 

excessive contingency, which are not appropriate for BART cost effective 

 

164 Best Available Retrofit Technology (Bart) Determination, American Electric Power  Northeastern Power Plant, 

Prepared by N.N. Dharmarajan, AEP; Eugene Chen, P.E. and Jeremy Townley, Trinity Consultants, May 30, 2008. 

165 70 FR 39166. 166 70 FR 39168, "You should provide documentation of any unusual circumstances that exist for the source that 

would lead to cost-effectiveness estimates that would exceed that for recent retrofits. This is especially important in 

cases where recent retrofits have cost-effectiveness values that are within what has been considered a reasonable 

range, but your analysis concludes that costs for the source being analyzed are not considered reasonable." 

72 
analyses. The revised Northeastern capital cost is shown in Appendix 2, 

Line 12. 

AEP/PSO states that Appendix 1, Line 65 in the TSD analysis utilizes values of 262 

$/kW for Sooner 1&2 and 268 $/kW for Muskogee 4&5. AEP/PSO claims these revised values 

for the cost analysis are not properly derived or justified. Further, states AEP/PSO, no rationale 

is provided for how the average of these arbitrary values derived for Sooner and Muskogee are 

applicable to the Northeastern units. Therefore, concludes AEP/PSO, the use of the 265 $/kW 

should be disregarded. 

Response: The basis for calculating the average capital cost for OG&E’s units, as well as 

why we believe it is appropriate to use certain OG&E’s costs in the cost calculations for the 

Northeastern units, is explained elsewhere in our response to comments. The derivation of the 

value $265/kW is explained in the TSD167: 

Thus, I revised the Trinity capital cost estimate using the average capital 

cost from my revised Sooner and Muskogee analysis in Exhibit 1, Line 65. 

This value is $265/kW, without escalation, AFUDC, bond costs, and 

excessive contingency, which are not appropriate for BART cost effective 

analyses. The revised Northeastern capital cost is shown in Exhibit 2, 

Line 12. 

The actual calculation can be seen by clicking on the cell containing this value in the 

Excel version of Appendix 1. The underlying calculation was not modified from the Trinity 

version so the cell is not highlighted in blue. However, the cell that uses this value in Appendix 

2, Line 10, is highlighted in blue to signal the new use. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 36 of Technical Support Document) 

Operating and maintenance costs comprise the sum of variable O&M 

(utilities and replacement parts), fixed O&M (operating and maintenance 

labor), and indirect O&M (administrative/overhead). The Trinity analysis 

omitted some of the components of O&M and overestimated others. 

These errors and omissions are discussed below and corrected in 

Appendix 2. 

AEP/PSO states this statement is unfounded and provides no citations to references that 

define the parameters which the TSD alleges should and should not be considered. AEP/PSO 

states that O&M variables and related costs will be based on site- and project-specific 

considerations, which were considered by Trinity to more accurately estimate potential FGD 

retrofit costs for the Northeastern Plant. 

 

167 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, pages 33-34, Figure 2, Table 7. 

73 
Response: We disagree with this comment. Each variable that was modified in the 

Northeastern analysis is specifically identified and the basis for the modification identified and 

footnoted in our TSD.168 In fact, in some cases, we added costs that AEP/PSO erroneously 

omitted, (e.g., water, FGD waste disposal, bag & cage replacement), thus increasing our cost 

basis for installing dry scrubbers at the Northeastern units. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 36 of Technical Support Document) 

A dry scrubber requires water to prepare the reagent slurry and to cool the 

flue gas stream. The cost to supply water was not included in the Trinity 

analysis. I added water cost, scaled from the water demand for Sooner 

and Muskogee. See Section III.B.4.a.ii. The average cost of water, based 

on Sargent & Lundy's tabulation of water cost for six similar facilities is 

$1.10 per 1,000 gallons. The water cost, calculated using these 

assumptions, is included in Appendix 2, Line 23. 

AEP/PSO references a footnote we cited earlier in our TSD in section III.B.4.a.ii, and 

states the justification cited by that footnote is an email from a vendor (to an unknown recipient) 

that utilizes general information from a 2005 reference. According to AEP/PSO, the use of such 

a reference is of little value as it ignores site-specific considerations for water supply and water 

use, which are influenced by a number of factors. 

Response: In general, ODEQ (which utilized the AEP/PSO analysis) provided little 

support for the overall cost analysis of the Northeastern units which we reviewed. Site-specific 

information has not been provided to us. As we discuss elsewhere in our response to comments, 

documentation for site-specific information is specifically required by the BART Guidelines.169 

In the case of water, the subject of this comment, AEP/PSO’s analysis failed to include any 

estimate, let alone a site-specific estimate. We added this cost, which had the effect of 

increasing the annual cost. As the footnote to the comments AEP/PSO cites indicates, the 

estimate we used for water cost at Northeastern was not taken from the cited vendor email, but 

rather from a summary prepared by Sargent & Lundy of water costs used in other BART 

analyses.170 The water cost value we used for the Northeastern units falls within the acceptable 

range, as reported in the TSD171. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 37 of Technical Support Document) 

A dry scrubber generates about 5 pounds of solids per pound of SO2

removed.141 These solids may be reused, but most commonly, are 

 

168 Ibid., TSD, Appendix C, pages 36 - 38, Section IV.B., subsections on water, FGD waste disposal, bag and cage 

replacement, labor, insurance, and property taxes. 169 70 FR 39166, 39168. 170 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, pages 28-29, 36 and footnote 140. 

171 Ibid., TSD, Appendix C, page 36, footnotes 140 and pp. 28-29. 

74 
disposed of at an on-site or off-site landfill. The capital cost estimates for 

Northeastern include costs for an on-site landfill. Sargent & Lundy 

summarized the O&M landfill disposal costs for eight similar facilities, 

including Sooner and Muskogee. The costs range from $5/ton at Gerald 

Gentleman to $40.59/ton at Muskogee.142 As the Northeastern costs 

include $25 million for an on-site landfill, disposal costs would be lower 

than off-site disposal and further can be optimized. Thus, they would be 

expected to fall at the lower end of the reported range, or $5/ton. 

Therefore, in Appendix 2, Line 24, I estimated the cost of on-site landfill 

disposal assuming that 5 pounds of solids would be generated for each 

pound of SO2 removed and that it would cost $5 per ton to dispose of 

them. 

AEP/PSO states the amount of byproduct generated by a dry scrubber is dependent on 

unit-specific variables, including the sulfur content and quantity of coal consumed, as well as the 

performance of the dry FGD. They state we inaccurately assumed that the byproduct production 

rate will be the same at Northeastern as that estimated for the Sooner and Muskogee units 

without providing any basis for this assumption. AEP/PSO states we provide no basis for our 

conclusion in the TSD in which we question the landfill cost estimate for Northeastern by noting 

that “disposal costs....further can be optimized” and “would be expected to fall at the lower end 

of the...range, or $5/ton.” AEP/PSO notes that proposed EPA rules for the disposal of coal 

combustion residuals could significantly increase the compliance requirements—and cost— for 

developing a landfill. 

Response: AEP/PSO failed to include any cost estimate, let alone a site-specific 

estimate, for us to further refine our cost assumptions for waste disposal. As we discuss 

elsewhere in our response to comments, documentation for site-specific information is 

specifically required by the BART Guidelines.172 We added this cost, which had the effect of 

increasing the annual cost. The estimate that we used for Northeastern solids disposal was not 

based on site-specific estimates for Sooner and Muskogee, but rather estimated from the lower 

end of the range reported by Sargent & Lundy for other BART analyses. As explained in the 

TSD, the lower end of the range was selected because the capital costs already included $25 

million for an on-site landfill.173 Thus, transportation costs would be lower than for facilities 

that use off-site landfills. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 37 of Technical Support Document) 

The fabric filter baghouse, which follows the spray chamber, contains 

filter bags and supporting cages that are changed out every three years. 

These O&M costs were not included in the Northeastern cost analysis. 

These costs should be similar to those that I estimated for Sooner and 

Muskogee as the plants are similar. I estimated the cost of bag and cage 

 

172 70 FR 39166, 39168. 173 Technical Support Document for the Oklahoma Regional Haze State Implementation Plan and Federal 

Implementation Plan, March 2011, Appendix C, page 37. 

75 
replacement at Sooner to be $544,026/yr and at Muskogee to be 

$599,020/yr (Sec. III.B.4.a.iv). Thus, in Appendix 2, Line 25, I assume 

the cost of bag and cage replacement at Northeastern to be $572,000/yr. 

This should slightly overestimate the cost at Northeastern, as it has a 

smaller capacity. 

AEP/PSO states we did not provide any basis for why change out rate and cost-estimates 

we applied to the Sooner and Muskogee units are applicable to the Northeastern units. 

Response: AEP/PSO’s analysis does not include any estimate for periodic bag and cage 

replacement. We added annual costs for bag and cage replacement, based on our estimate for 

Sooner and Muskogee.174 This is a reasonable approximation as the six units are similar, as 

explained in the TSD175. This has the effect of increasing the annual cost, for two reasons. First, 

this cost was omitted from the Northeastern analysis contained in ODEQ’s RH SIP altogether. 

Second, while it is reasonable to draw comparisons between the OG&E and AEP/PSO units 

because they are similar in size, we note that because the AEP/PSO units are approximately 470 

MW in size, versus the approximately 570 MW OG&E units, the baghouse would be smaller, 

roughly in proportion to the MW rating of the units. This would result in somewhat lower O&M 

costs. Thus, we find that our calculation for bag and cage replacement is conservative. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 37 of Technical Support Document) 

Insurance for Northeastern was estimated as 1% of the total capital 

investment, based on the Cost Manual default. The Sargent & Lundy 

analysis for Sooner and Muskogee indicates that 

insurance rates for similar facilities are about a factor of ten lower, or 

0.0105% of total capital investment. Thus, I revised the Northeastern 

insurance cost to use this value in Appendix 2, Line 32. 

AEP/PSO states we did not provide any basis for why change out rate and cost-estimates 

applied to the Sooner and Muskogee units are applicable to the Northeastern units. AEP/PSO 

states that if indeed the Control Cost Manual is the source of the value, then this is contradictory 

to the criticism in Section III of the TSD that the Control Cost Manual should play a greater role 

in such an analysis. 

Response: To clarify, the quoted material references insurance rates, not "change out 

rates." Nevertheless, the TSD explains why insurance rates are similar for Sooner, Muskogee, 

and Northeastern. The six units consist of nearly identical pulverized coal fired boilers installed 

around the same time that burn a similar low sulfur coal.176 Thus, a site-specific estimate for 

four of these six units is more representative than a generic factor from the Control Cost Manual. 

This comment does not explain why a site-specific estimate of insurance rates was not used in 

the AEP/PSO cost analysis. 

 

174 Ibid., TSD, Appendix C, page 37. 175 Ibid., TSD, Appendix C, page 23 and Table 4. 176 Ibid., TSD, Appendix C, page 23. 

76 
The Control Cost Manual contains two types of information: (1) a costing methodology, 

the overnight method as discussed –elsewhere in our response to comments and (2) study level 

capital cost estimating methods for certain generic types of pollution control equipment. This 

comment confuses the general methodology of the Control Cost Manual with factors used in the 

study level capital cost estimates. The study level estimates are commonly replaced with sitespecific data when it is available. In this and other comments, AEP/PSO has claimed that its cost 

estimate is based on site-specific information, but it has not provided that information, such as 

the site-specific estimate for insurance rates, discussed herein. We find that our application of 

the site-specific insurance rates for four nearly identical units is more representative than a 

generic Control Cost Manual factor. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 38 of Technical Support Document) 

The Northeastern cost effectiveness analysis for dry scrubbing is based on 

an 83% SO2 control efficiency, resulting in emission reductions of 26,599 

ton/yr.145 See Appendix 2, Lines 45 and 59. However, BART requires the 

most stringent emission control level.146 As discussed elsewhere, a dry 

scrubber can achieve 95% SO2 control. Further, the same mismatch 

problem discussed for Sooner and Muskogee exist here. The capital and 

O&M costs for Northeastern were scaled from capital costs and utility 

demands for the Sooner and Muskogee scrubbers, which were based on 

91% SO2 control. Thus, I revised the SO2 control efficiency to 91% in 

Appendix 2, Line 59. This increases the SO2 emission reductions from 

26,559 ton/yr to 29,119 ton/yr in Appendix 2, Line 45. 

AEP/PSO states we do not provide any basis for why change out rate and cost-estimates 

applied to the Sooner and Muskogee units are applicable to the Northeastern units. 

Response: This comment is apparently not related to the quoted material and we are 

therefore not able to understand it or offer a response. We have, however, explained in 

responses to other comments that we based our cost analysis on the Sooner and Muskogee units, 

based on their having vendor quotes and their similarity with the Northeastern units. We do not 

agree that the cross-comparisons were without basis. 

Comment: A commenter states we incorrectly criticized ODEQ by assuming the 

necessity of FGDs at the four OG&E units that we said were larger and therefore more costly 

than needed, given that OG&E is using low sulfur coal. The commenter states that according to 

us, if OG&E continues to use low sulfur coal, it can and should build much smaller FGDs at a 

much lower capital cost. The commenter states we said that, as a result of ODEQ’s assumption 

that OG&E will build what we consider to be larger-than-necessary FGDs while continuing to 

use low sulfur coal, OG&E will experience high costs for FGDs that will produce relatively 

small emission reductions. This, we say, will result in a high “cost-effectiveness” value in terms 

of dollars per tons of SO2 reduced. In contrast, according to us, if OG&E assumed it would 

switch to higher sulfur coal, the dollars per ton “cost-effectiveness” of the FGDs would be lower, 

77 
since the amount of SO2 removed would increase. The commenter states we decided for 

purposes of our analysis to assume emission reductions in an amount that would occur if OG&E 

in fact switched to high-sulfur coal. According to the commenter, this resulted in a significant 

increase in the assumed SO2 emission reductions (calculated by the consultant as an increase 

from 27,729 tons to 89,886 tons) and a reduction in the dollars/ton cost-effectiveness number by 

about one-third. 

Response: We based our cost effectiveness calculations on OG&E’s specifications. As 

we discuss elsewhere in our response to comments, OG&E did this by instructing the vendors in 

its request for proposal to design the SO2 scrubber systems on the basis of a higher sulfur coal 

than it has historically burned. The OG&E BART analysis was in effect based on a SO2

scrubber system that could accommodate a higher sulfur coal. However, the OG&E analysis 

failed to take into consideration the concomitant increase in emission reductions because it 

assumed for the purpose of calculating the cost effectiveness in $/ton that the tonnage of SO2

emissions that would be removed corresponded to its historical emissions, which resulted from 

the burning of a lower sulfur coal. This same error was not made in the AEP BART analysis. 

Comment: A commenter states our analysis, departs from the statutory framework under 

which BART determinations must be made. First, states the commenter, we seem to assume that 

OG&E has a choice in the size of the FGDs that it can install, since we state that if OG&E wants 

to continue using low sulfur coal, it should build a smaller scrubber. However, states the 

commenter, we only provide what appears to be no more than a back-of-the-envelope calculation 

as to the cost of smaller FGDs without discussing whether that assumed equipment would be 

compatible at all with the four units or would even be feasible. In contrast, states the commenter, 

OG&E’s analysis that ODEQ reviewed was based on actual preliminary design work using site 

specific factors. The commenter states that OG&E’s comments our hypothetical FGDs are 

indeed infeasible. The commenter states we therefore have no basis to conclude that the 

hypothetical alternative FGD that we think can be built actually can be built and operated. 

The commenter states we conclude that OG&E, if forced to build FGDs as a result of our 

BART requirements, will build the FGDs set forth in the Sargent & Lundy report. As we noted, 

states the commenter, OG&E needs FGDs of that size to preserve the option of burning high 

sulfur coal, so that the units can, over time, choose whether to use high sulfur versus low sulfur 

coal depending on their relative economics. The commenter states we assumed the “larger” 

FGDs would be built precisely because it makes sense to preserve the coal-switching option. 

The commenter states whether or not OG&E continues to use low sulfur coal or switches 

to high sulfur coal should be irrelevant in a BART analysis under Section 169A. The commenter 

states BART is a defined emission limit, and the FGDs will be operated to achieve the applicable 

limit whether low or high sulfur coal is used. In either case, states the commenter, the downwind 

impact on visibility stays the same, because the same amount of SO2 will be emitted from the 

unit regardless of the choice of coal. Thus, concludes the commenter, in weighing, as required 

by Section 169A, the “costs of compliance” against the “degree of visibility improvement,” the 

cost of installing and operating the OG&E FGDs must be weighed against the degree of visibility 

improvement that will result from those controls, and that visibility improvement remains the 

same whether low or high sulfur coal is used. Thus, claims the commenter, we departed from the 

78 
statutory framework for making BART determinations in tying her analysis to the type of coal 

OG&E ultimately uses. 

The commenter states our insistence in giving so much weight to whether low or high 

sulfur coal is used leads us to the absurd conclusion that high rather than low sulfur coal should 

be assumed for purposes of analysis. The commenter states that given that the whole point of the 

BART exercise is to improve visibility conditions consistent with the BART factors, and our 

presumption that reducing SO2 is a key component of doing so, our assumption that high rather 

than low sulfur coal should be assumed makes no sense. In fact, states the commenter, 

depending on the relative cost of high versus low sulfur coal and other factors, using high sulfur 

coal may increase the “costs of compliance” since the FGDs will need to be operated more 

intensively if high rather than low sulfur coal is used. 

Moreover, states the commenter, making “cost-effectiveness,” as we would have it, the 

“basic decision point” for a BART determination ends up not only far from the statute and 

reality. The commenter criticizes our conclusion that it would be cost-effective for OG&E “to 

build a larger scrubber and burn a higher sulfur coal,” and that “[h]igher sulfur coal would 

improve the economics” of building the FGDs. The commenter also criticizes our statement that 

“Sargent & Lundy assumed a higher sulfur coal would be used when it costed the scrubbers.” It 

states high sulfur coal can be said to “improve[ ] the economics” of building the OG&E FGDs 

only in the sense that it leads to the conclusion that the OG&E FGDs operated when the units use 

high sulfur coal produce more emissions reductions than operating those FGDs when the units 

use low sulfur coal. The commenter states using high sulfur coal does not necessarily 

“improve[] the economics” of the OG&E FGDs at all. 

The commenter states because the FGDs will likely have to be run more intensively if 

higher sulfur coal is used, using higher sulfur coal may worsen the economics of the FGDs. The 

commenter states the relative economics of using low or high sulfur coal will be determined by 

the respective delivered prices of the two coals, how those coals affect the efficiency of the units 

and FGDs, how much the FGDs have to be run given the different sulfur content of the coals, 

and a myriad of other factors. The commenter states that once OG&E builds the FGDs, 

however, it will not matter to the economics of the high versus low sulfur choice whether the 

FGDs with high sulfur coal can be said to be more “cost-effective” than the FGDs with low 

sulfur coal because the former option removes more tons of SO2 than the latter option. The 

dominant consideration will be the lowest cost way of meeting the BART emission limit. 

Response: The OG&E analysis submitted by ODEQ failed to cost and evaluate any 

scrubber designed to remove SO2 from the lower sulfur coal currently burned at Sooner and 

Muskogee, requiring us to make that estimate. As we discuss elsewhere in our response to 

comments, we have modified our cost analysis for Option 2, which addresses the minimum 

scrubber necessary to treat the coal that OG&E presently burns. We made these modifications in 

response to comments we received from OG&E. 

The commenter is correct that we recognize that OG&E may determine that it may be 

economically advantageous to burn a higher sulfur coal. We also agree with the commenter that 

BART is an emission limit. We disagree with the commenter’s general statement that the type of 

79 
coal is immaterial. There are limits to the efficiency of SO2 scrubber systems which are 

dependent in part on coal characteristics. Thus, we considered the effects of the sulfur content in 

our BART determinations for the OG&E units in question. The problem with ODEQ’s BART 

determination for OG&E’s Sooner and Muskogee units is that the designed SO2 scrubber 

systems for those units are based on a higher sulfur coal than it has historically burned, yet 

assumed its historical emissions in its cost analysis. Doing this creates a mismatch that 

compromises the resulting BART determination submitted by ODEQ that we had to address by 

creating a cost analysis for an Option 1 and Option 2. We do agree with the commenter in that 

the relative economics of using low or high sulfur coal will be determined by the respective 

delivered prices of the two coals, and other factors. Our analyses, demonstrate that regardless of 

whether OG&E continues to burn the lower sulfur coal it presently burns, or burns the higher 

sulfur coal for which it specified the scrubber system be designed, our SO2 BART determination 

remains cost effective. That was in fact the entire reason we developed the Option 1 and Option 

2 cases. We disagree with the commenter that we made cost effectiveness the basic decision 

point of our BART analysis. As outlined in detail in our proposal, we followed the requirements 

of the BART Guidelines, in which cost effectiveness is only one consideration. 

Comment: A commenter states we over emphasized the use of our Control Cost Manual. 

It criticizes us for sticking to the Control Cost Manual when according to the commenter, OG&E 

submitted more accurate costing information, including AFUDC, escalation, and bond costs. 

The commenter states we removed more than $150 million in the real-world cost of compliance 

based on our mistaken view that real-world costs are not relevant in the BART process, only 

virtual-world costs that can be used to compare one unit against another. The commenter states 

that neither the BACT [sic] Guidelines nor the Control Cost Manual itself provides that the 

Control Cost Manual should be taken as the exclusive or even primary source of cost information 

where better source-specific information is available. 

Response: The AFUDC, escalation, and bond costs that the commenter references were 

removed by us because, as we discuss elsewhere in our response to comments, they are not 

allowed in the overnight costing method used in the Control Cost Manual. We agree with the 

commenter that the BART Guidelines state177: 

The Control Cost Manual addresses most control technologies in sufficient detail for a 

BART analysis. The cost analysis should also take into account any site-specific design or other 

conditions identified above that affect the cost of a particular BART technology option. 

In fact, we incorporated much site-specific information into our cost analysis, such as 

vendor quotes, but only in accordance with the overnight costing methodology. 

Comment: A commenter quotes from the BART Guidelines that “[t]he basis for 

equipment cost estimates also should be documented, either with data supplied by an equipment 

vendor (i.e., budget estimates or bids) or by a referenced source (such as [the EPA Cost 

Manual]).” The commenter states that although the Guidelines then say that cost estimates 

should be based on the Cost Manual, it also says that the Cost Manual should only be used 

“where possible.” The Guidelines go on to say, continues the commenter, that the Cost Manual 

 

177 70 FR 39166. 

80 
“addresses most control technologies in sufficient detail for a BART analysis,” id., implying 

correctly that in some areas the Cost Manual does not supply the necessary information. Finally, 

states the commenter, the Guidelines state that the cost analysis should “take into account any 

site-specific design or other conditions identified above that affect the cost of a particular BART 

technology option.” 

Response: We agree with the commenter that the BART Guidelines require that 

deviations from the Control Cost Manual methodology should be documented, and that the 

Control Cost Manual should be used where possible. As stated elsewhere in our response to 

comments, we requested that OG&E supply vendor quotes in order to address this situation. We 

disagree with the commenter’s implication that the Control Cost Manual is inherently lacking in 

some respect with regard to its application to the present case. The Control Cost Manual 

provides a costing methodology, that as we explain elsewhere in our response to comments, is 

fully applicable to providing a BART cost effectiveness analysis for the six AEP/PSO and 

OG&E units. 

Comment: A commenter states it is not appropriate for us to disapprove ODEQ’s BART 

determination for OG&E’s units because the Control Cost Manual itself recognizes that it is not 

the final word in determining costs, and makes clear that the electric generation sector is one of 

the areas not covered in the Guidelines: 

...this Manual does not directly address the controls needed to control air pollution at 

electrical generating units (EGUs) because of the differences in accounting for utility sources. 

Electrical utilities employ the EPRI Technical Assistance Guidance (TAG) as the basis for their 

cost estimation processes. 

Moreover, continues the commenter, although the Control Cost Manual provides cost 

information as to a number of different technologies that might be applicable to an electric 

generator, it does not provide information as to FGDs. 

Response: The commenter misrepresents the context of the quote it reproduces from the 

background section of the Control Cost Manual. The footnote to the text it quotes actually 

states:178

This does not mean that this Manual is an inappropriate resource for utilities. In fact, 

many power plant permit applications use the Manual to develop their costs. However, 

comparisons between utilities and across the industry generally employ a process called 

“levelized costing” that is different from the methodology used here. 

Here, the Control Cost Manual makes it clear that although the utility industry commonly 

uses a different costing methodology, the basic overnight methodology we have discussed 

elsewhere in our response to comments, that is utilized by the Control Cost Manual, can and is 

employed by EGUs. The BART Guidelines recognized this when it specified that EGUs follow 

 

178 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452-B-02-001, January 2002, Section 1, Chapter 1, 

page 1-3. 

81 
the Control Cost Manual where possible.179 Elsewhere in our response to comments we discuss 

OG&E’s failure to follow the Control Cost Manual and how that inflated their cost analysis. 

Comment: A commenter states the Cost Manual recognizes that it is best suited to 

facilitate the development of regulations by regulators by providing general and consistent 

information as to the costs that will result from regulation. According to the commenter, this 

allows a general determination of whether one set of regulations would likely be more expensive 

than another: 

The accuracy of the information in the Manual works at two distinct levels. From a 

regulatory standpoint, the Manual estimating procedure rests on the notion of the “study” (or 

rough order of magnitude – ROM) estimate, nominally accurate to within ±30%. This type of 

estimate is well suited to estimating system control costs intended for use in regulatory 

development because they do not require detailed site-specific information necessary for industry 

level analysis. 

Response: We agree with the commenter that one purpose of the Control Cost Manual is 

to provide general and consistent information as to the costs that will result from regulation, 

thereby allowing a general determination of whether one set of regulations would likely be more 

expensive than another. As the BART Guidelines state, with regard to cost effectiveness 

determinations, “a reasonable range would be a range that is consistent with the range of cost 

effectiveness values used in other similar permit decisions over a period of time.180 Thus, a 

consistent method of determining cost effectiveness, as employed in the Control Cost Manual, 

and directed by the BART Guidelines, is essential. 

Comment: A commenter states that the other level on which the Control Cost Manual 

says it works is in providing information to industry to determine compliance costs, but only at a 

scoping level and with the understanding that the industry will be able to “customize” the costs 

set forth in the Manual based on more accurate source specific information: 

The Manual and its supporting programs are also well suited to customization by 

industrial sources to provide more accurate assessments of control cost sizing and cost that can 

be used for scoping level decision making and planning purposes. While such customized 

analyses are by definition of greater accuracy than the generic study level analysis of the 

regulator, the Agency does not make any claim for a greater accuracy than the study level’s 

nominal ±30%. 

Response: We agree with the commenter that both the BART Guidelines and the Control 

Cost Manual allow for the use of supplemental information in making a BART cost effectiveness 

determination. In fact, we requested that OG&E obtain vendor quotes to support its previously 

unsupported capital cost determination, which OG&E then supplied. As we detail in our 

responses to comments elsewhere, we recognized that how OG&E specified those vendor quotes 

and its subsequent use of them in its cost analysis was flawed, for which we made appropriate 

 

179 70 FR 39167. 180 70 FR 39168. 

82 
and thoughtful adjustments. We find the accuracy of our resulting cost effectiveness analyses 

improved as a result. 

Comment: A commenter states we criticize ODEQ for doing exactly what the Control 

Cost Manual says it should do when determining the cost for a particular source to comply with 

regulation. For the four OG&E units, the commenter states, ODEQ concluded that OG&E’s use 

of the Control Cost Manual in its first report produced in 2008 had led to costs that were high, 

which led to the second OG&E report in 2009 that was based on actual vendor quotes and more 

detailed site-specific analysis that afforded an estimate with accuracy in the range of ±20% rather 

than the ±30% range that the first report, using the Control Cost Manual, afforded. As stated by 

ODEQ, “[t]his methodology provides a better estimate of the capital costs associated with 

installing DFGD control systems, and a more accurate estimate of the actual costs that OG&E 

would incur to install DFGD....” 

ODEQ’s reliance on site-specific and more detailed information than provided in the 

Control Cost Manual was thus entirely proper based on the BART Guidelines and the terms of 

the Control Cost Manual itself. And most importantly, use of real-world data as opposed to 

virtual data comports with determining the true “costs of compliance” as required by the statute. 

Response: The commenter’s assertion is incorrect because we did not criticize ODEQ for 

following the Control Cost Manual. We see no support in the record to substantiate this claim. 

In fact, the contrary is true. The reason OG&E utilized vendor quotes was because we requested 

they do so, as their consultant stated that their capital costs at the time were based on a 

proprietary database they refused to disclose. 

The Control Cost Manual contains two types of information: (1) a general costing 

methodology and (2) study level capital cost estimating methods for certain generic types of 

pollution control equipment. The general costing methodology, the overnight method, must be 

used to assure an apples to apples or dollars to dollars comparison of the costs at the OG&E and 

AEP units with the costs at other similar facilities to evaluate reasonableness. However, the 

study level capital costs estimated for specific controls can and are routinely replaced with site 

specific estimates. 

Comment: ODEQ commented that the cost-effectiveness analysis contained in the SIP is 

consistent with the requirements of our RHR. ODEQ believes it followed the established 

guidance and documented additional information used to improve the accuracy of its cost 

effectiveness assessment. ODEQ states it relied upon a credible cost analysis from the affected 

Oklahoma sources, compared cost effectiveness for the Oklahoma sources with BART 

submittals and decisions around the country, and considered cost effectiveness guidance 

provided by the relevant Federal Land Managers. ODEQ states it determined that the installation 

of scrubbers for SO2 control is not cost effective, because of the high costs and the associated 

limited potential visibility improvement at the impacted class I Federal areas. As a result, the 

ODEQ's determination that S02 scrubbers are not cost-effective should be approved by EPA. 

Response: For the reasons we set out in detail through our proposal and in our response 

to comments, we disagree with ODEQ that its cost effectiveness analysis for the six AEP/PSO 

83 
units followed the BART Guidelines. In performing our own cost analyses, we determined that 

the costs of installing SO2 scrubbers on the six affected units is substantially less than the costs 

estimated by ODEQ, which were based on an incorrect costing methodology not allowed by the 

Control Cost Manual. We therefore disagree with ODEQ that we should have approved the SO2

BART determinations for the six units. 

Comment: ODEQ states that initial cost estimates for dry and wet scrubbers were 

developed based on maximum observed 24-hour emission rates from the Regional Haze baseline 

period (2001-2005) for the AEP/PSO and OG&E boilers in question. ODEQ states these 

emission rates (in lbs/MMBtu) were multiplied by the design heat input for the facility and a 

capacity factor to arrive at the basis for cost estimates and emission reductions. According to 

ODEQ, use of maximum 24-hour emission rates for design and cost effectiveness calculations 

was generally perceived to provide conservative assessments of cost effectiveness. 

ODEQ references the advanced notice of proposed rulemaking for BART units at the 

Four Comers Power Station and the Navajo Generating Station, wherein we revised the 

emissions basis for the cost effectiveness calculations submitted by the applicant to reflect 

annual average emission rates from the baseline period rather than the maximum 24-hour 

emission rates that were the basis for engineering assessments. ODEQ states we did not revise 

the capital cost assumptions to reflect annual average emissions, as specified by the BART 

Guidelines. ODEQ states it subsequently updated OG&E’s submissions in September of 2009 to 

be consistent with this notice. ODEQ states in these subsequent submissions it was determined 

that lowering the baseline emission rates would not affect the capital cost estimates prepared for 

the BART evaluations because the capital cost estimates were based on the unit size, flue gas 

flow rates, and maximum design pollutant loading (i.e., the maximum actual 24-hour inlet rate). 

ODEQ states that while sulfur content of the coal may fluctuate, the facility must be in 

compliance at all times. And the use of an annual average emission rate in the design of the 

control is short sighted and use of the annual average emission rate in the permit limit is 

inconsistent with our mandate to use compliance averaging periods of no longer than 30-day 

rolling averages. 

ODEQ states the proposed FIP indicates that the most cost effective option would be a 

scenario where the control equipment is designed for the maximum expected sulfur content of 

Powder River Basin coal and associated emission reductions are then calculated based on the 

continued use of coal with a higher sulfur content. ODEQ agrees that the equipment should be 

designed for the maximum expected sulfur content of Powder River Basin coal. However, it 

states, the BART Guidelines specifically call for the use of actual annual average emissions from 

a baseline period in the determination of tons removed for cost effectiveness calculations. 

ODEQ states this guidance provides that, in communications with the public, both the realistic 

cost of the proposed control technology and the actual expected benefit to the public are 

described. ODEQ feels that artificially inflating the baseline to reflect a determination to 

purchase coal with a higher sulfur content in order to improve the cost effectiveness of the 

control is misleading. 

Response: The example of our position in the Advanced Proposed Rulemaking for 

Navajo and Four Corners (74 FR 44321) for adjusting historic baseline emissions is not relevant 

84 
to this case as there was no issue of anticipated change in fuel quality in the Navajo/Four 

Corners case. Furthermore, we did not assume a 24 hour maximum emission rate. Rather, in 

Option 1, we recognized that OG&E specified in its vendor request for quote that the SO2

scrubbers be designed on the basis of a higher sulfur coal than the facilities have previously 

burned in any appreciable quantities. We therefore raised our emission baseline to match this 

overdesigned scrubber and demonstrated such a situation would be cost effective. However, we 

did not base our proposed decision solely on this outcome. In Option 2, we based our emissions 

baseline on annualized data, just as ODEQ did and costed the installation of scrubbers designed 

to address a coal with a sulfur content the OG&E units historically burned. Taken together, 

Options 1 and 2 demonstrate that whether OG&E continues to burn its historical coal, or decides 

to burn a higher sulfur coal that actually matches the capability of its scrubber, both results are 

cost effective. We agree with ODEQ that coal sulfur content will fluctuate and that a facility 

must be in compliance with its BART emission limits at all times. Elsewhere in our response to 

comments, we demonstrate that OG&E and AEP/PSO can meet our SO2 emission limit of 0.06 

lbs/MMBtu on the basis of a 30 day BOD average. 

Comment: ODEQ agrees with us that initial cost estimates provided by the utilities 

appeared to overstate the capital costs of scrubber installation. However, ODEQ states that in 

the initial BART review, it revised capital cost estimates to be consistent with surveyed cost 

estimates published in an online industry magazine and concluded that scrubbers remained 

marginally cost effective. ODEQ states that OG&E subsequently supplied revised cost estimates 

in December of 2009 that relied on vendor quotations. ODEQ states it allowed control cost 

calculations in this supporting documentation to deviate from the our Control Cost Manual 

approach in order to reflect industry cost estimating practices and to provide a more accurate cost 

associated with the projected visibility improvement. It states this decision was based on the 

review of the initial submittal which more closely followed the Control Cost Manual approach 

and resulted in some absurd conclusions such as calculating the annual administrative costs as a 

two percent function of capital cost. Outside of EPA guidance, states ODEQ, these 

administrative costs are generally evaluated as a function of operating labor costs and are 

attributed to salaries and wages for secretaries, accountants, engineers, and legal personnel. 

ODEQ states that the Control Cost Manual approach, as documented in the supporting technical 

documentation to the proposed FIP, was not designed for evaluation of scrubber costs at coal 

fired power plants, and felt a deviation from the methodology in the additional submittal was 

warranted to answer outstanding questions by both us and ODEQ. ODEQ states use of the 

revised estimates constitutes an apples-to-oranges comparison to analyses which follow the EPA 

Cost Manual. However, as they were lower than the previous cost submittal which did follow 

the EPA manual, ODEQ determined that in this context the comparison was appropriate. 

ODEQ states that while its analysis indicates that some of the project costs in the final 

submittal by OG&E were possibly redundant, these elements collectively would not change the 

control effectiveness determination made by ODEQ. ODEQ states that in departing from EPA 

guidance, it allowed the inclusion of contingency, bond costs, and allowance of funds used 

during construction ("AFUDC") costs to be included in the final submittal, which do 

substantially change the cost effectiveness evaluation. ODEQ explains that while these elements 

are not part of the Control Cost Manual methodology, they are reflective of actual costs borne by 

the subject sources. ODEQ determined that a cost analysis reflective of reality used to 

85 
substantiate the cost analyses which followed EPA methodologies were appropriate decision 

making tools in the determination of control effectiveness. 

Response: As ODEQ describes, it did not follow the Control Cost Manual approach. 

The additional costs allowed by ODEQ— contingency, bond costs, AFUDC, etc.— are only 

allowed under the "all-in" costing methodology, which is not used in cost effectiveness analyses. 

See our responses elsewhere for more information on this. 

The Control Cost Manual contains two types of information: (1) a general costing 

methodology and (2) study level capital cost estimating methods for certain generic types of 

pollution control equipment. The general costing methodology, the overnight method, must be 

used to assure an apples to apples or dollars to dollars comparison of the costs at the OG&E and 

AEP units with the costs at other similar facilities to evaluate reasonableness. 

We agree with ODEQ that the use of the revised cost estimates constitutes an "apples to 

oranges" comparison, but disagree that the context for allowing this deviation was appropriate. 

The costs were not higher than those reported in other States due to market driven forces, but 

rather due to the use of a different costing methodology. 

Cost effectiveness values calculated using the all-in methodology must be compared with 

all-in cost at other similar facilities to determine if they are "reasonable." Representative 

comparative all-in cost data was not provided by OG&E or AEP nor sought out by ODEQ and 

thus is not in the record. Therefore, ODEQ had no basis to conclude that any of the cost 

effectiveness analyses, based on the all-in method, are unreasonable and thus not cost effective. 

Even if such information were available, it would not be in compliance with the Control Cost 

Manual methodology and thus could not be compared to other properly conducted BART 

analyses. When the OG&E and AEP cost analyses are revised to use the overnight method, as 

reported in the TSD, they demonstrate that both wet and dry scrubbers are cost effective, based 

on comparison with other similar facilities. TSD, Table 7. 

We agree with ODEQ that the Control Cost Manual does not include a section to estimate 

study level capital costs for scrubbers. Thus, other sources of information must be relied on 

(e.g., vendor quotes). The capital costs in the 2009 Sargent & Lundy cost revision were still 

higher than costs estimated in other States' BART analyses primarily due to the inclusion of the 

kinds of costs (e.g., AFUDC) ODEQ itself states are not valid under the overnight method used 

in the Cost Manual. 

Comment: A commenter states Oklahoma properly used real-world vendor cost data in 

making its determination that scrubbers are not cost-effective. They state our disapproval of 

Oklahoma's BART determination for the six coal-fired generating units rests in part upon its 

determination that Oklahoma did not use the Control Cost Manual, but instead used real-world 

vendor cost data. The commenter states that we opine that use of the Control Cost Manual is 

required because the BART guidelines state that "cost estimates should be based on the [Cost 

Manual] where possible." The commenter states that however, preceding the sentence quoted by 

EPA, the guidelines state: "the basis for equipment cost estimates also should be documented, 

either with data supplied by an equipment vendor ... or by a referenced source... . Further, states 

86 
the commenter, the footnote to the sentence quoted by us provides, “You should include 

documentation for any additional information you used for the cost calculations, including any 

information supplied by vendors that affects your assumptions regarding purchased equipment 

costs, ... that differs from the [Control Cost Manual]. 

The commenter concludes the plain meaning of these provisions is that a state may use 

vendor cost data when that data differs from the Control Cost Manual, as is the case with 

ODEQ’s SIP. Accordingly, states the commenter, it would be improper for EPA to disapprove 

Oklahoma's determination that scrubbers are not cost-effective, and EPA should approve 

Oklahoma' s BART determination. 

Response: As explained more fully elsewhere in our response to comments, we did not 

disapprove ODEQ’s SO2 BART determination for the six units because ODEQ used site specific 

information. We agree with the commenter that vendor quotes are specifically suggested by the 

BART Guidelines as providing pertinent information for use in a BART cost effectiveness 

analysis. In fact, as we discuss elsewhere in our response to comments, we requested that 

OG&E obtain this information, and incorporated it into our analysis. The Control Cost Manual 

contains two types of information: (1) a general costing methodology and (2) study level capital 

cost estimating methods for certain generic types of pollution control equipment. The subject 

"real-world vendor cost data" is the site-specific replacement for the study level costs. We do 

not dispute the "real-world vendor cost data," but rather OG&E’s misuse of that data. That 

misuse includes the general costing method they employed. 

Cost effectiveness is a relative determination, in which costs for the source being 

analyzed are compared with costs for other similar facilities. A value is considered to be "cost 

effective" if it falls within a reasonable range, i.e., is consistent with, the range of cost 

effectiveness values used in other similar permit decisions. In order to make a valid 

determination, the same general costing methodology must be used for both the source being 

analyzed and the other similar facilities. AEP/PSO and OG&E’s analyses were estimated using 

the "all-in" method while the Control Cost Manual methodology is based on the "overnight" 

method. Thus, as we discuss elsewhere in our response to comments, the OG&E’s cost analyses 

compare apples with oranges. OG&E’s inclusion of costs specifically disallowed by the Control 

Cost methodology, along with its scrubber overdesign in relation to the coal they presently burn, 

are the main reasons its cost effectiveness analysis resulted in such high values. When these 

disallowed cost items are removed, as we did in our analysis, the resulting costs are seen to be 

cost effective. 

Comment: A commenter states our cost-effectiveness analysis is flawed and cannot be 

used for the purposes of making a BART determination. The commenter states in calculating the 

cost-effectiveness of retrofitting scrubbers ($/ton SO2 removed) on OG&E's plants, we assumed 

an SO2 emissions reduction level which is more than three times the level actually achievable 

with the low sulfur coal used at the plants. The commenter states our rationale for this 

unrealistic assumption is that OG&E' s scrubber cost estimate is based on a scrubber that can 

remove more SO2 than is produced by the low sulfur coal used at the plants, and that OG&E 

sized a larger than necessary scrubber to give it flexibility to burn higher sulfur coal in the future. 

87 
However, states the commenter, we failed to show how OG&E can achieve the higher SO2

reductions burning its current low sulfur coal. 

Response: The vendor proposals indicate that the scrubbers were designed to burn a 

higher sulfur coal than currently used. Absent an enforceable condition restricting these units to 

current coal, the SO2 emission reductions must be based on "anticipated" emissions. In Option 1, 

we recognized that OG&E specified in its vendor request for quote that the SO2 scrubbers be 

designed on the basis of a higher sulfur coal than the facilities have burned in any appreciable 

quantities. We therefore raised our emission baseline to match this overdesigned scrubber and 

demonstrated such a situation would be cost effective. However, we did not base our proposed 

decision solely on this outcome. In Option 2, we based our emissions baseline on annualized 

data, just as ODEQ did. In addition, as we discuss elsewhere in our response to comments, we 

also made an adjustment to the capital cost to reflect a scrubber system that is designed to treat 

the coal that OG&E historically burns. Thus, there is no need for us to demonstrate that OG&E 

can achieve the higher SO2 reductions while burning its current sulfur coal. Instead, Options 1 

and 2 demonstrate that whether OG&E continues to burn its historical coal, or decides to burn a 

higher sulfur coal that actually matches the capability of its scrubber, the result is cost effective. 

Comment: A commenter states that as an alternative for OG&E's plants, we attempted to 

estimate the cost-effectiveness of using a smaller scrubber. However, this alternative cost 

estimate was based on a "six-tenth rule" cost estimation formula which we admit "is an over 

simplification" and not based on "any public data specific to dry scrubbers.” The commenter 

states that because there is no basis for this determination, it cannot be used. 

Response: In our proposal, we modified our cost analysis of Option 2, utilizing the sixtenths rule. As we explain elsewhere in our response to comments, we modified our cost basis 

for Option 2. We find that Option 2 remains cost effective. 

Comment: A commenter states we note that the Control Cost Manual prohibits use of 

escalation, AFUDC and contingencies in the estimated costs used for cost-effectiveness 

determinations. However, states the commenter, the Control Cost Manual does not always have 

to be followed. The commenter states these are real costs, which will be borne by the utilities 

and passed along to their ratepayers and excluding them reduces the scrubber capital cost by 

more than $200 million. The commenter states to obtain a real-world cost analysis, and not one 

predetermined in favor of costly controls, these costs must be considered. 

Response: Escalation and AFUDC are possibly pertinent to an "all-in" cost analysis. 

However, the Control Cost Manual method is not an "all-in" method, but rather an "overnight" 

method. Overnight costs are real world costs, as of the date of the estimate, as if the project were 

built overnight. Thus, they explicitly exclude costs that would occur in the future. Furthermore, 

we did include contingencies in our cost analysis, as allowed by the Control Cost Manual, and in 

so doing, scaled them down from what OG&E employed, which included demolition, 

fabrication, and installation—contingencies that are specifically excluded by the Control Cost 

Manual. 

88 
Comment: A commenter states we relied upon comparisons to scrubber cost data 

provided for other plants as the primary basis for the conclusion that scrubbers are cost-effective 

in Figure 2 and Table 7. However, states the commenter, these comparisons are not supported 

by source documents or any details that would show how they were derived, or whether they are 

in fact comparable. Absent proof of the accuracy of this data, concludes the commenter, it 

cannot be used. 

Response: The support for the comparative cost data, included detail as to how they were 

derived, is noted in the Report in footnotes 134 and 156 – 164 to the cited section of our TSD. 

Comment: A commenter states we, without any justification, increased the assumed 

scrubber service life at OG&E's plants from 20 years to 30 years. They note this has the effect of 

lowering the annual capital costs for the scrubbers by approximately 33%, thereby lowering the 

capital costs by $40 million a year. If scrubbers are installed in 2015, states the commenter, 

OG&E' s plants will then be approximately 40 years old. The commenter states that assuming 

those plants will operate for 70 years is an unwarranted assumption which cannot be used. 

Response: We discuss elsewhere in our response to comments as to how we justify a 30 

year useful life. Neither AEP/PSO or OG&E requested to engage in an enforceable commitment 

to limit the life of the units in question to 20 years, and we conclude we have adequately justified 

a 30 year life. 

Comment: A commenter states we assert that, as long as the adjusted cost per ton of SO2

removed is within 30% of the range for other plants presented in Table 7, the scrubber option is 

assumed to be cost-effective. The commenter states that while it might be appropriate to have 

some "fudge factor" in determining cost-effectiveness, it is unclear why the appropriate figure is 

30%. In addition, states the commenter, any such fudge factor should only apply when similar 

plants are being compared, since plant size, fuel sulfur content and other factors account for 

differences in costs. The commenter states it is unclear what plants are being used for 

comparison purposes, therefore no fudge factor should be used. 

Response: The 30% factor is based on the general requirement that BART cost 

effectiveness analyses be accurate to within +/-30% of the true value.181 The notation "+/- 30%" 

means that the real value can be anywhere from 30% higher to 30% lower than the stated value. 

Thus, when making the cost comparison, the upper and lower end of the comparison range can 

be 30% higher than the upper bound to 30% lower than the lower bound and still be considered 

to be reasonable. 

Comment: A commenter states that instead of considering the specific details of the 

AEP/PSO plant, we simply used the average capital cost determined for OG&E's plants for the 

AEP/PSO plant. The commented states that the OG&E and AEPPSO plants are not comparable. 

Therefore, concludes the commenter, there is no rational basis for determining that scrubbers are 

cost-effective for the PSO plant. 

 

181 Control Cost Manual, p. 1-2 ("From a regulatory standpoint, the Manual estimating procedure rests on the notion 

of the "study" (or rough order of magnitude - ROM) estimate, nominally accurate to within +/- 30%."). 

89 
Response: AEP/PSO did not provide any documentation for its capital costs, therefore, 

we had no choice but to estimate the capital costs ourselves. As we discuss elsewhere in our 

response to comments, the six units are nearly identical pulverized coal-fired boilers installed 

around the same time that burn similar low sulfur PRB coal. Therefore, we conclude that the 

OG&E capital costs, which were based on vendor estimates, are appropriate for use in 

calculating a SO2 BART cost effectiveness analysis for the AEP/PSO units in question. 

Comment: A commenter notes that we determined at 76 Fed. Reg. 16182-83 that ODEQ 

erroneously relied upon inflated dry and wet scrubbing control costs to justify rejection of SO2

controls. The commenter states that by way of example, such exaggerated costs apparently 

include OG&E wage rates for journeymen pipefitters which we understand were calculated at 

$100 per hour. The commenter notes for the record that the current prevailing wage rate for the 

local pipefitters union in Oklahoma is $40.80 per hour. The commenter is concerned the public 

has no assurance that the other costs relied upon by ODEQ to analyze emission controls 

including NOx emissions were not similarly flawed. Accordingly, the commenter claims that the 

public record is inadequate to justify the selected controls within the EPA Proposed Rule. 

Response: We agree with the commenter that the costs ODEQ relied upon in making its 

BART determination for the six OG&E and AEP/PSO units were too high. The too high cost 

numbers were a reflection of ODEQ’s flawed cost methodology in calculating those cost 

numbers for OG&E’s and AEP/PSO’s unit as part of the BART determination. We have 

determined that the faults in ODEQ’s cost methodology were significant enough that they 

resulted in BART determinations for SO2 that were both unreasoned and unjustified. Elsewhere 

in our response to comments we cite the commenter’s current prevailing wage rate for the local 

pipefitters union in Oklahoma is $40.80 per hour in support of our determination that OG&E’s 

scrubber costs lie at the upper bounds of the range. 

Comment: A commenter states we demonstrated that Oklahoma overestimated the cost 

of installing dry scrubbers by as much as five times. According to the commenter, Oklahoma 

estimated costs based on a much bigger scrubber than what it assumed in its BART analysis, 

double-counted some costs, and did not use the conventions from the EPA’s cost manual. 76 

Fed. Reg. 16168, 16183. The commenter states our cost analysis indicates that dry scrubbers are 

a cost effective control option. The commenter supports our analysis and conclusion that both 

dry scrubbers and wet scrubbers are cost effective controls in Oklahoma. 

Response: We agree with the commenter that ODEQ relied on cost estimates that greatly 

overestimated the costs of controls. The faults in ODEQ’s cost methodology were significant 

enough that they resulted in BART determinations for SO2 that were incorrect because they were 

based on inflated cost estimates. In addition, we agree that when we utilized the correct cost 

methodology we reached an accurate cost estimate which indicated that scrubbers are cost 

effective. 

Comment: OG&E states the installation of scrubbers could result in a significant net 

GHG emissions increase from the OG&E Units, and that we did not consider the costs associated 

with potentially triggering PSD review under the PSD Tailoring Rule. 

90 
Response: We agree that the installation of SO2 scrubbers at the six OG&E and 

AEP/PSO units, if not offset by increased efficiency measures, may slightly increase the 

emissions of other regulated new source review pollutants, including GHGs, to the point where 

PSD review is triggered. Any PSD permit that is necessary would have to be obtained from the 

ODEQ, which is the permitting authority in Oklahoma. Whether or not PSD permitting is 

required would be based on design-specific considerations and applicability determinations that 

will vary with each unit. OG&E has not provided underlying data or facts to substantiate first, 

that PSD permitting could not be avoided through controls designed to consume less power, and 

second that a PSD permit, if needed, would impose additional or collateral costs that would 

materially change our cost evaluation. We also disagree with the assertion that PSD permitting 

will require 18-24 months, as the Oklahoma SIP requires the issuance of a PSD permit within 

365 days. 

Comment: A commenter states we improperly calculated fewer emission reductions for 

the flue gas desulfurization (FGD) technology when we evaluated ODEQ’s cost analysis. The 

commenter states we calculated the cost effectiveness of FGD assuming OG&E switched to a 

high sulfur coal when OG&E currently uses low sulfur fuel. According to the commenter, this 

incorrectly lowered the dollars per ton cost effectiveness for FGS. The commenter states this 

contradicts the RH rule. The commenter states that burning low versus high sulfur coal is 

irrelevant to the analysis of the cost effectiveness of FGD for BART since BART is a defined 

emission limit and FGD will be operated to achieve the BART emission limit regardless of 

whether low or high sulfur coal is used. Thus, concludes the commenter, we did an improper 

BART analysis when they tied the analysis to the use of high sulfur coal use for OG&E’s four 

units with a faulty lower dollar per ton cost effectiveness. 

Response: We discuss the commenter’s assertion that the BART Guidelines do not 

provide that a BART determination should rise or fall based on an assumption as to whether a 

unit will use high or low sulfur coal when that assumption makes no difference to downwind 

visibility, in another response to a comment. 

II. Comments Relating to Our SO2 BART Emission Limit 

Comment: OG&E states our analysis of the technical capabilities of retrofit dry scrubbing 

systems, and its reliance on information summarized in the TSD, is inadequate for establishing 

an enforceable BART emission limit. OG&E states that information provided in the National 

Lime Report, which we reference as Figure 3 in our TSD, was intended to provide a high-level 

comparison of the effectiveness and cost-effectiveness of wet and dry FGD control systems on 

coal-fired boilers firing various types of coal. According to OG&E, the report was never 

intended to be a design document, nor was it based on OG&E-specific design parameters. 

OG&E claims that relying on removal efficiencies expressed in that report to establish an 

enforceable permit limit is incorrect, as removal efficiencies in the report “represents a general 

guideline” for application of dry scrubbing technology and does not take into consideration any 

site-specific operating parameters. Furthermore, states OG&E, we misrepresent information in 

the chart when we conclude that the a dry scrubber on the Sooner and Muskogee units can 

remove about 90% of the SO2 when burning current coal (0.51 lb/MMBtu), 91.5% when burning 

91 
the proposed BART coal (0.65 lb/MMBtu), and 95% when burning the coal used to size the 

scrubber. 

 OG&E also states that although hourly emissions data provided by us for the Newmont 

TS Power Generating facility (“Newmont”) may provide insight into the technical capabilities of 

a dry scrubbing system on a new unit, that data are not representative of emissions that would be 

achieved on a retrofit project. OG&E states Newmont’s emission rate would be more 

representative of the lowest emission rate achieved in practice by the best controlled similar 

source, and might be representative of Lowest Achievable Emission Rate (“LAER”) or Best 

Available Control Technology (“BACT”) for a new source, but would not be representative of 

BART. 

 OG&E lists the average annual SO2 emissions from what it claims includes all existing 

coal-fired boilers equipped with dry lime scrubbing. OG&E states the top four units listed in its 

table are new units which commenced commercial operation since 2007 and were specifically 

designed with an integrated DFGD/FF control system. 

 OG&E states we also relies on SO2 emission rates included in the final PSD permit for 

the Longleaf Generating Station in Georgia to establish the BART emission limits for the OG&E 

units. OG&E states the Longleaf PSD permit was issued in May 2007 and included an SO2

emission limit of 0.065 lb/MMBtu (30-day average) when the uncontrolled SO2 emission rate is 

less than or equal to 1.0 lb/MMBtu. According to OG&E, although the Longleaf unit has been 

permitted, it has not commenced commercial operation and has not demonstrated the ability to 

achieve the proposed emission limits. OG&E concludes it is not appropriate to establish BART 

emission limits based on PSD limits for a new facility that has not yet commenced commercial 

operation. 

 OG&E states that based on an uncontrolled SO2 emission rate of 0.51 lb/MMBtu, the 

most aggressive design target for a DFGD/FF retrofit project on an existing boiler could be in the 

range of 0.06 lb/MMBtu. However, adds OG&E, an emission rate as low as 0.06 lb/MMBtu 

does not represent a permit limit or an emission rate that can be achieved under normal operating 

conditions. OG&E states some reasonable margin must be provided between the design target 

and the enforceable permit limit to allow for normal fluctuations in the controlled emission rate. 

 OG&E states the BART analysis must take into account the full range of possible fuels, 

operating conditions, operating system fluctuations, and normal wear-and-tear on the units and 

control systems. OG&E BACT requirements are more stringent but that, EPA’s Environmental 

Appeals Board has recognized that “permitting agencies have the discretion to set BACT limits 

at levels that do not necessarily reflect the highest possible control efficiencies but, rather will 

allow permittees to achieve compliance on a consistent basis. 

 OG&E concludes that imposing a BART emission limit of 0.06 lb/MMBtu is below the 

demonstrated capabilities of the control technology for retrofits, and would eliminate all margin 

between the possible design target of the control system and the enforceable permit limit. 

Response: We proposed a BART SO2 emission limit of 0.06 lb/MMBtu met on a 30-day 

92 
rolling average for the OG&E and AEP/ISO units.182 As a preliminary matter, we note that 

BART is an emission limit. The proposed limit of 0.06 lb/MMBtu can be met with any 

combination of technologies that the owner chooses. Although we based our SO2 BART 

analyses on the ability of the six units to meet this emission limit by using dry scrubbers, both 

dry and wet scrubbing can meet this limit, are technically feasible, and are cost effective. 

Further, the existing low sulfur coal burned at the station could continue to be burned, rather than 

switching to a higher sulfur coal. 

The BART Guidelines provide instruction in the selection of the BART emission limit183: 

It is important, however, that in analyzing the technology you take into 

account the most stringent emission control level that the technology is 

capable of achieving. You should consider recent regulatory decisions 

and performance data (e.g., manufacturer’s data, engineering estimates 

and the experience of other sources) when identifying an emissions 

performance level or levels to evaluate. 

In assessing the capability of the control alternative, latitude exists to 

consider special circumstances pertinent to the specific source under 

review, or regarding the prior application of the control alternative. 

However, you should explain the basis for choosing the alternate level (or 

range) of control in the BART analysis. Without a showing of differences 

between the source and other sources that have achieved more stringent 

emissions limits, you should conclude that the level being achieved by 

those other sources is representative of the achievable level for the source 

being analyzed. 

(1) National Lime Association Report Chart

We cited to a chart in a Sargent & Lundy report as one line of evidence that a BART 

limit of 0.06 lb/MMBtu could be achieved. TSD, Ex. B, pp. 42-43. This comment claims that 

relying on removal efficiencies from this report “to establish an enforceable permit limit would 

be incorrect as these removal efficiencies represent a general guideline for application of dry 

scrubbing technology and do not take into consideration any site-specific operating parameters.” 

This mischaracterizes our use of the subject chart. The information in this chart is one of 

several sources of information that the RH rule allows us to utilize when establishing our SO2

BART emission limit. We relied on this and other sources of information to confirm that the 

proposed BART limit could be achieved. As the RH rule states above, manufacturers’ data (e.g., 

vendor’s proposals) is a recommended type of performance data when setting BART emissions 

limits. The other sources that we relied on include the site-specific SO2 removal efficiency of 

95% quoted in the vendor proposals as well as other information cited in the TSD, Ex. B, pp. 42-

47, including the information cited footnotes 174, 176, 177, 180-182 and in Figure 4. For ease of 

 

182 76 FR 16,194 col. 1. 183 70 FR 39104, at 39166. 

93 
reference, this information is reproduced below.184

We agree this is a general guideline for application of the dry scrubber technology. This 

figure is widely used by Sargent & Lundy in materials filed in other cases. Sargent & Lundy 

characterizes it as “derived from Sargent & Lundy's in-house database on the technology 

performance, as obtained from various suppliers of FGD systems.”185 Thus, it is a reasonable 

starting point for assessing the performance of a dry FGD at the OG&E units. 

(2) Performance on New Units Is Applicable

This comment argues that limits achieved by "new" units, such as Newmont, cannot be 

achieved at existing or "retrofit" units. Ex. B, p. 40. However, it does not offer any explanation, 

justification, or examples to support this claim. 

The subject flue gases containing SO2 come from a coal-fired boiler. A scrubber, 

regardless of type, is not influenced by whether the flue gas comes from a new boiler or an old 

boiler located in an existing plant. The scrubber merely reacts to physical and chemical 

characteristics of the gas stream. These do not depend on the age of the unit generating the gas. 

The achievable SO2 limit would only be influenced in a retrofit application if there were 

space constraints that limited the design of the scrubber, e.g., insufficient space to build a fullsized scrubber. No such constraints have been identified at the subject units. Further, no such 

constraints were identified in the Request for Budgetary Quote or in the vendor proposal. Such 

constraints are unusual for scrubbers as they are located at the tail end of the plant where there is 

commonly adequate space. The plot plans included in the 12/28/09 S&L FollowUp report 

indicate there are no space constraints at Sooner or Muskogee that would affect the performance 

of scrubbers. 

The performance at “new” units is better than at existing units because the "new" 

scrubbers installed in the last few years are generally designed to meet BACT limits and are 

 

184 TSD footnote 174: See also Sargent & Lundy, IPM Model - Revisions to Cost and Performance for APC 

Technologies, SDA FGD Cost Development Methodology, Final, August 2010, p. 1 ("It should be noted that the 

lowest available SO2 emission guarantees, from the original equipment manufacturers of SDA FGD systems, are 

0.06 lb/MMBtu."). 

Footnote 176: Nevada Bureau of Air Pollution Control, Class I Air Quality Operating Permit to Construct, No. 

AP4911-1349, Issued to Newmont Nevada Energy Investment, LLC. 

Footnote 177: Georgia Environmental Protection Division, Longleaf Energy Station, Permit No. 4911-099-0033-P01-0, April 9, 2010. Available at: http://airpermit.dnr.state.ga.us/gaairpermits/PermitPDF.aspx?id=PDF-PI-18499. 

Footnote 180: 3/07 S&L National Lime Association Report, p. 10 and Table 4.1-1; Sargent & Lundy, IPM Model - 

Revisions to Cost and Performance for APC Technologies, Wet FGD Cost Development Methodology, Final, 

August 2010, p. 1 ("It should be noted that the lowest available SO2 guarantees, from the original equipment 

manufacturers of wet FGD systems, are 0.04 lb/MMBtu."). 

Footnote 181: U.S. EPA, Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, August 

2010, p. 5-2. Available at: http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation. 

Footnote 182: Inlet and Outlet NOx and SO2 CEMS Data, Pleasant Prairie Units 1 and 2, General Average Report, 

1/1/07 – 12/31/07, Wisconsin PSC Ref. #93460. 

185 Sargent & Lundy, Flue Gas Desulfurization Technology Evaluation, Dry Lime vs. Wet Limestone FGD, 

Prepared for National Lime Association, March 2007, p. 6. 

94 
more stringent than NSPS. Existing SDA scrubbers, on the other hand, were largely designed to 

meet NSPS limits.186 The SO2 NSPS in effect historically only required compliance with an SO2

limit of 1.2 lb/MMBtu and 90% minimum reduction or a 70% minimum reduction when SO2

emissions are less than 0.60 lb/MMBtu. 40 CFR 60.43Da(a). Further, most of these existing 

scrubbers were installed in the 1990s, when the SDA technology was still being developed. 

Much more advanced designs are used in the “new” units. 

OG&E states that CEMS data for retrofit units should be used to establish BART and that 

the lowest SO2 emission rate achieved by such units is 0.088 lb/MMBtu, annual average. Ex. B, 

p. 37. The determination of BART does not require CEMS data to demonstrate that a given 

emission level or control efficiency has been achieved continuously on a retrofit unit. The 

CAMD CEMS data is useful only to establish an upper bound for SO2 BART but cannot be used 

to establish BART itself as BART is the “emission limitation based on the degree of reduction 

achievable through the application of the “best” system of continuous emission reduction...”187 

An "achievable" emission limit does not have to be demonstrated by CEMS data. 

Most of the SO2 CEMS data in the CAMD database is generated under cap and trade 

programs, such as the Acid Rain Program and the Clean Air Interstate Rule (CAIR), to comply 

with the SO2 New Source Performance Standard, or to comply with permit limits, such as from 

netting out of Major NSR review. Thus, the absence of CEMS data proving compliance with the 

proposed SO2 BART limit at a retrofit unit does not mean that the proposed limit is not 

achievable at Sooner and Muskogee, only that it has not yet been achieved. Nevertheless, we do 

present CEMS data that demonstrates these units are capable of achieving our BART FIP SO2

emission limits of 0.06 lbs/MMBtu. 

OG&E presents performance data that it describes as the average annual SO2 emissions 

from all existing coal-fired boilers equipped with dry lime scrubbing. As OG&E notes, it 

considers the units listed in this table to be applicable for comparison based on a size basis, as it 

states, “Smaller boilers (i.e., <1,000 MMBtu/hr) would be less than 1/5th the size of the OG&E 

units, and would not necessarily be considered a similar source.” We agree with this distinction. 

However, as discussed above, we disagree with OG&E’s assertion that the SO2 scrubber 

performance of the new units represented on this table cannot be used to inform our BART 

determination. Therefore, we included these units in our investigation of the performance of four 

of the top performers on OG&E’s table. As we discuss in response to another comment, we 

agree with AEP/PSO’s request that our proposed SO2 emission limit should be based on a Boiler 

Operating Day (BODs) convention in lieu of a straight 30 day calendar average and conducted 

our analysis on that basis. 

Figure 7 presents the 30 day BOD SO2 emission data for the 242 MW TS Power Plant, 

near Dunphy, Nevada, which has a similar permitted BACT SO2 emission limit to our BART 

FIP.188 This plant burns a similar Powder River Basin (PRB) coal as the six AEP/PSO and 

 

186 Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced 

After September 18, 1978, 40 CFR 60, Subpart Da. 

187 40 CFR 51.301 (emphasis added). 188 Nevada Department of Conservation and Natural Resources, Division of Environmental Protection, Facility ID 

No. A0359 Permit No. AP4911-2502: 

95 
OG&E units. As can be seen from the data in Figure 7, this plant remained well below our 

BART SO2 emission limit of 0.06 for the approximately 20 month period of time in 2010-2011 

we investigated. In fact, there are months when the 30 day BOD average remained below 0.05 

lbs/MMBtu. 

Figure 7 

Figure 8 presents the 30 day BOD SO2 emission data for the 90 MW Wygen II unit 

located outside Gillette, Wyoming. This plant burns a similar Powder River Basin (PRB) coal as 

the six AEP/PSO and OG&E units. As can be seen from the data in Figure 8, this unit remained 

well below our BART SO2 emission limit of 0.06 for almost all of 2009 and 2010. Note, only 

three data points are responsible for the large spikes in the 30 day BOD average. These 24-hr 

 NAC 445B.305 Part 70 Program BACT Emission Limit – The discharge of SO2 to the atmosphere will not 

exceed: 

(i) While combusting coal with a Sulfur content equal to or greater than 0.45 percent (30-day rolling period), 

based on daily ASTM sampling: 

(a) 0.09 pound per million Btu, based on a 24-hour rolling average period. 

(b) 95% minimum SO2 removal efficiency will be maintained across the system, based on a 30-day rolling 

period. 

(ii) While combusting coal with a Sulfur content less than 0.45 percent (30-day rolling period), based on daily 

ASTM sampling: 

(a) 0.065 pound per million Btu, based on a 24-hour rolling average period. 

(b) 91% minimum SO2 removal efficiency will be maintained across the system, based on a 30-day rolling 

period. 

96 
data points are a 5.25 lb/MMBtu value on 4/5/09, a 9.36 lb/MMBtu value on 12/4/09, and a 4.3

lb/MMBtu value on 3/3/10. This results in a range of approximately from 72 to 156 times the 

nominal high-range monitored value of 0.06 lbs/MMBtu. It appears these three extreme points

represent either a situation in which the scrubber malfunctioning or otherwise not operating, or 

potential data point errors. Without the inclusion of these three extreme points, the Wygen II 

units would have operated continuously under our FIP SO2 emission limit of 0.06 lb/MMBtu, 

based on 30 day BOD averaging, for over a year Regardless, there are many months when thi

plant operated with a continuous 30 day BOD average below 0.05 lbs/MMBtu. 

3 

s 

Figure 8 

Figure 9 presents the 30 day BOD SO2 emission data for the 525 MW Weston 4 unit 

located as 

e 

 near Wausau, Wisconsin. This plant burns a similar Powder River Basin (PRB) coal 

the six AEP/PSO and OG&E units. We note that this facility does not have as restrictive a 

permit limit as our SO2 BART limit of 0.06 lbs/MMBtu. Regardless, as can be seen from th

data in Figure 9, this unit has also operated below our BART SO2 emission limit of 0.06 for 

significant periods of time, thus demonstrating its capability to meet this limit. 

 

97 
Figure 9 

 The data represented by the above figures do not depict the lowest levels these units are 

capable of achieving. Of the three units discussed above, the TS Power Plant has a permit limit 

that is somewhat similar to our proposed BART SO2 limit for the six OG&E and AEP/PSO units. 

While combusting coal with a sulfur content less than 0.45 percent (30-day rolling period), it is 

required to meet a SO2 limit of 0.065 pound per million Btu, based on a 24-hour rolling average 

period. As a result, it is consistently under our proposed BART SO2 limit for the six OG&E and 

AEP/PSO units. The Wygen II and Weston Unit 4 are not similarly constrained. The data is, 

however, illustrative of the level of control achievable by similar units on a continuous basis. 

Neither AEP/PSO nor OG&E have presented any information that could be interpreted as “a 

showing of differences between the source and other sources that have achieved more stringent 

emissions limits,” Therefore, in consideration of the data represented in Figures 7, 8, and 9, and 

the other information discussed above, we conclude the six AEP/PSO and OG&E units can 

achieve our proposed SO2 BART emission limit of 0.06 lbs/MMBtu. 

(3) LAER and BACT Are Applicable

This comment argues that our proposed BART emission limit of 0.06 lb/MMBtu is "more 

representative of the lowest emission rate achieved in practice by the best controlled similar 

source, and might be representative of Lowest Achievable Emission Rate ("LAER") or Best 

Available Control Technology ("BACT") for a new source, but would not be representative of 

BART." Ex. B, p. 37. This is incorrect. The BART guidelines state that “[t]echnologies 

98 
required as BACT or LAER are available for BART purposes”.189 The guidelines instruct: "You 

are expected to identify potentially applicable retrofit control technologies that represent the full 

range of demonstrated alternatives. Examples of general information sources to consider 

include: The EPA's Clean Air Technology center, which includes the RACT/BACT/LAER 

Clearinghouse (RBLC)..."190 The 2008 BART analyses prepared by the commenter explicitly 

recognize that "[c]ontrol technologies required under the new source review (NSR) program as 

best available control technology (BACT) or lowest achievable emission rate (LAER) are 

available for BART purposes and must be included as potential control alternatives."191

(4) Role of Permits in Setting BART

Reliance on permits for new facilities to establish BART is consistent with and 

anticipated by BART guidance. The BART Guidelines note: "... if there is a permit requiring 

the application of a certain technology or emission limit to be achieved for such technology, this 

usually is sufficient justification for you to assume the technical feasibility of that technology or 

emissions limit."192 The BART Guidelines also require permitting agencies to “consider recent 

regulatory decisions . . . when identifying an emissions performance level” that can be achieved 

by available pollution-reduction methods.193 The language "requiring application" and "recent 

regulatory decisions" indicates the limits need only exist. The process of establishing limits 

involves determining their achievability. Thus, reliance in part on existing permit limits is 

consistent with the BART Guidelines. 

(5) Technical Capability

OG&E asserts a BART emission limit of 0.06 lb/MMBtu "is beyond the technical 

capabilities of the control technology," specifically referring to DFGD/FF. No evidence is 

presented to support this assertion. This is directly contradicted by the performance of the 

examples we provide above, which include significant periods of time in which two of the units 

below 0.05 lbs/MMBtu, while burning a similar coal. In addition, as we discuss above, OG&E 

specified in its vendor requests for bids(which was confirmed by the vendor quotes) that its 

DFGD/FF be capable of controlling SO2 to 95%. We note that based on the sulfur content of the 

coal specified in its request for proposal, this approximately equals 0.06 lbs/MMBtu. 

Further, although we based our BART analysis on the ability of the six OG&E and 

AEP/PSO units to meet a SO2 emission limit of 0.06 lbs/MMBtu using dry scrubbers, we note 

that the BART emission limit can be met with any combination of technologies that the owner 

chooses. The subject DFGD/FF is not the only control option that can meet this limit. As 

explained in the TSD, this limit can also be met using a wet FGD system (and has been 

demonstrated well below 0.06 lb/MMBtu on retrofit applications) or a combination of low/lower 

sulfur coal and either DFGD or WFGD. 

 

189 70 FR 39,164, Col. 1. 190 70 FR 39,164, Col. 3. 191 Sargent & Lundy, Muskogee Generating Station, Best Available Retrofit Control Technology Evaluation, May 

28, 2008, p. 5 and Sargent & Lundy, Sooner Generating Station, Best Available Retrofit Control Technology 

Evaluation, May 27, 2008, p. 3. 

192 70 FR 39165 (July 6, 2005). 193 70 FR 39,166 (July 6, 2005. 

99 
(6) Compliance Margin

Our analysis in the TSD demonstrated that the TS Power Plant (Newmont) facility had 

consistently achieved an SO2 emission rate less than the proposed BART limit of 0.06 lb/MMBtu 

based on a 30-day rolling average. TSD, Ex. B, p. 44 & Fig. 4. We have updated our analysis of 

this facility’s data through the present based on a boiler operating day averaging convention. As 

we discuss above, we present similar data from other facilities as well. This updated analysis 

indicates that Newmont has continued to meet an emission limit of less than 0.06 lb/MMBtu on a 

30-day boiler operating day rolling average basis. 

 

OG&E suggests that an emission limit of 0.10 lb/MMBtu is required to provide a 

"reasonable margin for operating fluctuations and compliance." The comment also claims that a 

limit of 0.06 lb/MMBtu "would eliminate all margin between the possible design target of the 

control system and the permit limit." Finally, it states that EPA's Environmental Appeals Board 

(EAB) has recognized the discretion to set emission limits that do not necessarily reflect the 

highest possible control efficiencies. However, as we explain below, this comment fails to cite 

to all of the relevant cases. 

The margin suggested by this comment is nearly a factor of two (0.10/0.06=1.7). This 

proposed margin is both excessively large and unsupported. We are not aware of any technical 

or scientific basis for nearly doubling an achieved SO2 emission limit. The comment fails to 

explain why a margin is required, given the performance at Newmont and other sites, and 

specifically fails to explain why a margin of nearly a factor of two is warranted. The actual data 

for Newmont includes all of the sources of variability that must be addressed in establishing a 

BART limit, as identified in the cited EAB cases. Adding a margin on top of actual fluctuations 

in long-term CEMS data is not justified. 

This comment advances several generic reasons for requiring such a large margin. First, 

it argues that "the BART analysis must take into account the full range of possible fuels.." 

However, the scrubber design is based on the maximum "anticipated" fuel sulfur content. 

Further, to the contrary, as explained –elsewhere in our response to comments, clean fuels is one 

of the BART controls. The owner cannot demand an elevated BART limit to accommodate 

increased fuel sulfur content. Rather, BART for these units includes continuing to burn the low 

sulfur coals burned in the baseline or even burning a lower sulfur coal. 

Second, the comment argues "the BART analysis must take into account . . . operating 

conditions, operating fluctuations. . ." The comment lists a number of operating parameters that 

affect SO2 removal efficiency including type and quality of the reactant, reactant stoichiometric 

ratio, inlet flue gas temperature, approach to saturation conditions, and amount of solids recycled 

to the atomizer. These are design parameters that are implicitly included in the design basis of 

the scrubber. Further, actual performance data at the facilities described above explicitly takes 

into account operating conditions and operating fluctuations. This comment presents no 

justification for an additional margin above actual operating data and system design. 

Third, the comment argues "the BART analysis must take into account . . . normal wear100 
and-tear on the units and control systems." Normal wear and tear is addressed by routine 

maintenance and repair, not permit limit compliance margins. 

As we discuss elsewhere in our response to comments, we are modifying the compliance 

averaging period from a 30 calendar period to a 30 day boiler operating day (BOD) period, As 

the BART Guidelines direct, “[y]ou should consider a boiler operating day to be any 24-hour 

period between 12:00 midnight and the following midnight during which any fuel is combusted 

at any time at the steam generating unit.”194 To calculate a 30 day rolling average based on 

boiler operating day, the average of the last 30 "boiler operating days" is used. In other words, 

days are skipped when the unit is down, as for maintenance. This, in effect, provides a margin 

by eliminating spikes that occur at the beginning and end of outages and is consistent with 

Appendix Y. 

Comment: OG&E states that wet flue gas desulfurization (WFGD) systems using 

limestone as the reactant have demonstrated the ability to achieve greater than 95% SO2

reduction on coal-fired boilers firing high-sulfur bituminous coals. However, OG&E claims that 

on boilers firing low sulfur coals (such as OG&E’s), the high removal efficiencies would not be 

expected because of the reduced SO2 concentration in the flue gas. OG&E states that even 

though WFGD systems are not typically used on utility boilers firing low sulfur subbituminous 

coals, there are no technical limitations that would preclude its use on the Sooner and Muskogee 

units. 

OG&E notes that both we and ODEQ noted that while the May 2008 BART Evaluations 

identified WFGD technology as a technically feasible SO2 control option capable of achieving a 

higher SO2 reduction, WFGD was determined to result in higher costs compared to DFGD. 

OG&E states that ODEQ recognized in its SIP that WFGD systems have higher capital costs, 

require more energy to operate, higher annual operating costs, and in comparison to dry 

scrubbing have a higher incremental costs. OG&E concludes WFGD is not a cost effective 

control option for the OG&E units. 

Response: We concluded that wet flue gas desulfurization or WFGD is cost effective for 

the subject units as it costs only about 9% more than dry scrubbing, resulting in cost 

effectiveness values of $1,555/ton at Sooner, $1,417/ton at Muskogee, and $1,699/ton at 

Northeastern. TSD, Ex. C, pp. 47-48. These costs are within the range reported by others.195

This comment states that "[t]he incremental cost effectiveness levels are significantly 

higher than the cost effectiveness values for DFGD systems. Therefore, WFGD is not a cost 

effective control option for the OG&E units." This conclusion is cited to the 2008 BART 

analysis. First, the 2008 BART analysis was not the basis of the OK BART determination in the 

SIP submitted to EPA for approval. Second, we did not propose a lower BART limit based on 

wet FGD. Rather, we pointed to wet FGD as an alternative, cost effective way to meet the SO2

BART limit. We did not assume any additional SO2 emission reduction due to the use of a wet 

scrubber, although we believe it is capable of greater reductions than a dry scrubber. We 

identified the wet scrubber only as an alternative method to meet the proposed BART limit. We 

 

194 70 FR 39172. 195 See Cichanowicz, October 15, 2010 p. 5 ($645/ton - $1950/ton,). 

101 
are not advocating the choice between two controls that result in two separate limits, but rather a 

single limit that can be met with two alternative technologies. Incremental cost effectiveness is 

irrelevant for this case, because we based our SO2 BART determination for the six OG&E and 

AEP/PSO units on the performance characteristics and costs of a dry SO2 scrubber. 

Comment: AEP/PSO states that there is a mathematical error in the TSD. They state that 

the assumed baseline fuel for the six Oklahoma units analyzed in the TSD is described using the 

unit of pounds of sulfur per million Btu. AEP/PSO states this is incorrect and should have been 

described as pounds of SO2 per million Btu. No PRB fuel sources have a sulfur in fuel content 

approaching 0.9 pounds of sulfur per million Btu. AEP/PSO states the paragraph on page 43 

under Figure 3 indicates that “a dry scrubber on the Northeastern units can remove 93% of the 

SO2 when burning the current coal (0.9 lb/MMBtu) which further supports that the units 

provided on Table 4 are incorrect. 

Response: This is not a mathematical error. The units used for coal sulfur content 

throughout Appendix C are either weight percent sulfur, expressed as a percent (%) or pounds of 

SO2 per million Btu of fuel combusted (lb/MMBtu). Thus, the units in Tables 1 and 4 are lb 

SO2/MMBtu, not lb S/MMBtu. This distinction does not affect any of the calculations, which 

are all appropriately based in lb SO2/MMBtu. 

Comment: AEP/PSO reiterates the following statement from our TSD: 

(From Page 1-2 of Technical Support Document) 

I revised the wet scrubber cost analyses based on the ratio of my revised 

dry scrubber cost to the initial company costs. This lowered the cost of wet 

scrubbing at Sooner from $8,101/ton to $1,555/ton; at Muskogee from 

$8,001/ton to $1,417/ton; and at Northeastern from $3,625/ton to 

$1,699/ton. Wet scrubbers can remove up to 98% of the SO2 from low 

sulfur coals and meet SO2 emission limits of 0.03 lb/MMBtu based on a 

365-day rolling average and 0.06 lb/MMBtu based on a 24-hour average. 

AEP/PSO states that we have not provided any reference or basis for the following 

statement “meet SO2 emission limits of 0.03 lb/MMBtu.” They state they are not aware of any 

pulverized coal fired unit that has been permitted with a limit of 0.03. 

Response: This comment misinterprets the quoted material. It does not claim that there 

is a permit requiring 0.03 lb/MMBtu but rather only that there are units that meet this level that 

are similar to the six units. These levels are achieved with low sulfur coal and wet scrubbing.196 

Comment: AEP/PSO reiterates the following statement from our TSD, concerning Figure 

3, which is a chart showing the relationship between inlet SO2 and removal efficiency: 

(From Page 43 of Technical Support Document) 

This report included a chart showing the relationship between inlet SO2

and removal efficiency, reproduced in Figure 3.175 This figure shows that 

 

196 Ibid., TSD, Appendix C, pages 52-53. 

102 
a dry scrubber on the Sooner and Muskogee units can remove about 90% 

of the SO2 when burning current coal (0.51 lb/MMBtu), 91.5% when 

burning the proposed BART coal (0.65 lb/MMBtu), and 95% when 

burning the coal used to size the scrubber (1.18 lb/MMBtu). This figure 

also indicates that a dry scrubber on the Northeastern units can remove 

93% of the SO2 when burning current coal (0.9 lb/MMBtu) and about 

91.5% when burning the proposed BART coal Higher removal 

efficiencies, up to 96%, have been demonstrated at a 600 MW PRB coal 

fired plant in the United States and 98% on a 350 MW coal-fired boiler in 

Denmark for an entire year. Thus, the BART requirement to evaluate the 

maximum degree of reduction has not been satisfied. 

 

175 Sargent & Lundy, Flue Gas Desulfurization Technology, Dry Lime vs. 

Wet Limestone FGD, Prepared for National Lime Association, March 

2007, pp. 6, 14 (Table 4.1-1), 25 (Table 5.1-1), p. 41 (Table 7.2). 

AEP/PSO states Figure 3 is from the 2007 Sargent & Lundy report, which introduces the 

figure by noting: “It represents a general guideline for application of LSD technology, and is 

derived from Sargent & Lundy’s inhouse database on the technology performance, as obtained 

from various suppliers of FGD systems” As such, opines AEP/PSO, the figure generalizes 

potential performance, but should not be used to predict the performance of a specific FGD unit, 

and does not offer more accurate information compared to the site-specific BART analyses. 

Response: This figure was not used to determine the performance of scrubbers on the 

Northeastern units. The role of this chart in the BART analysis is explained elsewhere in our 

response to comments. The performance of scrubbers on the Northeastern units is based on the 

site specific costs for Sooner and Muskogee, as well as monitoring and other data we have 

presented in the TSD, and explained in our responses to comments elsewhere. 

Comment: To be consistent with the RH Rule and Title V reporting requirements, 

AEP/PSO requests that our FIP be conditioned to (1) allow BART units at a facility to average 

emissions across those units and (2) condition the averaging period for the SO2 emission limit on 

the basis of “operating days,” in lieu of “calendar days,” in section 2(d). 

Another commenter submitted a similar comment. The commenter states there is no 

legal or sound policy reason for imposing this or any other BART limit on each unit individually 

within a given facility and for disallowing facility-wide compliance averaging. The commenter 

states any proposed BART limit should be eligible for averaging on a plant-wide basis. The 

commenter states our own BART rules expressly authorize and encourage application of BART 

emission limits on a plant-wide basis. 

Response: We agree with AEP/PSO that our proposed SO2 emission limit should be 

based on Boiler Operating Days (BODs), rather than a straight calendar average. We believe 

that such an averaging scheme complies with the BART Guidelines, which defines a BOD to be 

“any 24-hour period between 12:00 midnight and the following midnight during which any fuel 

103 
is combusted at any time at the steam generating unit.”197

AEP/PSO is also correct in that the BART Guidelines state, “You should consider 

allowing sources to ‘‘average’’ emissions across any set of BART-eligible emission units within 

a fenceline, so long as the emission reductions from each pollutant being controlled for BART 

would be equal to those reductions that would be obtained by simply controlling each of the 

BART-eligible units that constitute BART-eligible source.”198 

However, combining this request with BOD averaging request presents an enforcement 

difficulty. As a consequence of the BOD averaging scheme, days in which a unit is shut in for 

the full 24-hour period don’t count in calculating the 30 day average. Therefore, during periods 

when one or both of the two BART units at each of the OG&E Sooner and Muskogee plants; and 

the two BART units at the AEP/PSO Northeastern plant are idled, the 30 days used in the 

average will be offset from that used by the unit that may not be idled. Once idled, a unit’s 30 

days will continue to be offset from that used by the other units. In fact, under the BOD 

averaging scheme, it is likely after an initial period of time passes, that both units at each of the 

three plants will be using different 30 days of time in calculating their individual 30 day BOD 

averages. This adds an additional level of complexity to the calculation of a plant wide average. 

Just after the language appears in the BART Guidelines concerning a plant wide average, 

we advise, “In addition, emissions limits must be enforceable as a practical matter (contain 

appropriate averaging times, compliance verification procedures and recordkeeping 

requirements).” We believe it is possible to combine the 30 day BOD and plant wide averaging 

concepts, but due to our consent decree deadline, we do not have the time to construct the 

algorithm that could be used to guarantee enforceability. Therefore, we will condition the SO2

limit for the six OG&E and AEP/PSO units on the basis of a rolling 30 day BOD average. We 

leave the issue of a plant wide average to a possible future SIP revision that includes a verifiable, 

workable and enforceable algorithm that ensures the resulting emissions are equal to those 

reductions that would be obtained by simply controlling each of the BART-eligible units that 

constitute BART-eligible source. 

Comment: A commenter states we cannot, under any circumstances, impose SO2

emission limits on the six OG&E and AEP/PSO units greater than the presumptive SO2 emission 

limit, either 0.15 lbs/MMBtu, or 95 percent control. The commenter states our explanation of 

the presumptive limits in the preamble to the RH rule is limited to allowing a state alone to 

establish more stringent BART emission limits. The commenter argues that is because 0.15 

lbs/MMBtu is the "presumptive" limit. A commenter reasons that a state can adopt that limit 

without any further analysis, and we are obligated to approve the presumptive limit as BART. 

Response: The commenter is incorrect that the RH rule prevents us from considering an 

SO2 BART limit that is below the presumptive limit for the six OG&E and AEP/PSO units. The 

RH rule requires that the presumptive limits should be met, “unless a State determines that an 

alternative control level is justified based on a careful consideration of the statutory factors.”199 

 

197 70 FR 39172. 198 Ibid. 199 70 FR 39131. 

104 
In a FIP situation, we are authorized to assume the state’s role in conducting a BART analysis. 

While a State has broad authority over a BART determination when it is the decision maker, we 

similarly have broad authority when promulgating a FIP. Therefore, we have a duty to examine 

those factors including the technology available and the costs of compliance of alternative levels 

of control. Further, the BART Guidelines state200,

201: 

It is important, however, that in analyzing the technology you take into account the most 

stringent emission control level that the technology is capable of achieving. 

You should be sure to consider the level of control that is currently best achievable at the 

time that you are conducting your BART analysis. 

Thus, the BART Guidelines require that potential emission limits that are more stringent 

than the presumptive limits must be examined as part of the BART determination. As a result of 

our BART analysis, we adopted a more stringent emissions limit for SO2 because dry scrubber 

control technology has been demonstrated among similar facilities to be capable of achieving 

this SO2 emission limit and we find that OG&E and AEP/PSO units can achieve these SO2

emission limits as well. 

Comment: A commenter states using low-sulfur coal does not satisfy BART 

requirements for coal-fired power plants, as the RH rule establishes presumptive SO2 BART 

limits for coal plants at a 95% removal or 0.15 lbs/MMBtu, which equates to reductions that 

could be achieved by installing scrubbers. The commenter notes we accepted the vast majority 

of Oklahoma's state plan for addressing regional haze. The commenter states the limited portion 

of the Oklahoma SIP that we rejected is essentially based on a narrow aspect: the emission limits 

for S02 for six coal-fired electric generating units, including two units each at the OG&E 

Muskogee and Sooner power plants, and two units at PSO's Northeastern power plant. The 

commenter believes the use of low sulfur coal does not come close to meeting presumptive 

BART emission limits, and would allow significant emissions that harm both the environment 

and public health. 

Response: We agree with the commenter that the continued use of low sulfur coal does 

not constitute SO2 BART for the six OG&E and AEP/PSO units, as that practice would result in 

the emission of large amounts of SO2, which would cause or contribute to visibility impairment 

at four Class I areas. As we state elsewhere in our response to comments, we are open to any of 

the six AEP/PSO and OG&E units switching to natural gas as a potential means of satisfying 

BART. 

Comment: A commenter states we failed to consider the costs of imposing our preferred 

SO2 emission limits on ratepayers. The commenter states we are obligated to consider these 

costs under the CAA, which requires consideration of "the costs of compliance," which is a 

broader term than "cost-effective," CAA section 169A(g)(2), and pursuant to the Unfunded 

Mandates Reform Act of 1995, 2 U.S.C. section 1532(a). 

 

200 70 FR 39166. 201 70 FR 39171. 

105 
A commenter states that OG&E's 2011 Integrated Resource Plan shows that EPA's FIP 

would cost OG&E ratepayers $2,4 billion more than ODEQ’s proposed RH SIP (which provides 

for burning low sulfur coal) on a present value basis. Moreover, states the commenter, OG&E's 

analysis shows that the conversion of coal-fired power plants to burn natural gas as proposed in 

the FIP would cost approximately $5,4 billion more than the SIP on a present value basis. The 

commenter believes increased costs of the magnitude caused by implementation of the FIP can 

only have devastating impacts on the Oklahoma economy, investment in Oklahoma industry will 

stagnate, and many jobs will be lost as a consequence of the increase in energy costs making 

Oklahoma goods uncompetitive. In the commenter’s view, not only are scrubbers or conversion 

to natural gas not cost effective, the true "costs of compliance" are unreasonable. Because of this, 

the FIP should be withdrawn. 

Response: As we state elsewhere in our response to comments, the term, “cost effective” 

is descriptive of the metric that is used to assess the BART factor , “cost of compliance,” 

required to be analyzed by section 51.308(e)(1)(ii)(A) of the RH rule. As discussed in our 

proposal, we disagree with OG&E’s and AEP/PSO’s cost estimates for installing SO2 scrubbers 

on their six units. In response to comments we received we have refined our cost estimate. 

Based on our Option 1 and Option 2 analyses, we find the total project costs to range between 

$290,418,007 to $299,400,007 for Sooner Units 1 and 2, and from $298,818,917 to 289,791,940 

for Muskogee. In light of the visibility benefits we predict will occur, we consider this to be cost 

effective. We take our duty to estimate the cost of controls very seriously, and make every 

attempt to make a thoughtful and well informed determination. We do note that, when using the 

cost methodology outlined in EPA’s Control Cost Manual, our cost estimate is lower than 

OG&E’s or AEP/PSO’s estimates resulting in less costs being passed on to rate payers than 

OG&E estimates. 

Regarding the Unfunded Mandates Reform Act (UMRA) of 1995 requires that Federal 

agencies assess the effects of Federal regulations on State, local, and tribal governments and the 

private sector. In particular, UMRA requires that agencies prepare a written statement to 

accompany any rulemaking that "includes any Federal mandate that may result in the 

expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of 

$100 million or more (annually adjusted for inflation) in any one year" (Section 202(a)). 

According to the Bureau of Labor Statistics, adjusted for inflation to 2011, this $100 million 

figure becomes $148.88 million.202 As we discuss in our proposal, we believe the OG&E 

facilities can meet their SO2 BART emission limit of 0.06 lbs/MMBtu on the basis of Option 2. 

Option 2 is less costly both in terms of capital and annual costs than Option 1. We calculate the 

total annual costs for the four OG&E units under Option 2 is $97,692,000. We calculate the 

annual costs for the AEP/PSO Northeastern units to be $44,969,595. This totals to $142,661.595 

Thus, our FIP does not include a Federal mandate that may result in estimated costs of $100 

million adjusted for inflation or more to either State, local, or tribal governments in the 

aggregate, or to the private sector. 

 

202 http://www.bls.gov/data/inflation_calculator.htm 

106 
III. Comments Related to the SO2 BART Compliance Timeframe 

Comment: A commenter suggests that the use of two different time periods for the 

installation of the NOx BART controls we proposed to approve, and the SO2 BART controls 

contained in our FIP, appears to be inconsistent and could result in additional costs and potential 

delays for utility customers. The commenter notes the time limit for installation for NOx control 

technologies, “expeditiously as practicable, but in no event later than 5 years after approval of 

the implementation plan revision” is inconsistent with the installation of SO2, "three (3) years 

from the date our final determination becomes effective" In both cases, argues the commenter, 

the time required to design, purchase, install and test the control technologies should be 

considered in establishment of a time limitation. The commenter suggests that two separate time 

frames does not make sense, is probably not a cost-effective approach to proper installation of 

control technologies and will result in unneeded expenditures of time and resources to allow the 

retrofit process to be done in an efficient and economic manner. The commenter supports a five 

year time frame that allows for an uniform time period for both requirements. 

Response: The NOx BART controls we proposed to approve are typically much less 

challenging and require less time to retrofit than are the SO2 BART controls (presumably 

scrubbers) necessary to meet our FIP for the six OG&E and AEP/PSO units. These retrofits can 

either be staged or in some cases, performed at the same time as the SO2 scrubbers that will be 

used to comply with the FIP. We believe granting the companies the full five years allowed 

under the RH rule provides those units that will also be installing scrubbers with additional 

flexibility. In addition, we did not see the need to reject Oklahoma’s BART determinations on 

that basis, in order to place the affected units on a shorter time schedule. As we discuss 

elsewhere in our response to comments, we have modified the time period for compliance with 

our SO2 BART FIP for the six OG&E and AEP/PSO units to the same full five years allowed 

under the RH rule. 

Comment: A commenter states that retrofitting of scrubbers is now routine in the U.S. 

and that approximately 290 coal-fired units totaling about 116,000 MW nationwide have been 

retrofit with scrubbers since 1990. These retrofits, according to the commenter, have included 

units in 35 states, with unit sizes ranging from under 20 MW to 1,300 MW, installed in 1943 

through 1996. The commenter believes three years is enough time for the installation of dry 

scrubbers on the six OG&E and AEP/PSO units. They state we are required under the CAA to 

adopt a compliance deadline that reflects expeditious installation of pollution controls. The 

commenter references the BART guidelines: “each source subject to BART [is] required to 

install and operate BART as expeditiously as practicable, but no later than five years after the 

date of EPA’s approval.” 40 CFR 51.308(e)(1)(iv). The commenter concludes that three years 

of time from the effective date of the final rule is a reasonable length of time to install the 

required pollution controls and comply with these emission limitations. They state there are 

numerous examples of SO2 scrubbers being installed at coal-fired power plants within a three 

year timeframe. As an example, the commenter, states that a new SO2 scrubber was installed at 

the Brandon Shores power plant, and according to the company’s website, construction took 

three years. 203 Further, the commenter states that American Electric Power completed 

 

203 

http://www.constellation.com/SocialResponsibility/EnvironmentalPerformance/Pages/BrandonShoresScrubber.aspx 

107 
construction of a scrubber at its John Amos power plant Unit 3 in three years.204 The commenter 

also states that TVA installed new SO2 scrubbers at its Bull Run and Kingston power plants in 

about three years as well.205 The commenter also states the installations of SO2 scrubbers have 

also been accomplished in less than three years, and cite the following examples: 

The Indianapolis Power & Light installed an SO2 scrubber at Unit 7 of its Harding Street 

Station in less than three years, with construction beginning in May 2005 and being completed in 

September 2007.206 A new scrubber was installed at Gulf Power Company’s Plant Crist to scrub 

the SO2 from 4 coal-fired boilers in less than three years from engineering design of the scrubber 

to operation.207

The commenter states these are but a few of numerous such examples that SO2 scrubbers 

can be installed in three years or less time. Further, argues the commenter, we have often 

required scrubber installation to occur in three years or less time in its settlement agreements for 

purported CAA violations at coal-fired EGUs and cites the following examples: 

The December 2008 Consent Decree regarding Salt River Project’s Coronado station 

required installation and operation of an SO2 scrubber at Unit 1 by January 1, 2012 which 

essentially reflects three years for design, construction, and operation.208 In addition, the 

October 2007 consent decree with American Electric Power requires SO2 scrubbers to be 

installed and operational at numerous of the units coal-fired EGUs within three years or less of 

the date of the settlement agreement, including John Amos Units 1, 2, and 3, Cardinal Units 1 

and 2, Conesville Unit 4, Mitchell Units 1 and 2, and Mountaineer Unit 1.209 

The commenter concludes that these and other examples provide ample support that three 

years for installation of SO2 controls and compliance with our proposed FIP is reasonable. In 

addition, these examples show that a BART compliance deadline for SO2 controls longer than 

three years is not consistent with the CAA requirement that BART be met as expeditiously as 

practicable. However, the commenter believes extending the compliance period to five years for 

any of the units that elected to switch to natural gas is appropriate. 

OG&E states that to complete a dry scrubber project, extensive planning is required. 

According to OG&E, the bid phase engineering, review, and contract negotiation can take up to 

one year to complete and the construction will generally require about 32 to 40 months to 

complete. OG&E states that following construction, final unit connections will require a plant 

outage. OG&E presents what it refers to as a typical schedule, which would require 52 months. 

 

204 http://statejournal.com/story.cfm?func=viewstory&storyid=54167&catid=283 205 http://www.knoxnews.com/news/2008/nov/21/new-scrubber-at-bull-run-plant-may-help-improve

http://msbusiness.com/2010/06/tva-puts-new-scrubbers-in-operation/ 

206 

http://www.iplpower.com/ipl/index?page=IPLGeneral&Menu=06000000&DocID=02039b33d0a010bcb031eea007b

7f 

207 Sierra Club states the award for engineering and design was awarded in May 2007 (see 

http://www.bv.com/wcm/press_release/05072007_1374.aspx), and the scrubber came on-line and was operational at 

the end of 2009 (see http://www.gulfpower.com/about/plant_crist.asp). 208 http://www.epa.gov/compliance/resources/decrees/civil/caa/srp-cd.pdf 209 http://www.epa.gov/compliance/resources/decrees/civil/caa/americanelectricpower-cd.pdf 

108 
OG&E adds the schedule provided above does not account for installation of two units 

that would be required at each of the Sooner and Muskogee Stations. OG&E states the 

construction activities for the four total DFGD units would have to be coordinated to account for 

staggered delivery of materials and to ensure that construction labor is available. OG&E adds 

that the DFGD tie-in schedules must coincide with planned unit outages. OG&E concludes that 

based on the general retrofit schedule provided above, and challenges associated with the 

simultaneous installation of four DFGD systems, a 3-year compliance schedule is not practical. 

Further, OG&E adds that the compliance time frame should include the time needed for 

OG&E to obtain a construction permit for any scrubbers under the Prevention of Significant 

Deterioration (PSD) permit tailoring rule for greenhouse gas emissions. If a PSD permit is 

needed, notes OG&E, it must be obtained before construction commences, and the permit can 

take 18-24 months to obtain. According to OG&E. it would be impossible to accommodate the 

PSD permit application process in a three year compliance time frame. 

Another commenter provided similar comments. The commenter states that we cannot 

make a showing that a time less than the maximum of five years allowed under the RHR only if 

we demonstrate that compliance within that shorter period is shown to be “practicable.” The 

commenter states that we cannot make a showing that compliance is practicable simply by 

referring to what may have been accomplished at other facilities. Even if compliance within 

three years may arguably have been practicable at another facility, continues the commenter, it 

does not mean it is practicable at the specific EGUs to which this proposed rule would apply. 

The commenter states that a BART determination that shortens the presumptive five-year 

compliance period in the case of any given BART facility must be based on a site-specific 

analysis that adequately accounts for all variables affecting feasibility, including costs. 

AEP/PSO states that the RH Rule specifically recognizes that a compliance time line of 

five years from the effective date of the RH SIP is a reasonable schedule, but we have proposed a 

much shorter timeline of three years. They allege that our schedule focuses on actual 

construction timelines, but fails to acknowledge or allow sufficient time for the engineering, 

design, and permit processes that must be completed prior to the commencement of construction. 

According to AEP/PSO, the planning, selection of engineering and design professionals, vendors 

and contractors, permitting, construction, startup and commissioning required for AEP/PSO’s 

compliance with the proposed FIP is anticipated to take significantly longer than the proposed 

three years, making a 36 month compliance schedule unachievable. 

AEP/PSO states the complexity of the “construction” of an FGD system at an existing 

generating station is very site specific, which strongly influences the time required for 

installation. AEP/PSO estimates the Front End Engineering & Design (FEED) work required to 

determine the feasibility of the project, to support the technology selection and to establish the 

high level cost estimates requires a 6 to 8 month effort. Following the completion of the FEED 

effort, continues AEP/PSO, the air permit modeling, application and regulatory review and 

approval require 18 months, and this permit is required before construction can commence. 

AEP/PSO states that during this same timeframe, 6 to 8 months of preliminary engineering is 

required to advance the maturity of design to the point that the long lead time major equipment 

109 
orders can be placed, followed by the detailed engineering and design. Based on its experience 

to date and assuming some of the detailed design is performed in parallel with the construction 

effort, AEP/PSO concludes that the construction of the FGD, including startup and 

commissioning, will take 28 months, resulting in an overall project duration of 52 to 54 months. 

AEP/PSO states its experience is consistent with estimates provided by experienced third 

parties for similar work. They cite a schedule to retrofit a dry FGD/fabric filter system at an 

AEP coal fired generating station that was developed in 2009 as part of a conceptual engineering 

study and completed by a third party engineering, procurement and construction contractor. 

AEP/PSO states the total duration from a “Notice to Proceed” to “first gas” through the new 

FGD/fabric filter system under that schedule was 53 months. AEP/PSO also cites another 

similar study conducted in 2011 by another independent architectural/engineering firm which 

resulted in a total schedule of 55 months. AEP/PSO concludes our 36-month schedule proposed 

for the FIP is not feasible. 

AEP/PSO states that a 20-25 acre landfill would be required to handle the additional 

waste required of a FGD system which would require 54 months to complete. AEP/PSO states 

that land acquisition could add an additional 6 to 12 months to the development schedule. 

AEP/PSO states that following submittal of the permit applications , the review and approval 

cycle for an air permit, the Clean Water Act Section 401 and 404 permits (if required), and a 

solid waste permit must be completed before landfill construction can commence, and consumes 

approximately 18 additional months. AEP.PSO states the next 18 months are spent constructing 

the haul roads, borrow areas and landfill cells required before the landfill is available for first 

disposal use. 

AEP/PSO states that the addition of FGD systems can trigger a need to construct a 

replacement stack if the original stack and liner materials cannot accommodate the different 

physical and chemical characteristics of the scrubbed flue gas. According to AEP/PSO, the 

schedule to design, permit, procure materials and install a typical concrete stack with a single 

liner, built to GEP height, can take a total of 44 to 48 months from the project “Notice to 

Proceed” to first gas. AEP/PSO states these durations are based upon its experience with the 

construction of eight such stacks during the past seven years. 

AEP/PSO states that due to the economic climate, and the significant downturn in the 

number of large capital intensive projects since 2008, domestic suppliers of environmental 

equipment, material and services have scaled back production and skilled resources in an attempt 

to maintain their long term viability. AEP/PSO states that this will not make major components 

and material more readily available, but that economic stagnation and uncertainty lead suppliers 

to reduce productive capacity, which results in longer lead times for critical system components. 

They state the lead time after receipt of order for limestone ball mills for FGD systems has 

increased from 70 weeks in 2006 to 90 weeks in 2011, and that major electrical transformers are 

currently quoted with a 40 to 48 week delivery period. AEP/PSO conjectures that if numerous 

utilities are forced to move to market simultaneously to comply with other pending requirements, 

like EPA’s Clean Air Transport and Hazardous Air Pollutant rules, they will all be seeking the 

same components in a severely-constrained timeframe. Such market concentration, according to 

AEP/PSO, will increase lead times for practically all significant components, even beyond those 

110 
that are commonly quoted currently for similar equipment. AEP/PSO proposes that, in the event 

the FIP is issued, compliance with both the SIP and FIP requirements should be scheduled to 

occur as soon as practicable, but no later than five years from the effective date of the final rules. 

Response: We proposed that compliance with our SO2 BART emission limits be within 

three years of the effective date of our final rule. We solicited comments on alternative 

timeframes, from as few as two years to up to five years from the effective date of our final rule. 

We received comments that retrofitting of scrubbers is now routine in the U.S. and that 

approximately 290 coal-fired units totaling about 116,000 MW nationwide have been retrofit 

with scrubbers since 1990. The commenter cites to many examples of SO2 scrubbers being 

installed at coal-fired power plants within a three year timeframe. OG&E, and others state that 

our proposed three year schedule focuses on actual construction timelines, but fails to 

acknowledge or allow sufficient time for the engineering, design, and permit processes that must 

be completed prior to the commencement of construction. They state a compliance schedule of 

from 52-54 months would be required. 

Although we do not specify what technology the six OG&E and AEP/PSO units must use 

to satisfy the SO2 BART emission limit, we expect that either dry or wet SO2 scrubbers will be 

used, or that the SO2 limit will be met by switching one or more of the units to natural gas. We 

agree that that SO2 scrubbers have been installed at other facilities with construction timeframes 

of three years or less. However, we also agree with OG&E and AEP/PSO that there may be 

issues such as PSD permitting, and the construction/expansion of a landfill that may not be 

reflected in the example compliance times reported by the commenter. Therefore, we find that 

compliance with the emission limits be within five years following the effective date of our final 

rule, which is the maximum amount of time allowed by the RH rule. 

IV. Visibility Improvement Analysis Comments 

Comment: OG&E states that EPA proposes to overturn the State’s SO2 BART 

determination on the grounds that scrubbers would reduce visibility impairment at Class I areas 

from values that are above 1.0 dv to levels that are below 0.5 dv. OG&E asserts this reasoning is 

legally flawed and ignores the State’s discretion to weigh projected visibility improvement in the 

overall BART analysis. In making this argument, OG&E references the RHR, “When making 

this determination [BART Step 5 on visibility impacts], you have flexibility in setting absolute 

thresholds, target levels of improvement, or de minimis levels since the deciview improvement 

must be weighed among the five factors, and you are free to determine the weight and 

significance to be assigned to each factor.” 70 FR 39170. OG&E concludes that in exercising 

its discretion, the State may consider other factors, such as the incremental degree of visibility 

improvement (in Δ-dv) that would result from adding scrubbers to each individual facility and 

the costs per Δ-dv of visibility improvement. OG&E also asserts that EPA does not sufficiently 

justify its disagreement with Oklahoma that the visibility improvement due to the installation of 

scrubbers justifies the cost of the installation of scrubbers. OG&E states the visibility 

improvement is nearly imperceptible and that sources in Texas contribute more to the visibility 

problem in Oklahoma than do Oklahoma’s own sources. OG&E concludes this situation 

obviates any argument under the RHR that “[e]ven though the visibility improvement from an 

111 
individual source may not be perceptible, it should still be considered in setting BART because 

the contribution to haze may be significant relative to other source contributions in the Class I 

areas.” 70 Fed. Reg. at 39129. OG&E concludes, less-than-perceptible visibility improvements 

from OG&E’s BART sources should not be considered significant in that context because 

visibility modeling shows OG&E’s sources are not one of the larger stationary source 

contributors to visibility impairment at a Class I area. 

Response: As we have discussed elsewhere in our response to comments, we find 

Oklahoma’s BART determinations for SO2 for the six OG&E and AEP/PSO units are not 

approvable. We conclude they are not approvable because Oklahoma did not follow the BART 

five factors under section 51.308(e)(1)(ii)(A). Specifically, we find that Oklahoma did not 

properly take into consideration the costs of compliance. Because we are disapproving ODEQ’s 

BART determinations for OG&E Sooner and Muskogee plants and the EPA is under a consent 

decree deadline to act on controlling these sources since they interfere with other states visibility 

programs, we are obliged to promulgate a FIP under CAA section 110(c)(1). We agree with 

OG&E that the degree of improvement in visibility is one of the five BART factors that must be 

addressed under section 51.308(e)(1)(ii)(A). However, although the BART guidelines do state 

that states have the flexibility in “setting absolute thresholds,” we have the authority and 

obligation under CAA section 110(c)(1) to determine whether the state’s decision in that regard 

satisfies the requirements of the RHR. 

We disagree with OG&E that we do not have a supportable rationale to disapprove 

Oklahoma’s determination that the degree of visibility improvement due to the installation of 

scrubbers does not support the cost of installation of scrubbers. We provided a well reasoned 

and complete evaluation of the visibility benefits the installation of SO2 scrubbers on the six 

AEP /PSO and OG&E units in question are predicted to have on four Class I areas. As we stated 

in the proposal210: 

[W]e disagree with ODEQ’s conclusion on costs for SO2 controls and we 

find that cost effective SO2 controls are available and our modeling 

demonstrates that substantial visibility improvement is achievable based 

on the installation of these controls. In particular, our modeling indicates 

that dry scrubbing will result in a 2.89 deciview improvement in visibility 

at the Wichita Mountains. Furthermore, the addition of SO2 scrubbers 

(wet or dry) on each of the three facilities (2 units at each facility) will 

reduce visibility impairment at Class I areas (Wichita Mountains and/or 

other surrounding Class I areas) from values that are above the 1 deciview 

impact that is a direct causation of visibility impairment to levels that are 

below the 0.5 deciview threshold that ODEQ used for determining if a 

source contributed to visibility impairment. We consider the reduction in 

visibility impairment at Wichita Mountains, Caney Creek, Upper Buffalo, 

and Hercules-Glades to be significant both for the RH SIP and also for 

reduction of visibility impairment on other states in meeting the 

requirements of the 110 (a)(2)(D) SIP. 

 

210 76 FR 16168 

112 
We agree with OG&E that sources in Texas are responsible for more of the visibility 

impact at the Wichita Mountains, more than Oklahoma’s own sources including OG&E’s Sooner 

and Muskogee facilities. However, we disagree with the premise that because the hundreds of 

Texas sources collectively contribute more to visibility impairment than OG&E’s four BART 

sources, those BART sources should not be controlled. The CAA and the RHR do not provide 

an exemption to BART if a source contributes less than other sources to visibility impairment. 

Furthermore, regarding OG&E’s argument concerning the perceptibility of visibility 

improvement, the RHR is clear that perceptibility of improvement is not a test for the suitability 

of BART controls in the sentence following the one OG&E’s quoted211 : 

Thus, we disagree that the degree of improvement should be contingent 

upon perceptibility. Failing to consider less-than-perceptible contributions 

to visibility impairment would ignore the CAA’s intent to have BART 

requirements apply to sources that contribute to, as well as cause, such 

impairment. 

We discuss the visibility benefits that are projected to occur as a result of our SO2 BART 

determination for the six OG&E and AEP/PSO units in more detail in our response to comments 

in our federal register notice. We find that we have appropriately conducted the BART 

evaluation for Units 4 and 5 of the OG&E Muskogee plant, and Units 1 and 2 of the OG&E 

Sooner plant, and Units 3 and 4 of the AEP/PSO Northeastern plant. 

Comment: OG&E states the RHR specifically authorizes states to select BART based on 

a consideration of “total annualized costs ($), cost effectiveness ($/ton), and incremental cost 

effectiveness ($/ton), and/or any other cost-effectiveness measures (such as $/deciview).” 70 

Fed. Reg. at 39,170. OG&E states the RHR also recognizes that the metric of $/dv reflects the 

visibility improvement of a control option as well as its cost and that Oklahoma did consider 

$/dv as it was authorized to do under the RHR. We, OG&E asserts, may not ignore the $/Δ-dv 

metric now in disapproving of the State’s determinations and EPA has not and cannot show that 

scrubbers are cost-effective in terms of $/dv, even when using our own understated estimates of 

the total annual costs of scrubbers. OG&E further alleges that we incorrectly rejected ODEQ’s 

reliance on the $/Δ-dv metric in reaching our BART determination as well as not considering 

visibility improvement cost effectiveness in our FIP BART determination. 

OG&E states the Federal Land Managers have asserted that $10 - $19 million/dv should 

be considered reasonable for SO2 control. In developing the SIP, OG&E states, ODEQ took the 

FLM’s comments under advisement but questioned the rationale behind a threshold as high as 

$19 million/dv. OG&E states that our cost estimates indicate that scrubbers would cost $30.9 

million/Δ-dv at Sooner and $22.9 million/Δ-dv at Muskogee which are far above the FLM’s 

view of the reasonable range of $/Δ-dv for SO2 control. OG&E’s states its May 2008 BART 

evaluations, which were developed consistent with the Control Cost Manual, indicate even 

higher $/Δ-dv for scrubbers ($68.6 million/Δ-dv for Sooner and $44.6 million/Δ-dv for 

Muskogee). OG&E states the poor cost effectiveness of scrubber in $/Δ-dv for the OG&E Units 

is a function of the existing low emissions and low baseline visibility impacts of those units. 

According to OG&E, because of this, the cost of installing and operating dry FGD is high in 

 

211 70 FR 39129 

113 
relation to a relatively small improvement in visibility in class I areas. OGE states that even 

using EPA’s cost estimates for OG&E’s units, the visibility improvement projected by EPA from 

the use of scrubbers at OG&E’s units does not justify our costs. 

OG&E contrasts the visibility impact of its four BART sources to those of other BART 

determinations: the Four Corners Power Plant in AZ, the San Juan Generating Station in NM, 

and the Boardman Power Plant in OR. OG&E believes that since the $/dv is much higher for its 

four BART units in comparison to these BART units, the costs of our proposed SO2 controls is 

not warranted. OG&E concludes that EPA’s failure to recognize Oklahoma’s assessment of the 

$/dv metric for SO2 control at the OG&E Units is arbitrary, capricious and contrary to applicable 

law. 

Response: As stated elsewhere in our response to comments, we reject the assertion that 

our cost estimates are understated. Regardless, the BART Guidelines require that cost 

effectiveness be calculated in terms of annualized dollars per ton of pollutant removed, or 

$/ton212. OG&E provided a $/deciview analysis for its units and comparable BART 

determination performed by us. In our analysis for our BART FIP for OG&E and AEP/PSO, we 

did not evaluate $/deciview. We explain that the BART Guidelines list the $/deciview metric as 

an optional cost effectiveness measure that can be employed along with the required $/ton metric 

for use in a BART evaluation. The metric can be useful in comparing control strategies or as 

additional information in the BART determination process; however, due to the complexity of 

the technical issues surrounding regional haze, we have never recommended the use of this 

metric as a cutpoint in making BART determinations. We note that to use the $/deciview metric 

as the main determining factor would most likely require the development of thresholds of 

acceptable costs per deciview of improvement for BART determinations for both single and 

multiple Class I analyses. We have not developed such thresholds for use in BART 

determination made by us. As OG&E acknowledges, EPA did not use this metric as part of its 

proposed BART determinations for either the Four Corners Power Plant FIP in AZ, or the San 

Juan Generating Station FIP in NM. Generally speaking, while the metric can be useful if 

thoughtfully applied, we view the use of the $/deciview metric as suggesting a level of precision 

in the calculation of visibility impacts that is not justified in many cases. While we did not use a 

$/deciview metric, we did, however, consider the visibility benefits and costs of control together, 

as noted above by weighing the costs in light of the predicted visibility improvement. 

Comment: A commenter stated that the BART determinations set forth in Oklahoma’s 

SIP the SIP followed EPA’s five-step process set forth in the Guidelines. The commenter 

believes the Oklahoma SIP balanced the cost-benefit factors and determined that EPA’s 

presumptive emission limit for SO2 was not justified by the visibility improvement benefits. 

However, the commenter alleges we conflated “cost of compliance” with “cost-effectiveness,” 

when we indicated that “scrubbers are typically considered to be highly cost-effective controls 

for power plants such as those at issue here,” and did not indicate what “cost-effective” means in 

the context of applying the five statutory BART factors, as required, on a source-specific basis. 

The commenter states the purpose of the RH program is to improve visibility not, per se, to 

reduce SO2 emissions, and that the term “cost-effective” does not even appear in Section 169A, 

much less any requirement that a source can be required to reduce SO2 emissions if the cost of 

 

212 70 FR 39167. 

114 
doing so is below a certain dollars-per-ton level. A source, states the commenter, can only be 

required to reduce SO2 emissions under Section 169A if it is justified by weighing the cost of 

reducing SO2 emissions against visibility improvements. 

The commenter acknowledges, the BART Guidelines set forth a cost-effectiveness test in 

terms of dollars per ton of SO2 removed. 70 Fed. Reg. at 39167/1. However the commenter 

argues the Guidelines must be read in light of the five statutory BART cost-effectiveness factors 

which are reiterated in the Guidelines. The commenter states that dollars per ton of SO2

removed is an informational item that EPA has used to create a rebuttable presumption of a 0.15 

lbs/MMBtu SO2 emission limit, but does not eliminate the need to apply the five statutory BART 

determination factors in weighing the cost of control technologies against visibility benefits, and 

it does not provide that a BART determination should rise or fall based on an assumption as to 

whether a unit will use high or low sulfur coal when that assumption makes no difference to 

downwind visibility. 

Response: We disagree with the commenter that Oklahoma followed the five-step 

process set forth in the Guidelines. As we discussed in our proposal, we proposed to find that 

ODEQ did not properly follow the requirements of section 51.308(e)(1)(ii)(A) in determining 

BART for the six OG&E and AEP/PSO units. For the reasons discussed elsewhere in this 

action, we finalize that finding. 

We agree with the commenter that the goal of the RH program is to improve visibility. 

Regional haze is the result of the collective contribution of many sources of air pollution over a 

broad region. However, visibility improvement cannot be accomplished without reducing 

emissions including SO2 emissions. 

We disagree with the commenter that we confused “cost of compliance” with “costeffectiveness,” or that issue is even significant to our BART determination. We note we 

proposed “that ODEQ did not properly take into consideration the ‘costs of compliance’ when it 

relied on cost estimates that greatly overestimated the costs of dry and wet scrubbing to conclude 

these controls were not cost effective.”213 Use of the term, “cost effective” appears in the BART 

Guidelines in numerous places. It is descriptive of the metric that is used to assess the BART 

factor , “cost of compliance,” required to be analyzed by section 51.308(e)(1)(ii)(A) of the RH 

rule. We agree with the commenter that a source, can only be required to reduce SO2 emissions 

under Section 169A if it is justified by weighing the cost of reducing SO2 emissions against 

visibility improvements. We would add that determination must follow RH rule. As the 

commenter acknowledges, the BART Guidelines explain214 that cost effectiveness is expressed 

in terms of the $/ton factor, which is simply the annualized cost of the control, divided by the 

amount of pollutant removed. Without the use of such a cost effectiveness metric (in unison 

with visibility modeling), we would not have the ability to judge whether the cost of compliance 

for one particular control was more suitable than another. We disagree that $/ton is an 

informational item that EPA has used to create a rebuttable presumption of a 0.15 lbs/MMBtu 

SO2 emission limit, as the BART Guidelines clearly require its use for the reason outlined above. 

We do agree with the commenter that the use of the $/ton metric does not eliminate the need to 

 

213 76 FR 16182. 214 70 FR 39170. 

115 
116 

apply the five statutory BART determination factors in weighing the cost of control technologies 

against visibility benefits, which we have done. 

Comment: A commenter states that the main objection to limiting emissions at the power 

plants is the cost. According to the commenter, the power plants have operated for years without 

paying the true cost of energy production, which should include the cost of limiting their air 

pollution. It also appears that the companies have overstated the costs. The commenter claims 

that AEP reported $1.2 billion and OG&E $292 million in profit last year, so they can apparently 

afford to address the problem without passing all the costs to their customers. The commenter 

believes that three years would be a reasonable time for the power plants to come into 

compliance. The commenter believes that AEP/PSO and OG&E should have made a move 

toward compliance long ago, and further stalling should not be allowed. 

Response: We agree with the commenter that cost is one of the factors of a BART 

determination, and that OG&E and AEP/PSO have overstated the cost of installing SO2

scrubbers at the six units in question. We discuss the BART compliance deadline in the response 

to another comment. 

Comment: A commenter believes the FIP should be rejected in favor of the adoption by 

the EPA of the ODEQ SIP in this docket. The commenter believes we did not conduct a full 

analysis of the costs that will be required by utilities if the FIP is implemented. The commenter 

states that according to its consultant, the Oklahoma coal plants in question have all been in 

operation a minimum of 30 years. The commenter believes that due to the estimated remaining 

useful life of the plants, when factoring in the cost of the EPA FIP-required scrubbers to be 

installed on the existing coal plants, together with the costs of new gas fired combined cycle 

plants that will be necessary once the existing coal plants are retired (just one alternative), the 

FIP costs are too high to be considered a viable option. 

Response: The BART guidelines do allow for consideration of the remaining useful life 

of facilities when considering the costs of potential BART controls. Such a claim would have to 

be secured by an enforceable commitment. Neither OG&E nor AEP/PSO claimed any such 

restriction on the operation of these six units. As we explain in a response to another comment, 

we find that our original determination that the scrubbers for the six OG&E and AEP/PSO units 

should have a 30 year useful life remains correct. 
Attachment 1 

Sargent & Lundy Fabric Filter IPM Model Study 

As discussed in our response to comments, we incorporated the algorithm from the fabric filter baghouse model deve

for EPA's IPM Model215 into a spreadsheet to explore the savings from building one large baghouse to serve each un

baghouses as included in the Request for Quote and vendor proposals. The full spreadsheet, along with a copy of the 

derived, has been added to the docket for our final action, and a screen copy of the spreadsheets is reproduced hereinare summarized in Table 1 in our response to comments. Presented here are 4 screenshots of the results of this modedesigned for one of the Sooner units (570 MW), one 50% baghouse for one of the Sooner units (285 MW), a 100% bthe Muskogee units (572 MW), and one 50% baghouse for of one of the Muskogee units (286 MW). 

215 IPM Model – Revisions to Cost and Performance for APC Technologies, Particulate Control Cost Development Methodology, Final, March 

Research and Applications Corporation, Prepared by, Sargent & Lundy 
Figure 1-100% Baghouse for Sooner (570 MW) 

2
Figure 2 - 50% Baghouse for Sooner (285 MW) 

3
Figure 3 - 100% Baghouse for Muskogee (572 MW) 

4
Figure 4 - 50% Baghouse for Muskogee (286 MW) 

5
 

Attachment 2 

Sargent & Lundy SDA IPM Model Study 

We have revised our Option 2 cost analysis to address the sulfur content/sizing issue raised in this and other 

comments. Our revised Option 2 analysis relies on certain design algorithms in the dry scrubber absorber 

(SDA) cost model developed by Sargent & Lundy for EPA.216 This model does not consider changes in flue 

gas volume due to changes in coal composition. The design coal, for example, has a higher heat content than 

currently burned coal and would thus generate less flue gas, reducing costs. Further, this model does not 

optimize mass transfer to account for the smaller amount of SO2 that would have to be removed by the Option 2 

scrubber. We used it only to establish a floor. The actual cost of a smaller scrubber could be much less. 

 We used this model to estimate the difference in the capital cost of dry scrubbers for Sooner and 

Muskogee when burning coal containing the two sulfur contents that we analyzed in the TSD, 0.48% sulfur 

(1.176 lb SO2/MMBtu) and 0.22% sulfur (0.509 lb SO2/MMBtu), assuming a 100% capacity factor. The results 

of this analysis indicates that the use of the lower sulfur coal alone would reduce the capital cost of the scrubber 

by about $7 million or 3%.217 The full spreadsheet, along with a copy of the report from which it was derived, 

has been added to the docket for our final action, and screen copies of the spreadsheet and information on the 

model is reproduced herein. The 3% reduction is incorporated into the revised Option 2 cost analysis in Exhibit 

2. 

 

216 Sargent & Lundy, IPM Model - Revisions to Cost and Performance for APC Technologies, SDA FGD Cost Development 

Methodology, Final, August 2010, Table 1. 

217 Using the formula in Table 1 of the 8/2010 S&L SDA FGD Report, Table 1, the total cost with AFUDC for a single unit at Sooner 

when burning 1.176 lb SO2/MMBtu coal is $229,122,268 and when burning 0.509 lb SO2/MMBtu coal, it is $221,885,381. The total 

cost with AFUDC for a single unit at Muskogee when burning 1.176 lb SO2/MMBtu coal is $236,228,452 and when burning 0.509 lb 

SO2/MMBtu coal, it is $228,861,061. 
 

Figure 1 – Sooner SDA Cost with 1.176 lb/MMBtu Coal 

2
 

Figure 2 – Sooner SDA Cost with 0.509 lb/MMBtu Coal 

3
 

Figure 3 – Muskogee SDA Cost with 1.176 lb/MMBtu Coal 

4
 

Figure 4 – Muskogee SDA Cost with 0.509 lb/MMBtu Coal 

5
Attachment 3 

 
 

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3