UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
 

REGION 8
 

1595 Wynkoop Street 

DENVER, CO 80202-1129 

Phone 800-227-8917 

http://www.epa.gov/region08 

FEB - 4 2008 

Ref: 8P-AR 

James Parker 

Manager - Compliance Services 

PPL Montana, LLC 

303 N. Broadway, Suite 400 

Billings, MT 591 01 

Re: Best Available Retrofit Technology (BART) Assessment J E. Corette Generating Station 

Dear Mr. Parker: 

On February 28,2007, EPA Region 8 sent a letter to PPL Montana- Corette (PPL) that 

provided the results of our "subject to" modeling for Best Available Retrofit Technology 

(BART) and requested that PPL perform a BART analysis for Corette Generating Station 

(Corette) and submit it to EPA Region 8. On August 10,2007, PPL submitted a BART analysis 

to EPA that was performed by TRC. We would like to thank you for submitting the BART 

analysis and recognize the effort that has gone into developing this document. 

We have completed our initial review of the August 10,2007 submittal and have 

determined that there is additional information and analysis needed from PPL in order for us to 

complete our review on Corette. Following are EPA Region 8's comments on the analysis. In 

addition, we are attaching a copy of comments on the BART analysis for Corette submitted to 

EPA on November 8, 2007 from the U.S. Fish and Wildlife Service. 

Visibility Improvement and Impacts 

Throughout your analysis, you state that the amount of visibility improvement resulting 

from a reduction in emissions, based on your current BART analysis, would not be discernible 

and therefore additional controls are not justified. The visibility improvement for S02, NOx, 

and PM in your analysis are all below 1.0 deciviews, and this is used as a reason not to 

implement more stringent control measures. EPA disagrees with your assertion. EPA states in 

the preamble to its BART Guidelines that, "Even though the visibility improvement from an 

individual source may not be perceptible, it should still be considered in setting BART because 

the contribution to haze may be significant relative to other source contributions in the Class I 

areas." (see 70 FR 39129, July 6, 2005). Visibility modeling shows that for numerous Class I 

areas in Montana, Corette is one of the larger stationary source contributors to visibility 

impairment. 
In addition, failing to consider less-than-perceptible contributions to visibility impairment 

would ignore the Clean Air Act's (CAA) intent to have BART requirements apply to sources that 

contribute to, as well as cause, such impairment (see 70 FR 39129, July 5, 2006). The BART 

Guidelines indicate that for purposes of determining which sources are subject to BART, "A 

single source that is responsible for a 1.0 deciview change or more should be considered to 

"cause" visibility impairment; a source that causes less than a 1.0 deciview change may still 

c;ontribute to visibility impairment and thus be subject to BART." (see 70 FR 39161, July 5, 

2006). The BART Guidelines further state that "As a general matter, any threshold that you use 

for determining whether a source "contributes" to visibility impairment should not be higher than 

0.5 deciviews" (see 70 FR 39161, July 5,2006). Given that EPA has said that sources are subject 

to BART based on a contribution threshold of no greater than 0.5 deciviews, it would be 

inconsistent to automatically rule out additional controls where the improvement in visibility 

may be less than 1.0 deciview or even 0.5 deciviews. 

General Comments 

1.	 PPL's analysis is based on adding control technology to meet what it terms "best 

demonstrated technology." PPL assumes recently updated NSPS emission limits for 

particulates, S02, and NOx represent best demonstrat~d technology and does not take into 

account the highest efficiency many of these control technologies are capable of 

achieving. However, the BART Guidelines state that "It is not our intent to require 

analysis of each possible level of efficiency for a control technique as such an analysis 

would result in a large number of options. It is important, however, that in analyzing the 

technology you take into account the most stringent emission control level that the 

technology is capable of achieving. You should consider recent regulatory decisions and 

performance data (e.g., manufacturer's data, engineering estimates and the experience of 

other sources) when identifying an emissions performance level or levels to evaluate." 

(see 70 FR 39166, July 6, 2005). Throughout your analysis, you have not evaluated 

control technologies with the most stringent emission control level, resulting in inflated 

calculated cost effectiveness values. PPL needs to redo the analysis for control 

technologies using the most stringent emission control level that the technology is 

capable' of achieving. Specific examples of this include: 

PPL should reevaluate the costs and benefits ofreducing S02 based on a higher 

removal efficiency. For S02, PPL only estimates a maximum 75% removal 

efficiency with additional control technology, but in the EPA Control Cost 

Manual, EPA states that most absorbers have removal efficiencies in excess of 

90% and packed tower absorbers have removal efficiencies as high as 99.9% 

("EPA Air Pollution Control Cost Manual" Sixth ed., EPA-452-02-00 1, January 

2002, Section 5.2, Chapter 1, pg 1-3). 

The BART analysis assumed that the addition of SNCR to SOFA could reduce 

NOx emissions by about 19%. However, EPA estimates that SNCR can reduce 

NOx by 40%-50% for a boiler this size (EPA 2002, Section 4.2, Chapter 1, pg 1­

3). ppL should re-evaluate SNCR at these higher efficiencies. 

2 
PPL has assumed that the addition of SCR would reduce NOx by 52% to 0.15 

lb/MMbtu. However, EPA estimates that SCR can reduce NOx by 70%-90+% for 

a boiler this size (EPA 2002, Section 4.2, Chapter 2, pg 2-3). IfSCR is capable of 

reducing emissions below PPL's target, then the amount of the reductions and 

consequent visibility improvements will increase. PPL should re-evaluate SCR at 

these higher efficiencies. 

2.	 The cost analysis for the control technologies included in the analysis does not contain the 

proper documentation to support the costs contained in the appendices. The BART 

.Guidelines state that "Once the control technology alternatives and achievable emissions 

performance levels have been identified, you then develop estimates of capital and annual 

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

supplied by an equipment vendor (i.e.,nbudget estimates or bids) or by a referenced 

source (such as the OAQPS Control Cost Manual, Fifth Edition, February 1996, EPA 

453/B-96-00l). In order to maintain and improve consistency, cost estimates should be 

based on the OAQPS Control Cost Manual, where possible." (see 70 FR 39166, July 

6,2005). PPLneeds to provide the proper documentation to support the costs used in the 

analysis. Please note that the "OAQPS Control Cost Manual", Fifth Edition, referenced 

above has been replaced by the "EPA Air Pollution Control Cost Manual", Sixth Edition, 

January 2002. 

3.	 There is a discrepancy between the emission rates discussed in the text and those 

presented in tables 4-9 and 4-12. For example, the text on page 4-20 discusses reaching 

0.18 lb/MMBtu ofNOx through the application of SOFA, however table 4-12 shows that 

the application of SOFA would achieve only 0.21lb/MMBtu. It appears that the lower 

emission numbers in the text reflect 24-hour averaging times, while those in the table 

reflect 30-day rolling averages. Since the EPAfWRAP modeling that was conducted to 

de~ermine that Corette is subject-to-BART was based on 24-hour actual emission rates, 

we believe that modeling conducted to show the visibility improvement from applying 

controls should also be based on 24-hour averages. In addition to the modeling that has 

been provided, PPL needs to remodel the control measures based on 24-hour averages. 

S02 Emissions and Controls 

4.	 The analysis used 11 years for the remaining useful life for all of the control technologies; 

however, the typical useful life of these control technologies is expected to be 15 years 

based on information from the EPA Control Cost Manual (EPA 2002, Section 5.2, 

Chapter 1, pg. 1-28). The boilers are expected to have a useful life beyond 20 years, and 

therefore do not have any effect on the useful life determinations. PPL needs to reanalyze 

the annualized costs for the control technologies using fifteen years as provided in the 

EPA Control Cost Manual. . 

5.	 The capital cost for the S02 control equipment was done using the "Air Pollution Control 

Technology Fact Sheet, Flue Gas Desulfurization (FGD) -Wet, Spray Dry, and Dry 

Scrubbers" (EPA-452/F-03-034). This document is meant to provide information and 

3
 
estimated cost ranges for using various FGD technologies, and is not intended to be used 

for cost analyses. The cost analysis for the control technologies based on the EPA Fact 

Sheet has resulted in capital equipment cost estimates that are high in comparison to other 

estimates. As an example, the capital equipment costs were estimated to be $24,300,000 

for the 25% dry injection option and $243,000,000 for each of the 70% dry injection and 

wet scrubber options: The lime injection equipment cost supplied in the Colstrip 

Generating Station BART analysis was only $1,500,000. PPL needs to use the EPA 

Control Cost Manual to re-evaluate the costs and benefits of reducing S02 from the 

boiler. 

6.	 In your BART analysis, you did not analyze any fuel switching options for 502 control. 

Fuel substitution to lower the fuel sulfur content can be a very cost effective means for 

reducing S02 emissions and should be analyzed. The analysis does state that coal 

cleaning would not result in sulfur reductions; however there are no calculations or 

documentation that support this. PPL needs to provide an analysis for fuel switching 

options and provide an analysis to show what emission reductions coal cleaning would 

result in. 

NOx Emissions and Controls 

7.	 The analysis used 11 years for the remaining useful life for all of the control technologies. 

However, the typical useful life of these control technologies is expected to be 20 years 

based on information from the EPA Control Cost Manual (EPA 2002, Section 4.2, 

Chapter 1, pg. 1-39). The boilers are expected to have a useful life beyond 20 years, and 

therefore do not have any effect on the useful life determinations. PPL needs to reanalyze 

the annualized costs for the control technologies using twenty years as provided in the 

EPA Control Cost Manual. 

8.	 You state in the BART analysis that the new NOx NSPS level is below the presumptive 

BART level and therefore was not analyzed. The BART Guidelines require an analysis 

of a level of control equivalent to NSPS, even if it is below the presumptive limits. 

Specifically, the BART Guidelines state that "Where a NSPS exists for a source category 

(which is the case for most of the categories affected by BART), you should include a 

level of control equivalent to the NSPS as one of the control options. The NSPS standards 

are codified in 40 CFR part 60. We note that there are situations where NSPS standards 

do not require the most stringent level of available control for all sources within a 

category. For example, postcombustion NOx controls (the most stringent controls for 

stationary gas turbines) are not required under subpart GG of the NSPS for Stationary Gas 

Turbines. However, such controls must still be considered available technologies for the 

BART selection process." (see 70 FR 39164). PPL needs to provide an analysis for NOx 

that is equivalent to the current NSPS. 

9.	 The emitting unit at Corette is a tangential-fired, sub-bituminous boiler. PPL analyzed 

SOFA, SNCR, and SCR for this unit. The BART Guidelines state "Most EGUs can meet 

these presumptive NOx limits through the use of current combustion control technology, 

4 
i.e. the careful control of combustion air and 10w-NOx burners. For units that cannot 

meet these limits using such technologies, you should consider whether advanced 

combustion control technologies such as rotating opposed fire air should be used to meet 

these limits." (see 70 FR 39172, July 6,2005). In addition to the analysis for SOFA, 

SNCR, and SCR, PPL should analyze new control technologies than can achieve higher 

control levels than LNB and SOFA. Some of the technologies PPL should analyze 

include advanced separated overfire air (ASOFA), rich reagent injection (RRI), and 

rotating overfire air (ROFA). These technologies meet the requirements for consideration 

as part ofthe BART analysis. 

Particulate Matter Emissions and Controls 

10. The uncontrolled emission rate for the boiler used in the cost effectiveness calculations is 

based on the stack test results from the electrostatic precipitator (ESP) outlet. Therefore, 

the cost effectiveness calculations for BART are in conjunction with the currently 

installed ESP. This approach provides unrealistic and inflated cost effectiveness values 

for applying BART. The cost effectiveness calculations should be based on the actual 

uncontrolled emission rates (i.e., inlet emission rates before the ESP). PPL needs to 

reanalyze the cost effectiveness calculations based on uncontrolled emission rates. 

11. PPL did not provide any design parameters for the existing PM control technologies, 

which include an ESP and fabric filters (FF). It is possible that BART for PM for these 

two sources could include additional controls and/or increased performance of the 

existing technologies. The BART Guidelines state that "For emission units subject to 

BART review, there will often be control measures or devices already in place. For such 

emission units, it is important to include control options that involve improvements to 

existing controls and not to limit the control options only to those measures that involve a 

complete replacement of control devices" (see 70 FR 39164, July 6, 2005). PPL needs to 

submit the design parameter information for the current PM controls and analyze the 

possibility of additional controls and increased performance of the existing equipment. 

12. The PPL PMI0 BART analysis assumes that the lowest emission rate achievable by 

either aFF (baghouse) or an ESP is 0.015 Ib/MMBtu. However, EPA has proposed that 

the Desert Rock power plant will meet a filterable PMI0 limit of 0.010 Ib/MMBtu (see 

Desert Rock Energy Center Proposed Permit, AZP 04-0 I, 

http://www.epa.gov/region09/air/permitJdesertrockidesert-rock-proposed-permit.pdt). 

PPL should re-evaluate the costs and benefits ofreducing PM10 to the level that EPA has 

said represents Best Available Control Technology using techniques developed in the 

EPA Control Cost Manual. 

5
 
In order to move forward with the BART process, we ask that you submit the requested 

information and analysis to our office within thirty days from the date of this letter. 

Once again, we would like to thank you for submitting the BART analysis and 

acknowledge the work that has gone into preparing this analysis. If you have any questions, 

please contact Laurel Dygowski at (303) 312-6144. 

Sm~e~ely,

.. /. /L' A. .) . ... ..~. (;~ ._----_._­

.. _~eA. Videtich, Dire . 

Air and Radiation Program 

6
 
United States Department of the Interior 

FISH AND WILDLIFE SERVICE
 

National Wildlife Refuge System
 

Branch of Air Quality
 

7333 W. Jefferson Ave., Suite 375 IN REPLY REFER TO: 

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·-1·;:9
 

RE:	 Comments on the Corette Generating Station Best Available Retrofit Technology
 

(BART) Assessment, Billings, Montana
 

Dear Ms. D~owskI: /~

I am sending these draft comments on the Corette Generating Station BART determination at this 

time with the understanding that our final comments. will be incQrp,orated within our overall 

review on reasonable progress ofthe M~ritana.Regio1}alijaze.Federallmplementation Plan near 

the end ofthe:60~1ay cOlnmen(period,··· ",... . . . ~,:

"fhefacility IS owned and operated by PPL M6titana, LLC(PPL),which includes one Electric 

Generating Unit (EGU), in Billings, MT. The plant is located within 300 km of seven Class I 

areas: North Absaroka Wilderness Area, Yellowstone National Park, Washakie Wilderness Area, 

. UL Bend National Wildlife Refuge, Teton Wilderness Area, Gates of the Mountains Wilderness 

Area, and Red Ruck Lakes. 

The boiler is tangentially-fired using Powder River Basin sub-bituminous.coal (0.3% weight 

. percent sulfur) and is rated at 154 MW. The boiler is equipped with 8n electrostatic precipitator 

(ESP) to control emissions of particulate matter (PM), and low NOx burners (LNB) and close 

coupled over-fire air to limit the formation of nitrogen oxides (NOx). 

Visibility Improvement Comments 

We believe that it is appropriate to consider both the degree of visibility improvement in a given 

Class I area as well as the aggregate effects of improvi~g visibility acro.ss <),11 ofthe Class Jareas 

a'ffected: For the PPL/Corette BART-eligible unit, the base case'shows the greatest impact to 

visibility at any single Class I areais 0.645 deciviews (dv) at UL Bend Wildlife Area. Impacts to 

vrsibility 'are'shown for each'ofthe seven Class I areas analyzed .~n .the BART report, and for 

three oftheise, impacts are at or ab()vethe 0.5 dv BART screening threshoid. The collective . 

impacts and potential improvements should be addressed by the BART determination. 

TAKE PRIDE·~
 

INAMERICA~
 
PPL analyzed several pote11.tial BART options to project the visibility improvement that would be 

realized in each case. The largest, single improvement was 0.238 dv using wet scrubbing for S02 

control. PPL concluded on page 5-2 that, if the amount of visibility improvement resulting from 

a reduction in emissions is 0.238 dv, it is not discernable, and therefore the cost of achieving the 

improvement is not justified. 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 sho.uld 

still be considered in setting BART because the contribution to haze may be significant relative 

to other source contributions in the Class I areas. Thus, we disagree that the degree of 

improvement should be contingent upon perceptibility. Failing to consider less-than-perceptible 

contributions to visibility impairment would ignore the CAA's intent to have BART 

requirements apply to sources that contribute to, as well as cause, such impairment.,,2 

General Cost-Effectiveness Comments 

EPA's BART guidelines state, "The basis for equipment cost estimates also should be 

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

by a referenced source (such as the OAQPS Control Cost Manual). In order to maintain and 

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

possible. The Control Cost Manual addresses most control technologies in sufficient detail for a 

BART analysis. The cost analysis should also take into account any site-specific design or other 

conditions identified above that affect the cost of a particular BART technology option.',3 While 

PPL used the Cost Manual in many cases, it used a 1988 EPRI study for the PM control 

equipment cost that was not provided and may well be out of date, or provided no supporting 

documentation at all. In addition, the capital cost for the S02 control equipment was done using 

the "Air Pollution Control Technology Fact Sheet, Flue Gas Desulfurization (FGD) - Wet, Spray 

Dry, and Dry Scrubbers" (EPA-452/F-03-034). This document is meant to 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 useful life of 11 years for all of the control 

technologies, which corresponds to a capital recovery factor of 0.1334. The typical useful life of 

these control technologies are expected to 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 on the useful life determinations. 

EPA's threshold of perceptibility is 0.5 dv. 

2 See Federal Register at 70 FR 39129, July 6, 2005; middle column 

3 See 40 eFR 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 Register on July 6, 

2005. The rulemaking action added Appendix Y to Part 51, titled "Guidelines for BART Determinations Under the 

Regional Haze Rule." The section of the Appendix referenced above appears in the Federal Register at 70 FR 

39166, July 6, 2005. 

2 

I 
We are also concerned with the way in which the incremental cost analysis was used. According 

to EPA's BART Guidelines, "You should considenhe incremental cost effectiveness in 

combination with the average cost effectiveness when considering whether to eliminate a control 

option...."4 "You should exercise caution not to misuse these [average and incremental cost 

effectiveness] techniques...[but consider them in situations where an option shows] ...slightly 

greater emission reductions... "s Reviewing agencies are quite familiar with the concept of total 

average cost and expect to see costs in the $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 of incremental cost effectiveness will always result 

in the choice of the cheapest option if carried to the extreme. For example, if only 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 given to the control cost compared to the aggregate visibility 

improvement projected (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 not provide any fuel switching options. The evaluation used a S02 emission 

rate of 0.46 IblMMBtu 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 eliminated the coal pre-treatment approach because the coal is already low-sulfur and 

gasification of the coal would require a complete change in the operation. The analysis did not 

distinguish between the other control teclmologies and instead presented cost evaluations for dry 

injection and wet scrubbing approaches. The dry injection options were performed using a 25% 

S02 reduction and a 70% S02 reduction. 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 that this reduction level does not impact the PM emission rate. 

The cost analysis for the control technologies uses an EPA Fact Sheet to support the equipment 

costs contained in the appendices. The capital equipment costs were estimated to be $24,300,000 

4 See 40 eFR Part 5 I, Appendix Y, Section IV.DA.e. J., also appearing in the Federal Register at 70 FR 39167, July
 

6,2005.
 

5 See 40 CFR Part 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.
 

3 
for the 25% dry injection option and $243,000,000 for each of the 70% dry injection and wet 

scrubber options. Both of these capital equipment" cost estimates are extremely high in 

comparison to 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 of reducing S02 using techniques 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 documentation that supports this. 

The Corette facility is currently equipped with Low NOx Burners (LNB) and Close Coupled 

Over-Fire Air to 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 stated that each of these control options 

were feasible and proceeded to estimate the cost effectiveness of each ofthe options. No options 

for fuel switching (i.e., natural gas, fuel oil) were presented in the analysis. PPL evaluated the 

costs effectiveness of each of these options using cost data from the World Bank for the SOFA 

option and the OAQPS Cost Manual for the SNCR and SCR options. The boiler tuning cost was 

not referenced, but appears that it may be based on past cost informationJor the boilers. 

PPL estimated the emission reductions for the boiler tuning and the SOFA options using typical 

NOx reductions using these technologies. The cost effectiveness for these options are $147 per 

ton ofNOx reduced for the boiler tuning option, and $914 per ton of NOx reduced for the SOFA 

option. These values are reasonable in comparison to other control cost calculations. 

The SNCR and SCR cost effectiveness options were calculated based on achieving an NSPS 

emission rate of 0.16 Ib/MMBtu for SNCR and 0.15 Ib/MMBtu for SCR from the current 

emission rate of 0.26 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 of achieving 90-99% 

reduction in NOx emissions from ·similar units. Therefore the cost effectiveness value of $4,354 

per ton ofNOx removed for SCR is biased high in comparison to other SCR application costs. 

We believe that PPL 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 of SNCR to SOFA could reduce NOx emissions by about 

19%. However, EPA estimates that SNCR can reduce NOx by 40% - 50% for a boiler 

this size. 9 PPL should re-evaluate SNCR at these higher efficiencies. 

7 PPL should also justify using an eleven year equipment life instead of the 15 years assumed by the OAQPS Control
 

Cost Manual.
 

8 The presumptive NOx limit for similar boilers is 0.15 Ib/mmBtu.
 

9 OAQPS Cost Manual, p1-3 and EPA Cost Tool for Corette
 

4 
•	 PPL concluded that the $1,723/ton cost of SNCR is not justifiable. However, in the 

preamble to its BART Guidelines, EPA states, "The limits provided were chosen at levels 

that approximately 75 percent of the units could achieve with cun-ent combustion control 

technology. The costs of such controls in most cases range from just over $100 to $1000 

per ton.,,10 This range of proposed control costs includes addition of SOFA at Corette. 

Application of EPA's Cost Tool model to Corette predicts that 40% NOx reductions can 

be achieved for $826 - $1016 per ton. 

•	 PPL has assumed that addition ofSCR would reduce NOx by 52% to 0.15 Ib/mmBtu. 

However, EPA estimates that SCR can reduce NOx by'70% to 90% or more for a boiler 

this size. 11 IfSCR is capable of reducing emissions below PPL's target, then the amount 

of the reductions and consequent visibility improvements will increase. PPL should reevaluate SCR at these higher efficiencies. 12 

Technical Feasihility ofROFA: In the preamble to its BART Guidelines, EPA states "For those 

units that cannot meet the presumptive limits using cun-ent combustion control technology, states 

should carefully consider the use of advanced combustion controls such as Rotating Over-Fire 

Air (ROFA) in their BART determinations." 13 PPL did not consider ROFA, and provided no 

reason why this technology could not be transferred14 froin similar, but smaller applications, such 

as at MN Power's Taconite Harbor facility where it will install Mobotec multi-pollutant control 

technology on each ofthree 75 MW boilers to reduce S02 (by 65% to 0.24 lb/mmBtu) and NOx 

(by 64% to 0.14 lb/mmBtu). 

PMIO BART 

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 lb/MMBtll NSPS emission rate. The use of a mechanical collector 

in conjunction with the existing ESP should achieve a significant reduction in PM emissions 

from the boiler with relatively little cost. However, this scenario was not researched in this 

analysis. '111e wet scrubber was analyzed as a control option for S02, but not for PM. No options 

for fuel switching (i.e., natural gas, fuel oil) were presented in the analysis. Also there was no 

discussion on remodeling the current ESP to increase the PM removal efficiency. 

The uncontrolled emission rate for the boiler used in the cost effectiveness calculations are based 

on the stack test results from the ESP outlet. Therefore, the cost effectiveness calculations for 

10 See 70 FR 39135, July 6, 2005, first column. 

11 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 

power plant meet a 24-hour average NOx limit of 0.06 lb/mmBtu. 

IJ See 70 FR 39135, July 6, 2005; middle column below tables. 

14 See 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 of the control technology on a new or existing 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." 

5 
BART are in conjunction with the currently installed ESP. We believe this approach provides 

unrealistic and inf1ated cost effectiveness values for applying BART. The cost effectiveness 

calculations should be based on the actual uncontrolled emission rates (i.e., inlet emission rates 

before the ESP). No information on the PM removal efficiency of the currently installed ESP 

was provided in the analysis. 

The PPL BART analyses assume that the lowest emission rate achievable by either a fabric filter 

(baghouse) or an ESP is 0.015 Ib/mmBtu. Data from EPA has shown that these technologies are 

able to achieve lower emission rates than the NSPS level. For example, the De~ert Rock power 

plant will meet a filterable PMIO limit of 0.010 Ib/mmBtu. We believe that PPL should reevaluate the costs and benefits of reducing PM to the level that EPA has said represents Best 

Available Control Technology using techniques developed in the OAQPS Control Cost 

Manual.'s 

Equipment cost values for the ESP and FF are based on cost data from the Air Pollution 

Engineering Manual developed by the Air & Waste Management Association. The capital costs 

were obtained using $60/kW for the ESP and $50/kW for the FF and are based on a collection 

efficiency of99%. These capital cost values seem high in comparison to other cost evaluations 

for these technologies. 

Conclusions & Recommendations 

•	 PPL should recognize that control equipment can achieve varying degrees of control 

based upon how it is designed and operated, and use the highest level of control feasible 

in its analyses. 

•	 Impacts upon all affected Class I areas should be considered collectively. Therefore, the 

relative cost-effectiveness of control strategies should be compared on a cost/deciview 

improvement basis. 

•	 The costs of adding SOFA and SNCR are economically feasible and produce relatively 

high visibility benefits. 

•	 PPL should re-evaluate application of ROFA. 

•	 PPL should evaluate meeting a lower filterable PMlo limit using the highest degree of 

control for the ESP and FF. 

•	 PPL should use a useful life of 20 years for calculating aJillual cost of the control
 

equipment rather than the 11 yeaJ's used in the BART assessment.
 

•	 Because of .I.E. 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 look forward to working with EPA and PPL as this process advances. We believe that good 

communication and sharing of information will help expedite this process, and suggest that you 

15 PPL should also justify using an eleven year equipment life instead of the twenty years assumed by the OAQPS 

Control Cost Manual. 

6 
contact Tim Allen (Tim_Allen@fws.gov at (303) 914-3802) of my staff if you have any 

questions or comments. 

Sincerely. 

yj~cz yLiveD Sandra Silva, Chief 

Branch of Air Quality 

cc: 

Richard Coleman, Regional Chief 

National Wildlife Refuge System 

FWS-Mountain Prairie Region 

Denver Federal Center 

P.O. Box 25486 

Denver, CO 80225 

Barron Crawford, Project Leader 

UL Bend National 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 

7·