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 ·l:?Q 

RE:	 Comments on the 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 with the understanding that our final comments will be incorporated within our overall 

review on reasonable progress ofthe Montana Regional Haze Federal Implementation Plan near 

the end ofthe60-day comment period. . 

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 of seven Class I 

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

Ui. Bend National Wildlife Refuge, Teton Wilderness Area, Gates of the 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 is rated at 154 MW. The hoiler is equippecl with ::In f'lf'rtf0<:tnti/' pre(·i~i.t?t0!

(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 improving visibility across all ofthe Class I areas 

affected. For the PPL/Corette BART-eligible unit, 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 of the seven Class I areas analyzed in the BART report, and for 

three of these. 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 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 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. 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 usetulliie 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. 

I 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 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 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 ofthe Appendix referenced above appears in the Federal Register at 70 FR 

39166, July 6, 2005. 

2 
We are also concerned with the way in which the incremental cost analysis was used. According 

to EPA's BART Guidelines, "You should consider the 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 ... ,,5 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 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 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 technologies 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 CFR Part 51, Appendix Y, Section IV.DA.e.l., 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 ofthese 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 of the 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 information for 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 of NOx 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, pl-3 and EPA Cost Tool for Corette
 

4 
•	 PPL concluded that the $1,723/ton cost ofSNCR 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 current combustion control 

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

per ton."lO 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 of SCR 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. ll If SCR 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 eftlciencies. ll 

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

units that cannot meet the presumptive limits using current 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 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 of three 75 MW boilers 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 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. 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 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. 

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
 

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

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

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 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 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). 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 lb/mmBtu. Data from EPA has shown that these technologies are 

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

plant will meet a filterable PM IO limit of 0.01 0 lb/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. J5 

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 of 99%. 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 costldeciview 

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 PMIO limit using the highest degree of 

control for the ESP and FF. 

•	 PPL should use a useful life of20 years for calculating annual cost of the control
 

equipment rather than the 11 years used in the BART assessment.
 

•	 Because of lE. 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 justity 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, 

xJarr&tc~ YliJCu 

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