### Response to Technical Comments for Sections E. through H. of the Federal Register Notice for the Oklaho ma Regional Haze and Visibility Transport Federal Im plementation Plan

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

12/13/2011Table of Contents

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

I. Comments Related to our SO2 BART Cost Evaluation ..............................................1 II. Comments Relating to Ou r SO2 BART Emission Limit ..........................................91 III. Comments Related to the SO2 BART Compliance Timeframe ................................107 IV. Visibility Improveme nt 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 Sulf ur Content Per Coal Fuel Receipt,

Jan 2004 – Dec 2010 .......................................................................... 50 Figure 2 – Muskogee Plant, OK, Average Su lfur Content Per Co al Fuel Receipt,

Jan 2004 – Dec 2010 ........................................................................... 50 Figure 3 – Muskogee Unit 4 Monthly Average SO 2 Emissions and Coal Sulfur .................. 51 Figure 4 – Muskogee Unit 5 Monthly Average SO 2 Emissions and Coal Sulfur .................. 52 Figure 5 – Sooner Unit 1 Monthly Average SO 2 Emissions and Coal Sulfur ...................... 52 Figure 6 – Sooner Unit 2 Monthly Average SO 2 Emissions and Coal Sulfur ...................... 53 Figure 7 – TS Power Plant (NV) SO 2 Emission Rate lb/MMBtu .................................... 96 Figure 8 – Wygen II (WY) SO 2 Emission Rate lbs/MMBtu ..........................................97 Figure 9 – Weston Unit 4 (WI) SO 2 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 Analys es for Dry Flue Gas Desulfurization at Sooner Units 1 and 2 and Muskogee Units 4 and 5

iIntroduction

This document contains a partia l listing of responses to comme nts received as a result of our proposed Oklahoma Regional Haze and Visibili ty 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 SO 2 BART Cost Evaluation, our SO 2 BART Emission Limit, and our SO 2 BART Compliance Timeframe for the six Oklaho ma Gas and Electric (OG&E) and American Electric Power/Public Service Company of Ok lahoma (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 commen ts we received, some groups expressed support

for or otherwise endorsed the comments submi tted by the utility owners, OG&E and AEP/PSO, who are subject to the BART SO 2 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 SO 2 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 redu ctions due to multiple identical units, use of common facilities, use of existing equipment, a nd 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, there by incorrectly reducing th e 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 filte r) 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 savi ngs 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, eq uipment vendors were provided with plant design data sheets for all of the generating units, whic h 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 engineeri ng data, could allow the potential use of co mmon facilities.

In conclusion, OG&E claims we had no basi s to assume the budgetary quotes in the December 2009 Budget Cost Estimates did not alrea dy 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 th at site-specific gene ral arrangements were prepared for each station, which could be used to speculate regardi ng opportunities to use common facilities. However, they claim that si gnificantly 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 us e common facilities, which was beyond the scope of a study level or even a scoping-level cost estimate. OG&E stat es 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 addi tional 5% for common fac ilities arbitrary. In addition, OG&E claims that we provide no documenta tion that any savings would be realized by designing the scrubber to us e common facilities.

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

facilities discounts was not arbitr ary and without basis, but rath er based on standard cost estimating practices and further supp orted by vendor quotes supplied by OG&E. 1

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

fabricated from scratch. It is common sense a nd a well established princi ple of cost estimating that considerable savings can be achieved by designing, fabricating, and constructing multiple identical units simultaneously. Fabricating multi ple units would save th e 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 cont ractor, Sargent & Lundy were provided for a single generating unit at Soone r 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, th e single unit specificat ion requested two 50% systems or equipment, rather than a more ec onomical 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 industr y 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 busine ss 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. Enviro nmental Systems & Services. Price Estimate for Spray Dry Absorber and Pulse Jet Fabric Filter Systems, dated Decem ber 9, 2009. It appears as if we were provided with abbreviated vendor quotations and not the entire vendor quota tion. 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 spreadsh eet capital costs in our cost effectiveness analysis and used the provided vendor quotations to confirm our cost effectiveness cal culations, with the exception of those items expressly

outlined herein.

2Sargent & 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 sta tions. 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 considera tion of multiple units. Furthermore, these prices are exactly double the per-unit prices in the vendor qu otes. 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 co sts could be reduced by considering multiple units rather than single units.

Our 5% discount on equipment for multiple iden tical 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 lo wer end of this range. We provide examples later in this response showi ng 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 th e 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 pract ice of using one baghouse to handle 100% of the load – that one baghouse is used by similar facilities. We in corporated the algorithm from the fabric filter baghouse model developed by Sargen t & Lundy for EPA's IPM Model 4 into a spreadsheet to explore the savings from building one large baghous e to serve each unit, rath er 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 T echnology, 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 uni ts to account for reduced engineering costs and economy of scale. The discount was determined by assuming a 50 percent reduction in engi neering 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.do e.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.d ec.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

3Table 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 Ta ble 1 shows that one large baghouse designed to serve each unit, rather than two 50% baghous es, 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 capita l costs, very close to the 5% we assumed. As noted previously, we chose 5% savings from optim izing 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 co st and erection man hours (380,000 hrs) to design and construct one standal one 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 design s are the same, a common lime preparation and recycle system, and the same schedule. The re sulting 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 th e system for one station to supply two duplicate SDA/FF systems is about 5% off of the to tal 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

Document 6 states, “A common lime handling system w ill be installed at each station.” The vendor quotes confirmed that OG&E required a sepa rate 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.

4unit when these systems can be shared successful ly 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 us ed, thus double counting so me of the cost of the lime handling system that was meant to be shared between the two units.

Consequently, we find that our initial assu mptions that (1) vendors would offer a 5% discount on equipment costs for multiple identi cal units and large uni t operations; and (2) designing the control system to use common faci lities (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 c ontrol options that we iden tified 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 adju stments 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 SO 2 inlet rate of 1.176 lb/MMBtu SO 2 , and its annual emission reductions assumption, which was based on an average inlet SO 2 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 assu mption (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 emi ssions, as expressed in the BART Guidelines, and other BART determinations. As a result, OGE states our approach significantly overestimates baseline SO 2 emissions from the subject units.

OG&E notes the BART Guidelines in Appendi x Y to 40 CFR Part 51 state that “[t]he baseline emissions rate should represent a realis tic depiction of anticipated annual emissions for the source. In general, for the existing sources subject to BART, you will estimate the anticipated annual emissions base d 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 Corner s 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 co al being fired is incorrect, and redesigning the scrubber, as we suggest, would result in an undersized and in effective 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 emi ssions, would not change our conclusion that dry scrubbers are cost effective. We explored this option in our proposal as

5Option 2. As discussed elsewhere in our response to comments, we have revised Option 2 due to comments we have received. In summary (but disc ussed in greater detail later), the use of the

lower estimate of emission reductions results in a revised cost effec tiveness 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, colu mn 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 repres ent a realistic depiction of anticipated annual emissions for the source. In gene ral, for the existing sources subject to BART, you will estimate the anticipated annual emissions based upon actual emissions from a baseline period. Wh en you project that future operating parameters (e.g., limited hours of operation or capacity utilizati on, 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 en forceable limitations. In the absence of enforceable limitations, you calculate base line 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 depi ction 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 op erating 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 t oo high. However, we find it is

reasonable to conclude the RHR’s desire to realign baseline em issions with potential future changes in operations applies equall y to this situation as well.

In addition, the RHR states that when differenc es from "past practice, " as here, have "a deciding effect in the BART dete rmination, you must make these pa rameters or assumptions into enforceable limitations." The OG&E analysis does not propose making the basis of their emission reductions enforceable. In fact, the sc rubbers are designed to allow the station to burn higher sulfur coals than historica lly used at the station. Theref ore, we affirm our position taken in Option 1, that our decision to raise the baseline to match the SO 2 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 SO 2 BART determination for Unit 1 of the

Stanton Station in North Dakota. 8 In that case, the Stanton Sta tion Unit 1 historically burned a

7 70 FR 39167

8 76 FR 58585

6mix of lignite and Powder River Basin coal. Since Stanton was permitted to burn both lignite and Powder River Basin (PRB) co al and wanted the flexibility to burn 100% of each, in its BART determination, North Dakota changed the base line emissions to reflect the future emission potential of Stanton under either scenar io. North Dakota then analyzed the SO 2 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 calcula ted on the basis of either 100% lignite or 100% PRB.

The scrubbers that were costed were designed to treat the e xhaust gases from a coal that contains much higher amounts of sulfur than coal s that were burned in th e baseline period (2004- 2006). As we discuss elsewhere in our response to comments, th is design thus "anticipates" much higher SO 2 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 emi ssions 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/F our Corners cases. In those cases, we adjusted the hi storical baseline emissions because the company, “used the same 24-hour average actual emission rate from the hi ghest 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 emissi ons over the same period. Therefore, this example is not pertinent. Furthermore, we di d 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 SO 2 scrubbers be designed on the basis of a hi gher 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 co al 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 matche s 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 SO 2 emission limit of 0.06 lbs/MMBtu on the basis of a 30 day BOD average.

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

accordance with the BART Guidelines and are c onsistent with the cost estimating methodology

described in the Control Cost Manual. 10 OG&E further st ates 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 Co st 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

7estimation, 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 projec t is completed "overnight." As explained in our proposal, OG&E’s December 2009 cost es timates did not follow the overnight method

used in the Cont rol Cost Manual.

There are only very limited s ituations under which an analys t can depart from the Control Cost Manual methodology under the RHR 12 :

The basis for equipment cost estimates al so 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 contro l technologies in sufficient detail for a BART analysis. Th e cost analysis should also take into account any site-specific design or other c onditions 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 determina tion. It also states why—to maintain and improve consistency. However, the Control Cost Manual does state that site-specific conditions should be incorporated. Site-s pecific conditions could include space constraints, or a design feature that could complicate inst alling a control. However, a f ootnote at the bottom of the same page of the RHR makes it clear th at the analyst should document any deviations from the Control

Cost Manual:

You should include documentation for a ny additional information you used for the cost calculations, including any info rmation supplied by vendors that affects your assumptions regarding purchased equipment costs, equipment life, replacement of major compone nts, 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 th an 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 method 13 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 additiona l 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

8The ‘‘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 a nnualized costs in EPA’s OAQPS Control Cost Manual require the use of a specified time peri od 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 amortizati on 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 befo re controls are put in place can be rolled into the first year, as suggested in EPA’s OAQPS Co ntrol Cost Manual.” Although this passage is again focused on the remaining usef ul life, the text we reproduce is a reference to the basic Control Cost Manual cost methodology—the overnigh t 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. A lthough the Control Cost Manual does not use the term, overnight cost,” it is widely used in industry.

The U. S. Energy Information Administrati on (EIA) defines “overnight cost” as “an estimate of the cost at which a plant could be co nstructed 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 fr ont to completely pay for a construction project. 16

The Control Cost Manual does, however, use th e 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. Si nce different controls have different expected useful lives and will result in different cash flows, the first step in comparing alternatives is to normalize thei r 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 curre nt 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 sa me (generally year zero of the project), employing an appropriate interest (disc ount) rate and then add them together.

OG&E, on the other hand, states that cost e ffectiveness 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.

9commissions, 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, co st effectiveness is a relative determination, based on comparing the cost of a project wi th the cost borne by other similar projects. 18 If costs are outside of the range at other similar facilities , the control can be rej ected as not being cost effective. This comparison requires the cost effec tiveness 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, mixe d 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 e ffective 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 compar ison, 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 facil ities costed using the overnight method.

Finally, as to the 2008 cost analysis, we ba sed our determination a bout 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 revi sions cited by OG&E, including the use of vendor quotes. Regardless, both analyses contai n many of the same fundamental methodological flaws, such as including escalation and A llowance for Funds Used During Construction (AFUDC). These 2008 costs are not valid under the overnight costing method. The cost of

scrubbers would not be substantia lly higher than those reported for other similar projects if OG&E had used the costing method and basis, i.e., overnight costs in curr ent 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 Cont rol Cost Manual allows deviations from the standard approach for FGD (flue gas desulfuri zation). 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 excl ude 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.”

10continues OG&E, the Control Cost Manual states th at “the user has to be able to exercise ‘engineering judgment’ on those occasions when th e procedures may need to be modified or disregarded;” and that “the application of an a ppropriate [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 fo r the FGD technology when the Control Cost Manual is explicit in providing co st information for other technologies, it is reasonable to incorporate site specific design a nd conditions in the cost calcula tion 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 estimat e. OG&E concludes the level of detail is more than is required by our Control Co st Manual and departs from its default factors to identify the true site-specific costs, but it still follo ws the Control Cost Manual’s methodologies.

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

Control Cost Manual. The Control Cost Manual c ontains two types of information: (1) a generic costing methodology and (2) study le vel capital cost estimates fo r certain general types of pollution control equipment. The Cost Ma nual does not include st udy level capital cost estimates for any type of SO 2 scrubbing. This means scrubber capital costs must be based on site-specific vendor quotes or ot her 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 scr ubbers in the Control Cost Manual does not mean that the standard costing methodology, i. e., the overnight cost ing approach, can be disregarded. See the previous response to comm ents on the overnight cost method versus the all in cost method. The overnight costing methodolo gy 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 co sting methodology to the overni ght methodology but does offer alternative study-level cost estimating methods.

In evaluating cost effectiveness, it is importa nt 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 a nd improve consistency, cost estimates should be based on the OAQPS Cost Contro l Manual, where possible." 19 OG&E used vendor estimates for equipment costs but did not follow the gene ric costing method, i.e., the overnight method.

This comment also suggests that "engin eering judgment" can be substituted for the procedures stipulated in the C ontrol Cost Manual "when the proce dures may need to be modified or disregarded and that "the application of an appropriate [indirect capita l cost] factor requires the subjective application of the analyst's best judgment." Th ese arguments are taken out of

context.

19 70 FR 39166 (July 6, 2005).

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

the Control Cost Manual is made with reference to th e use of study level capital cost estimating procedures, not the general overnight costing methodology. The second citation, to the statement "the application of an appropria te [indirect capital cost] factor requires the subjective application of the analyst's best judgment," refers to co st estimating factors fo r freight, sales tax, and instrumentation, not to the gene ral overnight co sting 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 th e 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, re placement of major com ponents, and any other

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

OG&E states that the May 2008 BART Evalua tions 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 specifi c 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 D ecember 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 arrangeme nt 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 scopi ng-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-l evel estimate with a nominal accuracy of ±30%. The Control Cost Manual, c ites 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 prepar e the December 2009 Budget Cost Estimates provides more detailed and robust estimates of th e capital costs associat ed with installing the DFGD and baghouse control syst ems on a large subbituminous co al-fired boiler and more specific estimates of the actual costs that OG&E w ould incur to install these control systems at the Sooner and Muskogee Stations.

Therefore, concludes OG&E, the Control Cost Manual is not the ex clusive or primary source of costs when there is better source-speci fic 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.

12Response: The May 2008 study level BART cost estimate and the December 2009 budget cost estimate do not follow the cost methodol ogy in the Control Cost Manual. These two

cost estimates are based on the al l-in costing approach and thus deviate from the Control Cost Manual which is based on the overnight cost appro ach, as discussed elsewhere in our response to

comments. Both the 2008 and 2009 cost estimat es contain many of the same methodological flaws including, for example, excessive conti ngencies, 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 sc rubbing at Sooner and Muskogee, compared to

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

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

estimates for certain additional costs. We s upport the use of vendor quotes and site specific estimates but only as used with in the parameters of the overn ight cost methodology. However, the Guidelines, cited in this co mment, are clear that "[y]ou s hould include documentation for any additional information you used for the cost ca lculations, 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 s upport deviations from the Control Cost Manual, were not provided to us. For inst ance, although OG&E provided two spreadsheets that listed their cost line items, these spreadsheets, each over 600 lines in le ngth (and including line items such as seeding and fertilizing the grass at the plant sites), we re stripped of all cell calculations, preventing any meani ngful 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, a nd by annualizing the capital costs using an overstated capital recovery factor. OG&E states that the constant dollar appr oach described in the Control Cost Manual only require s the analyst to establish a baseline year from which total annual costs can be equalized (in constant dolla rs) over the life of th e control system. The Control Cost Manual, claims OG&E, does not dict ate 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 construc tion 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 co sts to 2014 and 2015 dollars. OG&E states that annual O&M and auxiliary power costs in 2009 dolla rs were also escalated to the respective baseline years. From those ba seline years, explain OG&E, th e O&M and auxiliary power costs were calculated using the constant dollar appr oach over the operating life of the control

20 70 FR 39166, footnote 15.

13equipment. Inflation was removed from the di scount rate and from the O&M and auxiliary power costs with respect to th e 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 Ma nual, 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 sta nding practice, articulated in the Control Cost Manual, of reporting

cost effectiveness values in current dollars. 21 The Control Cost Ma nual 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 oper ation 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, es calation of current dollar s 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 ot her 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 fo r 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 possibl e 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 pr oject of interest. This is done to assure an apples to apples comparison. It would be inap propriate to compare a co st effectiveness value reported in future dollars with a range reported in histor ic dollars.

OG&E estimated cost effectiveness valu es 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 pe r 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 conclu ding 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 contro ls 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.

141990, 2009, 2015, 2050, or any other year—so long as all th e costs are in the same year’s dollars.

Since historical data ar e 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 rath er than some hypothetical future year. We made the comparison in 2009 dollars in our propos al 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 determina tion based on current dollars that requires the application of a consistent methodol ogy 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, be cause they were compared to costs from 2000 to 2009, rather than from 2014 or 2015.

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

not evidence that future escalation should be ex cluded. We disagree. The Cost Manual states that "[t]his [referring to excludi ng inflation] is the preferred way to approach this kind of analysis, since it relies on the most accurate in formation available (curre nt prices) and does not try to extrapolate those prices into the future ." This is the overni ght approach described elsewhere. This statement is not specific to the example cited in Table 2.6, but rather is our standard practice in performing re gulatory cost analysis under th e Cost Manual approach. This method is based on current prices and real do llars without any infla tion. Escalating vendor quotes in current dollars to future operating dates and comparing th e cost with the cost in historic dollars is inappropriate. Overni ght costs in current dollars sh ould 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 th e Kaplan report, published in co llaboration with major utility companies. Third, OG&E states that the two ex amples we cited as evidence that AFUDC should

be excluded were for controls with a short c onstruction periods, SNCR and SCR, where AFUDC would not apply. They feel the zero adjustment is not appropri ate for a FGD because of its long construction period of 42 months. Moreover, th ey state, we have allowed AFUDC costs in

several coal-fired BART determinations and AF UDC is included as a line item in EPA’s CUECost worksheets for FGD control systems. Consequently, conclude s OG&E, we improperly disallowed the AFUDC costs on the grounds th at 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

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

First, the comment states that the Control Cost Manual includes "all" costs required to purchase and install a co ntrol system, citing to Section 2.3.1 of the Manual, Elements of Total Capital Investment, and stating that AFUDC is one of these co sts. 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 diag rams the "elements of total cap ital investment," does not list

AFUDC. AFUDC costs are not included because the Control Cost Manual costing methodology is based on overnight cost as explained pr eviously in our response to comments.

AFUDC is the cost of capital that is incurred to finance th e project during the construction period. The overnight cost method is th e 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 Manua l overnight cost approach. Ne ither 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, base d 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. Neve rtheless, 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 Contro l Cost Manual anticipa tes the inclusion of AFUDC by including "working capita l," which is underlined. Wh ile 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, chem ical, labor and maintenanc e 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’ mate rials, supplies and the cash needed to pay wages before the fac ility 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 allowa nce 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 in clusion 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 co st estimates ... include a line item for AFUDC, but zero out AFUDC for the example.”

OG&E suggests that the zero AF UDC in these tables may be due to the fact that these technologies have shorter constr uction 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.

16than do FGD systems (42 months and 12%, acc ording to OG&E), and thus are not worth considering. However, in estimating the cost s 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 adde rs and a 2% adder. Further, as AFUDC accounts for the cost of capital to finance a pr oject during the construc tion period, there would always be a finite financing ch arge for any length of construc tion. 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 Cont rol Cost Manual reference to S CR 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 a nd engineering costs

such as construction and cont ractor fees, preproduction costs such as startup and testing, inventory capital a nd any process and project contingency costs. As explained in the Manual Section 1 Intr oduction, average values of indirect installation factors are applied to the direct capital cost estimate to obtain values

for indirect installation costs. These co sts are estimated as a percentage of the TCI. The equations for indirect insta llation costs are pres ented in Table 2.5. 28

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

that are set to zero in the tabl e (including AFUDC) ar e not included in the text. Contrary to OG&E’s assertion, the Control Cost Manual doe s not describe Table 2.5 as a “simplified example” with AFUDC “zeroed out for the exam ple.” Table 2.5 presen ts the” equations for indirect installation costs,” includi ng the “average values of indire ct installation factors” to be “applied to the direct capital cost estimate to obtai n values for indirect in stallation costs.” The

discussion of Table 1.4 is essentia lly the same as for Table 2.5.

The Control Cost Manual also defines and e numerates indirect cost s 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 co nstruction supervisory personnel, office personnel, rental of temporary offices, et c.); 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.

17scope of indirect costs at least eleven times (S ection 1, p. 2-5 and Figure 2.2; Section 2, Table 3- 14; Section 3.2, p. 1-27 and Table 2.8; Secti on 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 "I n cases where the time value of money during the construction period would be significant (e.g., projects with longer construction periods such as th e installation of DFGD), the Cont rol Cost Manual clearly allows inclusion of AFUDC" (OG&E, E x. 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 re port 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 repor ts are included in the referen ces 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 Chap ter 2 that specifically cite to these two reports and tie them to any narrative; the narrative do es not provide any information on how these two reports are to be used in a regul atory cost analysis; and there is nothing to tie them to AFUDC. As they cover a wide range of topics, there is no basis for co ncluding that listing them in the references supports any specific fact in the Control Cost Manual.

Second, the Shattuck report is the founda tion for the CUECost model and some of the costing algorithms for specific control methods , but not for the gene ral overnight costing methodology used in the Control Cost Manual. CU ECost 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 fo llow the overnight cost methodology prescribed by the Control Cost Manual.

Third, OG&E explains that the all-in costing approach is r ecognized in publications by other agencies (EIA, EPRI). As noted, AFUDC is valid cost unde r the all-in method, and all-in method is a valid approach in other settings. Ot her 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 th at "the EPA clearly followed th is approach in its studies

of retrofit costs of SO 2 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 comment s, the RHR states the Control Cost Manual should be followed where possible, and the C ontrol Cost Manual uses overnight costing

18methodology.

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 accura te information available (current prices) and does not try to extrapolate those prices into the future." 29

Comment: OG&E states that we im properly set OG&E’s bond costs to zero in the capital cost estimate on the premise that bond costs are sim ilar to AFUDC costs in that they are transfer payments and not allowed under the constant dolla r approach in EPA’s Control Cost Manual.

The comment states that bond costs are distinct from AFUDC costs a nd should not be set to zero. They claim AFUCD costs are tang ible expenses paid to a bond underwriter for actual services associated with financing a large capital project and thus should be incl uded in the total capital expenditure. OG&E states Bond costs are an i ndirect tangible cost pa id 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 a nd 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 th e interest rate Sargen t & Lundy uses in its computations (6.03% nominal) includes those cost s. Neither the S&L Fo llowUp Report nor the Comments provide any derivati on or source for the assumed bond cost interest rate.

In most cases, the issuer of corporate debt does not pay the underwrite rs directly for their service, but instead sells the bonds to the underwriters at a disc ount. 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, ra ther 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 pert ain to the cost of de bt, the scrubbers may be financed in part with Polluti on Control Bonds, at very low tax-ex empt 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 reject ed the range estimating process used by them that provides a better estim ate of an appropriate project c ontingency (14%). They state our 3% estimate used in our revised cost analys is is arbitrary, not supported by the Control Cost Manual, and ignores site-specific information. OG&E states a larger co ntingency 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.

19needed if the project is not well-defined and/or if a high level of conf idence 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 co mmonly used technique to determine the level of contingency needed in a cost estimate to achieve the desired level of c onfidence. In addition,

OG&E states our Control Cost Manual does not specify any particular methodology for estimating an appropriate level of contingency a nd allows both process and project contingencies in an estimate of the indirect capital costs.

Response: We disagree. Under the overnight co st 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 demoliti on, fabrication, and installation of the system. For example, a hundred year flood may postpone delive ry of materials, but their arri val at the job site is not a problem unique to a retrofit situation." 32

In contrast, OG&E urges a de finition of "contingency" ba sed on a different authority, Perry's Chemical Engineers' Handbook, which de fines 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, speci fically excludes from the definition of contingency: “A contingency factor should be re served (and applied to) only those items that could incur a reasonable but unanticipated increa se but are not directly related to the demolition, fabrication, and installation of the system.” 33 In contrast, OG&E appl ies a 14% contingency to all project costs, including demolition, fabrication, a nd 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, co mpared 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 si milar to the proposed controls —a wet scrubber for acid gases (similar to the spray dryer absorb er) 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 c ontingency than our 3% is sp ecified 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 continge ncy 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.

20contingencies would be "signifi cantly higher" than estimated us ing 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% contingenc y 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 co sts are based on current prices.

The comment also states the range estima ting process used to determine contingency provides a more detailed estimate of contingenc y. However, the underlying calculations, cost probabilities, and Monte Carlo analysis 38 are not supported in th e record, preventing any meaningful review of this claim.

Finally, we note that the cost estimat es prepared by Trinity for the AEP/PSO Northwestern plant, nearly id entical 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% conti ngency factor, more than four times greater than the contingency allowance of 0.7% (line it em 41 divided by line item 32) used as the basis for the estimates in Appendix 2.

Comment: OG&E states that crew wage rates di d not include contr actor's general and administrative expenses and profit, otherwise kn own as Balance of Plant (BOP) profits. Thus, states OG&E, contractor profit wa s included as a separate line ite m, and therefore we improperly rejected it from the capital cost estimate on the pr emise that profits are embedded in labor rates, supplies, and materials.

Response: . The commenter misunderstood our a pproach. This does not require any modification to our cost analysis as we did not make any adjust ments 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 Con tingency Determination Using Range Estimating, Available at: http://www.wsdot.wa.gov/NR/rdonlyres/BAB31979-0B6F-4AB7-841E-5666289A8021/0/RangeEstimating.pdf.

21included a man-hour estimate and a crew wage rate for the installation of each major piece of equipment. OG&E states it based nonunion cr aft labor rates were developed from the publication “Merit Shop Wage a nd Benefit Survey,” published by Personnel Administration, Inc. (PAS), for Region 6, which includes average J ourneyman 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 unemploym ent insurance, and all applicable taxes. The resulting burdened craft rates, states OG&E, were used to develop crew ra tes 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 constructi on project. OG&E states it would be incorre ct and inaccurate to arbitrarily remove these additional cost s from the Labor Rate calculation.

Response: In our proposal, we noted that the labo r rates used in OG&E’s cost estimates ($40/hr – $80/hr) were excessive for an open sh op 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 a ccess to the electronic sp readsheets containing the respective calcula tions and Sargent & Lundy provi ded 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 unemp loyment insurance, all applicable taxes, construction equipment, site overheads, small t ools, and jobsite consumables and incidentals. OG&E further explains that thes e “crew rates” more accurately re flect the labor costs associated with a large construction project than “craft rates”. In its co mments, 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 unempl oyment insurance, and all applicable taxes. (OG&E comments, p. 24).” The resulting costs ar e 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 ar e not the source of the discrepancy.

The wages from the Bureau of Labor St atistics and FMI Management Consulting

references we cited in the TSD include fri nge benefits, including employer-provided or employer-paid housing, group insurance (health, dental , life etc.), disability income protection, retirement benefits, daycare, tuition reimburseme nt, sick leave, vacation (paid and non-paid), social security, profit shari ng, funding of education, and ot her specialized benefits.

Further, FICA and unemployment insura nce amount to only about 7.5% of OG&E’s payroll 40 . OG&E does not report workmen’s compensati on 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 fri nge benefits and FICA, workmen’s compensation, federal and state unemployment insura nce, and all applicable taxes.

39 Technical Support Document for the Oklahoma Re gional Haze State Implemen tation Plan and Federal Implementation Plan, March 2011, Appendix C, pages.15-18.

40 OG&E FERC Form 1, page 264.

22The 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 repor ted 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 calcula ted at $100 per hour. GCELC [Gulf Coast Environmental Labor Coalition] notes for the record that the current prevai ling wage rate for the local pipefitters union in Oklahoma is $40.80 per hour." 41

Prevailing wages is a term used in a legisla tive 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 in clude employee's taxes, employee's portion of FICA and Social Security but exclude benefits. Fe deral law requires all em ployers engaged in the performance of federal contracts to pay "prevaili ng" wages to their workers. This ensures that nonunion employers cannot gain an unfair biddi ng advantage by paying wages far below the union rate and passing the savings on to the governm ent 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 a nd 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 la bor rates and publicly available information cannot be explained by FICA, workmen’s co mpensation, federal and state unemployment insurance, and all applicable ta xes, which adds only about 10% to the base rate. Rather, it appears that other costs have b een added to the labor rates.

This comment explains that certain “additi onal allowances” were added to the burdened craft rates (wage + FICA, workme n’s compensation, federal and st ate unemployment insurance, and all applicable taxes), includ ing “construction equipment, site overheads, small tools, and jobsite consumables and incidentals.” The reco rd contains no support for these adders, which appear to have elevated craft labor rates far a bove 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, speci al tools and consumables" a nd "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 subj ect survey or excerpts there from supporting its choices. This survey is updated ye arly 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 it s labor rates and significantly overestimated

41 Comment received from Joseph M. Sant arella, Counsel for GCELC, May 20, 2011.

42 http://definitions.uslegal.com/p/prevailing-wages/

43 http://definitions.uslegal.com/p/prevailing-wages/

23them. However, we did not make any cha nges to OG&E's cost estimates based on this conclusion, but it is one of severa l factors that supports our opin ion 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 th at per diem is not being paid for by “open shop jobs in today’s soft labor market” is simila rly 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 constr uction 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 incorr ect, our proposed cost analysis did not adjust the OGE cost estimate downward based on excessive pe r diem expense. We did note a per diem expense of $10/hr was added to the already high labor rates for ev ery single hour (1,790,700 hours for Sooner and 1,854,271 hours for Muskogee) requi red to build the project. We further pointed out that per diem is not being paid for ope n shop jobs in today's soft labor market. This comment responds that per diem is required to at tract and retain a skilled labor force for major construction projects and is requir ed 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 wo rker 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 incorrec tly identified the construction man-hour adjustment used to account for labor productivity as anot her 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 inco rrectly deleted this co st 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 stat es that applying a factor to account for labor productivity is common practice on large constructi on projects, is specifically r ecognized in the Cost Control Manual, and is necessary to address regional differe nces 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 Internationa l publication. OG&E states it included an

additional 10% factor to account fo r the fact that the DFGD/FF c onstruction projects are back-fit projects that would require a si gnificant 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

2415% to account for “productivity”. 44 We discussed how this increase was unprecedented/inappropriate in a cost-effectivene ss 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 allowa nces 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 co mment for at least five reasons.

First, the OG&E does not define “labor pr oductivity.” 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 pr oductivity 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 th e underlying Sargent & Lundy cost analyses define the job-site cond itions reflected in the base labor rates or the job-site conditions at Sooner and Muskogee that would warrant a 15% increase. Furthe r, they provide no evidence that any of the citations refer to the same index of labor productiv ity. It is reasonable to assume that the vendors who quoted the erection man-hours/costs were awar e 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 vendo r specific information is available”). 48 This section of the Manual is summarizing a “CEMS Cost Model” that is used to es timate the cost of monitoring equipment, not pollution control eq uipment. The cited material does not relate to the Control Cost Manual methodology, but rather a methodology us ed 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 rate s) 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 Re gional Haze State Implemen tation 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.

25U.S. university libraries. Furthermore, there is evidence that some produc tivity adjustments are

considered to be unreliable. 49

Fourth, the comment discloses that an additional 10% was added to the 1.05 50 Compass

factor “to account for the f act that the OG&E DFGD/FF constr uction projects are back-fit projects that would require a sign ificant amount of work in tight site conditions.” The basis for this further adjustment is cite d 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 re sult in factor of 1.10, not 1.15. Regardless, a merit shop has not been propos ed 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 fact ors 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 co uld, for example, adjust it to Oklahoma by multiplying it by a factor of 1.05. The Sooner an d 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 de gree of difficulty, the re trofits at Sooner and Muskogee could be described as average.” 54 We are not aware of cost -effectiveness analyses of average retrofit difficulty that incr eased 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 factor s that are derived from empiri cal data for specific conditions and are necessary to adjust refe rence prices to local conditions . The Kaplan report cited in footnote 91 does not contain any “l abor productivity factors” incl uding regional cost factors and access/congestion factors. Further, based on this list, even if it did, none of these are “labor productivity factors,” the s ubject of this comment.

49 R. Brunies and Z. Emir, Calculating Loss of Productivity Due to Overtime Using Pub lished 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 ra tes taken from the S&L database.").

54 12/28/09 S&L FollowUp Report, pdf 6.

26Comment: 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 doubl e counting as a general continge ncy was included elsewhere in the cost analysis. OG&E states we incorrec tly assumed that the new scrubbers would be installed during normal maintenance outages by work ing five 10 hour days and that the efficient scheduling of the labor pool s hould not result in an overtime in efficiency. 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, nu merous 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 ho urs worked per week and assuming an overtime cost equal to 1.5 times the base pay rate. Theref ore, 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 Cont rol 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 th e labor pool should not re sult in an overtime inefficiency. 56 Therefore, there is no reason to pl an for inefficiency. The 12/28/09 S&L FollowUp Report contains no support for overtime inefficiency.

This comment explains that a 50-hour work w eek 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 productivit y. 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 cl aimed 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 th e 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 th at 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, Decembe r 2009, p. 316, is an incorrect cite. The report itself is also available at a cost. The cite in foot note 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.

27comment, 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 construc tion 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 site 59 and the Zachry Constructi on (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 pr ojects, would be more likely to offer 40 hours, compared to short-term shutdown or turnaround wo rk. Therefore, consid ering the large amount

of additional labor costs involved and the failu re of OG&E to demonstrate that a overtime inefficiency adjustment was necessary, we find th is 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 fi nancing 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 cost s are project specific and include costs incurred by the ow ner to manage the project, hire and retain staff to support the project, and costs associated w ith third party assistance associat ed 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 engineeri ng costs for limestone forced oxidation and lime spray dryer control systems.

Response : In our proposal, we stated 61 that owner's costs were double counted, i.e., they are included in two places, as a se parate line item of 5% of TCI and under indirect capital cost. This comment ignores our argument that they ar e double counted and instead argues that owners

costs are real costs and are include d in the CUECost model. We ag ree that owners costs are real, are part of the cost of buildi ng a scrubber, and thus are valid costs under the overnight costing method. However, here, they have been include d twice. The Sargent & Lundy cost analyses include owner's costs as a sepa rate indirect capital cost, estimated as 5% of total capital expended. The costs that owners incur are also included under "ind irect capital cost," which also includes engineering/procurement estimated at 6.5% of total direct costs and construction management, estimated as 2% of total direct cost s. These factored costs (which are not site specific, but rather based on gene ral factors) are high compared to costs that result when using the factors in the Control Cost Manual (both engineering and construc tion/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 Pub lished Charts -- Fact orFiction, 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 Over time 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 Re gional Haze State Implemen tation Plan and Federal Implementation Plan, March 2011, Appendix C, page 19.

28for engineering, procurement, and construction ma nagement. The Control Cost Manual does not provide that Owner's costs are se parately 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-alon e cost model for BART determinations because it does not follow the overnight co st 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 cost s when estimated as a percent of the TCI as

these costs are included in indir ect installation costs. In its May 10, 2010 formal comments to the North Dakota Department of Health, for exam ple, EPA rejected the inclusion of "owner's costs" in a cost analysis for the Milton R. Young facility 63 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 a ssumption that “vendor proposals that Sargent & Lundy re lied on include the cost to both design and supply the dry scrubber and baghouse” is incorrect. Thus, ar gues OG&E, because they also separately calculated engineering/procurement, our assumpti on 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 engineer ing and procurement costs are included as part of the vendor equipment costs; however, th ere are significant engi neering and procurement costs associated with balance-of-plant (BOP) e quipment and integrating the control system into the existing facility. OG&E states major equi pment suppliers, includ ing those who supplied

estimates in connection with the December 2009 Budget Cost Estimates, fu rnish their equipment with no foundations or other suppor t structures and do not integrat e the control sy stems into the existing facility for functional operation. OG&E states the Engi neering/Procurement line item includes the costs for engineering and procuring all BOP equipment, including ID fans, dampers, expansion joints, pumps, air compressors, a nd electrical equipment (high voltage power transformers, switchgear, motor control centers). OG&E also states the Engineering/Procurement also includes the en gineering design and detailed drawings for buildings, support steel, foundations, ductwork, BO P piping, BOP compressed and instrument air systems, electrical design (i ncluding auxiliary power require ments, raceway, conduits, cabling, controls, and instrumentation), resolving interferences, and prepar ing a general work installation specification.

Response: OG&E estimated engineer ing and procurement as 6.5% of the total direct

62 See, e.g., Sargent & Lundy, Dry FGD and ID Fan & Aux iliary 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 Comme nts on the North Dakota Department of Health's April 2010 Draft BACT Determin ation for NOx for the Milton R. Young Station, May 10,

2010.

64 76 FR 58570.

29costs, 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 po rtion of these costs were double counted. The vendor proposals include the co st to both design and supply th e dry scrubbers and baghouses, which include the cost of engineering and procurement. Sargent & Lundy also separately calculated engineering/ procur ement costs on top of the vendo r-supplied portion of the capital

costs and thus double counted them. We applied Sargent & Lundy's 6.5% engineering/procurement factor only to the bala nce of plant materials and labor, excluding the scrubber system, fabric filter, a nd 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 f acility." 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 otherwis e included in the vendor quotes.

This comment additionally claims that th e major equipment suppliers, including those who provided the estimates for the Sooner and Muskogee scrubbers "fur nish 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 request s for quote sent to the vendors li sts foundations as the owner’s responsibility, it specific ally required that "all steel inte gral 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 S DA, baghouse and connecting ducts and detailed arrangement and erection drawi ngs. The vendor quotes also in cluded 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 elec trical equipment as well as engineering design and detailed drawings for buildings, suppor t steel, foundations, ductwork, BOP piping, BOP compressed and instrument air systems, electrica l design, resolving interferences, and preparing a general work installation specification." We agr ee these are valid costs, but some of them were included in the vendor quotes, such as suppor t 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 th e 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 orig inal revision remains appropriate.

Comment: OG&E states we incorrectly attribut ed double counting to BOP construction

65 12/28/09 S&L FollowUp Report, pdf 40, 56.

30management costs in two places in their Cost Esti mate: 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 expl ains that BOP contractor’s general and administrative (“G&A”) costs and th e 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 a pplicable taxes, but do not include contractor G&A expenses or profit. Theref ore, 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 co sts. This comment expl ains 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, di fferent from the BOP contractor and different from the owner. Based on this explanation, we have restored the constr uction management costs in our revised Options 1 and 2 cost estimates in Exhibits 1 and 2.

Comment: OG&E states we incorrectly attribut e 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 li ne item for startup and commissioning resulted in double counting.

OG&E states that equipment suppliers, in cluding 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 th e general work contract or (as opposed to the equipment suppliers) during the dur ation of start-up and commissioning (which can take several months). OG&E states that project schedules de veloped for the Sooner and Muskogee DFGD projects included a five-month startup/commissioning duration for th e first unit and an additional five-months for the second unit, but not at the sa me time. OG&E asserts that the 10 months of craft support will require extended mobilization, supervision, and la bor costs to help the owner during the startup/commissioning period. OG&E conc ludes 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 commissi oning; thus, there is no double counting, and it

is incorrect and inaccurate for us to excl ude 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 thos e 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.

31This comment states that equipment supplie rs provide very limited field support during control system startup and commissioning and th at the Start-up and Co mmissioning line item accounts for "the craft support required by the general work contract or (as opposed to the equipment suppliers) during the dur ation of start-up and commissioning (which can take several months). This comment also stat es that this support will requ ire 10 months of craft support for extended mobilization, supervision, and labor co sts. However, one of the vendor quotes specifically states that their sc ope of supply is to "design, supp ly and commission" the SDA/FF system. Another vendor states in a section captioned Site Servic e: "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 requi red in their comment to EPA’s proposal. 67 Therefore, it appears that OG&E overstate d 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 adjustmentin our Options 1 and 2 cost estimate in Exhibits 1 and 2 are required.

Comment: OG&E states that we incorrectly a ssumed 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 ite m for operating training

and manuals is not double c ounting. OG&E states that o perator training costs are not generally included in budgetary proposals received from eq uipment vendors and were not included in the proposals received in connection with the Decem ber 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 ap plications 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, a nd it is incorrect to

exclude these costs from the cost estimate.

Response: OG&E estimated operator training and ma nuals, an indirect cost, as 0.55% of the total construction & erection cost portion of to tal 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 budgeta ry 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.

32include operating manuals. It is standard practice to include the cost of an operating manual with the cost of an expensive piece of complex pollu tion control equipment, such as the subject

SDA/FF. The basic manual is the same for a ll similar models of an SDA/FF; only minor modifications are required to tailo r a manual to a site specific app lication. 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 EP A for fabric filters and SDA FGD 69 do not separately breakout commissioning, personnel training or manuals. Th ese costs are imbedded in the costs of the controls, which calculated under the Sargent & L undy 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 manua l costs remains appropriate.

Comment: OG&E states that under the Contro l Cost Manual met hodology, total capital costs are annualized by calculating an annual paymen t sufficient to finance the investment over its entire life. OG&E asserts we incorrectly f ound they did not follow the Control Cost Manual when they calculated the annual capital recove ry 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 Manua l dictate using a 7% soci al 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 pr obably not appropriate for industr y." OG&E goes on to claim that "[b]ecause OG&E is an investor-owned utility company and not a gove rnmental agency, the Control Cost Manual suggests that it use an a ppropriate 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 a nnual 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 recove ry of principal but also a return on the principal, with the rate of return equal to the discount rate. OG&E assert s that for an investor owned utility such as OG&E, which is financed by a mix of debt and equit y, 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 investo r-owned utility companies such as OG&E. OG&E states that a more complete derivation of the a nnual 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

33separate steps. First, the TCI is determined ba sed 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 opera ting 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 . . . understa nd 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 calcul ation of control costs. Common interest rates used by industry and accepted by th e EPA for source petitions include the business’ current borrowing rate, the cu rrent prime rate, and other acceptable

industrial rates of return.

Only debt is specifically listed in the allowe d carrying costs. "Indus trial rates of return" might include the utility's debt a nd 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 cap ital 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 doe s not offer any cost effectiveness values for

other similar facilities calculated in the same wa y as it proposes in Table B-5, including taxes. Thus, for comparability with other cost-effectiv eness computations and consistency with the Control Cost Manual, income taxes must be excl uded from the levelized cap ital recovery factor, along with AFUDC and inflation to arbitrary years (discussed el sewhere in our response to comments).

OG&E states that the nominal return on equ ity of 10.75%, the "levelized capital recovery factor (LCRF)," used to annualize total capital investment, was cal culated 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 disc ount 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 lif e into the CRF formula in Eq. 2.8a of the Manual yields a CRF of 8.72%, rather than the L CRF of 10.36% used by OG& E. The 7% social discount rate would yield a 9.44% CRF. Thus, th e site-specific calculation for the OG&E units, using its method, corrected to exclude taxes, yiel ds a lower CRF than the default values of 7%

70 Chapter 2, p. 2-9.

34that 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 effectivene ss 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 in terest rate as included in the levelized cost recovery factor in th e 12/28/09 S&L FollowUp Report, Table B-5, is incorrect and

overstated.

OG&E makes two serious errors in its developm ent of the levelized co st 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 amortiz ation of “atmospheric pollution control facilities” acquired and placed in service after April 11, 2005, in connection with an electric generation plant or other pr operty placed in operati on 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 w ould generate large defe rred taxes, starting

with 14.3% – 5% = 9.3% X 38% tax rate = 3.5% of the original pl ant investment at the end of year one, and 24.8% of the origin al investment (about 37% of th e 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 benef its. Including the seven-year tax depreciation

schedule would reduce OG&E’s estimate of th e carrying charge by about 1.3%, to 9.1%.

Second, OG&E uses a mixture of real and nom inal rates in Table B-5. The debt rate appears to be expressed in real terms, but the eq uity return is expresse d 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 disc ount of 5.43% (see OG&E comm ents, Exhibit B, p. 32), producing a much higher cost than if it had discou nted 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 le velized at the real di scount rate, the result would be a levelized carrying charge of 9.35% , a full point lower th an their estimate.

Combining these corrections, results in a le velized 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 leve lizing in real terms, w ould 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.

35the 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 sometime s appropriate, and thus actual age of existing scrubbers is not the appropriate meas ure. OG&E further state that our examples of other facilities use of a 30 year lifetime is not appropriate, is not suppor ted by the Control Cost Manual, and have not been demonstrated to be operational for the full 30 years.

AEP/PSO states that the capital r ecovery charges we employ in our SO 2 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 fr om 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 la te 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 ove r 30 years old and then retrofit with FGD systems, and operated for an additional 30 years. AE P/PSO states the operating lives of electric generating units are highly variable, and the 20-year re maining life of the Northeastern units was based on a realistic assessment of the units’ operati ng characteristics and economic value. AEP/PSO states we presented no basis why 30 years might be more appropriate than 20 year s (for example: EPA guidance, ODEQ experience, BART guidelines, etc.).

In other comments, AEP/PSO takes issu e with our statements in the TSD 73 :

Scrubber vendors indicate that the life time 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 Un it 3,48 Cholla 5, Basin Electric, Mitchell Unit 33). Standard cost estimating handbooks 74 and published

papers 75 report 30 years as a typical life for a scrubber.

Further, many utilities routinely specif y 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 analys is without comment. The BART determination for Big Stone Unit 1, on-line in 1974, assumed a 30 years scrubber life. Thus, I used 30 year s in my revised cost estimates.

AEP/PSO states these statements lack support.

Response: In the section of the Control Cost Ma nual on the capital recovery factor, the subject of this comment, control equipment lifetim e is clearly defined as the entire life of the control. For example, on page 2-19, the Contro l Cost Manual states: “For each alternative: calculate a discounting f actor 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.

36essence, annualization involve s establishing an an nual "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 tota l capital investment is thus the ac tual 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 serv ice 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 polluti on control device (NPV analysis), what if the payment could be equa lized (in constant net present value dollars) over the

life of the control ?” 78 Thus, under the Control Manual defi nition, 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 lif e of the scrubber is "arbitrary." We disagree. We supported our estimate. First, we noted that scrubber vendors

indicate that the lifetime of a sc rubber is equal to the lifetime of the boiler, which might easily be well over 60 years. Second, we identified sp ecific scrubbers installed between 1975 and 1985 that are still in operation today. 79 Third, we cited to sta ndard cost estimating handbooks 80 and published papers 81 that report 30 years as a typical life for a scrubbe r. Fifth, we noted that Sargent & Lundy's 2008 cost estimate assumed a 25 y ear lifetime, but lowered it to 20 years in the revised 2009 analysis without explanation. Si xth, 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 Sarg ent & Lundy in its comments in a number of places for the truth of various matters (e.g., inclusion of AFUDC at 21, cost of auxili ary power at 35), reported the "book life" of scrubbers as 30 year s and the "tax life" as 20 years. 82 Further, we have assumed a 30-year lifetime for scrubbe rs 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 Spra y Dryer Absorber Material: Production, Characterization, Utilization Appli cations, 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 Pl ants, 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

37In quoting the Control Cost Manual, OG&E asse rts 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 installe d.” We agree. The subject applica tion, the use of a scrubber to remove

SO 2 from low sulfur coal, is a mild environm ent for a scrubber, compared to high sulfur applications, which have alrea dy demonstrated 30 year lifetimes. The corrosion potential and bag plugging issues in a low sulf ur application are much lower th an in a comparable high sulfur application. 84

OG&E also asserts that the Control Cost Ma nual 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 ye ars being typical," citing to a 1980 report. 85 Significant

advances have been made in the material of construction and ba ghouse design since this publication. 86 Further, the 1981 EPA/TVA report cite d above, "Technical Review of Dry FGD Systems and Economic Evaluation of Spray Dr yer FGD System" assumes a 30 year economic and tax life for an SDA/FF, which includes the fabr ic 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 fe deral regulations. In so doing, we make a well reasoned determination, documenting our analysis as appropriate.

In response to questions from us, OG&E atte mpted 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 serv ice 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 assumpti on 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, sugges ting 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 Res ource Plan projects the installation of FGD at Northeastern in 2016 and the addition of carbon cap ture at Northeastern Unit 3 in 2030, implying

efSeekPage=x&SearchBack=ZyActionL&Back=ZyActi onS&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., In tegrated Resource Plan , Redacted, May 2011, Appx. D, p. 9.

89 Oklahoma Gas & Electric Co., Integrated Re source Plan, Redacted, May 2011, p. 37

38they 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. Accord ing 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 cost s. OG&E states we incorrectly stated that S&L overestimated the amount of lime necessary for the 80% SO 2 removal case because the cost

estimate was based on a stoichiometric ra tio of 1.5 moles of calcium/mole of SO 2 entering the system rather than using the “rule of thumb” va lue of 1.2. They state th e stoichiometry required for a specific application is a f unction of several design parameters including, but not limited to, the spray-down temperature (i.e., the differen ce between the spray dr yer inlet and outlet temperatures), the approach to the adiabatic sa turation temperature in the scrubbing vessel, and the degree of recycle possible with in the physical limits of the c ontrol system. OG&E states for the OG&E dry scrubbers it was determined, base d on the unit-specific design parameters and unit-specific SO 2 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-specifi c nature of the December 2009 Budget Cost

Estimates.

Response: We disagree with this comment. We did not recalc ulate 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 th is 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 a ny 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.".

39Rather, as we explained in the TSD, Appe ndix 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 revi sed our Option 2 lime costs to us e OG&E’s average sulfur case and stoichiometric ratio, adjust ed accordingly to use a baseline capacity factor of 78.5%, as we discuss in response to another comment.

Further, OG&E estimated lime costs ba sed on $118.50 per ton at Sooner and $105.53 at Muskogee. 92 In its response in Section 4.2.6, Vari able Operating and Maintenance (O&M) Costs, OG&E indicates that it applied an inflation ra te to its auxiliary power cost to adjust it to the anticipated year of startup of the controls. It appears th at OG&E has escalated other O&M costs to the anticipated year of startup (2014, 2015). As we st ate in our response to other comments, this does not comport with the C ontrol Cost Manual’s methodology of calculating costs on the basis of the overnight met hod, 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 Sarg ent & Lundy also escalated its lime costs to the year of startup. As inflation to future years is not al lowed in the overnight co sting 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 cost s are overestimated as they are based on a lime stoichiometric ratio higher than assumed in the site-specific ve ndor 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 ga llons/MMBtu heat input was beyond the upper end of the range of 3.6 to 4.4 gal./MMBtu for othe r similar dry scrubbers. They state the water consumption in a DFGD control system is calcula ted based on the amount of water needed to cool the flue gas from the spray dryer inlet temp erature to the spray drye r outlet temperature (the spray-down temperature); thus, water consumpti on 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

40will 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-sa turation 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 para meters, 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 adju st the water consumption

rate based on a "rule of thumb" estimate. Rath er, we used the site-spe cific water consumption rate quoted by a vendor for the subject units. 96

The typical range of water consumption rate s was mentioned to confirm that the vendor's quote fell within the usual range for similar installations. This typical rang e also confirms that OG&E’s stated water consumption ra te 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 consumpti on 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 wa ste generated in the FGD (based on the higher inlet SO 2 loading rate). OG&E also states we were wrong to stat e the unit cost to dispose of the FGD solids was high compared to other similar BART cost analys es. OG&E states we incorrectly calculated the quantity of FGD waste generated based on an in let 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 SO 2 removed from the flue gas were calculated based on the average

SO 2 loading to the scrubber. This approach, acco rding to OG&E, provides a consistent basis for estimating capital costs, O&M costs, and SO 2 removal. In OG&E’s opinion, revising the

variable O&M costs based on the maximum inlet SO 2 loading rather than average SO 2 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 aver age sulfur case should be us ed to estimate O&M cost for Option 2 based on OG&E's explanation elsewher e in its comments. Because, as explained elsewhere in our response to comments, we continue to increase the SO 2 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, th at these revised costs likely remain high.

96 Technical Support Document for the Oklahoma Re gional Haze State Implemen tation 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.

41First, OG&E assumes the unit disposal co st 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, Va riable Operating a nd Maintenance (O&M) Costs, OG&E indicates that it esca lated auxiliary power cost to the anticipated year of startup of the controls. It appears that OG&E has likewis e escalated other O&M costs to the anticipated year of startup (2014, 2015), thus overestimati ng 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 S ooner 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 si gnificantly overestimated. Fina lly, as we noted previously, 100 in some cases FGD wastes can be reused, thus redu cing 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 pr oduce electricity.” OG&E states we mixed terminology by equating busbar costs to energy charge s. Further, they cl aim our price quotations completely ignore the summer on-peak period, wh ich has significantly higher rates. OG&E notes that by definition, busbar co sts are the all-in cost to pro duce 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 va riable 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 insta lled net plant capacity, which is a lost value to OG&E, as may be measured by the $/kW cost of base load re placement capacity, or the $/kW cost of required capacity reserve margins. OG&E states they used average year-round ma rket 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 co sts. OG&E cites to a previously cited report by the EPA, Air and Energy Engineering Rese arch 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%/yea r, this would be equivalent to a value of $95/MWh (2014 $) and $97/MWh (2015 $). OG&E c oncludes 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 Re gional Haze State Implemen tation 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.

42justified as this study accounted for both ener gy and capacity, as did OG&E in its December 2009 Budget Cost Estimates.

Response: OG&E states that the cost of pow er used in the S&L December 2009 cost analysis is the average year-round ma rket retail rates including infla tion 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 genera tion-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 De partment 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 pow er 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 stat es that “S&L used average year-round market re tail rates of $85.93/MWh (2015$) for Sooner and $83.83/MWh (2014$) for Muskogee as the best long-run meas ure 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 exis t only at the w holesale level.

It appears that OG&E estimated the cost of wholesale replacement generation-only energy and capacity 102 at a 90% capacity factor 103 from the average retail rate (including transmission, distribution, meteri ng, 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 ot her non-generation charge s that should not be included in generation-only prices. Thus, the re tail price for generation-on ly service to replace

101 US 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., Integrat ed 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.

43lost 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 Daily 108 , the forward price for on- peak energy delivered to Entergy (which borders on OG&E, and is the closest hub with regul ar 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, a nd 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 la st twelve months, the monthly price ratio and the average ratio over the year. 109 Note that none of the mont hly prices, even the on-peak summer prices, are anywhere near the $85/MW h 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 av erage 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 ener gy 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 ÷ 1.02 5 = $35.8/MWh; 111 $41/MWh ÷ 1.02 6 = $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.

44power costs. As explained below, we assume capacity costs are zero as capacity costs are currently zero, are likely to remain zero for severa l 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 cap acity 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 pe aking capacity is likely to be minimal, since OG&E and th e SPP region are awash in capacity.

The cost of capacity would be zero un til 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 cost s: "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 requirem ent 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 additi on 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 re gion appears to be in surplus until at least 2030 or s o, 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 co sts, 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.

45While OG&E never fully explains how they de rived 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 SO 2 and NOx Control at 200 U.S. Coal-Fired Power Plants,” Pittsburgh Coal C onference, 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 th e 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 au xiliary 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 sc rubber 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 pl ant, 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 logi cal outgrowth of the comment we received, we have not revised our cost effec tiveness analysis to use $36/MWh. Instead, we retain the $50/MWh figure we proposed. We vi ew this, however, as evidence buttressing our position that OG&E’s scr ubber costs are high.

Comment: OG&E claims we selectively picked f actors from the Control Cost Manual, using default Control Cost Manual factors when they yielded lower results, but otherwise ignored them. OG&E states we di d not adjust the lower site-spe cific factors used for property taxes, insurance, and administrative charges in the December 2009 Budget Cost Estimates.

OG&E states that fixed O&M cost s are recurring annual costs that are generally independent of the plant capacity factor. According to OG&E, th ese 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 syst ems that are not part of the direct O&M, consisting of property taxes, insurance, and admi nistration. 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).

46specific numbers where they lower overall costs and “rule of thumb” num bers 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 feasib le, based on publicly available in formation. 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, accordi ng 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 thatvariable costs (as well as emission reductions) in their December 2009 Budget Cost Estimates were based on “Option 2” (i.e., reducing SO 2 emissions from an uncontrolled rate of 0.509 lb/MMBtu to a controlled rate of 0.10 lb/MMBtu), while the scrubber si zing and capital costs were ba sed on “Option 1” (i.e., reducing

SO 2 emissions from an uncontrolled rate of 1.176 lb/MMBtu to a cont rolled rate of 0.10 lb/MMBtu). OG&E states we incorrectly concluded that this mismatch results in underestimating

emission reductions and fi xed O&M costs, while overe stimating 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 2 009 Budget Cost Estimates. OG&E states capital costs were based on sizing the DFGD/FF control sy stems to handle the full load flue gas flow rate associated with firing subbituminous coal . OG&E states annual O&M costs, and annual SO 2 emission reductions, were calculated based on the average actual baseline SO 2 loading to the scrubber. This approach, claims OG&E, is cons istent 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/oklahom a/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).

47OG&E states that the cost estimates develope d for “Option 2” in the Fox Report and in Tables 5 and 6 of the proposed rule are invalid because this option is t echnically 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 Decembe r 2009 Budget Cost Estimates “assumed that the Sooner and Muskogee plants burn ed coal with a higher sulf ur content [1.172 lb/MMBtu

uncontrolled SO 2 emissions] than they are currently burning [0.51 lb/MMBtu uncontrolled SO 2 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 gros sly 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 cost s should be based on a scrubbe r designed to be capable of controlling the highest sulfur co al 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 sulf ur 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 sulf ur content. OG&E and their cons ultant state that the size of the reactant and ash handling syst ems cannot be designed for an av erage 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 fac ility. Sizing the reactan t 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, woul d be approximately one-half of all the coal

fired. OG&E states that desi gning the scrubber based on the aver age coal content could greatly limit fuel supply options.

Response: We disagree, as explained in our re sponses to these issues in the next comment. However, we address he re OG&E’s use of a coal that is not typically burned, as the basis for its scrubber designs. OG&E presents sulfur content da ta for coal delivered to the OG&E units during the previous fi ve years to support its coal sulfur design basis. The company's analysis calculates emission reductions based on aver age 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 wa s designed based on a maximum

sulfur content of 0.48%.

We obtained sulfur content data (fuel receipts data) re ported by OG&E to the Energy Information Agency (EIA) for the period Ja nuary 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: "2 010: EIA-923 Schedule 2, January - Decembe r, 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 (h ttp://www.eia.gov/cneaf/elect ricity/page/eia423.html). Accessed September 16, 2011.

482 for Muskogee. These figures show that sulf ur 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 reporte d to the EIA. In fact, only tw o data points over the six year period shown are greater than 0.40% for each facilit y. 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/eia4 23.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/ei a423.html). Accessed September 16, 2011.

2007 and earlier data is from: "2007: FERC-423, January - December, Excel Fo rmat." 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/ferc 423.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/fe rc423.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/fe rc423.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/fe rc423.html). Accessed September 16, 2011.

49Figure 1

Sooner Plant, OK, Average Sulfur Content Per Coal Fuel Receipt, Jan 2004 - Dec 2010

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50Jan-04Apr-04Aug-04Dec-04Apr-05Aug-05Dec-05Apr-06Aug-06Dec-06Apr-07Aug-07Dec-07Apr-08Aug-08Dec-08Apr-09Aug-09Nov-09Mar-10Jul-10Nov-10

MonthSulfur Content (% by weight)

Figure 2

Muskogee Plant, OK, Average Sulfur Content Per Coal Fuel Receipt, Jan 2004 - D

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 ec 2010Nov-09Mar-10Jul-10Nov-10Jan-04Apr-04Aug-04Dec-04Apr-05Aug-05Dec-05Apr-06Aug-06Dec-06Apr-07Aug-07Dec-07Apr-08Aug-08Dec-08Apr-09Aug-09

MonthSulfur Content (% by weight)

50The EIA data in these figures is also consis tent with sulfur cont ent data presented by OG&E in the initial, May 28, 2008 BART analys es, 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 SO 2 emission data reported by OG&E to CAMD, as re quired by the Acid Rain program.

The monthly average SO 2 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 averag e 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.

51Figure 4

Figure 5

52Figure 6

These plots demonstrate that the average m onthly fuel sulfur cont ent closely tracks the average monthly SO 2 emissions, confirming the conclusion fr om the EIA data in Figures 1 to 2

that coals burned ove r 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 st ates that the design basis fuel was developed based on the PRB coal fired at the st ation "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 SO 2 emissions are trending up over time. One potential strategy to reduce SO 2 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 fo r the control technology are cons istent 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 c ontent than they are currently burning. OG&E states we incorrect ly argued that this assumpti on led to OG&E costing a much bigger scrubber than is necessary for the co al currently being burne d, and resulted in a

“mismatch” between annual costs and emission re ductions. OG&E states we incorrectly scaled down the capital cost of the sc rubber by approximately 50% in our Option 2 approach. OG&E

53argues that there is no mismatch between the co st calculation and emission reductions. OG&E further argues that the Option 2 scrubber is undersized resulting in an ineff ective control system.

Response: We noted in the TSD that in perf orming its BART analysis, OG&E assumed that the Sooner and Muskogee plan ts burned coal with a higher sulfur content than currently

burned but the emission reductions used to calcul ate cost effectiveness were based on a lower

sulfur coal. The scrubbers were costed to remove 95% of the SO 2 from a coal containing 0.48% sulfur (1.176 lb SO 2 /MMBtu) while the boiler operated at 100% capacity. ODEQ calculated annual emissions assuming a 90% capacity fact or. In comparison, during the years that established the emission baseline, the units burne d coal containing an average of 0.51 lb/MMBtu

of SO 2 and operated only 78.5% of the time. This m eans 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 faci lities have historically operated, and (3) future emissions were over predicted compared to the f acilities’ past capacity. As we have stated previously, we do not in principl e 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. Ho wever, we do object to OG&E not considering these mismatches in their SO 2 BART cost analyses, as it does not comport with the requirements of the RHR.

This mismatch between the design of the scrubb er system and historical practices resulted

in an erroneous calculation that made SO 2 scrubbers appear less cost effective. Thus, we explored the range in co st effectiveness by both raising the hi storical emission baseline to match the potential reductions from the higher sulfur cont ent 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 bu rned (Option 2). 122 The following discussion separately addresses the baseline mismatch issu e, 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 secti on 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 effectiven ess are annualized dollars per ton of SO 2 ($/ton).

122 76 FR 16183, Tables 4 - 6.

123 70 FR 39129.

124 70 FR 39167.

54However, the OG&E cost effectiveness analys es contain two mismatches. The cost and emission reductions are mismatched, and componen ts of emission reductions — the baseline and

future controlled emissions — are mismatched. These mismatches contribute to OG&E’s

erroneous conclusion that scrubber s 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 SO 2 scrubber system that was desi gned to remove 95% of the SO 2 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 overdes igned and more expensive than necessary in order to treat the coal the company has histori cally burned. This eff ectively results in both increasing the numerator (annualized cost) a nd decreasing the denominator (tons of SO 2 removed) in the $/ton cost effectiveness, thus gr eatly increasing the result of this calculation and erroneously making SO 2 scrubbers appear to be much less cost effective, i.e., have a higher dollar per ton value due to dividing a hi gher cost by a lower emission reduction.

We have treated the problem of the errone ously high annualized co st elsewhere in our response to comments, and now turn to the problem of the erroneously low baseline SO 2 emissions. In calculating baseline emissions , the BART Guidelines assume the source in question is otherwise unchanged in the future, ex cept 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 s ource. In general, for the existing sources subject to BART, you will estimate the anticipated annual emissions based upon actual emissions fr om a baseline period. When you project that future operating parame ters (e.g., limited hours of operation or capacity utilization, type of fuel, ra w 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 em issions based upon continuation of past practice.

Clearly, the RHR assumes the ba seline 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. Inst ead, as discussed elsewhere in our response to comments, it employs substantially different operating and design characteristics to proj ect the units’ pre- and post-control emissions and costs. Cost aside, this under estimates reductions that may be reasonably anticipated to result from the contro ls’ installation. The baseline example discussed above in the RHR, contemplates a situation in which a change in future operations makes the

historical baseline emissions eff ectively too high. However, we find it is reasonable to conclude

125 70 FR 39167

55the RHR’s desire to realign base line emissions with potential fu ture changes in operations cuts both ways.

In addition, the RHR states that when differenc es from "past practice, " as here, have "a deciding effect in the BART dete rmination, you must make these pa rameters or assumptions into enforceable limitations." The OG&E analysis does not propose making the basis of their emission reductions enforceable. In fact, the sc rubbers are designed to allow the station to burn higher sulfur coals than histor ically used at the station.

Therefore, we affirm our position taken in Op tion 1, that our decision to raise the baseline

to match the SO 2 removal potential of the ove rdesigned 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 fi nal action, and a screen copy of the spreadsheet is reproduced as Attachment 3 to this document.

Costs:

Moreover, even assuming the use of high-sulf ur 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 co als cost less. The resulting reduction in operating costs from using higher sulfur coal was not include d in the cost effectiveness analysis. 126

The OG&E units currently burn ultra low sulf ur coal or "SA" coal, which results in

uncontrolled SO 2 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 co al that the IPM model 129 currently anticipates OG&E will burn is "SB" coal, with an uncontrolled SO 2 emission rate of 0.94 lb/MMBtu, well below the OG&E design basis of 1.175 lb/MMBt u. 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 re duce their operating costs by at least 6% and perhaps more. This reduction in costs was not included in Sargen t & Lundy's analysis. Although we do not incorporate it into our SO 2 BART determination cost analysis for the six OG&E and AEP/PSO units, we did in clude this information in a s upplemental 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-effectiven ess 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

56our final action, and a screen copy of the spreadsh eet 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 co al 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 re ductions that will result from compliance with BART. In order to provide th at reasonable assessment, future anticipated

conditions should be used as the common baseline for estimating emission reductions.

Thus, the emission reductions used by Sargen t & Lundy to calculate cost effectiveness minimize emission reductions by subtracting a high pos t-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 significan t 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 sc rubber sizing. Thus, the use of a higher sulfur coal would not significantly affect the size and he nce the cost of a scrubber. Th e comment states that our Option

2 scrubber is undersized and thus te chnically infeasible as we redu ced the cost of the scrubber in Option 2 based on coal sulfur content.

We agree that the sulfur content of the fu el, 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 ba sis. We advised in our initial analysis that OG&E did not supply any cost data for a sm aller scrubber option, re quiring 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. Howe ver, as explained below, a smaller scrubber is technically feasible and cost effective.

The subject scrubbers only need to be co sted 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 attribut ed 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 re vised 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.

57mass transfer to account for the smaller amount of SO 2 that would have to be removed by the Option 2 scrubber. We used it only to establis h 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 th e two sulfur contents that we analyzed in the TSD, 0.48% sulfur (1.176 lb SO 2 /MMBtu) and 0.22% sulfur (0.509 lb SO 2 /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 fr om 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. Th e 3% reduction is incor porated into the revised Option 2 cost analysis in Exhibit 2. Elsewh ere in our response to comments we discuss corrections we have made to Option 2. The full sp readsheet 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 characte rization of our initial analys is and many of OG&E’s related

arguments.

Our analysis did not adjust co sts based on the sulfur content of the coal, but rather based

on the amount of SO 2 removed. Our analysis also did not make any assumptions about reactor vessel sizes or sizing of lime stor age, preparation, and slurry inj ection 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 comm only used in cost estimating and has been specifically recommended for dry sc rubbers using an exponent similar to the one

we used. 133 We explained that the use of this rule "i s 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 scr ubber is generally divi ded 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 struct ure 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 Re gional Haze State Implemen tation 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.

58First, the lime slurry, recycle slurry, and ash handling systems were designed for the maximum fuel sulfur content exp ected 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 c ontent expected at the facility. However, the design sulfur is higher than th e range of coal sulfur burned hi storically. OG&E cites a Babcock & Wilcox book, as the authority for the reactant ha ndling 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 hand ling 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 cost s 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 calcul ate cost effectiveness.

Second, OG&E’s contractor, Sargent a nd 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 th e scrubber model develope d for EPA, Sargent & Lundy explains: "Several input vari ables 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 an alyses 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 reacta nt, reactant stoichiometric ratio [lime to sulfur ratio], how close the SDA is ope rated to saturation condi tions, and the amount of solids product recycled to the atomizer...High SO 2 removal efficiencies in a SDA are also dependent upon good gas-to-liquid contact." 137

Third, OG&E cites the same Babcock & Wilc ox book referenced above as the source for the claim that "The primary design parameter fo r 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 si zed 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, a nd 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 SO 2 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 Avai lable 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.

59performance, for example, depends on the diffusion of SO 2 gas into the scrubber liquid. This process is referred to as mass transfer. The higher the mass transfer, the higher the SO 2 removal. Option 1 assumed 91.5% removal of 43,428 ton/yr to 46,458 ton/yr of SO 2 while Option 2 assumed only 80% removal of 13,799 ton/yr to 13,930 ton/yr of SO 2 . 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 th e required surface area. The design and cost of this atomizer does not depend solely on the exha ust gas flow rate, but also on the amount of SO 2 that must be removed. Thus, the cost of the absorber island, which includes the SDA chamber and atomizer, is not indepe ndent of the amount of SO 2 that is removed, as suggested by Sargent & Lundy.

The amount of surface area can be increased by changing the t ype 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 dec line due to reductions in mass transfer area required to remove smaller amounts of SO 2 , e.g., modifications in the design of the atomizer, required to achieve a lower SO 2 removal efficiency or remove lesser amount of SO 2

.

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 co al 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 th e historical operating pract ices 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 SO 2 BART analyses, ODEQ calculated annual emissions based on the

controlled SO 2 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 SO 2 BART analysis. However, OG&E’s baseline SO 2 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 fo r the four units in 2004–2006, based

140 See, e.g., Eui-Kyung Oh et al., Effect of Initial Dropl et 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.

60on 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 uncontrolle d 2004-2006 baseline emissions at a 78.5% capacity factor to controlled emissions when burning a higher sulfur coal at 90% capacity factor. This resu lts in two errors in Option 2: The future emissions were overestimated, and certain operating costs were unde restimated. However, because we arrived at these errors due to independent re search that we do not view as being a logical ou tgrowth of the comment we received, we have not revised our cost effectiveness analysis in Option 2. Instead,

we view this as further evid ence buttressing our conc lusion that OG&E’s scr ubber costs are high.

Comment: AEP/PSO states that as pa rt 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 (SO 2 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 e ffectiveness for dry scrubbing of $1,544/ton, in 2009 dollars based on the assumpti on 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 jus tification is given for this “one-size-fits-all” approach. AEP/PSO incorporates by reference the critique of EP A’s cost-effectiveness analysis in OG&E’s comments, which demonstrate that si gnificant errors and un justified assumptions were made, and artificially reduce the costs of FGD installations at all units. AEP/PSO states that the Total Capital Investment (TCI) for re trofitting 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 conc ludes that there is no site-specific estimate for the work at Nort heastern, the cost estimate in the TSD is considerably understated, and this calculated value drives the enti re cost effective analysis.

Response: See our response to the OG&E commen ts 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 ha s identified any site-specific differences, such as retrofit issues or space constrai nts, that would significan tly affect the cost to

143 Technical Support Document for the Oklahoma Re gional Haze State Implemen tation Plan and Federal Implementation Plan, March 2011, Appendix C, page 23 and Table 4.

61retrofit 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 retr ofit these units should be roughly equal. The TSD's estimate to retr ofit 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-effectiv eness 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 f ound in EPA’s Technical Support Document Appendix C have no site-specific analyses, inco rporate generic estimates and vendor information without regard to its suitabi lity for this site, and omit critical project components. According to AEP/PSO, the calcul ations from Appendix C therefore lack the fundamental attributes require d of a site-specific BART cost estimate and provide no justification for rejecting the Oklahoma SIP.

Response: The ODEQ SO 2 BART evaluation of AEP/PSO Northeastern units 3 and 4 does not provide any support for its assumption that the cost of sc rubbers is $555/kW to $582/kW. We are not aware of a detailed site-sp ecific 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 su bstantiate the capital

costs for installation. In review ing BART submittals to other st ates, AEP-PSO’s estimated costs were found to be somewhat higher than those re ported for similar projects. However, the evaluations in neighboring states are known to underestimate presen t 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 SO 2 cost evaluation to be well founded, representative of the AEP/PSO un its 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 instal lation 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 Cichanowi cz, Overview of Information on Projected Control Technology Costs and Performance As Developed fo r 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 Re gional 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.

62believes 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 Northeaste rn. A new stack is not specified for similar retr ofits 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 scrubbe r costs. The unit cost estimat es for both Sooner and Muskogee, which were extrapolated to Northeastern, in clude $1.4 million for coating the top 100 feet of

stack. 148 Thus, the cost for stack modifications is included in our Northeas tern cost estimates.

Comment: AEP/PSO states that the estimate provid ed 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 de sign and supply pricing from an FGD/fabric filter equipment manufacturer for bo th Northeastern 3 and 4. This cost totaled approximately $76,000,000, and included a multiple purch ase discount, as suggested in the TSD.

Response: The ODEQ BART evaluation for the No rtheastern 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 $72,000,000 149 compared to $76,000,000 stated by AEP for Northeastern (without any record support).

Comment: AEP/PSO states that based on hist orical analysis of actual costs for retrofitting air pollution technology at several AEP co al fired generating stati ons, the base cost of material design and supply of the FGD/fabric filt er 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, 3r d 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 th e $555/kW estimate in the Trinity report submitted to the ODEQ. AEP/PSO states that not hing in the TSD demonstrates that these costs are unreliable, or provides any basis for rejecti ng these site-specific estimates in favor of the

costs derived for different units in the TSD.

Response: Based on our review of the 4 th edition of the cited re ference, 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 cost s for the AEP/PSO Northeastern sc rubber 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.

63AFUDC, 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 insta lled capital costs of about $506 million by dividing th e vendor quote by AEP's unsuppor ted rule of thumb of 0.15 (74/0.15 = 493) and increasing the result to $5 06 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 a bout 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 analys es, 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 cost s 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 onl y 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 SO 2 BART analysis of the Northeastern units in Appe ndix 2 for the dry FGD/fabric filter results in a cascading reduction of Indirect Op erating Costs (Administrative Charges, Insurance, Property Taxes and Capital Recovery) as th ey are calculated as a percenta ge of Total Capital Investment (TCI). AEP/PSO states the understated PEC results in an understated co st in line item 12 in Appendix 2 for administrative, insurance and property taxes of over $13 million.

Response: As we state elsewhere in our res ponse to comments, we see no support for

AEP/PSO’s PEC. Our PEC is consistent wi th our detailed analysis of the OG&E SO 2 scrubber cost evaluation, and the range reported in other studies, as summarized in the TSD. 150

Comment: AEP/PSO states that since the North eastern analysis included in the TSD is based, in large part, on the analysis conduc ted 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 an alysis. AEP/PSO states that categorizing escalation as a contingency and set ting it to zero is not appropriate, as it is a real cost associated with expected increases for labor and materials that occur over time, a nd 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 demo lition, fabrication and instal lation of the system. They state that our assertion on es calation is in direct conflict with page 2-30 of the Control Cost

150 Technical Support Document for the Oklahoma Re gional Haze State Implemen tation Plan and Federal Implementation Plan, March 2011, Appendix C, pp. 33-35 and Fig. 2. , Appx. C, pp. 33-34.

64Manual, 6 th Ed., and unrealistically decr eases 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 concerni ng the Producer Price Index, wh ich is typically used by Contractors to calculate projec t escalation. According to AEP/PSO, this critical index is approaching an all time high and has increased 8% since January 2009. AE P/PSO concludes that in light of such circumstances, eliminating an escalation factor is unreas onable and artificially

understates the cost of a major capital project.

Response: The escalation referred to in this co mment is the escalati on of current year dollars to the future, when the co sts 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 ba sis. 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 differe nt concept than escalating current dollars to a future year of operation dollars, which is not allowed under the Contro l Cost Manual approach as it involves speculation. Histor ical escalation, which is allo wed under the overnight costing approach in the Control Cost Manua l, is based on known cost indices. Escalation to future years, beyond 2009, is not allowed under the overnight cos ting approach used in the Control Cost Manual. See elsewhere in our response to comme nts 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 draw ings, 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 commonl y used in the Cont rol Cost Manual for similar equipment to SO 2 scrubbers at a similar stage of de sign (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 in vestment, not total purchased cost [e.g., 100 (2,136,000/289,791,940) = 0.74%]. The 3% contingency specified in the Co st 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 Re gional Haze State Implemen tation Plan and Federal Implementation Plan, March 2011, Appendix C, p. 13 and footnote 44.

152 Ibid., TSD, Appx. C, Appx. 1.

65Comment: 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 sy stem, a single ash handling system, a single fabric filter or similar comm on 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 & L undy. AEP/PSO states we applied, without apparent basis, a reduction of 5% to the costs associated with these pr ocess units, that also impacts the Northeastern cost analysis. Accord ing to AEP/PSO, no such reduction is justified in

the case of the Northeastern units , because site-specifi c vendor equipment estimates were used to generate the costs associ ated with these units.

Response: The request for quote and vendor eq uipment estimates AEP/PSO mentions have not been provided for the Northeastern uni ts. Thus, the design basis and opportunity for

discounts and economies of scale can not be assessed. However, th e Northeastern units are very similar to the Sooner and Muskogee units, for whic h 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 discount s are justified for the OG&E units. Thus, absent any supporting inform ation from AEP/PSO fo r any of the capital costs it presents for its SO 2 BART analysis, we find that this 5% discount is similarly justified

for the AEP/PSO units.

Comment: AEP/PSO states that we assumed the No rtheastern units will shift to a higher sulfur fuel than is currently burned, thus infl ating the baseline emissi ons 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 fo r AEP/PSO’s Northeastern units is biased and provides no basis for rejecting the ODEQ SO 2 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 SO 2 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 e fficiency 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 imprope rly discarded insurance costs for

Northeastern and instead used Sooner and Musk ogee’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 a nd why the insurance costs for the Sooner and Muskogee plants are applicable to Northeastern. They state that t he value for insurance is generally calculated as 1% of the TCI. Howeve r, they note that the a ssumed TCI in Appendix 2

is the sum of Landfill Construc tion ($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.

66Response: 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 ca lculation for AEP/PSO because of the similarities of the units owned by both companies. We find it is approp riate to use OG&E’s site specific costs to

calculate insurance costs for the AEP/PSO units b ecause of the similarity of these units to the

OG&E units. The TSD 154 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 parenthe tical (1% TCI) shown in Appendix 2 is from AEP/PSO’s contractor’s report a nd does not represent the calculations made in Appendix 2. Therefore, we find that the calcul ation of insurance in the TSD, Appendix 2, Line 32, is correct

as stated.

Comment: AEP/PSO states that there is a ma thematical error in the TSD in our calculation of property tax and we improperl y discarded the property tax estimate for Northeastern and instead used Sooner and Muskog ee’s property tax rate as a basis for lowering Northeastern’s property taxes. They state the valu e for property tax is gene rally calculated as 1% of the TCI, which is $2.741 million based on th e assumed cost of the FGD/fabric filter technology assumed in the TSD. AEP/PSO co ncludes that line item 33 is $2.329 million, not
$2.741 million.

AEP/PSO states that the TS D 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 Docu ment 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 prope rty tax, but rather a

correction to AEP/PSO's analysis. The TSD 155 explains that property tax for Northeastern was estimated as 1% of TCI, based on the Cost Ma nual 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 in surance costs in Appendix 2, Line 33. The parenthetical (1% TCI) s hown in Appendix 2 is from AEP/PS O’s contractor’s report and does not represent the calculations made in Appendix 2. The TSD explains w hy property tax rates are similar for Sooner, Muskogee, and Northeastern. The six units consist of nearly identical pulverized coal fired boilers inst alled 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 reason able upper bound for Northeastern, located in Rogers County. This comment does not explain why a site-specific estimate of pr operty tax was not used in the Trinity cost analysis, given th e 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 TS D, Appendix 2, Line 33, is correct as stated.

154 Ibid., TSD Appendix C, p. 37.

155 Ibid., TSD Appendix C, p. 38

67Comment: AEP/PSO states that many of the as sertions in the TSD are unsupported and inconsistent with actual operating experience at re trofit FGD installations. As a utility provider and the owner of the units at issue, AEP/PSO stat es 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 posi tion to calculate the costs to re trofit 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 a ny 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 uns upported unit cost estimate of $555/kW, which is inconsistent with analyses pres ented 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 Cont rol 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. Howeve r, 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 a ny information supplied by vendors that affects your assumptions regarding purchased equipment costs, equipment life, replacement of major components, and any other element of the calcu lation that differs from the Control Cost

Manual." 157 The TSD, Appendix C, on the other ha nd, provides the basis for each modification that was made by us to the Northeastern cost es timate. 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 simila r 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 eff ectiveness 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 si milar facilities nationwide indicate

that the cost effectiveness of a wet sc rubber is about 9% higher than for a dry scrubber.

Response: This material is quoted from the su mmary and conclusions. The detailed support is found elsewhere in the report. See th e table of contents. For instance, the cost

effectiveness information for "sim ilar facilities" is found in Table 7 of Appendix C of the TSD. The support for the fact that the co st effectiveness of a wet scrubbe r is about 9% higher than for a dry scrubber is found in the TSD 158

.

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 increm ental cost effectiveness is zero. This is likely the case for the su bject units, but this option was not evaluated by the companies.

AEP-PSO disagrees with us that an existing el ectrostatic 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 ef fectiveness of dry scrubbing and eliminates the

incremental cost effectiveness. AEP/PSO states th at a fabric filter baghouse is integral to the design and performance of a dry FGD. No examples or citations are provid ed 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 su mmary and conclusions. The detailed support is found elsewhere in the report. See tabl e of contents. The support for the use of an existing electrostatic precipitator in the de sign of a dry FGD system is found in the TSD 159 at 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. Howe ver, 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 Re gional Haze State Implemen tation Plan and Federal Implementation Plan, March 2011, Appendix C, Table 8.

159 Ibid., TSD, Appendix C, pages 25-26.

69costs for a new baghouse, when an acceptable dust control device is already present, could make a signifi cant difference in an incremental cost comparison with a wet scrubber, wh ich 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 devi ce is an integral part of a dry FGD. This device

does not have to be a fabric filt er, 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 es timate 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 retr ofit issues. AEP, the owner of Northeastern, has publicly reported the capital cost of sc rubber 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 Northeaste rn units. They state th eir retrofit program is designed to prioritize the inst allation of FGD units to achieve the most cost-effective SO 2 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, whic h have different FGD design va riables and associated cost considerations compared to the Northeastern units, that are sma ller 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 retrof it 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 provi des greater flexibility in futu re 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.

70Response: ODEQ’s RH SIP submittal contains no support for the cited unit cost of $555/kW, which is very high compared to other publicly re ported estimates. 161 As explained elsewhere in our response to comments, this va lue includes costs such as AFUDC, escalation,

and inflation that are not allowed in the overn ight cost analysis used to estimate cost

effectiveness in the Control Cost Manual.

This comment states that the AEP-reported value of $262/kW is fo r larger units, 800 to 1300 MW, that use higher sulfur coal and diffe rent 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 reduc tions are higher for roughly the same cost) to build a single wet scrubber to serve the two 490 MW No rtheastern units (980 MW), designed to remove 98% of the SO 2 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 signifi cantly reduces the capital cost of controlling SO 2 emissions. One large wet scrubber designed to service 980 MW may be more cost e ffective than two smaller dry scrubbers, each designed to serv ice 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 po tentially 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 id entify any retrofit issues or unusual

circumstances that would lead to such a high unit capital cost.

AEP/PSO states this is an unfounded statement w ith 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 determin ation. The record does not identify any

retrofit issues or unusual circumstances that w ould 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 Re gional Haze State Implemen tation Plan and Federal Implementation Plan, March 2011, Appendix C, pages 33-34, Figure 2, Table 7.

71The unit capital cost for the two coal -fired Northeastern units should be

about the same as for Sooner and Mus kogee. These six units are similarsized, tangentially-fired boilers that burn similar low sulfur PRB coal and were built about the same time (Tab le 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 sim ilarities exist, accurate cost -estimates for any retrofit project are based on variety of s ite- and project-specific variables. According to AEP/PSO, these include site-specific unit integration consider ations; current unit disposition and condition; available footprint at the proj ect site to support th e control equipment; available water supply, water treatment, and coal combustion by-product dis posal 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 ap proach 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 ODE Q, who performed its own BART analyses, including the SO 2 BART analysis we reviewed for units 3 and 4 of the AEP/PSO Northeastern facility However, we also re viewed an earlier draf t 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 review ed. The BART Guidelin es 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 com ponents, 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 subs tantially 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 Mu skogee analysis in Appendix 1, Line 65. This value is $265/kW, without escalation, AFUDC, bond costs, and excessive contingency, which are not a ppropriate 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 th at 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 th at costs for the source being analyzed are not considered reasonable."

72analyses. 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 prope rly derived or justified. Further, states AEP/PSO, no rationale is provided for how the average of these arbitr ary 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 cap ital 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 TSD 167 :

Thus, I revised the Trinity capital cost estimate using the average capital cost from my revised Sooner and Muskog ee analysis in Exhibit 1, Line 65. This value is $265/kW, without es calation, AFUDC, bond costs, and excessive contingency, which are not a ppropriate 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 ce ll 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 co mprise the sum of variable O&M (utilities and replacement parts), fi xed O&M (operating and maintenance labor), and indirect O&M (administrat ive/overhead). The Trinity analysis omitted some of the components of O&M and overestimated others.

These errors and omissions are di scussed below and corrected in Appendix 2.

AEP/PSO states this statement is unfounded a nd provides no citations to references that define the parameters which the TSD alleges sh ould 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 Re gional Haze State Implemen tation Plan and Federal Implementation Plan, March 2011, Appendix C, pages 33-34, Figure 2, Table 7.

73Response: We disagree with this comment. E ach 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 prepar e 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, scal ed 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 earlie r 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 informati on 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 North eastern units which we re viewed. 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 comm ent, 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 fr om 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 No rtheastern units falls within the acceptable range, as reported in the TSD 171

.

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 SO 2 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, insuran ce, and property taxes.

169 70 FR 39166, 39168.

170 Technical Support Document for the Oklahoma Re gional Haze State Implemen tation 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.

74disposed 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 e nd of the reported range, or $5/ton. Therefore, in Appendix 2, Line 24, I es timated the cost of on-site landfill disposal assuming that 5 pounds of solids would be generated for each pound of SO 2 removed and that it would co st $5 per ton to dispose of

them.

AEP/PSO states the amount of byproduct ge nerated by a dry scrubber is dependent on unit-specific variables, including th e 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 th at 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.” AE P/PSO notes that proposed EPA ru les 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 a ssumptions for waste disposal. As we discuss elsewhere in our response to comments, docum entation 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 Mu skogee, 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 cost s already included $25

million for an on-site landfill. 173 Thus, transportation costs woul d 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 foll ows the spray chamber, contains filter bags and supporting cages that ar e changed out every three years.

These O&M costs were not included in the Northeastern cost analysis.

These costs should be similar to t hose 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 Re gional Haze State Implemen tation Plan and Federal Implementation Plan, March 2011, Appendix C, page 37.

75replacement 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 provi de any basis for why change out rate and cost-estimates we applied to the Sooner and Muskogee units ar e applicable to the No rtheastern units.

Response: AEP/PSO’s analysis does not include a ny 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 TSD 175 . 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 co mparisons 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 Mu skogee 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 provi de any basis for why change out rate and cost-estimates applied to the Sooner and Muskoge e units are applicable to the Northeastern units. AEP/PSO

states that if indeed the Control Cost Manual is the source of the va lue, then this is contradictory

to the criticism in Section III of the TSD that th e Control Cost Manual should play a greater role in such an analysis.

Response: To clarify, the quoted material refere nces insurance rate s, not "change out rates." Nevertheless, the TSD explains why insurance rates ar e 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 re presentative than a generic factor from the Control Cost Manual. This comment does not explain why a site-specific estimate of in surance 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.

76The Control Cost Manual contains two type s 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 generi c types of pollution control equipment. This comment confuses the general methodology of the C ontrol Cost Manual with factors used in the study level capital cost estimates. The study leve l 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, di scussed 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 an alysis for dry scrubbing is based on

an 83% SO 2 control efficiency, resulti ng in emission reductions of 26,599 ton/yr.145 See Appendix 2, Lines 45 a nd 59. However, BART requires the most stringent emission control leve l.146 As discussed elsewhere, a dry

scrubber can achieve 95% SO 2 control. Further, the same mismatch problem discussed for Sooner and Muskogee exist here. The capital and

O&M costs for Northeastern were sc aled from capital costs and utility demands for the Sooner and Muskogee scrubbers, which were based on

91% SO 2 control. Thus, I revised the SO 2 control efficiency to 91% in Appendix 2, Line 59. This increases the SO 2 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 fo r why change out rate and cost-estimates applied to the Sooner and Muskogee units are applicable to the No rtheastern units.

Response: This comment is apparently not rela ted to the quoted material and we are

therefore not able to understa nd 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 similar ity with the Northeastern units. We do not agree that the cross-compar isons 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 resu lt in a high “cost-effectiveness” value in terms of dollars per tons of SO 2 reduced. In contrast, accordi ng to us, if OG&E assumed it would switch to higher sulfur coal, the do llars per ton “cost-effectiveness” of the FGDs would be lower,

77since the amount of SO 2 removed would increase. The co mmenter states we decided for purposes of our analysis to assume emission re ductions 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 SO 2 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-e ffectiveness number by

about one-third.

Response: We based our cost effectiveness ca lculations on OG&E’s specifications. As

we discuss elsewhere in our re sponse to comments, OG&E did this by instructing the vendors in its request for proposal to design the SO 2 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 SO 2 scrubber system that could accommodate a higher sulfur coal. However, the OG&E analysis

failed to take into consideration the concom itant increase in emission reductions because it assumed for the purpose of calcula ting the cost effectiveness in $/ton that the tonnage of SO 2 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, de parts 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 st ate that if OG&E wants to continue using low sulfur coal, it should build a smaller sc rubber. 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 discus sing whether that assumed equipment would be compatible at all with the four un its or would even be feasible. In contrast, states the commenter, OG&E’s analysis that ODEQ reviewed was based on actual preliminary de sign work using site specific factors. The commenter states th at OG&E’s comments our hypothetical FGDs are

indeed infeasible. The commenter states we th erefore 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 concl ude 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, choos e whether to use high sulfur versus low sulfur coal depending on their relative economics. Th e 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 con tinues 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 SO 2 will be emitted from the unit regardless of the choice of coal. Thus, concludes the comme nter, in weighing, as required by Section 169A, the “costs of compliance” agains t the “degree of visibi lity improvement,” the cost of installing and operating the OG&E FGDs mu st be weighed against th e 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

78statutory framework for ma king BART determinations in tying he r analysis to the type of coal OG&E ultimately uses.

The commenter states our insistence in givi ng so much weight to whether low or high

sulfur coal is used leads us to the absurd conclusion that high ra ther 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 vi sibility conditions consistent w ith the BART factors, and our presumption that reducing SO 2 is a key component of doing so, our assumption that high rather

than low sulfur coal should be assumed make s no sense. In fact, states the commenter, depending on the relative cost of high versus low sulfur coal and other fa ctors, using high sulfur coal may increase the “costs of compliance” si nce 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 determinatio n ends up not only far from the statute and reality. The commenter criticizes our conclusi on that it would be co st-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. Th e commenter also criticizes our statement that “Sargent & Lundy assumed a higher su lfur 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 conclusi on that the OG&E FGDs opera ted 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 lik ely 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, ho w those coals affect the efficiency of the units and FGDs, how much the FGDs have to be run gi ven 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 th e 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 SO 2 than the latter option. The

dominant consideration will be the lowest co st 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 SO 2 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 analys is for Option 2, which addresses the minimum scrubber necessary to treat the co al 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 th e commenter’s general statement that the type of

79coal is immaterial. There are limits to the efficiency of SO 2 scrubber systems which are dependent in part on coal character istics. 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 Mu skogee units is that the designed SO 2 scrubber systems for those units are based on a higher sulf ur coal than it has hi storically burned, yet

assumed its historical emissions in its cost an alysis. 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 Optio n 2. We do agree with the commenter in that the relative economics of using low or high sulf ur coal will be determined by the respective delivered prices of the two coals, and other factor s. 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 SO 2 BART determination

remains cost effective. That was in fact the entire reason we develope d 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 deta il in our proposal, we followed the requirements of the BART Guidelines, in which cost e ffectiveness 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 Co st 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-wor ld cost of compliance

based on our mistaken view that real-world costs are not releva nt 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 th e Control Cost Manual it self provides that the

Control Cost Manual should be take n as the exclusive or even prim ary source of cost information where better source-specific in formation 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 state 177 :

The Control Cost Manual addresses most cont rol technologies in su fficient 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 documen ted, either with data supplied by an equipment vendor (i.e., budget estimates or bids) or by a referenced source (suc h as [the EPA Cost Manual]).” The commenter states that although th e 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 technolog ies in sufficient detail for a BART analysis,” id., implying correctly that in some areas the Cost Manual doe s not supply the necessary information. Finally, states the commenter, the Guidelin es state that the co st analysis should “take into account any site-specific design or other conditio ns 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 me thodology should be documented, and that the Control Cost Manual should be used where possibl e. As stated elsewhere in our response to comments, we requested that OG&E supply vendor quot es in order to addre ss this situation. We disagree with the commenter’s im plication 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 explai n elsewhere in our response to comments, is fully applicable to providing a BART cost e ffectiveness 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 re cognizes that it is not the final word in determining costs, and makes clear that the electric gene ration sector is one of

the areas not covered in the Guidelines:

...this Manual does not directly address the co ntrols needed to control air pollution at electrical generating units (EGUs) because of th e 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 technologi es that might be applicable to an electric generator, it does not provide information as to FGDs.

Response: The commenter misrepresents the contex t of the quote it reproduces from the background section of the Control Cost Manual. The footnote to the te xt it quotes actually

states: 178

This does not mean that this Manual is an in appropriate 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 diffe rent 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 basi c 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 recogni zed 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.

81the 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 re gulators 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 se t of regulations would likely be more expensive

than another:

The accuracy of the information in the Manua l 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, nomina lly 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 Contro l Cost Manual is to provide general and consistent information as to the costs that will result from regulation, thereby allowing a general determin ation of whether one set of re gulations would likely be more expensive than another. As th e 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 sim ilar permit decisions over a period of time. 180 Thus, a consistent method of determining cost effectiven ess, 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 C ontrol Cost Manual says it works is in providing info rmation to industry to determin e 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 assessm ents 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 in formation 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 anal ysis was flawed, for which we made appropriate

179 70 FR 39167.

180 70 FR 39168.

82and 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 th e cost for a particular source to comply with regulation. For the four OG&E units, the comm enter states, ODEQ concluded that OG&E’s use of the Control Cost Manual in its first report pr oduced 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 cap ital costs associated with installing DFGD control systems, and a more accura te estimate of the actual costs that OG&E

would incur to install DFGD....”

ODEQ’s reliance on site-specific and more deta iled information than provided in the Control Cost Manual was thus entirely proper ba sed 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 substa ntiate 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 type s of information: (1) a general costing methodology and (2) study level cap ital cost estimating methods for certain generic types of pollution control equipment. The general cost ing 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 facili ties to evaluate reasonableness. However, the study level capital costs estimated for specific cont rols can and are routinel y 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 us ed 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, an d considered cost effectiveness guidance provided by the relevant Federal La nd Managers. ODEQ states it determined that the installation

of scrubbers for SO 2 control is not cost effective, because of the high costs and the associated limited potential visibility improvement at the imp acted class I Federal areas. As a result, the ODEQ's determination that S02 scrubbers are no t 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 co st effectiveness analysis for the six AEP/PSO

83units followed the BART Guidelines. In performing our own cost analyses, we determined that the costs of installing SO 2 scrubbers on the six affected units is substantially less than the costs estimated by ODEQ, which were based on an in correct costing methodol ogy not allowed by the Control Cost Manual. We therefore disagree w ith ODEQ that we should have approved the SO 2 BART determinations for the six units.

Comment: ODEQ states that initial cost estim ates for dry and wet scrubbers were developed based on maximum observed 24-hour em ission rates from the Regional Haze baseline period (2001-2005) for the AEP/PSO and OG&E bo ilers 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 th e basis for cost estimates and em ission reductions. According to ODEQ, use of maximum 24-hour emission rates for design and cost effec tiveness calculations was generally perceived to provi de conservative assessments of cost effectiveness.

ODEQ references the advanced notice of pr oposed rulemaking for BART units at the Four Comers Power Station and the Navajo Generating Station, wher ein we revised the

emissions basis for the cost effectiveness calcu lations submitted by the applicant to reflect annual average emission rates from the baseli ne period rather than the maximum 24-hour emission rates that were the basis for engineerin g 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 update d 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 co al may fluctuate, the facility must be in compliance at all times. And the use of an a nnual 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 complia nce averaging periods of no longer than 30-day rolling averages.

ODEQ states the proposed FIP i ndicates that the most cost effective option would be a scenario where the control equipment is designe d for the maximum expected sulfur content of

Powder River Basin coal and associated emissi on reductions are then calculated based on the continued use of coal with a higher sulfur cont ent. ODEQ agrees that the equipment should be designed for the maximum expected sulfur conten t 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 comm unications with the public, both the realistic cost of the proposed control technology and th e actual expected bene fit to the public are described. ODEQ feels that arti ficially 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 th e Advanced Proposed Rulemaking for Navajo and Four Corners (74 FR 44321) for adjusti ng historic baseline emissions is not relevant

84to this case as there was no i ssue of anticipated change in fu el 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 re quest for quote that the SO 2 scrubbers be designed on the basis of a higher sulf ur coal than the facili ties have previously burned in any appreciable quantitie s. We therefore raised our emission baseline to match this overdesigned scrubber and demonstrat ed such a situation would be co st effective. However, we did not base our proposed decisi on solely on this outcome. In Option 2, we based our emissions baseline on annualized data, just as ODEQ did and costed the inst allation of scrubbers designed

to address a coal with a sulfur content the OG& E units historically bu rned. Taken together, Options 1 and 2 demonstrate that whether OG&E con tinues to burn its histor ical coal, or decides to burn a higher sulfur coal that actually matc hes 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 lim its at all times. Elsewhere in our response to comments, we demonstrate that OG &E and AEP/PSO can meet our SO 2 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 es timates to be consistent with surveyed cost estimates published in an onlin e industry magazine and concl uded that scrubbers remained marginally cost effective. ODEQ states that OG& E subsequently supplied revised cost estimates in December of 2009 that relied on vendor quotati ons. 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 estimat ing practices and to provide a more accurate cost associated with the projected visibility improveme nt. It states this de cision was based on the

review of the initial submittal which more clos ely followed the Control Cost Manual approach

and resulted in some absurd conclusions such as calculating the annual ad ministrative costs as a two percent function of capita l cost. Outside of EPA guidance, states ODEQ, these administrative costs are generally evaluated as a function of operati ng labor costs and are attributed to salaries and wage s for secretaries, accountants, e ngineers, and legal personnel. ODEQ states that the Control Cost Manual appro ach, as documented in the supporting technical documentation to the proposed FIP, was not desi gned 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 bo th 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 th is 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 inclusi on 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 e ffectiveness evaluation. ODEQ explai ns that while these elements are not part of the Control Cost Manual methodol ogy, they are reflective of actual costs borne by the subject sources. ODEQ determined that a co st analysis reflective of reality used to

85substantiate the cost analyses which followe d EPA methodologies were appropriate decision making tools in the determinati on of control e ffectiveness.

Response: As ODEQ describes, it did not follow the Control Cost Manual approach. The additional costs allowed by ODEQ— c ontingency, bond costs, AFUDC, etc.— are only

allowed under the "all-in" costi ng methodology, which is not used in cost effectiveness analyses. See our responses elsewhere for more information on this.

The Control Cost Manual contains two type s of information: (1) a general costing methodology and (2) study level cap ital cost estimating methods for certain generic types of pollution control equipment. The general cost ing 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 simila r 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 th e all-in methodology must be compared with

all-in cost at other similar facilities to dete rmine 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 ha d 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 w ould not be in compliance with the Control Cost Manual methodology and thus could not be co mpared to other properly conducted BART analyses. When the OG&E and AEP cost analyses are revised to use th e 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 Ma nual 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 unde r 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 co st-effective. They st ate our disapproval of

Oklahoma's BART determination for the six coal-f ired generating units rests in part upon its

determination that Oklahoma did not use the Cont rol 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 estima tes also should be documented, either with data supplied by an equipment vendor ... or by a referenced source... . Further, states

86the commenter, the footnote to the senten ce 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 commente r, 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 SO 2 BART determination for the six un its because ODEQ used site specific information. We agree with the commenter that vendor quotes are specif ically suggested by the BART Guidelines as providing pertinent inform ation 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 ge neral costing methodology an d (2) study level capital cost estimating methods for certa in generic types of pollution c ontrol 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 determin ation, 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 methodol ogy 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 disa llowed by the Control Cost methodology, along with its sc rubber overdesign in relation to the coal they presently burn, are the main reasons its cost effectiveness analys is 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 determinat ion. The commenter states in calculating the cost-effectiveness of retrofitting scrubbers ($/ton SO 2 removed) on OG&E's plants, we assumed

an SO 2 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 co st estimate is based on a scrubber that can

remove more SO 2 than is produced by the low sulfur co al used at the plants, and that OG&E sized a larger than necessary scrubbe r to give it flexibility to burn hi gher sulfur coal in the future.

87However, states the commenter, we failed to show how OG&E can achieve the higher SO 2 reductions burning its cu rrent low sulfur coal.

Response: The vendor proposals indi cate 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 SO 2 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 SO 2 scrubbers be designed on the basis of a higher su lfur coal than the facilities have burned in any appreciable quantities. We therefore rais ed our emission baseline to matc h this overdesigned scrubber and

demonstrated such a situation would be cost effe ctive. 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 addi tion, as we discuss elsewhere in our response to comments, we also made an adjustment to the capital cost to re flect a scrubber system th at is designed to treat the coal that OG&E historically burns. Thus, th ere is no need for us to demonstrate that OG&E can achieve the higher SO 2 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 matc hes the capability of its scrubber, the result is cost effective.

Comment: A commenter states that as an altern ative for OG&E's plants, we attempted to

estimate the cost-effectiveness of using a smaller scrubber. Ho wever, 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 fo r this determination, it cannot be used.

Response: In our proposal, we modified our cost analysis of Option 2, utilizing the sixtenths rule. As we e xplain 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 th e Control Cost Manual prohibits use of escalation, AFUDC and contingencies in the es timated costs used for cost-effectiveness determinations. However, states the commenter , the Control Cost Manua l 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 excludi ng 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 "a ll-in" cost analysis. However, the Control Cost Manual method is not an "all-in" method, but rather an "overnight" method. Overnight costs are real worl d costs, as of the date of the estimate, as if the project were built overnight. Thus, they explicitly exclude cost s 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—contin gencies that are specifically excluded by the Control Cost

Manual.

88Comment: A commenter states we relied upon comparisons to scrubber cost data provided for other plants as the primary basis fo r the conclusion that scrubbers are cost-effective in Figure 2 and Table 7. Howeve r, states the commenter, thes e 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 accur acy 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 plan ts from 20 years to 30 years. Th ey note this has the effect of lowering the annual capital costs for the scrubbe rs 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 commente r states that assuming those plants will operate for 70 years is an unwarranted a ssumption 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 year s, and we conclude we have adequately justified a 30 year life.

Comment: A commenter states we a ssert that, as long as the ad justed cost per ton of SO 2 removed is within 30% of the range for other plan ts presented in Table 7, the scrubber option is

assumed to be cost-effective. The commenter stat es that while it might be appropriate to have some "fudge factor" in determining cost-effectiven ess, it is unclear why th e appropriate figure is 30%. In addition, states the commenter, any su ch fudge factor should only apply when similar plants are being compared, since plant size, fuel sulfur content and ot her factors account for

differences in costs. The commenter states it is unclear what plants are being used for comparison purposes, therefore no f udge factor should be used.

Response: The 30% factor is based on the ge neral 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 th an 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% lowe r 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 capi tal cost determined for OG&E's plants for the AEP/PSO plant. The commented states that th e 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%.").

89Response: AEP/PSO did not provide any documenta tion for its capital costs, therefore, we had no choice but to estimate the capital cost s ourselves. As we di scuss elsewhere in our response to comments, the six units are nearly identical pulverize d 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 SO 2 BART cost effectiveness analysis for the AEP/PSO units in question.

Comment: A commenter notes that we determ ined at 76 Fed. Reg. 16182-83 that ODEQ erroneously relied upon inflated dry and wet scru bbing control costs to justify rejection of SO 2 controls. The commenter states that by way of example, such exaggerated costs apparently include OG&E wage rates for journeymen pipefi tters which we understand were calculated at $100 per hour. The commenter notes for the record that the current prevai ling 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 reli ed 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 SO 2 that were both unreasoned a nd unjustified. Elsewhere in our response to comments we cite the commen ter’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 th at 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 th at dry scrubbers are a cost effective control option. The commenter supports our analysis an d conclusion that both dry scrubbers and wet scrubbers are co st effective controls in Oklahoma.

Response: We agree with the commenter that OD EQ relied on cost estimates that greatly

overestimated the costs of controls. The fau lts in ODEQ’s cost methodology were significant enough that they resulted in BART determinations for SO 2 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 estimat e 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 th at we did not consider the costs associated with potentially triggering PSD re view under the PSD Tailoring Rule.

90Response: We agree that the installation of SO 2 scrubbers at the six OG&E and AEP/PSO units, if not offset by increased effi ciency 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 Ok lahoma. Whether or not PSD permitting is required would be based on design- specific considerations and app licability determinations that will vary with each unit. OG&E has not provided unde rlying 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 impo se 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 cal culated fewer emission reductions for the flue gas desulfurization (FGD) technology wh en we evaluated ODEQ’s cost analysis. The

commenter states we calculated the cost eff ectiveness of FGD assuming OG&E switched to a high sulfur coal when OG&E currently uses low su lfur fuel. According to the commenter, this incorrectly lowered the dollars pe r 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 effectiv eness of FGD for BART si nce 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. T hus, concludes the comment er, we did an improper BART analysis when they tied the analysis to the use of high sulfur co al use for OG&E’s four units with a faulty lower dolla r per ton cost effectiveness.

Response : We discuss the commenter’s assertio n that the BART Guidelines do not provide that a BART determinati on 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 SO 2 BART Emission Limit

Comment : OG&E states our analysis of the techni cal capabilities of re trofit dry scrubbing systems, and its reliance on information summarized in the TSD, is inadequate for establishing

an enforceable BART emission limit. OG&E stat es 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-effec tiveness 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 re port to establish an enforceable permit limit is incorrect, as removal e fficiencies in the report “represents a general guideline” for application of dry scrubbing techno logy 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 SO 2 when burning current coal (0.51 lb/MMBtu), 91.5% when burning

91the 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 provi de insight into the t echnical capabilities of a dry scrubbing system on a new unit, that data ar e 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 achie ved 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 SO 2 emissions from what it claims includes all existing coal-fired boilers equipped with dry lime scrubbi ng. OG&E states the top f our units listed in its

table are new units which commenced commercia l operation since 2007 and were specifically designed with an integrated DFGD/FF control system.

OG&E states we also relies on SO 2 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 SO 2 emission limit of 0.065 lb/MMBtu (30-da y average) when the uncontrolled SO 2 emission rate is less than or equal to 1.0 lb/ MMBtu. According to OG&E, al though 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 concl udes it is not appropriate to establish BART emission limits based on PSD limits for a new facility that has not ye t commenced commercial operation.

OG&E states that based on an uncontrolled SO 2 emission rate of 0.51 lb/MMBtu, the most aggressive design target for a DFGD/FF retrof it 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 achie ved 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 in to account the full range of possible fuels, operating conditions, operating sy stem 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 highe st possible control efficiencies but, rather will allow permittees to achieve co mpliance 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 cont rol system and the enforceable permit limit.

Response: We proposed a BART SO 2 emission limit of 0.06 lb/MMBtu met on a 30-day

92rolling 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 ow ner chooses. Although we based our SO 2 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 t echnically feasible, and are cost effective. Further, the existing low sulfur co al burned at the stati on 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 limit 183 :

It is important, however, that in analyzing the technology you take into account the most stringent emission c ontrol level that the technology is capable of achieving. You should co nsider recent regulatory decisions and performance data (e.g., manufactur er’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 cont rol alternative, latitude exists to consider special circumstances pert inent to the specific source under review, or regarding the prior applic ation of the cont rol 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 th at 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 re port 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 repor t “to establish an enforceable permit limit would be incorrect as these removal efficiencies repr esent a general guideline for application of dry scrubbing technology and do not take into consider ation any site-specific operating parameters.”

This mischaracterizes our use of the subject char t. The information in this chart is one of

several sources of information that the RH rule allows us to utilize when establishing our SO 2 BART emission limit. We relied on this and othe r sources of information to confirm that the proposed BART limit could be achieved. As the RH rule states above, manu facturers’ data (e.g., vendor’s proposals) is a recomm ended type of performance data when setting BART emissions limits. The other sources that we relied on include the site-specific SO 2 removal efficiency of 95% quoted in the vendor proposals as well as othe r information cited in the TSD, Ex. B, pp. 42- 47, including the information cited footnotes 17 4, 176, 177, 180-182 and in Figure 4. For ease of

182 76 FR 16,194 col. 1.

183 70 FR 39104, at 39166.

93reference, this information is reproduced below. 184

We agree this is a general guideline for appl ication of the dry sc rubber technology. This figure is widely used by Sargent & Lundy in mate rials filed in other cases. Sargent & Lundy

characterizes it as “d erived 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 assessi ng 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 SO 2 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 sc rubber merely reacts to physical and chemical characteristics of the gas stream. These do not de pend on the age of the unit generating the gas.

The achievable SO 2 limit would only be influenced in a retrofit application if there were space constraints that limited th e design of the scrubber, e.g., insufficient space to build a fullsized scrubber. No such constraints have been id entified at the subject units. Further, no such

constraints were identified in th e Request for Budgetary Quote or in the vendor proposal. Such constraints are unusual for scrubbers as they are locat ed 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 spa ce 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 designe d 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.s tate.ga.us/gaairpermits/Perm itPDF.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.

94more stringent than NSPS. Existing SDA scrubbe rs, on the other hand, were largely designed to

meet NSPS limits. 186 The SO 2 NSPS in effect historically only required compliance with an SO 2 limit of 1.2 lb/MMBtu and 90% minimum reduction or a 70% minimum reduction when SO 2 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 SO 2 emission rate achieved by such units is 0.088 lb/MMBtu, annual average. Ex. B, p. 37. The determination of BART does not requ ire 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 SO 2 BART but cannot be used

to establish BART itself as BART is the “em ission 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 ha ve to be demonstrated by CEMS data.

Most of the SO 2 CEMS data in the CAMD database is generated under cap and trade programs, such as the Acid Rain Program and th e Clean Air Interstate Rule (CAIR), to comply

with the SO 2 New Source Performance Standard, or to comply with permit limits, such as from netting out of Major NSR review. Thus, the abse nce of CEMS data proving compliance with the proposed SO 2 BART limit at a retrofit unit does not mean that the proposed limit is not achievable at Sooner and Muskogee, only that it ha s not yet been achieved. Nevertheless, we do present CEMS data that demonstrates these units are capable of achieving our BART FIP SO 2 emission limits of 0.06 lbs/MMBtu.

OG&E presents performance data that it describes as the average annual SO 2 emissions from all existing coal-fired boilers equipped with dry lim e scrubbing. As OG&E notes, it

considers the units listed in this table to be a pplicable for comparison ba sed 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 disa gree with OG&E’s assertion that the SO 2 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 reque st that our proposed SO 2 emission limit should be based on a Boiler Operating Day (BODs) convention in lieu of a straight 30 day calenda r average and conducted our analysis on that basis.

Figure 7 presents the 30 day BOD SO 2 emission data for the 242 MW TS Power Plant, near Dunphy, Nevada, which has a similar permitted BACT SO 2 emission limit to our BART

FIP. 188 This plant burns a similar Powder Rive r 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 Resour ces, Division of Environmental Protection, Facility ID

No. A0359 Permit No. AP4911-2502:

95OG&E units. As can be seen from the data in Figure 7, this plant remained well below our

BART SO 2 emission limit of 0.06 for the approxim ately 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 SO 2 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 SO 2 emission limit of 0.06 for almost all of 2009 and 2010. Note, only three data points are responsible for the large sp ikes in the 30 day BOD average. These 24-hr

NAC 445B.305 Part 70 Program BACT Emission Limit – The discharge of SO 2 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 SO 2 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.

96data 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 scr ubber malfunctioning or ot herwise not operating, or potential data point errors. W ithout the inclusion of these th ree extreme points, the Wygen II units would have operated continuously under our FIP SO 2 emission limit of 0.06 lb/MMBtu, based on 30 day BOD averaging, for over a year Regardless, ther e are many months when thi plant operated with a continuous 30 da y BOD average below 0.05 lbs/MMBtu. 3

s

Figure 8

Figure 9 presents the 30 day BOD SO 2 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 SO 2 BART limit of 0.06 lbs/MMBtu. Regard less, as can be seen from th data in Figure 9, this unit has also operated below our BART SO 2 emission limit of 0.06 for significant periods of time, thus demonstra ting its capability to meet this limit.

97Figure 9

The data represented by the above figures do not depict the lowest le vels these units are capable of achieving. Of the three units disc ussed above, the TS Power Plant has a permit limit that is somewhat similar to our proposed BART SO 2 limit for the six OG&E and AEP/PSO units. While combusting coal with a sulfur content less than 0.45 percen t (30-day rolling period), it is required to meet a SO 2 limit of 0.065 pound per million Btu, based on a 24-hour rolling average period. As a result, it is cons istently under our proposed BART SO 2 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 leve l of control achievable by simila r units on a continuous basis. Neither AEP/PSO nor OG&E have presented any in formation that could be interpreted as “a showing of differences between th e 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 SO 2 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 achie ved 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 stat e that “[t]echnologies

98required as BACT or LAER are available for BART purposes”. 189 The guidelines instruct: "You are expected to identify potential ly applicable retrofit control technologies that represent the full range of demonstrated alternat ives. Examples of general information sources to consider include: The EPA's Clean Air Technology cen ter, which includes the RACT/BACT/LAER Clearinghouse (RBLC)..." 190 The 2008 BART analyses prepared by the commenter explicitly recognize that "[c]ontrol technol ogies required under the new s ource review (NSR) program as best available control technology (BACT) or lowest achievabl e 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 emi ssion limit to be achieved for such technology, this usually is sufficient justificati on 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 emi ssions performance level” that can be achieved by available pollution-reduction methods. 193 The language "requiring application" and "recent regulatory decisions" indicates th e 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 techno logy," specifically referring to DFGD/FF. No evidence is presented to support this assertion. This is di rectly contradicted by the performance of the examples we provide above, whic h include significant periods of time in which two of the units below 0.05 lbs/MMBtu, while burning a similar co al. 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 SO 2 to 95%. We note that based on the sulfur content of the coal specified in its reques t for proposal, this approximately equals 0.06 lbs/MMBtu.

Further, although we based our BART analys is on the ability of the six OG&E and

AEP/PSO units to meet a SO 2 emission limit of 0.06 lbs/MMBtu using dry scrubbers, we note

that the BART emission limit can be met with an y combination of technologies that the owner chooses. The subject DFGD/FF is not the only co ntrol 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 SO 2 emission rate less than the pr oposed 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 th e present based on a boiler operati ng 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 ro lling 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 discreti on to set emission limits that do not necessarily reflect the highest possible control efficiencies . However, as we explain belo w, 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 excessive ly large and unsupported. We ar e not aware of any technical

or scientific basis for ne arly doubling an achieved SO 2 emission limit. The comment fails to explain why a margin is required, given the pe rformance at Newmont and other sites, and specifically fails to explain why a margin of nearly a factor of tw o 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 in to account the full range of possible fuels.." However, the scrubber design is based on the ma ximum "anticipated" fuel sulfur content. Further, to the contrary, as expl ained –elsewhere in our response to comments, clean fuels is one

of the BART controls. The owner cannot de mand 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 SO 2 removal efficiency including type and quality of the reactant, reac tant stoichiometric ratio, inlet flue gas temperature, approach to sa turation 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 describe d above explicitly takes into account operating conditions and operating fluctuations. This comment presents no justification for an additional margin a bove actual operating data and system design.

Third, the comment argues "the BART analysis must take into account . . . normal wear100and-tear on the units and control systems." No rmal 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 cons ider 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 de sulfurization (WFGD) systems using

limestone as the reactant have demonstrated the ability to achieve greater than 95% SO 2 reduction on coal-fired boilers fi ring 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 SO 2 concentration in the flue ga s. OG&E states that even though WFGD systems are not typically used on u tility 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 SO 2 control option capable of achieving a higher SO 2 reduction, WFGD was determined to result in higher costs compared to DFGD. OG&E states that ODEQ recognized in its SIP th at 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 desulf urization 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 S ooner, $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 incrementa l cost effectiveness levels are significantly higher than the cost effectiveness values for DF GD systems. Therefore, WFGD is not a cost effective control option for th e 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 SO 2 BART limit. We did not assume any additional SO 2 emission reduction due to the use of a wet scrubber, although we believe it is capable of greate r reductions than a dry scrubber. We identified the wet scrubber only as an alternative met hod to meet the propos ed BART limit. We

194 70 FR 39172.

195 See Cichanowicz, October 15, 2010 p. 5 ($645/ton - $1950/ton,).

101are not advocating the choice betwee n two controls that result in two separate limits, but rather a single limit that can be met with two alternative technologies. Incr emental cost effectiveness is irrelevant for this case, because we based our SO 2 BART determination for the six OG&E and AEP/PSO units on the performance char acteristics and costs of a dry SO 2 scrubber.

Comment: AEP/PSO states that there is a mathema tical error in the TSD. They state that

the assumed baseline fuel for the six Oklahoma un its analyzed in the TSD is described using the unit of pounds of sulfur per million Btu. AEP/PSO st ates this is incorrect and should have been described as pounds of SO 2 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

SO 2 when burning the current coal (0.9 lb/MMB tu) which further supports that the units provided on Table 4 are incorrect.

Response: This is not a mathematical error. The units used for co al sulfur content throughout Appendix C are either we ight percent sulfur, expressed as a percent (%) or pounds of

SO 2 per million Btu of fuel combusted (lb/MMBtu). Thus, the units in Tables 1 and 4 are lb

SO 2 /MMBtu, not lb S/MMBtu. This distinction does not affect any of the calculations, which are all appropriately based in lb SO 2 /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 analys es 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 SO 2 from low

sulfur coals and meet SO 2 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 SO 2 emission limits of 0.03 lb/MMBtu.” Th ey 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 lo w 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 SO 2 and removal efficiency:

(From Page 43 of Technical Support Document) This report included a chart showi ng the relationship between inlet SO 2 and removal efficiency, reproduced in Figure 3. 175 This figure shows that

196 Ibid., TSD, Appendix C, pages 52-53.

102a dry scrubber on the Sooner and Muskogee units can remove about 90%

of the SO 2 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 sc rubber (1.18 lb/MMBtu). This figure also indicates that a dry scrubber on the Northeastern units can remove

93% of the SO 2 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, th e BART requirement to evaluate the maximum degree of reduction has not been satisfied.

175 Sargent & Lundy, Flue Gas Desulfur ization 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 applic ation of LSD technology, and is derived from Sargent & Lundy’s inhouse databa se 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 comp ared to the site-specific BART analyses.

Response: This figure was not used to determ ine the performance of scrubbers on the

Northeastern units. The role of this chart in the BART analysis is e xplained elsewhere in our response to comments. The performance of scru bbers 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) c ondition the averagi ng period for the SO 2 emission limit on the basis of “operating days,” in lieu of “calendar days,” in section 2(d).

Another commenter submitted a similar commen t. 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 fac ility-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 SO 2 emission limit should be based on Boiler Operating Days (BODs), rather th an 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 th e following midnight during which any fuel

103is 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 si mply 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 averagi ng scheme, days in which a unit is shut in for the full 24-hour period don’t coun t in calculating the 30 day averag e. 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 us ed by the other units. In fact, under the BOD averaging scheme, it is likely after an initial peri od 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 comple xity to the calculation of a plant wide average.

Just after the language appears in the BART Guidelines conc erning a plant wide average, we advise, “In addition, emissions limits must be enforceable as a practical matter (contain appropriate averaging times, compliance ve rification 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 enfo rceability. Therefore, we will condition the SO 2 limit for the six OG&E and AEP/PSO units on the ba sis of a rolling 30 day BOD average. We leave the issue of a plant wide average to a possi ble future SIP revision th at includes a verifiable, workable and enforceable algorithm that ensure s the resulting emissions are equal to those reductions that would be obtained by simply cont rolling each of the BART-eligible units that constitute BART-eligible source.

Comment: A commenter states we cannot, unde r any circumstances, impose SO 2 emission limits on the six OG&E and AEP/PSO units greater than the presumptive SO 2 emission limit, either 0.15 lbs/MMBtu, or 95 percent control. The comment er 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 argue s that is because 0.15 lbs/MMBtu is the "presumptive" limit. A comme nter reasons that a st ate 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

SO 2 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 shou ld 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.

104In 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 a nd the costs of compliance of alternative levels of control. Further, the BART Guidelines state 200

, 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 cu rrently best achievable at the time that you are conducting your BART analysis.

Thus, the BART Guidelines requ ire that potential emission limits that are more stringent than the presumptive limits must be examined as pa rt of the BART determination. As a result of our BART analysis, we adopted a more stringent emissions limit for SO 2 because dry scrubber control technology has been demons trated among similar facilities to be capable of achieving

this SO 2 emission limit and we find that OG&E and AEP/PSO units can achieve these SO 2 emission limits as well.

Comment: A commenter states using low-sulf ur coal does not satisfy BART requirements for coal-fired power plants, as the RH rule establishes presumptive SO 2 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 esse ntially based on a narrow aspect: the emission limits for S02 for six coal-fired electric generati ng 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 c ontinued use of low sulfur coal does

not constitute SO 2 BART for the six OG&E and AEP/PSO un its, as that practice would result in the emission of large amounts of SO 2 , which would cause or contribu te 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 na tural gas as a potential means of satisfying

BART.

Comment: A commenter states we failed to consid er the costs of imposing our preferred

SO 2 emission limits on ratepayers. The commenter states we are obligated to consider these costs under the CAA, which requir es consideration of "the cost s of compliance," which is a broader term than "cost-effective," CAA s ection 169A(g)(2), and pur suant to the Unfunded Mandates Reform Act of 1995, 2 U.S.C. section 1532(a).

200 70 FR 39166.

201 70 FR 39171.

105A commenter states that OG&E's 2011 Integrat ed Resource Plan shows that EPA's FIP would cost OG&E ratepayers $2,4 billion more th an ODEQ’s proposed RH SIP (which provides for burning low sulfur coal) on a present value ba sis. Moreover, states the commenter, OG&E's analysis shows that the conversi on 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 magni tude 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 cons equence of the increase in energy costs making Oklahoma goods uncompetitive. In the commente r’s view, not only are sc rubbers 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 AE P/PSO’s cost estimates for installing SO 2 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 co st 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 Ac t (UMRA) of 1995 requi res 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 tr ibal governments, in the aggregate, or by the private sector, of $100 million or more (annually adjusted for infl ation) in any one year" (Section 202(a)). According to the Bureau of La bor Statistics, adjusted for in flation 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 SO 2 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. Th is 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

106III. Comments Related to the SO 2 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 SO 2 BART controls contained in our FIP, appears to be inconsistent and could result in addi tional costs and potential delays for utility customers. The commenter not es 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 in consistent with the installation of SO 2 , "three (3) years

from the date our final determination becomes e ffective" 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 a nd 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 appr ove are typically much less challenging and require less time to retrofit than are the SO 2 BART controls (presumably scrubbers) necessary to meet our FIP for the si x OG&E and AEP/PSO units. These retrofits can either be staged or in some cases, performed at the same time as the SO 2 scrubbers that will be used to comply with the FIP. We believe gr anting 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 ti me schedule. As we discuss elsewhere in our response to comments, we have modified the time period for compliance with

our SO 2 BART FIP for the six OG&E and AEP/PSO un its to the same full five years allowed

under the RH rule.

Comment: A commenter states that re trofitting 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 retrof its, 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 year s is enough time for th e installation of dry

scrubbers on the six OG&E and AEP/PSO units. They state we are requ ired under the CAA to adopt a compliance deadline that reflects expeditious installati on of pollution controls. The commenter references the BART guidelines: “eac h source subject to BART [is] required to install and operate BART as expeditiously as pr acticable, but no later than five years after the date of EPA’s approval.” 40 CF R 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 th ese emission limitations. They state there are numerous examples of SO 2 scrubbers being installed at coal-f ired power plants within a three year timeframe. As an example, the commenter, states that a new SO 2 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 th at American Electric Power completed

203
http://www.constellation.com/SocialResponsibility/Environm entalPerformance/Pages/Bran donShoresScrubber.aspx

107construction of a scrubber at its John Amos power plant Un it 3 in three years. 204 The commenter

also states that TVA installed new SO 2 scrubbers at its Bull Run a nd Kingston power plants in about three years as well. 205 The commenter also states the installations of SO 2 scrubbers have also been accomplished in less than thr ee years, and cite the following examples:

The Indianapolis Power & Light installed an SO 2 scrubber at Unit 7 of its Harding Street Station in less than three year s, 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 SO 2 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 SO 2 scrubbers can be installed in three years or less time. Further, argues the commenter, we have often required scrubber installation to occu r 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 regardi ng Salt River Project’ s Coronado station required installation and operation of an SO 2 scrubber at Unit 1 by January 1, 2012 which essentially reflects three years fo r design, construction, and operation. 208 In addition, the

October 2007 consent decree with Am erican Electric Power requires SO 2 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, includ ing 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 othe r examples provide ample support that three years for installation of SO 2 controls and compliance with our proposed FIP is reasonable. In addition, these examples show that a BART compliance deadline for SO 2 controls longer than three years is not consistent w ith 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, extens ive planning is required. According to OG&E, the bid phase engineering, review, and cont ract 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 construc tion, 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-sc rubber-at-bull-run-plant-may-help-improve http://msbusiness.com/2010/06/tva-puts-new-scrubbers-in-operation/

206
http://www.iplpower.com/ipl/inde x?page=IPLGeneral&Menu=06000000& DocID=02039b33d0 a010bcb031 eea007b

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 h ttp://www.gulfpower.com/a bout/plant_crist.asp).

208 http://www.epa.gov/c ompliance/resources/decr ees/civil/caa/srp-cd.pdf

209 http://www.epa.gov/comp liance/resources/decrees/civil/caa/americanelectricpower-cd.pdf

108OG&E adds the schedule provide d above does not account for installation of two units that would be required at each of the Soone r 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 th at construction labor is available. OG&E adds

that the DFGD tie-in schedules must coincide w ith planned unit outages. OG&E concludes that based on the general retrofit schedule provided above, and challenges associated with the

simultaneous installation of fourDFGD systems, a 3-year complia nce 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 befo re 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 maxi mum of five years allowed under the RHR only if we demonstrate that compliance within that shor ter period is shown to be “practicable.” The

commenter states that we cannot make a show ing 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 b een practicable at another fac ility, continues the commenter, it does not mean it is practicable at the specific EGUs to which th is proposed rule would apply.

The commenter states that a BART determina tion 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 vari ables affecting feasibility, including costs.

AEP/PSO states that the RH Rule specifical ly 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 complete d prior to the commencement of construction. According to AEP/PSO, the planni ng, selection of engineering a nd design professionals, vendors and contractors, permitting, cons truction, startup and commissi oning required for AEP/PSO’s compliance with the proposed FIP is anticipated to take significantly l onger than the proposed three years, making a 36 month compliance schedule unachievable.

AEP/PSO states the complexity of the “constr uction” of an FGD system at an existing generating station is very site specific, wh ich 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 mode ling, 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 th e point that the long lead time major equipment

109orders can be placed, followed by the detailed en gineering 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 constr uction 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 provide d 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 develo ped in 2009 as part of a conceptual engineering study and completed by a third pa rty engineering, procurement and construction contractor.

AEP/PSO states the total duration from a “Noti ce to Proceed” to “first gas” through the new FGD/fabric filter system under that schedule wa s 53 months. AEP/PSO also cites another similar study conducted in 2011 by another indepe ndent 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 w ould 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 applica tions , 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 re quired before the landfill is available for first disposal use.

AEP/PSO states that the addi tion of FGD systems can trigger a need to construct a replacement stack if the origin al stack and liner materials cannot accommodate the different physical and chemical characteristics of the sc rubbed flue gas. According to AEP/PSO, the schedule to design, permit, procur e materials and install a typical concrete stac k 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 c limate, and the significant downturn in the number of large capital intens ive projects since 2008, domestic suppliers of environmental equipment, material and services have scaled ba ck production and skilled resources in an attempt to maintain their long term viab ility. 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 re sults 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 simultane ously to comply with other pending requirements, like EPA’s Clean Air Transport and Hazardous Air Po llutant rules, they will all be seeking the same components in a severely-c onstrained timeframe. Such mark et concentration, according to AEP/PSO, will increase lead time s for practically all significant components, even beyond those

110that are commonly quoted currently for similar eq uipment. AEP/PSO proposes that, in the event the FIP is issued, compliance with both the SI P 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 SO 2 BART emission limits be within three years of the effective date of our fina l 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 scr ubbers is now routine in the U.S. and that approximately 290 coal-fired units totaling a bout 116,000 MW nationwide have been retrofit

with scrubbers since 1990. The comme nter cites to many examples of SO 2 scrubbers being installed at coal-fired power plants within a thr ee year timeframe. OG&E, and others state that our proposed three year schedule focuses on actual construction time lines, but fails to acknowledge or allow sufficient time for the engi neering, design, and permit processes that must be completed prior to the commencement of co nstruction. 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 SO 2 BART emission limit, we exp ect that either dry or wet SO 2 scrubbers will be used, or that the SO 2 limit will be met by switching one or more of the units to natural gas. We agree that that SO 2 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 construc tion/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 SO 2 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 argum ent, 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 im provement, or de minimis levels since the deciview improvement must be weighed among the five factors, a nd 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 scr ubbers to each indi vidual facility and the costs per Δ -dv of visibility improvement. OG&E al so asserts that EPA does not sufficiently justify its disagreement with Oklahoma that the vi sibility 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 sour ces 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]ve n though the visibility improvement from an

111individual source may not be perceptible, it should still be considered in setting BART because the contribution to haze may be significant relative to other sour ce contributions in the Class I areas.” 70 Fed. Reg. at 39129. OG&E concludes, le ss-than-perceptible visibility improvements

from OG&E’s BART sources should not be cons idered significant in that context because visibility modeling shows OG&E’s sources are not one of the larger stationary source contributors to visibility imp airment at a Class I area.

Response: As we have discussed elsewhere in our response to comments, we find

Oklahoma’s BART determinations for SO 2 for the six OG&E and AEP/PSO units are not approvable. We conclude they are not appr ovable 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 Mus kogee plants and the EPA is under a consent decree deadline to act on controlling these sources si nce 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 ab solute 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 ha ve a supportable rationale to disapprove Oklahoma’s determination that the degree of visi bility improvement due to the installation of scrubbers does not support the cost of insta llation of scrubbers. We provided a well reasoned and complete evaluation of the visibi lity benefits the installation of SO 2 scrubbers on the six AEP /PSO and OG&E units in question are predicted to have on four Class I ar eas. As we stated in the proposal 210 :

[W]e disagree with ODEQ’s conclusion on costs for SO 2 controls and we

find that cost effective SO 2 controls are available and our modeling

demonstrates that substantial visibi lity 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 SO 2 scrubbers (wet or dry) on each of the three faci lities (2 units at each facility) will reduce visibility impairment at Cla ss 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 visi bility impairment to levels that are below the 0.5 deciview threshold that ODEQ used for determining if a source contributed to visibility impair ment. 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

112We agree with OG&E that sources in Texas ar e 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 premis e that because the hundreds of Texas sources collectively contribute more to vi sibility impairment than OG&E’s four BART sources, those BART sources should not be c ontrolled. The CAA and the RHR do not provide an exemption to BART if a source contributes less than other sour ces to visibility impairment. Furthermore, regarding OG&E’ s argument concerning the pe rceptibility of visibility improvement, the RHR is clear that perceptibility of improvement is not a test for the suitability

of BART controls in the senten ce following the one OG&E’s quoted 211 :

Thus, we disagree that the degree of improvement should be contingent upon perceptibility. Failing to consider less-than-perceptible contributions to visibility impairment would ignor e the CAA’s intent to have BART requirements apply to sources that cont ribute to, as well as cause, such impairment.

We discuss the visibility benefits that ar e projected to occur as a result of our SO 2 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 th at we have appropriate ly conducted the BART

evaluation for Units 4 and 5 of the OG&E Mus kogee 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 author izes 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-eff ectiveness measures (such as $/deciview).” 70 Fed. Reg. at 39,170. OG&E states the RHR also r ecognizes 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 RH R. We, OG&E asserts, may not ignore the $/ Δ -dv metric now in disapproving of th e State’s determinations and EP A has not and cannot show that scrubbers are cost-effective in terms of $/dv, ev en when using our own understated estimates of

the total annual costs of scrubbers. OG&E furthe r alleges that we inco rrectly rejected ODEQ’s
reliance on the $/ Δ -dv metric in reaching our BART determ ination as well as not considering visibility improvement cost effectiven ess in our FIP BART determination.

OG&E states the Federal Land Managers have asserted that $10 - $19 million/dv should

be considered reasonable for SO 2 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 i ndicate 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 SO 2 control. OG&E’s states its May 2008 BART evaluations, which were develope d 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 lo w 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

113relation to a relatively small improvement in visibi lity 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 un its 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 believe s that since the $/dv is much higher for its four BART units in compar ison to these BART units, th e costs of our proposed SO 2 controls is

not warranted. OG&E concludes th at EPA’s failure to recognize Oklahoma’s assessment of the
$/dv metric for SO 2 control at the OG&E Units is arbitrary, capricious and contra ry 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
$/ton 212 . OG&E provided a $/decivi ew 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 m easure 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 determinati ons. We note that to use the $/deciview metric as the main determining factor would most lik ely require the development of thresholds of acceptable costs per deciview of improvement fo r 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 me tric as part of its proposed BART determinations for either the Fo ur 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 $/deci view metric as suggest ing 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 de terminations set forth in Oklahoma’s SIP the SIP followed EPA’s five-step process se t forth in the Guidelines. The commenter

believes the Oklahoma SIP balanced the cost-b enefit factors and determined that EPA’s presumptive emission limit for SO 2 was not justified by the visibility improvement benefits. However, the commenter alleges we conflated “c ost 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 sour ce-specific basis. The commenter states the purpose of the RH progr am is to improve visibility not, per se, to

reduce SO 2 emissions, and that the term “cost-effec tive” does not even appear in Section 169A, much less any requirement that a source can be required to reduce SO 2 emissions if the cost of

212 70 FR 39167.

114doing so is below a certain dollars-per-ton level. A source, states the commenter, can only be required to reduce SO 2 emissions under Section 169A if it is justified by weighing the cost of reducing SO 2 emissions against visibility improvements.

The commenter acknowledges, the BART Guidelin es set forth a cost-effectiveness test in terms of dollars per ton of SO 2 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 SO 2 removed is an informational item that EPA has used to create a rebutta ble presumption of a 0.15

lbs/MMBtu SO 2 emission limit, but does not eliminate the need to apply the five statutory BART determination factors in weighing th e cost of control technologies against visibility benefits, and it does not provide that a BART determination shoul d 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 di scussed 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. Fo r 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 th e collective contribution of many sources of air pollution over a broad region. However, visibility improve ment cannot be accomp lished without reducing emissions including SO 2 emissions.

We disagree with the commenter that we confused “cost of compliance” with “costeffectiveness,” or that issue is even signifi cant to our BART determination. We note we proposed “that ODEQ did not properly take into c onsideration the ‘costs of compliance’ when it relied on cost estimates that greatly overestimate d the costs of dry and we t scrubbing to conclude

these controls were not cost effective.” 213 Use of the term, “cost e ffective” 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 SO 2 emissions

under Section 169A if it is justified by weighing the cost of reducing SO 2 emissions against visibility improvements. We would add that determination must follow RH rule. As the commenter acknowledges, the BART Guidelines explain 214 that cost effectiveness is expressed in terms of the $/ton factor, wh ich 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 w ould not have the ability to judg e whether the cost of compliance for one particular contro l was more suitable than another. We disagree that $/ton is an

informational item that EPA has used to crea te a rebuttable presump tion of a 0.15 lbs/MMBtu

SO 2 emission limit, as the BART Guidelines clearl y require its use for th e 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.

115116 apply the five statutory BART determination fact ors in weighing the cost of control technologies against visibility benefits , which we have done.

Comment: A commenter states that the main object ion to limiting emissions at the power plants is the cost. According to the commenter, the power plants have op erated 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 reasonabl e time for the power plants to come into compliance. The commenter believes that AE P/PSO and OG&E should have made a move toward compliance long ago, and furt her 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 ha ve overstated the cost of installing SO 2 scrubbers at the six units in que stion. We discuss the BART co mpliance 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. Th e commenter believes we did not conduct a full analysis of the costs that will be required by u tilities if the FIP is implemented. The commenter states that according to its consultant, the Okla homa coal plants in que stion 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 EP A FIP-required scrubbers to be installed on the existing coal plan ts, 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 consid eration of the remaining useful life of facilities when considering the costs of potentia l 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 respons e to another comment, we find that our original dete rmination that the scrubbers for the six OG&E and AEP/PSO units should have a 30 year usef ul life remains correct.Attachment 1Sargent & Lundy FabricFilter IPM Model StudyAs discussed in our response to comments, we incorporated the algorithm from the fabric filter baghouse model developed by Sargent & Lundyfor EPA's IPM Model215into a spreadsheet to explore the savings from buildingone large baghouse to serve each unit, rather than two 50%baghouses as included in the Request for Quote and vendor proposals. The full spreadsheet, alongwith a copy of the report from which it wasderived, has been added to the docket for ourfinal action, and a screen copy of thespreadsheets is reproduced herein. The results of our analysisare summarized in Table 1 in our response to comments. Presented here are 4 screenshots of theresults of this model: A 100%baghousedesigned for one of the Sooner units (570 MW), one 50% baghousefor one of the Sooner units (285 MW), a 100% baghouse designed for one ofthe Muskogee units (572 MW), and one 50% baghouse for of one of the Muskogee units (286 MW).215IPM Model – Revisions to Cost and Performance for APC Technologies, Particulate Control Cost Development Methodology, Final,March 2011, Project 12301-009, SystemsResearch and Applications Corporation, Prepared by, Sargent & LundyFigure 1-100% Baghouse for Sooner (570 MW)2Figure 2 - 50% Baghouse for Sooner (285 MW)3Figure 3 - 100% Baghouse for Muskogee (572 MW)4Figure 4 - 50% Baghouse for Muskogee (286 MW)5

### Attachment 2 Sargent & Lundy SDA IPM Model Study

We have revised our Option 2 cost anal ysis to address the sulfur content/sizing issue raised in this and other comments. Our revised Option 2 anal ysis relies on certain design algorith ms 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 desi gn coal, for example, has a higher heat content than currently burned coal and would thus generate less flue gas, reducing co sts. Further, this model does not optimize mass transfer to account for the smaller amount of SO 2 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 sc rubber 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 c ontents that we analyzed in the TSD, 0.48% sulfur (1.176 lb SO 2 /MMBtu) and 0.22% sulfur (0.509 lb SO 2 /MMBtu), assuming a 100% capa city factor. The results of this analysis indicates that the use of the lower sulfur coal alone would reduce the ca pital 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 spread sheet and information on the model is reproduced herein. The 3% reduction is incorporat ed 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

2Figure 2 – Sooner SDA Cost with 0.509 lb/MMBtu Coal

3Figure 3 – Muskogee SDA Cost with 1.176 lb/MMBtu Coal

4Figure 4 – Muskogee SDA Cost with 0.509 lb/MMBtu Coal

5

### Attachment 323