# United States Departmentofthe Interior FISHAND WILDLIFE SERVICE NationalWildlifeRefuge System Branch ofAir Quality 7333 W. Jefferson Ave., Suite 375 IN REPLY REFERTO: Lakewood, CO 80235-2017 FWS/ANWS-AR-AQ November 8, 2007 Laurel Dygowski Air Quality Planning & Management Unit US EPA Region 8 1595 Wynkoop Street Denver, CO R0202 ·l:?Q RE: Comments onthe Corette Generating Station Best Available Retrofit Technology (BART) Assessment, Billings, Montana



# __.J**IJlwl~** Dear Ms. D)%owski: I am sending these draft comments on the Corette Generating Station BART determination at this time withthe understanding that our final comments will be incorporated within our overall review on reasonable progress ofthe Montana Regional Haze Federal Implementation Plannear the end ofthe60-day commentperiod.

. The facility is owned and operated by PPL Montana, LLC (PPL), which includes one Electric Generating Unit (EGU), in Billings, MT. The plant is located within 300 km ofseven Class I areas: North Absaroka Wilderness Area, Yellowstone National Park, Washakie Wilderness Area, Ui. Bend National Wildlife Refuge, Teton Wilderness Area, Gates ofthe Mountains Wilderness Area, and Red Rock Lakes. The boiler is tangentially-fired using Powder River Basin sub-bituminous coal (0.3% weight percent sulfur) and israted at 154 MW. The hoiler is equippecl with ::In f'lf'rtf0<:tnti /'**pre(·i~i.t?t0!** (ESP) to control emissions ofparticulate matter (PM), and lowNOx burners (LNB) and close coupled over-fire air to limit the formation ofnitrogen oxides (NOx). 

### Visibility Improvement Comments We believe that it is appropriate to consider boththe degree ofvisibility improvement in a given Class I area as well as the aggregate effects ofimproving visibility across all ofthe Class I areas affected. For the PPL/Corette BART-eligibleunit, the base case shows the greatest impact to visibility at any single Class I area is 0.645 deciviews (dv) at UL Bend Wildlife Area. Impacts to visibility are shown fOf each ofthe seven Class I areas analyzed in the BARTreport, and for three ofthese. impacts are at or above the 0.5 dv BART screening threshold. The collective impacts and potential improvements should be addressed by the BART determination.

### TAKEPRIDr~**INA.MERICA~**PPL analyzed several potential BART options to projectthe visibility improvementthat would be realized in each case. The largest, single improvement was 0.238 dv using wet scrubbing for S02 control. PPL concluded onpage 5-2 that, ifthe amount ofvisibility improvement resulting from a reduction in emissions is 0.238 dv, it is not discernable, and therefore the cost ofachieving the improvement is notjustified. EPA states in the preamble to its BART Guidelines that, "Even though the visibility improvement from an individual source may not be perceptible, I it should still be considered in settingBARTbecause the contributionto haze may be significantrelative to other source contributions in the Class I areas. Thus, we disagree thatthe degree of improvement should be contingentuponperceptibility. Failingto consider less-than-perceptible contributions to visibility impairment would ignore the CAA's intentto have BART requirements apply to sources that contribute to, as well as cause, such impairment.,,2 General Cost-Effectiveness Comments EPA's BART guidelines state, "The basis for equipmentcost estimates also should be documented, either with data supplied by an equipmentvendor (i.e., budget estimates orbids) or by a referenced source (such as the OAQPS Control Cost Manual). In orderto maintain and improve consistency, cost estimates should be based onthe OAQPS Control CostManual, where possible. The Control Cost Manual addresses most control technologies in sufficient detail for a BART analysis. The cost analysis should also take into account any site-specific design orother conditions identified above that affect the cost ofa particular BARTtechnology option.,,3 While PPL used the Cost Manual in many cases, it used a 1988 EPRI study for the PM control equipment costthat was notprovided and may well be outofdate, or provided no supporting documentation at all. In addition, the capital cost for the S02 control equipmentwas done using the "AirPollution Control Technology Fact Sheet, Flue Gas Desulfurization (FGD)

- Wet, Spray Dry, and Dry Scrubbers" (EPA-452/F-03-034). This document is meantto provide information and estimated cost ranges for using various FGD technologies, and is not intended to be used for cost analyses. The analysis used the OAQPS control cost method to calculate the annualized cost for the control technology. The equations and assumptions used to calculate the annualized cost are reasonable except for the equipment life. The analysis used a usetulliie of 11 years for all ofthe control technologies, which correspondsto a capital recovery factor of0.1334. The typical useful life of these control technologies are expectedto be 20 years, which would reduce the capital recovery factor to 0.09439. The boiler is expected to have a useful life beyond 20 years, and therefore do not have any effect onthe useful life determinations.

I EPA's threshold ofperceptibility is 0.5 dv. 2 See Federal Register at 70 FR 39129, July 6, 2005; middle column 3 See 40 CFR Part 51, Appendix Y, Section IV.DA.a.5. The U.S. Environmental Protection Agency finalized it's BART Guidelines on June 15,2005, and published the preamble and final rule text in the Federal Registeron July 6, 2005. The rulemaking action added Appendix Y to Part 51, titled "Guidelines for BARTDeterminations Under the Regional Haze Rule." The section ofthe Appendix referenced above appears in the Federal Register at70 FR 39166, July 6, 2005. 2We are also concerned with the way in which the incremental cost analysis was used. According to EPA'sBART Guidelines, "You should considerthe incremental cost effectiveness in combination with the average cost effectiveness when considering whetherto eliminate a control option

.... ,,4 "You should exercise cautionnot to misuse these [average and incremental cost effectiveness] techniques

... [but considerthem in situations where an option shows]

...slightly greater emission reductions

...,,5 Reviewing agencies are quite familiar with the concept oftotal average cost and expect to see costs inthe $2,000

- $12,000 per ton range. However, incremental costs are rarely estimated and evaluated, so the much higher numbers that result appear quite high at first glance. For this reason, rigid use ofincremental cost effectiveness will always result inthe choice ofthe cheapest option ifcarried to the extreme. For example, ifonly incremental costs were used to evaluate PM controls, it is likely that all controls more expensive than a multiple cyclone would be rejected. To use incremental costs properly, they must be compared to incremental costs for similar situations. In addition, in situations where a facility's emissions affect visibility at multiple Class I areas, consideration should be givento the control cost comparedto the aggregate visibility improvementprojected (i.e., cost/total dv reduction, or some other method).

PPL considered five approaches for reducing S02 emissions: coal pre-treatment, alkali wet scrubbing, limestone scrubbing with forced oxidation, spray dryer absorption, and dry injection. The analysis did notprovide any fuel switching options. The evaluation used a S02 emission rate of0.46lb/MMBtu as the base case for the cost analyses. This base case S02 emission rate was obtained from averaging the facility's CEM data for the Years 2001-2003. The facility notes that the boiler already combusts a low-sulfur coal. PPL eliminatedthe coal pre-treatment approach because the coal is already low-sulfur and gasification ofthe coal wouldrequire a complete change in the operation. The analysis did not distinguish betweenthe other control technologies and insteadpresented cost evaluations for dry injection and wet scrubbing approaches. The dry injection options were performed using a 25% S02reduction and a 70% S02reduction. The wet scrubbing option was performed at an emission reduction at 70% S02 reduction. The 25% S02 reduction option was performed because the facility believed thatthis reduction level does not impactthe PM emissionrate. The cost analysis for the control technologies uses an EPA Fact Sheet to supportthe equipment costs contained in the appendices. The capital equipment costs were estimated to be $24,300,000

4 See 40 CFR Part 51, Appendix Y, Section IV.DA.e.l., also appearing in the Federal Register at 70 FR39167, July 6,2005.

5 See40 CFRPart 51, Appendix Y, Section IV.DA.e.5., also appearing in the Federal Register at 70 FR 39168, July 6,2005. 6 The presumptive S02 limit for similar boilers is 0.15 Ib/mmBtu. 3for the 25% dry injection option and $243,000,000 for each ofthe 70% dry injection and wet scrubber options. Both ofthese capital equipment cost estimates are extremely high in comparisonto other estimates. As an example, the lime injection equipment cost supplied in the Colstrip Generating Station BART analysis was only $1,500,000. PPL should re-evaluate the costs and benefits ofreducing S02 usingtechniques developed in the OAQPS Control Cost Manual.? The PPL BART analysis states that coal cleaning would not result in sulfur reductions; however there are no calculations or documentationthat supports this.

The Corette facility is currently equipped withLowNOxBurners (LNB) and Close Coupled Over-Fire Airto reduce emissions ofNOx. PPL considered 4 approaches for reducing NOx emissions: boiler tuning, separated over-fire air (SOFA), selective non-catalytic reduction (SNCR), and selective catalytic reduction (SCR). PPL statedthat each ofthese control options were feasible and proceeded to estimate the cost effectiveness ofeach ofthe options. No options for fuel switching (i.e., natural gas, fuel oil) were presented in the analysis. PPL evaluated the costs effectiveness ofeach ofthese options using cost data from the World Bankfor the SOFA option and the OAQPS Cost Manual for the SNCR and SCR options. The boilertuning cost was not referenced, but appears that it may be based on past cost information for the boilers. PPL estimated the emissionreductions for the boilertuning and the SOFA options using typical NOxreductions using these technologies. The cost effectiveness for these options are $147 per ton ofNOx reduced for the boiler tuning option, and $914 per ton ofNOx reduced for the SOFA option. These values are reasonable in comparison to other control cost calculations. The SNCR and SCRcost effectiveness options were calculated based on achieving an NSPS emissionrate of0.16 Ib/MMBtu for SNCR and 0.15 Ib/MMBtu for SCRfrom the current emissionrate of0.26 Ib/MMBtu. This translates to only 38.5% reduction efficiency for SNCR and 42.3% reduction efficiency for SCR. EPA states that SCR is capable ofachieving 90-99% reduction in NOx emissions from similar units. Therefore the cost effectiveness value of$4,354 per ton ofNOxremoved for SCR is biased high in comparisonto other SCR application costs. We believe thatPPL should re-evaluate the cost effectiveness and visibility improvements from applying SCR to the boiler. PPL's cost analysis is based upon several significant errors and misrepresentations: • PPL has assumed that addition ofSNCRto SOFA could reduce NOx emissions by about 19%. However, EPA estimates that SNCRcan reduce NOx by 40%

- 50% for a boiler this size.9 PPL should re-evaluate SNCR at these higher efficiencies.

7 PPL should alsojustifyusing an eleven year equipment life instead ofthe 15 years assumed bythe OAQPS Control Cost Manual. 8 The presumptive NOx limit for similar boilers is 0.15 Ib/mmBtu. 9 OAQPS Cost Manual, pl-3 and EPA Cost Tool for Corette 4• PPL concluded that the $1,723/ton cost ofSNCRis notjustifiable. However, in the preamble to its BART Guidelines, EPA states, "The limits provided were chosen at levels that approximately 75 percent ofthe units could achieve with current combustion control technology. The costs ofsuch controls in most cases range fromjust over $100 to $1000 perton."lO This range ofproposed control costs includes addition ofSOFA at Corette. Application ofEPA's Cost Tool model to Corette predicts that 40%NOx reductions can be achieved for $826

- $1016 perton. • PPL has assumedthat addition ofSCRwould reduce NOx by 52% to 0.15 Ib/mmBtu. However, EPA estimates that SCRcan reduceNOxby 70% to 90% or more for aboiler this size. ll IfSCR is capable ofreducing emissions below PPL'starget, thenthe amount ofthe reductions and consequent visibility improvements will increase. PPL should reevaluate SCRat these higher eftlciencies.ll
Technical Feasibility of ROFA: In the preamble to its BART Guidelines, EPA states "Forthose units that cannot meetthe presumptive limits using current combustion control technology, states should carefully considerthe use ofadvanced combustion controls such as Rotating Over-Fire Air (ROFA) in theirBART determinations." 13 PPL did not consider ROFA, and provided no reason why this technology could not be transferred 14 from similar, but smaller applications, such as at MJ'J" Power's Taconite Harbor facility where it will install Mobotec multi-pollutant control technology on each ofthree 75 MWboilers to reduce SOl (by 65% to 0.24Ib/mmBtu) and NOx (by 64% to 0.14Ib/mmBtu). 

### PMlOBART PPL considered 4 approaches at Corette for reducing filterable particulate emissions; fabric filter (baghouse), electrostatic precipitator, mechanical collectors (i.e., cyclones), wet scrubbers. PPL eliminated mechanical collectors and wet scrubbers because they are unable to achieve the high efficiencies to reach the 0.015 Ib/MMBtu NSPS emission rate. The use ofa mechanical collector in conjunction withthe existing ESP should achieve a significant reduction in PM emissions from the boiler with relatively little cost. However, this scenario was not researched inthis analysis. The wet scrubber was analyzed as a control option for SOl, but not for PM. No options for fuel switching (i.e., natural gas, fuel oil) were presented inthe analysis. Also there was no discussion on remodeling the current ESP to increase the PM removal efficiency. The uncontrolled emission rate for the boilerused in the cost effectiveness calculations are based onthe stacktest results from the ESP outlet. Therefore, the cost effectiveness calculations for

10 See 70 FR 39135, July 6,2005, first column. II OAQPS Cost Manual, p2-3 and EPA Cost Tool for Corette 12 No reason is given in the BART analysis for setting this target. However, EPA has proposed that the Desert Rock powerplant meet a 24-hour average NOx limit of0.06 Ib/mmBtu. 13 See 70 FR39135, July 6, 2005; middle column belowtables. 14See 40 CFR Part 51, Appendix Y, Section IV.D.2., also appearing in the Federal Register at 70 FR 39165, July 6, 2005, which says: "Deployment ofthe control technology on a new orexisting source with similar gas stream characteristics is generally a sufficient basis for concluding the technology is technically feasible barring a demonstration to the contrary as described below." 5BART are in conjunction with the currently installed ESP. We believe this approach provides unrealistic and inflated cost effectiveness values for applying BART. The cost effectiveness calculations should be based on the actual uncontrolled emissionrates (i.e., inlet emission rates before the ESP). No information onthe PM removal efficiency ofthe currently installed ESP was provided in the analysis. The 

### PPL BART analyses assume thatthe lowest emission rate achievable by either a fabric filter (baghouse) or an ESP is 0.015 

### lb/mmBtu. Datafrom EPA has shownthatthese technologies are able to achieve lower emissionrates thanthe NSPS level. For example, the Desert Rockpower plantwill meet a filterable PMIO limit of0.010 

### lb/mmBtu. We believe that 

### PPL should reevaluate the costs and benefits ofreducing PM to the level that EPA has said represents Best Available Control Technology using techniques developed inthe OAQPS Control Cost Manual.J5 Equipment costvalues for the ESP and FF are based on costdata from the Air Pollution Engineering Manual developed bythe Air & Waste Management Association. The capital costs were obtained using $60/kWfor the ESP and $50/kWfor the FF and are based on a collection efficiency of99%. These capital cost values seem high in comparisonto other cost evaluations for these technologies. Conclusions & Recommendations



### • PPL should recognize that control equipment can achieve varying degrees ofcontrol based upon how it is designed and operated, and use the highest level ofcontrol feasible in its analyses. • Impacts upon all affected Class I areas should be considered collectively. Therefore, the relative cost-effectiveness ofcontrol strategies should be compared on a costldeciview improvement basis. • The costs ofadding SOFA and SNCR are economically feasible and produce relatively high visibility benefits. 

### • PPL should re-evaluate application ofROFA. 

### • PPL should evaluate meeting a lower filterable PMIO limit using the highest degree of control for the ESP and FF. 

### • PPL should use a useful life of20years for calculating annual cost ofthe control equipment rather than the 11 years used in the BART assessment. • Because oflE. Corette Power Plant's geographic location and its impacts to visibility at multiple Class I areas, the Federal Implementation Plan's Reasonable Progress analysis may benefit from revisiting the options for controls at this facility. We lookforward to working with EPA and 

### PPL as thisprocess advances. We believe that good communication and sharing ofinformationwill help expedite this process, and suggestthat you

15 PPL should also justity using an eleven year equipment life instead ofthe twenty years assumed by the OAQPS Control Cost Manual. 6contact Tim Allen (Tim_Allen@fws.gov at (303) 914-3802) ofmy staffifyou have any questions or comments. Sincerely,

# xJarr&tc~ 

# YliJCu Sandra Silva, Chief BranchofAir Quality

cc: Richard Coleman, Regional Chief National Wildlife Refuge System FWS-Mountain Prairie Region DenverFederal Center P.O. Box 25486 Denver, CO 80225 Barron Crawford, Project Leader UL BendNational Wildlife Refuge P.O. Box 110 Airport Road Lewistown, MT 59457 Ann Mebane USDA

- U.S. Forest Service Bruce Polkowsky National Park Service

- Air Resources Division

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