DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

BART Application Analysis

AP-6040

May 28, 2009

NAME OF FIRM: PacifiCorp

NAME OF FACILITY: Jim Bridger Power Plant

FACILITY LOCATION: Section 3, T20N, R101W

UTM Zone: 12

Easting: 684,055 m, Northing: 4,622,745 m

Sweetwater County, Wyoming

TYPE OF OPERATION: Coal-Fired Electric Generating Plant

RESPONSIBLE OFFICIAL: Robert Arambel, Plant Managing Director

MAILING ADDRESS: P.O. Box 158

Point of Rocks, WY 82942

TELEPHONE NUMBER: (307) 352-4220

REVIEWERS: Cole Anderson, Air Quality Engineer

Josh Nall, Air Quality Modeler

PURPOSE OF APPLICATION:

Sections 169A and 169B of the 1990 Clean Air Act Amendments require states to improve visibility at 

Class I areas. On July 1, 1999, EPA first published the Regional Haze Rule, which provided specific 

details regarding the overall program requirements to improve visibility. The goal of the regional haze 

program is to achieve natural conditions by 2064.

Section 308 of the Regional Haze Rule (40 CFR part 51) includes discussion on control strategies for 

improving visibility impairment. One of these strategies is the requirement under 40 CFR 51.308(e) for 

certain stationary sources to install Best Available Retrofit Technology (BART) to reduce emissions of 

three (3) visibility impairing pollutants, nitrogen oxides (NOx), particulate matter (PM), and sulfur 

dioxide (SO2). EPA published Appendix Y to part 51 - Guidelines for BART Determinations Under the 

Regional Haze Rule in the July 6, 2005 Federal Register to provide guidance to regulatory authorities for 

making BART determinations. Chapter 6, Section 9, Best Available Retrofit Technology was adopted 

into the Wyoming Air Quality Standards and Regulations (WAQSR) and became effective on December 

5, 2006. The Wyoming Department of Environmental Quality, Air Quality Division (Division) will 

determine BART for NOx and PM10 for each source subject to BART and include each determination in 

the §308 Wyoming Regional Haze State Implementation Plan (SIP).
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Section 309 of the Regional Haze Rule (40 CFR part 51), Requirements related to the Grand Canyon 

Visibility Transport Commission, provides states that are included within the Transport Region addressed 

by the Grand Canyon Visibility Transport Commission (i.e., Arizona, California, Colorado, Idaho, 

Nevada, New Mexico, Oregon, Utah, and Wyoming) an alternative to the requirements established in 40 

CFR 51.308. This alternative control strategy for improving visibility contains special provisions for 

addressing SO2 emissions, which include a market trading program and a provision for a series of SO2

milestones. Wyoming submitted a §309 Regional Haze SIP to EPA on December 29, 2003. As of the 

date of this analysis, EPA has not taken action on the SIP. National litigation issues related to the 

Regional Haze Rule, including BART, required states to submit revisions. On November 21, 2008, the 

State of Wyoming submitted revisions to the 2003 §309 Regional Haze SIP submittal. Sources that are 

subject to BART are required to address SO2 emissions as part of the BART analysis even though the 

control strategy has been identified in the Wyoming §309 Regional Haze SIP.

On January 16, 2007, in accordance with the requirements of WAQSR Chapter 6 Section 9(e)(i),

PacifiCorp submitted four (4) BART applications, one for each existing coal-fired boiler at the Jim 

Bridger Power Plant. A map showing the location of PacifiCorp‟s Jim Bridger Power Plant is attached as 

Appendix A.

October 16, 2007, PacifiCorp submitted updated applications for each of the four (4) Jim Bridger units 

subject to BART. Additional modeling performed after the January 16, 2007 submittal and revised 

visibility control effectiveness calculations were included.

December 5, 2007, PacifiCorp submitted revised applications incorporating changes to the postprocessing of the visibility model runs for each of the four (4) Jim Bridger units.

March 31, 2008, PacifiCorp submitted addendums to each of the BART applications for Jim Bridger 

Units 1-4. Revised cost estimates and updated visibility modeling for two (2) NOx control scenarios were 

included in the addendums.

February 2, 2009, PacifiCorp submitted additional information addressing presumptive BART emission 

rates for the four (4) coal-fired boilers at the Jim Bridger Power Plant. The information addresses the 

type of coal fired in the four boilers and its impact on NOx emissions.

BART ELIGIBILITY DETERMINATION:

In August of 2005 the Wyoming Air Quality Division began an internal review of sources that could be 

subject to BART. This initial effort followed the methods prescribed in 40 CFR part 51, Appendix Y:

Guidelines for BART Determinations Under the Regional Haze Rule to identify sources and facilities. 

The rule requires that States identify and list BART-eligible sources, which are sources that fall within the 

26 source categories, have emission units which were in existence on August 7, 1977 but not in operation 

before August 7, 1962 and have the potential to emit more than 250 tons per year (tpy) of any visibility 

impairing pollutant when emissions are aggregated from all eligible emission units at a stationary source. 

Fifty-one (51) sources at fourteen (14) facilities were identified that could be subject to BART in 

Wyoming.
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The next step for the Division was to identify BART-eligible sources that may emit any air pollutant 

which may reasonably be anticipated to cause or contribute to impairment of Class I area visibility. Three 

pollutants are identified by 40 CFR part 51, Appendix Y as visibility impairing pollutants. They are 

sulfur dioxide (SO2), nitrogen oxides (NOx), and particulate matter (PM). Particulate matter with an 

aerodynamic diameter of 10 microns or less (PM10) was used as an indicator of PM. In order to determine 

visibility impairment of each source, a screening analysis was performed using CALPUFF. Sources that 

emitted over 40 tons of SO2 or NOx or 15 tons of PM10 were included in the screening analysis. Using 

three years of meteorological data, the screening analysis calculated visibility impacts from sources at 

nearby Class I areas. Sources whose modeled 98th percentile 24-hour impact or 8th highest modeled 

impact, by year, was equal to or greater than 0.5 deciviews (dv) above natural background conditions 

(Δdv) were determined to be subject to BART. For additional information on the Division‟s screening 

analysis see the Visibility Improvement Determination: Screening Modeling section of this analysis. The 

four existing coal-fired boilers at PacifiCorp‟s Jim Bridger Power Plant were determined to be subject to 

BART. PacifiCorp was notified in a letter dated June 14, 2006 of the Division‟s finding.

DESCRIPTION OF BART ELIGIBLE SOURCES:

PacifiCorp‟s Jim Bridger Power Plant is comprised of four (4) identically sized nominal 530 Mega Watts 

(MW) tangentially fired boilers burning pulverized coal for a total net generating capacity of 2,120 MW. 

Jim Bridger Unit 1 was placed in service in 1974. Unit 2 commenced service in 1975. Unit 3 entered 

service in 1976 followed by Unit 4, which commenced service in 1979. Each unit was initially equipped 

with early generation low NOx burners (LNB) manufactured by Combustion Engineering to control 

emission of nitrogen oxides (NOx). They are also equipped with dry Flakt wire frame electrostatic 

precipitators (ESPs) to control particulate matter emissions (PM), for which particulate matter less than 

10 microns (PM10) is used as a surrogate. Finally, to control sulfur dioxide (SO2) emissions, each unit is 

equipped with a three absorber tower wet sodium flue gas desulfurization (WFGD) system made by 

Babcock & Wilcox.

Table 1: Jim Bridger Units 1-4 Pre-2005 Emission Limits

Source

Firing Rate 

(MMBtu/hour)

Existing 

Controls

NOx

(lb/MMBtu) (a)

SO2

(lb/MMBtu) (a)

PM/PM10

(lb/MMBtu) (a)

Unit 1 6,000 LNB, ESP, 

WFGD

0.70 (3-hour block)

0.42 (annual) 0.3 (2-hour block) 0.10 (2-hour block)

Unit 2 6,000 LNB, ESP, 

WFGD

0.70 (3-hour block)

0.40 ( annual) 0.3 (2-hour block) 0.10 (2-hour block)

Unit 3 6,000 LNB, ESP, 

WFGD

0.70 (3-hour block)

0.41 (annual) 0.3 (2-hour block) 0.10 (2-hour block)

Unit 4 6,000 LNB, ESP, 

WFGD

0.70 (3-hour block)

0.45 (annual)

3,514 lb/hr

0.2 (2-hour block)

1,004 lb/hr (2-hour block)

0.10 (2-hour block)

502 lb/hr (2-hour block)

(a) Emissions taken from Operating Permit 3-1-120 which does not include the most recent New Source Review construction 

permit limits.
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On April 1, 2005, Air Quality Permit MD-1138 was issued to PacifiCorp to replace the first generation 

low NOx burners (LNB) on Jim Bridger Unit 2 with a new ALSTOM TFS 2000TM low NOx firing system 

including two elevations of separated overfire air (OFA). The Division received written notification from 

PacifiCorp on June 13, 2005 that the new LNB were installed and placed into service May 29, 2005. The 

permitted NOx emission limit of 0.26 lb/MMBtu, annual average, authorized in MD-1138 for Jim Bridger 

Unit 2 went into effect in 2005.

On October 6, 2006, after the LNB modification to Unit 2 was completed, PacifiCorp submitted a

construction permit application to modify Jim Bridger Units 1, 2, 3 and 4 by replacing the existing first 

generation low NOx burners on Units 1, 3 and 4 with Alstom TFS 2000TM LNB with two elevations of 

separated overfire air, install a flue gas conditioning (FGC) system which injects SO3 gas into the flue gas 

to improve the efficiency of the electrostatic precipitator on Units 1-4, and upgrade the existing flue gas 

desulfurization (FGD) systems on all four units to achieve greater than 90% sulfur dioxide removal. Air 

Quality Permit MD-1552 was issued April 9, 2007 authorizing the new LNB, FGC, and WFGD

modifications to the Jim Bridger Power Plant. PacifiCorp notified the Division that the LNB upgrades to 

Unit 3 were completed and the unit started up May 30, 2007. June 18, 2008, the Division received 

notification from PacifiCorp that the new low NOx burners on Unit 4 were installed during a recent ten 

week outage and the unit started up June 8, 2008. Modifications to the scrubber vessels on Unit 4 were 

not necessary in order to meet the SO2 emission limits permitted in MD-1552. Unit 4 can meet the limits

by reducing the amount of flue gas bypassing the scrubber. However, this would increase the moisture 

content of the gas entering the exhaust stack and modifications to the stack drain system were required to 

accommodate the increased moisture. Current emission limits for Jim Bridger Units 1-4 are listed in 

Table 2 below.

Table 2: Jim Bridger Units 1-4 Current Emission Limits (a)

Source Controls NOx SO2 PM/PM10

(b)

Unit 1

Existing LNB, 

ESP with FGC, 

WFGD

0.45 lb/MMBtu

(12-month rolling)

0.3 lb/MMBtu (2-hour block)

1,600 lb/hr (24-hr rolling)

0.03 lb/MMBtu

180 lb/hr

Unit 2

New LNB with 

OFA, ESP with 

FGC, WFGD

0.26 lb/MMBtu

(12-month rolling)

0.3 lb/MMBtu (2-hour block)

1,600 lb/hr (24-hr rolling)

0.03 lb/MMBtu

180 lb/hr

Unit 3

New LNB with 

OFA, ESP with 

FGC, WFGD

0.26 lb/MMBtu

(12-month rolling)

0.3 lb/MMBtu (2-hour block)

1,600 lb/hr (24-hr rolling)

0.03 lb/MMBtu

180 lb/hr

Unit 4

New LNB with

OFA, ESP with 

FGC, WFGD

0.26 lb/MMBtu

(12-month rolling)

0.2 lb/MMBtu (2-hour block)

0.15 lb/MMBtu (12-month rolling)

1,004 lb/hr (2-hr block)

900 lb/hr (24-hr rolling)

0.03 lb/MMBtu

180 lb/hr

(a) Emissions limits from New Source Review construction permit MD-1552.

(b) Averaging period is 1 hour as determined by 40 CFR 60.46 and EPA Reference Test Methods 1-5.

PacifiCorp is currently evaluating the upgraded stack drain system on the Unit 4 exhaust stack. Upon 

completion of a wet scrubber upgrades permitted in MD-1552, the SO2 limits for the corresponding unit 

becomes 0.15 lb/MMBtu on a 12-month rolling average and 900 lb/hr on a 24-hr rolling average. A

construction schedule for the LNB and WFGD upgrades was submitted in the permit application for MD1552. PacifiCorp provided an update on the proposed construction schedule in a letter received on 

September 17, 2008. A construction summary is provided in Table 3.
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Table 3: MD-1552 Permitted Upgrades to Jim Bridger Units 1-4

Source

New Low NOx Burners with 

Separate Overfire Air 

(status, year)

Upgrades to the 

Existing Wet Scrubber

(status, year)

Unit 1 Planned, 2010 Planned, 2010

Unit 2 Completed, 2005 Planned, 2009

Unit 3 Completed, 2007 Planned, 2011

Unit 4 Completed, 2008 Completed, 2008

CHAPTER 6, SECTION 9 – BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

A BART determination is an emission limit based on the application of a continuous emission reduction 

technology for each visibility impairing pollutant emitted by a source. It is “...established, on a case-bycase basis, taking into consideration (1) the costs of compliance, (2) the energy and non-air quality 

environmental impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) 

the remaining useful life of the source, and (5) the degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such technology.”1 A BART analysis is a 

comprehensive evaluation of potential retrofit technologies with respect to the five criteria above. At the 

conclusion of the BART analysis, a technology and corresponding emission limit is chosen for each 

pollutant for each unit subject to BART.

Visibility control options presented in the application for each source were reviewed using the 

methodology prescribed in 40 CFR 51 Appendix Y, as required in WAQSR Chapter 6 Section 9(c)(i). 

This methodology is comprised of five basic steps:

Step 1: Identify all2available retrofit control technologies

Step 2: Eliminate technically infeasible options

Step 3: Evaluate control effectiveness of remaining control technologies

Step 4: Evaluate impacts and document the results

Step 5: Evaluate visibility impacts

The Division acknowledges that BART is intended to identify retrofit technology for existing sources and 

is not the same as a top down analysis required for new sources under the Prevention of Significant 

Deterioration (PSD) rules known as Best Available Control Technology (BACT). Although BART is not 

the same as BACT, it is possible that BART may be equivalent to BACT on a case-by-case basis. The 

Division applied all five steps to each visibility impairing pollutant emitted from each coal-fired boiler 

(Units 1-4) at the Jim Bridger Power Plant thereby conducting a comprehensive BART analysis for NOx, 

SO2 and PM/PM10.

 

1

40 CFR Part 51 Appendix Y: Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 39163).

2

Footnote 12 of 40 CFR 51 Appendix Y defines the intended use of „all‟ by stating “...you must identify the most stringent 

option and a reasonable set of options for analysis that reflects a comprehensive list of available technologies.”
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PRESUMPTIVE LIMITS FOR SO2 AND NOX FROM UTILITY BOILERS

EPA conducted detailed analyses of available retrofit technology to control NOx and SO2 emissions from 

coal-fired power plants. These analyses considered unit size, fuel type, cost effectiveness, and existing 

controls to determine reasonable control levels based on the application of an emissions reduction 

technology.

EPA‟s presumptive BART SO2 limits analysis considered coal-fired units with existing SO2 controls and 

units without existing control. Four key elements of the analysis were: “...(1) identification of all 

potentially BART-eligible EGUs [electric generating units], and (2) technical analyses and industry 

research to determine applicable and appropriate SO2 control options, (3) economic analysis to determine 

cost effectiveness for each potentially BART-eligible EGU, and (4) evaluation of historical emissions and 

forecast emission reduction for each potentially BART-eligible EGU.”3 491 BART-eligible coal-fired 

units were identified and included in the presumptive BART analysis for SO2. Based on removal 

efficiencies of 90% for spray dry lime dry flue gas desulfurization systems and 95% for limestone forced 

oxidation wet flue gas desulfurization systems, EPA calculated projected SO2 emission reductions and 

cost effectiveness for each unit. Based on the results of this analysis, EPA concluded that the majority of 

identified BART-eligible units greater than 200 MW without existing SO2 control can meet the 

presumptive limits at a cost of $400 to $2,000 per ton of SO2 removed.

A presumptive BART NOx limits analysis was performed using the same 491 BART-eligible coal-fired 

units identified in the SO2 presumptive BART analysis. EPA considered the same four key elements and 

established presumptive NOx limits for EGUs based coal type and boiler configuration. For all boiler 

types, except cyclone, presumptive limits were based on combustion control technology (e.g., low NOx

burners and overfire air). Presumptive NOx limits for cyclone boilers are based on the installation of 

SCR, a post combustion add-on control. EPA acknowledged that approximately 25% of the reviewed 

units could not meet the proposed limits based on current combustion control technology, but that nearly 

all the units could meet the presumptive limits using advanced combustion control technology, such as 

rotating opposed fire air. National average cost effectiveness values for presumptive NOx limits ranged 

from $281 to $1,296 per ton removed.

Based on the results of the analyses for presumptive NOx and SO2 limits, EPA established presumptive 

limits for EGUs greater than 200 MW operating without NOx post combustion controls or existing SO2

controls located at facilities with a generating capacity greater than 750 MW. 40 CFR part 51 Appendix 

Y states that the presumptive SO2 level for an uncontrolled unit is either 95% control or 0.15 lb/MMBtu. 

Presumptive NOx levels for uncontrolled units are listed in Table 1 of Appendix Y and classified by the 

boiler burner configuration (unit type) and coal type. NOx emission values range from 0.62 lb/MMBtu 

down to 0.15 lb/MMBtu. While Appendix Y establishes presumptive SO2 limits and says that states 

should require presumptive NOx, it also clearly gives states discretion to “...determine that an alternative 

[BART] control level is justified based on a careful consideration of the statutory factors.”4 The 

Division‟s following BART analysis for NOx, SO2, and PM/PM10 takes into account each of the five 

statutory factors.

 

3

40 CFR Part 51 Appendix Y: Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 39133).

4

Ibid. (70 Federal Register 39171).
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PacifiCorp‟s Jim Bridger Power Plant consists of four units with a total generating capacity of 2,120 MW. 

Jim Bridger Units 1-4 are identical nominal 530 MW units with tangentially fired pulverized coal boilers. 

SO2 emissions from all units are controlled with existing Babcock & Wilcox three absorber tower wet 

sodium flue gas desulfurization systems that were installed in 1982, 1986, 1988, and 1990 on Units 4, 2, 

3, and 1, respectively. NOx emissions from Units 1-4 were initially controlled using first generations low 

NOx burners. In 2005, the existing low NOx burners were replaced with Alstom TFS 2000TM low NOx

firing system including two elevations of separated overfire air (OFA) on Unit 2. Subsequent to 

PacifiCorp‟s filing of the Jim Bridger BART applications for all four units, Air Quality Permit MD-1552 

was issued on April 9, 2007 authorizing the upgrade of the remaining LNB with new Alstom TFS 2000TM

low NOx firing systems. As of the date of this analysis, two additional new LNB systems are installed on 

Units 3 and 4. The final Jim Bridger LNB upgrade is planned for 2010 on Unit 1, as shown in Table 3. 

Presumptive SO2 limits of 95% reduction or 0.15 lb/MMBtu and presumptive NOx limits based on unit 

type and coal type, could apply to all four Jim Bridger units. However, the Division required additional 

analysis of potential retrofit controls for NOx, SO2, and PM/PM10, taking into consideration all five 

statutory factors, before making a BART determination.

NOx emissions from coal combustion are affected by the chemical and physical properties of the feed 

coal. Heat content, carbon content, fuel-bound nitrogen and oxygen, volatile matter content, volatility, 

and agglomeration of the feed coal significantly affect the design and operation of combustion controls 

such as LNB and OFA systems. This is evidenced by EPA‟s decision to classify presumptive NOx

emission levels based on specific controls as applied to different boiler types firing various types of coal. 

In EPA‟s analysis for establishing presumptive NOx limits, three primary coal types were identified: 

bituminous, sub-bituminous, and lignite. These coal classifications were based on EPA's Mercury 

Information Collection Request (ICR) for the Electric Utility Steam Generating Unit Mercury Emissions 

Information Collection Effort, OMB Control Number 2060-0396. In responding to the ICR PacifiCorp 

reported that Jim Bridger Units 1-4 burned sub-bituminous coal. Subsequent to the ICR PacifiCorp 

further evaluated the coal classification using ASTM method D 388 - 05 Standard Classification of Coals 

by Rank, an industrial standard for classifying coal. After reviewing method D 388 coal classifications,

PacifiCorp noted that high volatile C bituminous coal and sub-bituminous A coals have similar heating 

values, but different agglomeration characteristics. Table 3 from ASTM method D 388 - 05 Standard 

Classification of Coals by Rank is shown as Figure 1.
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Figure 1

PacifiCorp contracted with CH2M Hill and ALSTOM, a boiler manufacturer, to further research the 

impact of coal characteristics on NOx emissions. Laboratory tests, including tests using a bench-scale 

drop tube furnace run by ALSTOM, showed the influence of both fuel type and stoichiometry on NOx

emissions. Additional testing examined the impact of coal volatility on NOx emissions. Based on the 

results of the research, PacifiCorp concluded that “[t]he coals used at Bridger and Naughton tend to be 

higher rank than typical PRB coals. As such, they will have less fuel nitrogen released during the 

devolatilization phase of combustion, and thus will produce have [sic] somewhat higher NOx than will 

true PRB coals when fired under low-NOx staged conditions.”
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PacifiCorp also examined how fuel-bound NOx evolves from solid coal char after the volatile component 

of the coal is combusted. After reviewing laboratory test data on NOx conversion from fuel-bound 

nitrogen during volatilization and during char combustion, PacifiCorp concluded: “Typically, lower rank 

(more reactive) fuels have more fuel NOx associated with the volatiles than the char, so low-rank coals 

overall have the lowest NOx potential. The performance of the Bridger and Naughton coals tends to fall 

between the PRB coals and eastern bituminous coals shown [Figure 3, CH2M Hill‟s Technical 

Memorandum: Coal Quality and Nitrogen Oxide Formation submitted by PacifiCorp on February 2, 

2009]. This would support the conclusion that the Bridger and Naughton coals have a NOx reduction 

potential below eastern bituminous coals, but not as low as true PRB coals.”

Coal characteristics affect the design and efficiency of pollution control equipment, as well as boiler 

design. Based on the information presented by PacifiCorp, it is likely that the Jim Bridger units will not 

be able to achieve presumptive NOx levels of 0.15 lb/MMBtu for tangential boilers firing sub-bituminous 

coal. As mentioned earlier, Air Quality Permit MD-1552 authorized the installation of new ALSTOM 

TFS 2000TM LNB and separated OFA systems. Jim Bridger Units 2-4 are currently equipped with this

combustion control system. Fourth quarter 2008 continuous emissions monitor (CEM) values for NOx

from units equipped with new LNB and OFA systems are shown in Table 4.

Table 4: Latest CEM Data for Units with New ALSTOM LNB and OFA

Jim Bridger

Source

Q4 2008 NOx Emissions

(lb/MMBtu, 12-month rolling average)

August September October November December

Unit 2 0.23 0.23 0.23 0.22 0.22

Unit 3 0.20 0.20 0.20 0.20 0.20

Unit 4 0.26 0.25 0.23 0.22 0.21

The Division required additional analysis of potential retrofit controls for NOx, which included add-on 

controls in addition to combustion control, taking into consideration all five statutory factors, before 

making a BART determination. While the Division noted the applicable presumptive NOx levels for the 

Jim Bridger units, the effectiveness of the proposed combustion control for removing NOx was evaluated 

under Step 2: Eliminate technically infeasible options, Step 3: Evaluate control effectiveness of remaining 

control technologies, and Step 4: Evaluate impacts and document the results of the BART process.

NOx: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

PacifiCorp identified four control technologies to control NOx emissions: (1) low NOx burners with two 

stages of separated OFA, a form of advanced OFA, (2) rotating opposed fire air (ROFA), (3) selective 

non-catalytic reduction (SNCR), and (4) selective catalytic reduction (SCR). LNB with separated OFA 

and ROFA are two combustion control technologies that reduce NOx emissions by controlling the 

combustion process within the boiler. These two technologies have been demonstrated to effectively 

control NOx emissions by reducing the amount of oxygen directly accessible to the fuel during 

combustion creating a fuel-rich environment and by enhancing control of air-fuel mixing throughout the 

boiler‟s combustion zone. SNCR and SCR are add-on controls that provide a chemical conversion 

mechanism for NOx to form molecular nitrogen (N2) in the flue gas after combustion occurs. These four 

technologies are proven emissions controls commonly used on coal-fired electric generating units.
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1. Low NOx Burners with Separated Overfire Air – LNB technologies can rely on a combination of 

fuel staging and combustion air control to suppress the formation of thermal NOx. Fuel staging 

occurs in the very beginning of combustion, where the pulverized coal is injected through the 

burner into the furnace. Careful control of the fuel-air mixture leaving the burner can limit the 

amount of oxygen available to the fuel during combustion creating a fuel rich zone that reduces 

the nitrogen to molecular nitrogen (N2) rather than using oxygen in the combustion air to oxidize 

the nitrogen to NOx. The addition of separated overfire air provides additional NOx control by 

injecting air into the lower temperature combustion zone when NOx is less likely to form. This 

allows complete combustion of the fuel while reducing both thermal and chemical NOx

formation.

2. Rotating Opposed Fire Air – ROFA can be used with LNB technology to control the combustion 

process inside the boiler. Similar to the separated overfire air technology discussed above, ROFA 

manipulates the flow of combustion air to enhance fuel-mixing and air-flow characteristics within 

the boiler. By inducing rotation of the combustion air within the boiler, ROFA can reduce the 

number of high temperature combustion zones in the boiler and increase the effective heat 

absorption. Both of which effectively reduce the formation of NOx caused by fuel combustion 

within the boiler.

3. Selective Non-Catalytic Reduction – SNCR is similar to SCR in that it involves the injection of a 

reducing agent such as ammonia or urea into the flue gas stream. The reduction chemistry, 

however, takes place without the aid of a catalyst. SNCR systems rely on appropriate injection 

temperatures, proper mixing of the reagent and flue gas, and prolonged retention time in place of 

the catalyst. SNCR operates at higher temperatures than SCR. The effective temperature range 

for SNCR is 1,600 to 2,100 F. SNCR systems are very sensitive to temperature changes and 

typically have lower NOx emissions reduction (up to fifty or sixty percent) and may emit 

ammonia out of the exhaust stack when too much ammonia is added to the system.

4. Selective Catalytic Reduction – SCR is a post combustion control technique in which vaporized 

ammonia or urea is injected into the flue gas upstream of a catalyst. NOx entrained in the flue gas 

is reduced to molecular nitrogen (N2) and water. The use of a catalyst facilitates the reaction at 

an exhaust temperature range of 300 to 1,100 F, depending on the application and type of catalyst 

used. When catalyst temperatures are not in the optimal range for the reduction reaction or when 

too much ammonia is injected into the process, unreacted ammonia can be released to the 

atmosphere through the stack. This release is commonly referred to as ammonia slip. A well 

controlled SCR system typically emits less ammonia than a comparable SNCR control system.

In addition to applying these control technologies separately, they can be combined to increase overall 

NOx reduction. PacifiCorp evaluated the application of LNB with separated OFA in combination with 

both SNCR and SCR add-on controls.

NOx: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

None of the four control technologies proposed to control NOx emissions were deemed technically 

infeasible by PacifiCorp.
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NOx: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

The Division considers the control effectiveness of a proposed control technology to be equivalent to the 

BART-determined permit limit. The limit is based on continuous compliance when the control 

equipment is well maintained and operated in a manner consistent with good air pollution control 

practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit 

it is important to consider that even well maintained and operated equipment will have some emissions 

variability. Complex emission control equipment, such as LNB with separated OFA, generally have 

inherent variability that must be considered when establishing the limit. Otherwise, the source will be out 

of compliance even though the equipment is operated and maintained as well as possible.

PacifiCorp contracted with Sargent and Lundy (S&L) to conduct a study of applicable NOx control 

technologies for the Jim Bridger units and to collect data from boiler vendors. Based on results from the 

study, PacifiCorp indicates that new LNB with separated OFA on the Jim Bridger units would result in a 

NOx emission rate as low as 0.24 lb/MMBtu. On pages 3-9 of the December 2007 submittals for Jim 

Bridger Units 1 and 3 and on pages 3-10 of the December 2007 submittals for Jim Bridger Units 2 and 4 

PacifiCorp states: “PacifiCorp has indicated that this rate [0.24 lb/MMBtu] corresponds to a vendor 

guarantee, not a vendor prediction, and they believe that this emission rate can be sustained as an average 

between overhauls.” However, due to unforeseen operational issues associated with retrofitting the 

boilers, including site specific challenges, PacifiCorp proposes an additional NOx increase of 0.02 

lb/MMBtu to total 0.26 lb/MMBtu.

PacifiCorp worked with Mobotec to conduct an analysis of retrofitting the existing boilers at the Jim 

Bridger Power Plant with Mobotec‟s ROFA. Mobotec analyzed the operation of existing LNB and OFA 

ports. Typically the existing LNB system does not require modification and the existing OFA ports are 

not used by a new ROFA system. Instead, computational fluid modeling is performed to determine the 

location of the new ROFA ports. Mobotec concluded that a NOx emission rate of 0.18 lb/MMBtu was 

achievable using ROFA technology. PacifiCorp added an additional operating margin of 0.04 lb/MMBtu 

to account for site specific issues, including the type of coal burned in the boilers, to total 0.22 lb/MMBtu.

S&L evaluated emission reductions associated with installing SNCR in addition to retrofitting the boilers 

with LNB with OFA. Based on installing LNB with separated OFA capable of achieving a NOx emission 

rate of 0.24 lb/MMBtu, S&L concluded that SNCR can reduce emissions another 15 % resulting in a 

projected emission rate of 0.20 lb/MMBtu. PacifiCorp noted in the analysis that the economics of SNCR 

are greatly impacted by reagent utilization. When SNCR is used to achieve high levels of NOx reduction, 

lower reagent utilization can result in significantly higher operating cost.

S&L prepared the design conditions and cost estimates for installing SCR in each of the Jim Bridger

units. A high-dust SCR configuration, where the catalyst is located downstream from the boiler 

economizer before the air heater and any particulate control equipment, was used in the analysis. The 

flue gas ducts would be routed to a separate large reactor containing the catalyst to increase the removal 

rate. Additional catalyst would be added to accommodate the coal feedstock. Based on the S&L design, 

which included installing both LNB with separated OFA and SCR, PacifiCorp concluded the Jim Bridger 

units could achieve a NOx emission rate of 0.07 lb/MMBtu.
PacifiCorp Jim Bridger Power Plant

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Table 5: NOx Emission Rates Per Boiler

Control Technology

Resulting NOx

Emission Rate 

(lb/MMBtu)

Existing LNB 0.45 (a)

New LNB with separated OFA 0.26 (b)

Existing LNB with ROFA 0.22

New LNB with separated OFA and SNCR 0.20

New LNB with separated OFA and SCR 0.07

(a) Annual averaged NOx emissions established through 40 CFR part 76 which vary among the four Jim 

Bridger units from 0.40-0.45 lb/MMBtu.

(b) Jim Bridger Units 2-4 have installed new LNB with separated OFA and are subject to a new NOx

emission limit of 0.26 lb/MMBtu, annual average, established in MD-1552.

NOx: EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impacts associated with installing each of the proposed control 

technologies. Replacing the existing LNB with new LNB including separated OFA will not significantly 

impact the boiler efficiency or forced draft fan power usage, two common potential areas for adverse 

energy impact often affected by changes in boiler combustion. Installing the Mobotec ROFA system has 

the highest energy impact on Jim Bridger. Two (2) 4,000 to 4,300 horsepower ROFA fans (6,410 kilo

Watts [kW] total) are required to induct a sufficient volume of air into each boiler to cause rotation of the 

combustion air throughout the boiler. PacifiCorp determined the SNCR system would require 

approximately 530 kW of additional power to operate pretreatment and injection equipment, pumps, 

compressors, and control systems. In addition to energy costs associated with the reagent handling and 

injection, installation of the SCR catalyst will require additional power from the existing flue gas fan 

systems to overcome the pressure drop across the catalyst. Based on the S&L study, PacifiCorp estimated 

the additional power requirements for SCR installation on each unit at the Jim Bridger Power Plant

ranged from approximately 3.22 MW to 3.36 MW.

PacifiCorp evaluated the environmental impacts of the proposed NOx control technologies. Installing 

LNB with separated OFA may increase carbon monoxide (CO) emissions and unburned carbon in the ash, 

commonly referred to as loss on ignition (LOI). Mobotec has predicted CO emissions and LOI would be 

the same or lower than prior levels for the ROFA system. The installation of SNCR and SCR could 

impact the saleability and disposal of fly ash due to higher ammonia levels, and could potentially create a 

visible stack plume sometimes referred to as a blue plume, if the ammonia injection rate is not well 

controlled. Other environmental impacts involve the storage of ammonia, especially if anhydrous 

ammonia is used, and transportation of the ammonia to the power plant site.
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PacifiCorp anticipates operating Jim Bridger Units 1-4 indefinitely and did not include life extension 

costs in the economic analysis. A standard control life of 20 years was used to calculate the capital 

recovery factor. The annual cost to control was determined using a capital recovery factor based on a 

7.1% interest rate. PacifiCorp labor and service costs were used to calculate the annual operating and 

maintenance costs. Annual power costs, including a cost escalation factor, associated with the operation 

of pollution controls were included.

Several different metrics can be considered when evaluating the cost-benefit relationships of different 

emission control technologies. In 40 CFR part 51 Appendix Y two metrics are specifically mentioned: 

cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has 

extensive experience using cost effectiveness (i.e., dollars per ton of pollutant removed) to evaluate 

different control technologies. Incremental cost effectiveness is also used extensively by the Division 

when comparing emission controls under the BACT process. While the BART and the BACT processes

are not necessarily equivalent, control determinations from either process are based on cost effectiveness 

and incremental cost effectiveness and are indicative of the economic costs to control emissions. In 

addition to providing cost effectiveness and incremental cost effectiveness results, PacifiCorp provided 

cost information in terms of cost of applying emission controls and the level of visibility improvement 

achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and visibility 

improvement differences between control options, it is not commonly used to assess the overall 

effectiveness of pollution control equipment. When performing the presumptive BART limits analyses 

for NOx and SO2, EPA addressed cost effectiveness and incremental cost effectiveness separate from 

visibility improvement. EPA did not use the dollars per deciview metric to compare control options. 

Visibility improvements from the application of the analyzed control measures used to establish 

presumptive levels were addressed in a separate visibility analysis. As discussed in the comprehensive 

visibility analysis presented later in this analysis as Step 5: Evaluate visibility impacts, the Division 

evaluated the amount of anticipated visibility improvement gained by the application of additional

emission control technology. The Division considered capital cost, annual cost, cost effectiveness, and 

incremental cost effectiveness in the evaluation of each proposed NOx emission control. Economic and 

environmental costs for additional NOx controls on Units 1-4 are summarized in the following tables.

Table 6: Jim Bridger Units 1, 3, & 4 Economic Costs Per Boiler

Cost

Existing 

LNB

New LNB with 

separated OFA

Existing LNB 

with ROFA

New LNB with 

separated OFA 

and SNCR

New LNB with 

separated OFA 

and SCR

Control Equipment Capital Cost $0 $11,300,000 $20,528,122 $22,127,239 $177,800,000

Capital Recovery Factor N/A 0.09513 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $1,074,969 $1,952,840 $2,104,964 $16,914,114

Annual O&M Costs $0 $70,000 $2,633,012 $605,837 $3,382,286

Annual Cost of Control $0 $1,144,969 $4,585,852 $2,710,801 $20,296,400
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Table 7: Jim Bridger Units 1, 3, & 4 Environmental Costs Per Boiler

Existing 

LNB

New LNB with

separated OFA

Existing LNB 

with ROFA

New LNB with 

separated OFA 

and SNCR

New LNB with 

separated OFA 

and SCR

NOx Emission Rate (lb/MMBtu) 0.45 (a) 0.26 0.22 0.20 0.07

Annual NOx Emission (tpy) (b)

10,643 6,150 5,203 4,730 1,656

Annual NOx Reduction (tpy) N/A 4,493 5,440 5,913 8,987

Annual Cost of Control $0 $1,144,969 $4,585,852 $2,710,801 $20,296,400

Cost per ton of Reduction N/A $255 $843 $459 $2,258

Incremental Cost per ton of Reduction N/A $255 $3,634 $1,103 (c) $5,721

(a) Annual averaged emissions established by 40 CFR Part 76 vary from 0.40-0.45 lb/MMBtu and using 0.45 lb/MMBtu is conservative.

(b) Annual emissions based on individual heat input rate of 6,000 MMBtu/hr for 7,884 hours of operation per year.

(c)

Incremental cost from installing new LNB with separated OFA since the incremental cost using existing LNB with ROFA is 

negative as a result of the higher annual cost of control.

Table 8: Jim Bridger Unit 2 Economic Costs

Cost

Existing LNB with

separated OFA

Existing LNB 

with ROFA

Existing LNB

with separated 

OFA and SNCR

Existing LNB

with separated 

OFA and SCR

Control Equipment Capital Cost $0 $20,528,122 $13,427,239 $166,500,000

Capital Recovery Factor N/A 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $1,952,840 $1,277,333 $15,839,145

Annual O&M Costs $0 $2,631,822 $605,837 $3,370,460

Annual Cost of Control $0 $4,584,662 $1,883,170 $19,209,605
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Table 9: Jim Bridger Unit 2 Environmental Costs

Existing LNB with

separated OFA

Existing LNB 

with ROFA

Existing LNB

with separated 

OFA and SNCR

Existing LNB

with separated 

OFA and SCR

NOx Emission Rate (lb/MMBtu) 0.26 0.22 0.20 0.07

Annual NOx Emission (tpy) (a)

6,150 5,203 4,730 1,656

Annual NOx Reduction (tpy) N/A 947 1,420 4,494

Annual Cost of Control $0 $4,584,662 $1,883,170 $19,209,605

Cost per ton of Reduction N/A $4,841 $1,326 $4,275

Incremental Cost per ton of Reduction N/A $4,841 $1,326 (b)

$5,636

(a) Annual emissions based on individual heat input rate of 6,000 MMBtu/hr for 7,884 hours of operation per year.

(b)

Incremental cost from existing LNB with separated OFA since the incremental cost using existing LNB with ROFA is 

negative as a result of the higher annual cost of control.

The cost effectiveness and incremental cost effectiveness of the four proposed BART technologies for 

NOx are all reasonable. PacifiCorp modeled the range of anticipated visibility improvement from the 

company-proposed BART controls by modeling LNB with separated OFA and LNB with separated OFA 

and SCR. While new LNB with OFA and SNCR and existing LNB with ROFA were not individually 

evaluated in Step 5: Evaluate visibility impact, the anticipated degree of visibility improvement from 

applying either control lies within the modeled range of visibility impacts.

The final step in the NOx BART determination process for Jim Bridger Units 1-4, Step 5: Evaluate 

visibility impacts, is addressed in a comprehensive visibility analysis covering all three visibility 

impairing pollutants. The visibility analysis follows Steps 1-4 for SO2 emissions in this application 

analysis. Tables 27-30, on pages 36-39, list the modeled control scenarios and associated emission rates.

PM10: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Jim Bridger Units 1-4 are currently equipped with electrostatic precipitators to control PM emissions 

from the boilers. As discussed in more detail below, ESPs control PM/PM10 from the flue gas stream by 

creating a strong electro-magnetic field in which fly ash particles gain electric charge. PacifiCorp states 

the existing ESPs are able to control PM/PM10 emissions to 0.045 lb/MMBtu, 0.074 lb/MMBtu, 0.057 

lb/MMBtu, and 0.030 lb/MMBtu from Units 1, 2, 3, and 4, respectively. Three PM control technologies

were analyzed for application on the four Jim Bridger units: fabric filters or baghouses, ESPs, and flue 

gas conditioning.
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1. Fabric filters (FF) – FF are woven pieces of material that collect particles with sizes ranging from 

submicron to several hundred microns in diameter at efficiencies generally in excess of 99%. The 

layer of dust trapped on the surface of the fabric, commonly referred to as dust cake, is primarily 

responsible for such high efficiency. Joined pores within the cake act as barriers to trap 

particulate matter too large to flow through the pores as it travels through the cake. Limitations 

are imposed by the temperature and corrosivity of the gas and by adhesive properties of the 

particles. Most of the energy used to operate the system results from pressure drop across the 

bags and associated hardware and ducting.

2. Electrostatic precipitators – ESPs use electrical forces (charge) to move particulate matter out the 

gas stream onto collection plates. The particles are given an electrical charge by directing the gas 

stream through a corona, or region of gaseous ion flow. The charged particles are acted upon by 

an induced electrical field from high voltage electrodes in the gas flow that forces them to the 

walls or collection plates. Once the particles couple with the collection plates, they must be 

removed without re-entraining them into the gas stream. In dry ESP applications, this is usually 

accomplished by physically knocking them loose from the plates and into a hopper for disposal. 

Wet ESPs use water to wash the particles from the collector plates into a sump. The efficiency of 

an ESP is primarily determined by the resistivity of the particle, which is dependent on chemical 

composition, and also by the ability to clean the collector plates without reintroducing the 

particles back into the flue gas stream.

3. Flue Gas Conditioning (FGC) – Injecting a conditioning medium, typically SO3, into the flue gas 

can lower the resistivity of the fly ash, improving the particles‟ ability to gain an electric charge. 

If the material is injected upstream of an ESP the flue gas particles more readily accept charge 

from the corona and are drawn to the collection plates. Adding FGC can account for large 

improvements in PM collection efficiency for existing ESPs that are constrained by space and 

flue gas residence time.

PM10: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

PacifiCorp did not eliminate any of the three control technologies listed above as technically infeasible. 

PacifiCorp analyzed the impact of installing FGC using the existing ESPs and installing a polishing fabric 

filter downstream of the existing ESPs on Jim Bridger Units 1-4.

PM10: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

The Division considers the control effectiveness of a proposed control technology to be equivalent to the 

BART-determined permit limit. The limit is based on continuous compliance when the control 

equipment is well maintained and operated in a manner consistent with good air pollution control 

practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit 

it is important to consider that even well maintained and operated equipment will have some emissions 

variability. Complex emission control equipment, such as dry electrostatic precipitators, generally have 

inherent variability that must be considered when establishing the limit. Otherwise, the source will be out 

of compliance even though the equipment is operated and maintained as well as possible.
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Jim Bridger Units 1-4 have existing ESPs and rather than evaluate costs of replacing them, PacifiCorp 

evaluated additional controls to improve the PM10 removal efficiency. An ESP is an effective PM control 

device, as the existing units are already capable of controlling PM10 emissions to 0.045 lb/MMBtu, 0.074 

lb/MMBtu, 0.057 lb/MMBtu, and 0.030 lb/MMBtu for Units 1, 2, 3, and 4, respectively. The technology 

continually improves and is commonly proposed for consideration in BACT analyses to control 

particulate emissions from new PC boilers. Rather than demolishing the existing ESP and constructing an 

entirely new PM control device, PacifiCorp recognized the cost benefit of keeping the existing unit and 

augmenting the control. Installing FGC on Units 1-4 can improve the PM removal efficiencies on the 

existing ESPs down to 0.030 lb/MMBtu. In addition to maintaining the existing ESPs, a polishing fabric 

filter can be installed downstream of the existing ESPs. PacifiCorp proposed the use of Compact Hybrid 

Particulate Collector (COHPAC) licensed by Electric Power Research Institute (EPRI). The COHPAC 

unit is smaller than a full-scale fabric filter and has a higher air-to-cloth ratio (7 to 9:1) compared to a fullsize pulse jet fabric filter (3.5 to 4:1). COHPAC is effective at controlling particulates not captured by the 

primary PM control device, but is not designed to treat high PM concentrations in the entire flue gas 

stream immediately downstream of the boiler. The existing ESP must remain in service for the COHPAC 

fabric filter to effectively reduce PM/PM10 emissions. PacifiCorp estimates the application of the 

COHPAC unit in addition to using FGC with the existing ESPs can reduce emissions an additional 50% 

resulting in a PM10 emission rate of 0.015 lb/MMBtu. PacifiCorp‟s proposed emission rates for each 

technology as applied to Units 1-4 are shown in Table 10 below.

Table 10: PM10 Emission Rates Per Boiler

Control Technology

Resulting PM10 Emission Rate 

(lb/MMBtu)

Existing ESPs 0.030-0.074 (a)

Existing ESPs with FGC 0.030

Existing ESP and New Polishing Fabric Filter 0.015

(a) Achievable baseline emission rates using existing ESPs on Jim Bridger Units 1-4.

PM10: EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impact of installing COHPAC on each of the four units. The pressure 

drop created by the fabric filter and associated ductwork requires additional energy from the existing draft 

fan, which will have to be upgraded. PacifiCorp calculated the additional energy costs based on a 90 

percent annual plant capacity factor. The installation of a COHPAC fabric filter would require 

approximately 3.4 MW of power, equating to an annual power usage of approximately 26.7 million kWhr for Unit 1. Installing a COHPAC on Unit 2 would require approximately 3.4 MW of power, equating 

to an annual power usage of approximately 26.5 million kW-hr. Unit 3 would require approximately 3.3 

MW of power, equating to an annual power usage of approximately 26.3 million kW-hr and Unit 4 would 

require approximately 3.4 MW of power, equating to an annual power usage of approximately 26.7 

million kW-hr.

Installing FGC on each of the four units will require a minimal amount of additional power. PacifiCorp 

estimates that FGC will require an additional 50 kW per unit.
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AP-6040 BART Application Analysis

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PacifiCorp evaluated the environmental impacts associated with the proposed installation of FGC and 

COHPAC on Units 1-4 and did not anticipate negative environmental impacts from the addition of either 

of these PM control technologies.

PacifiCorp anticipates operating Jim Bridger Units 1-4 indefinitely and did not include life extension 

costs in the economic analysis. A standard control life of 20 years was used to calculate the capital 

recovery factor. The annual cost to control was determined using a capital recovery factor based on a 

7.1% interest rate. PacifiCorp labor and service costs were used to calculate the annual operating and 

maintenance costs. Annual power costs, including a cost escalation factor, associated with the operation 

of pollution controls were included.

Several different metrics can be considered when evaluating the cost-benefit relationships of different 

emission control technologies. In 40 CFR part 51 Appendix Y two metrics are specifically mentioned: 

cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has 

extensive experience using cost effectiveness (i.e., dollars per ton of pollutant removed) to evaluate 

different control technologies. Incremental cost effectiveness is also used extensively by the Division 

when comparing emission controls under the BACT process. While the BART and the BACT processes

are not necessarily equivalent, control determinations from either process are based on cost effectiveness 

and incremental cost effectiveness and are indicative of the economic costs to control emissions. In 

addition to providing cost effectiveness and incremental cost effectiveness results, PacifiCorp provided 

cost information in terms of cost of applying emission controls and the level of visibility improvement 

achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and visibility 

improvement differences between control options, it is not commonly used to assess the overall 

effectiveness of pollution control equipment. When performing the presumptive BART limits analyses 

for NOx and SO2, EPA addressed cost effectiveness and incremental cost effectiveness separate from 

visibility improvement. The dollars per deciview metric was not used to compare control options. 

Visibility improvements from the application of the analyzed control measures used to establish 

presumptive levels were addressed in a separate visibility analysis. As discussed in the comprehensive 

visibility analysis presented later in this analysis as Step 5: Evaluate visibility impacts, the Division 

evaluated the amount of visibility improvement gained in relation to each proposed emission control 

technology. The Division considered capital cost, annual cost, cost effectiveness, and incremental cost 

effectiveness in the evaluation of each proposed PM emission control. Economic and environmental 

costs for additional PM control on Jim Bridger Units 1-4 are summarized in the following tables.

Table 11: Jim Bridger Units 1 Economic Costs

Cost

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

Control Equipment Capital Cost $0 $3,900,000 $48,386,333

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $371,007 $4,602,992

Annual O&M Costs $0 $175,564 $1,764,126

Annual Cost of Control $0 $546,571 $6,367,118
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Table 12: Jim Bridger Unit 1 Environmental Costs

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

PM10 Emission Rate (lb/MMBtu) 0.045 0.030 0.015

Annual PM10 Emission (tpy) (a)

1,064 710 355

Annual PM10 Reduction (tpy) N/A 354 709

Annual Cost of Control $0 $546,571 $6,367,118

Cost per ton of Reduction N/A $1,544 $8,980

Incremental Cost per ton of 

Reduction N/A $1,544 $16,396

(a) Annual emissions based on unit heat input rate of 6,000 MMBtu/hr and 7,884 hours of operation per year. 

Table 13: Jim Bridger Unit 2 Economic Costs

Cost

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

Control Equipment Capital Cost $0 $3,900,000 $48,386,333

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $371,007 $4,602,992

Annual O&M Costs $0 $175,564 $1,754,666

Annual Cost of Control $0 $546,571 $6,357,658

Table 14: Jim Bridger Unit 2 Environmental Costs

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

PM10 Emission Rate (lb/MMBtu) 0.074 0.030 0.015

Annual PM10 Emission (tpy) (a)

1,750 710 355

Annual PM10 Reduction (tpy) N/A 1,040 1,395

Annual Cost of Control $0 $546,571 $6,357,658

Cost per ton of Reduction N/A $526 $4,557

Incremental Cost per ton of 

Reduction N/A $526 $16,369

(a) Annual emissions based on unit heat input rate of 6,000 MMBtu/hr and 7,884 hours of operation per year. 
PacifiCorp Jim Bridger Power Plant

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Table 15: Jim Bridger Unit 3 Economic Costs

Cost

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

Control Equipment Capital Cost $0 $3,900,000 $48,386,333

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $371,007 $4,602,992

Annual O&M Costs $0 $175,564 $1,734,442

Annual Cost of Control $0 $546,571 $6,337,434

Table 16: Jim Bridger Unit 3 Environmental Costs

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

PM10 Emission Rate (lb/MMBtu) 0.057 0.030 0.015

Annual PM10 Emission (tpy) (a)

1,348 710 355

Annual PM10 Reduction (tpy) N/A 638 993

Annual Cost of Control $0 $546,571 $6,337,434

Cost per ton of Reduction N/A $857 $6,382

Incremental Cost per ton of 

Reduction N/A $857 $16,312

(a) Annual emissions based on unit heat input rate of 6,000 MMBtu/hr and 7,884 hours of operation per year. 

Table 17: Jim Bridger Unit 4 Economic Costs

Cost

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

Control Equipment Capital Cost $0 N/A $48,386,333

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 N/A $4,602,992

Annual O&M Costs $0 $175,564 $1,764,126

Annual Cost of Control $0 $175,564 $6,367,118
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Table 18: Jim Bridger Unit 4 Environmental Costs

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

PM10 Emission Rate (lb/MMBtu) 0.030 0.030 0.015

Annual PM10 Emission (tpy) (a)

710 710 355

Annual PM10 Reduction (tpy) N/A 0 355

Annual Cost of Control $0 $175,564 $6,367,118

Cost per ton of Reduction N/A N/A $17,936

Incremental Cost per ton of 

Reduction N/A N/A $17,936

(a) Annual emissions based on unit heat input rate of 6,000 MMBtu/hr and 7,884 hours of operation per year. 

The cost effectiveness and incremental cost effectiveness of applying a new polishing fabric filter are not 

reasonable. However, the control was included in the final step in the PM/PM10 BART determination 

process for Jim Bridger Units 1-4, Step 5: Evaluate visibility impacts, which is addressed in a 

comprehensive visibility analysis covering all three visibility impairing pollutants and associated control 

options. The visibility analysis follows Steps 1-4 for SO2 emissions in this application analysis. Tables 

27-30, on pages 36-39, list the modeled control scenarios and associated emission rates.

SO2: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

PacifiCorp reviewed a broad range of informative sources, including EPA‟s RACT/BACT/LAER 

clearinghouse, in an effort to identify applicable SO2 emission control technologies for Jim Bridger Units 

1-4. Based on the results of this review, PacifiCorp proposed wet flue gas desulfurization (WFGD) and 

dry flue gas desulfurization (DFGD) as potential retrofit technologies to reduced SO2 emissions.

1. Wet FGD – SO2 is removed through absorption by mass transfer as soluble SO2 in the exhaust gas 

mixture is dissolved in an alkaline water solvent that has low volatility under process conditions. 

SO2 diffuses from the gas into the scrubber water when the liquid contains less than the 

equilibrium concentration of the gaseous SO2. The rate of SO2 mass transfer between the two 

phases is largely dependent on the surface area exposed and the time of contact. A properly 

designed wet scrubber or gas absorber will provide sufficient contact between the gas and the 

liquid solvent to allow diffusion of SO2. Once the SO2 enters the alkaline water phase, it will 

form a weak acid and react with the alkaline component dissolved in the scrubber water to form a 

sulfate (SO4) or sulfite (SO3). The acid/alkali chemical reaction prevents the SO2 from diffusing 

back into the flue gas stream. When the alkaline scrubber water is saturated with sulfur 

compounds, it can be converted to a wet gypsum by-product that may be sold. SO2 removal 

efficiencies for wet scrubbers can be as high as 99%.

2. Dry FGD – Dry scrubbers are similar to sorbent injection systems in that both systems introduce 

media directly into the flue gas stream, however the addition of the dry scrubber vessel provides 

greater contact area for adsorption and enhances chemical reactivity. A spray dryer dry scrubber 

sprays an atomized alkaline slurry into the flue gas upstream of particulate control system, often a 

fabric filter. Water in the slurry evaporates, hydrolizing the SO2 into a weak acid, which reacts 
PacifiCorp Jim Bridger Power Plant

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with the alkali to form a sulfate or sulfite. The resulting dry product is captured in the particulate 

control and physically moved from the exhaust gas into a storage bin. The dry by-product may be 

dissolved back into the lime slurry or dried and sold as a gypsum by-product. Spray dryer dry 

scrubbers typically require lower capital cost than a wet scrubber. They also require less flue gas 

after-treatment. When exhaust gas leaves the wet scrubber, it is at or near saturation. A wet 

scrubber can lower exhaust gas temperatures down into a temperature range of 110 to 140 F, 

which may lead to corrosive condensation in the exhaust stack. A spray dryer dry scrubber does 

not enhance stack corrosion like a wet scrubber because it will not saturate the exhaust gas or 

significantly lower the gas temperature. Removal efficiencies for spray dryer dry scrubbers can 

range from 70% to 95%.

SO2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

PacifiCorp did not eliminate either of the two control technologies listed above as technically infeasible. 

PacifiCorp analyzed the impact of installing dry FGD on each of the units using the existing ESPs, 

optimizing the existing wet FGDs, and upgrading the existing wet FGDs.

SO2: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

The Division considers the control effectiveness of a proposed control technology to be equivalent to the 

BART-determined permit limit. The limit is based on continuous compliance when the control 

equipment is well maintained and operated in a manner consistent with good air pollution control 

practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit 

it is important to consider that even well maintained and operated equipment will have some emissions 

variability. Complex emission control equipment, such as wet FGD, generally have inherent variability 

that must be considered when establishing the limit. Otherwise, the source will be out of compliance 

even though the equipment is operated and maintained as well as possible.

PacifiCorp determined that Jim Bridger Units 1-4 have an uncontrolled SO2 emission rate, per unit, of 1.2

lb/MMBtu, based on an average coal sulfur content of 0.58% by weight. The existing three column 

Babcock & Wilcox wet FGD systems on Jim Bridger Units 1-3 currently reduce SO2 emissions by 

approximately 78% to achieve a SO2 emission limit of 0.27 lb per MMBtu. The Babcock & Wilcox wet 

FGD system on Jim Bridger Unit 4 currently reduces emission by 86% resulting in a SO2 emission rate of 

0.17 lb/MMBtu, based on an average coal sulfur content of 0.58% by weight.

Installing a new dry FGD system and utilizing the existing ESP on each of the Jim Bridger units may

reduce uncontrolled SO2 emissions by 82.5% resulting in an emission rate of 0.21 lb/MMBtu of SO2, 

based on an average coal sulfur content of 0.58% by weight. Presumptive SO2 levels for uncontrolled 

units are 95% emissions reduction or 0.15 lb/MMBtu. PacifiCorp does not anticipate achieving 

presumptive SO2 emission levels using dry FGD. Additionally, PacifiCorp‟s experience evaluating the 

application of dry FGD to coal-fired boilers indicates there will be a substantial capital cost involved in 

removing the existing wet FGD units and replacing them with the new dry FGD. For these reasons and 

the fact that wet FGD is an effective, modern SO2 emissions control technology capable of reducing 

emissions lower than 0.21 lb/MMBtu, PacifiCorp did not further evaluate and document the costs

associated with installing dry FGD on Jim Bridger Units 1-4 or quantify the resulting visibility 

improvement.
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PacifiCorp evaluated potential changes to the existing wet FGD systems on Jim Bridger Units 1-4 to 

improve the SO2 removal efficiencies. The first option was to optimize the existing equipment. Partially 

closing the bypass damper will reduce the amount of flue gas that is not treated by the wet FGD system 

and is instead used to reheat the treated flue gas exiting the scrubber. Relocating the opacity monitor and 

modifying the system to minimize scaling problems will also help reduce SO2 emissions. PacifiCorp 

anticipates the reduction in SO2 emissions from applying the above optimization changes on Units 1-3 

will be an additional 0.07 lb/MMBtu emission reduction, resulting in a 0.20 lb/MMBtu emission rate. 

The wet FGD system on Unit 4 is achieving an emission rate of 0.17 lb/MMBtu and any minor 

optimization changes to the system are not expected to significantly reduce emissions. PacifiCorp did not 

further evaluate optimizing the existing wet FGD systems on Units 1-4 because the anticipated emission 

rates, 0.20 lb/MMBtu for Units 1-3 and 0.17 lb/MMBtu for Unit 4, are above the presumptive SO2 limit

of 0.15 lb/MMBtu and do not achieve a 95% SO2 removal efficiency.

The final proposed option is upgrading the wet FGD systems. This would involve completely closing the 

bypass damper to eliminate bypass flue gas flow, relocating the opacity monitor, adding new induction 

fans, adding a liner and drains to the existing exhaust stack for wet operation, and using a refined soda ash 

reagent in place of the existing sodium reagent. Applying the proposed upgrades is anticipated to reduce 

total SO2 emissions by approximately 92% resulting in an emission rate of 0.10 lb/MMBtu, based on an

average coal sulfur content of 0.58% by weight. PacifiCorp considers it to be technically infeasible for 

the present wet FGD systems to achieve a 95% SO2 removal efficiency, which equates to 0.06 lb/MMBtu

for the Jim Bridger units, on a continuous basis. PacifiCorp‟s proposed emission rates for each SO2

emission reduction technology applied to Jim Bridger Units 1-4 are shown in Table 19.

Table 19: SO2 Emission Rates Per Boiler

Control Technology

SO2

Emission Rate 

(lb/MMBtu)

Existing Wet FGD 0.27 (a)

New Dry FGD with Existing ESP 0.21

Optimized Wet FGD 0.20 (b)

Upgraded Wet FGD 0.10

(a) Unit 4 currently achieves a 0.17 lb/MMBtu SO2 emission rate.

(b) Unit 4 is already well controlled and any additional optimization changes are not expected to 

significantly reduce emissions.

SO2: EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impacts of upgrading the existing wet FGD systems on all four units. 

The upgrades require 530 kW on Units 1 and 2, and 520 kW of additional power on Units 3 and 4. Using 

a 90% annual plant capacity factor, the additional power amounts to approximately 4.2 million kW-hr per 

unit.
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PacifiCorp‟s environmental evaluation of installing additional SO2 controls noted that upgrading the 

existing wet FGD systems on the four units results in additional scrubber waste disposal and makeup 

water requirements. Eliminating the scrubber bypass will reduce the stack gas temperature from 140°F to 

120°F, which in turn reduces the buoyancy of the exiting flue gas.

PacifiCorp anticipates operating Jim Bridger Units 1-4 indefinitely and did not include life extension 

costs in the economic analysis. A standard control life of 20 years was used to calculate the capital 

recovery factor. The annual cost to control was determined using a capital recovery factor based on a 

7.1% interest rate. PacifiCorp labor and service costs were used to calculate the annual operating and 

maintenance costs. Annual power costs, including a cost escalation factor, associated with the operation 

of pollution controls were included.

Several different metrics can be considered when evaluating the cost-benefit relationships of different 

emission control technologies. In 40 CFR part 51 Appendix Y two metrics are specifically mentioned: 

cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has 

extensive experience using cost effectiveness (i.e., dollars per ton of pollutant removed) to evaluate 

different control technologies. Incremental cost effectiveness is also used extensively by the Division 

when comparing emission controls under the BACT process. While the BART and the BACT processes

are not necessarily equivalent, control determinations from either process are based on cost effectiveness 

and incremental cost effectiveness and are indicative of the economic costs to control emissions. In 

addition to providing cost effectiveness and incremental cost effectiveness results, PacifiCorp provided 

cost information in terms of cost of applying emission controls and the level of visibility improvement 

achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and visibility 

improvement differences between control options, it is not commonly used to assess the overall 

effectiveness of pollution control equipment. When performing the presumptive BART limits analyses 

for NOx and SO2, EPA addressed cost effectiveness and incremental cost effectiveness separate from 

visibility improvement. The dollars per deciview metric was not used to compare control options. 

Visibility improvements from the application of the analyzed control measures used to establish 

presumptive levels were addressed in a separate visibility analysis. The Division considered capital cost, 

annual cost, cost effectiveness, and incremental cost effectiveness in the evaluation of each proposed SO2

emission control. Economic and environmental costs for additional controls on Jim Bridger Units 1-4 are 

summarized in the following tables.

Table 20: Jim Bridger Units 1-3 Economic Costs

Cost

Existing 

Wet FGD

Upgraded 

Wet FGD

Control Equipment Capital Cost $0 $12,999,990

Capital Recovery Factor N/A 0.09513

Annual Capital Recovery Costs $0 $1,236,681

Annual O&M Costs $0 $1,258,176 (a)

Annual Cost of Control $0 $2,494,857

(a) Annual maintenance costs for Unit 3 are $4,518 less per year than Units 1 and 2.
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Table 21: Jim Bridger Units 1-3 Environmental Costs

Existing 

Wet FGD

Upgraded 

Wet FGD 

SO2 Emission Rate (lb/MMBtu) 0.27 0.10

Annual SO2 Emission (tpy) (a) 6,386 2,365

Annual SO2 Reduction (tpy) N/A 4,021

Annual Cost of Control $0 $2,494,857

Cost per ton of Reduction N/A $620 (b)

Incremental Cost per ton of Reduction N/A $620 (b)

(a) Annual emissions based on unit heat input rate of 6,000 MMBtu/hr and 7,884 hours of operation per year.

(b) Cost per ton of SO2

reduction on Unit 3 is $619 because annual maintenance costs are $4,518 less.

Table 22: Jim Bridger Unit 4 Economic Costs

Cost

Existing 

Wet FGD

Upgraded 

Wet FGD

Control Equipment Capital Cost $0$5,759,814

Capital Recovery Factor N/A 0.09513

Annual Capital Recovery Costs $0 $547,931

Annual O&M Costs $0 $658,683

Annual Cost of Control $0 $1,206,614

Table 23: Jim Bridger Unit 4 Environmental Costs

Existing 

Wet FGD

Upgraded 

Wet FGD

SO2 Emission Rate (lb/MMBtu) 0.17 0.10

Annual SO2 Emission (tpy) (a) 4,021 2,365

Annual SO2 Reduction (tpy) N/A 1,656

Annual Cost of Control $0 $1,206,614

Cost per ton of Reduction N/A $729

Incremental Cost per ton of Reduction N/A $729

(a) Annual emissions based on unit heat input rate of 6,000 MMBtu/hr and 7,884 hours of operation per year.
PacifiCorp Jim Bridger Power Plant

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The cost effectiveness and incremental cost effectiveness of upgrading the existing wet FGD on all four 

units is reasonable. The final step in the SO2 BART determination process for Jim Bridger Units 1-4, 

Step 5: Evaluate visibility impacts, is addressed in a comprehensive visibility analysis presented in the 

next section of this BART application analysis. The Division evaluated the amount of visibility 

improvement gained from the application of additional NOx, PM/PM10, and SO2 emission control 

technology in relation to all three visibility impairing pollutants. Tables 27-30, on pages 36-39, list the 

modeled control scenarios and associated emission rates.

VISIBILITY IMPROVEMENT DETERMINATION:

The fifth of five steps in a BART determination analysis, as required by 40 CFR part 51 Appendix Y, is 

the determination of the degree of Class I area visibility improvement that would result from installation 

of the various options for control technology. This factor was evaluated for the PacifiCorp Jim Bridger

facility by using an EPA-approved dispersion modeling system (CALPUFF) to predict the change in 

Class I area visibility. The Division had previously determined that the facility was subject to BART 

based on the results of initial screening modeling that was conducted using current (baseline) emissions 

from the facility. The screening modeling, as well as more refined modeling conducted by the applicant,

is described in detail below. 

Bridger Wilderness Area (WA) and Fitzpatrick WA in Wyoming and Mount Zirkel WA in Colorado are 

the closest Class I areas to the PacifiCorp Jim Bridger facility, as shown in Figure 2 below. Bridger WA

is located approximately 98 kilometers (km) northwest of the facility and Fitzpatrick WA is located 

approximately 151 km northwest of the facility. Mount Zirkel WA is located approximately 185 km 

southeast of the facility. 

Only those Class I areas most likely to be impacted by the Jim Bridger Power Plant sources were 

modeled, as determined by source/Class I area locations, distances to each Class I area, and professional 

judgment considering meteorological and terrain factors. It can be reasonably assumed that areas at 

greater distances and in directions of less frequent plume transport will experience lower impacts than 

those predicted for the three modeled areas. All source-Class I area distances from Jim Bridger Power 

Plant to Bridger WA, Fitzpatrick WA, and Mount Zirkel WA exceed 50 km and are less than 300 km, 

thus falling within the range recommended for CALPUFF application. 

Screening modeling that was conducted to determine if the Jim Bridger plant sources would be subject to 

BART, as described below, included receptors for the two closest Class I areas only (Bridger WA and 

Fitzpatrick WA). Subsequent refined modeling, as described later in this document, was conducted for all 

three of the closest Class I areas (Bridger WA, Fitzpatrick WA, and Mount Zirkel WA).
PacifiCorp Jim Bridger Power Plant

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Figure 2

Jim Bridger Power Plant and Class I Areas

#*

Fremont

Carbon

Park

Sweetwater

Natrona

Sublette

Johnson

Big Horn

Washakie

Teton

Hot Springs

Uinta

Lincoln

Albany

Sheridan

Campbell

Converse

Washakie Wilderness

Bridger Wilderness

Fitzpatrick Wilderness

North Absaroka Wilderness

Mount Zirkel Wilderness

Wyoming

Colorado Utah

Cody

Basin

Lander

Casper

Worland

Rawlins

Buffalo

Pinedale

Thermopolis

Green River

Jim Bridger Power Plant

106°0'0"W

107°0'0"W

107°0'0"W

108°0'0"W

108°0'0"W

109°0'0"W

109°0'0"W

110°0'0"W

110°0'0"W

44°0'0"N

44°0'0"N

43°0'0"N

43°0'0"N

42°0'0"N

42°0'0"N

41°0'0"N

41°0'0"N
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SCREENING MODELING

To determine if the PacifiCorp Jim Bridger facility would be subject to BART, the Division conducted 

CALPUFF modeling using three years of meteorological data. These data, from 1995-1996 and 2001, 

consisted of surface and upper-air observations and gridded output from the Mesoscale Model (MM5). 

Resolution of the MM5 data was 36-km for all three of the modeled years. Sources input to the modeling 

included the potential emissions for current operation from the four coal-fired boilers at the Jim Bridger

facility.

Results of the modeling showed that the 98th percentile value for the change in visibility (in units of delta 

deciview [Δdv]) was above 0.5 Δdv for Bridger WA and Fitzpatrick WA for all three years of 

meteorology. As defined in EPA‟s final BART rule, a predicted 98th percentile impact equal to or greater 

than 0.5 Δdv from a given source indicates that the source contributes to visibility impairment, and 

therefore is subject to BART. The results of the screening modeling are shown in the table below.

Table 24: Results of the Class I Area Screening Modeling

Class I Area

Maximum 

Modeled 

Value (Δdv)

98th

Percentile 

Value (Δdv)

1995

Bridger WA 9.7 3.1

Fitzpatrick WA 3.3 1.5

1996

Bridger WA 8.7 2.0

Fitzpatrick WA 3.8 1.1

2001

Bridger WA 4.6 2.8

Fitzpatrick WA 4.3 1.5

Δdv = delta deciview

WA = wilderness area

REFINED MODELING

Because of the results of the Division‟s screening modeling, PacifiCorp was required to conduct a refined 

BART analysis that included CALPUFF visibility modeling for the facility. The modeling approach 

followed the requirements described in the Division‟s BART modeling protocol, BART Air Modeling 

Protocol - Individual Source Visibility Assessments for BART Control Analyses (WDEQ-AQD, 

September 2006). 

CALPUFF System

Predicted visibility impacts from the PacifiCorp Jim Bridger sources were determined with the EPA 

CALPUFF modeling system, which is the EPA-preferred modeling system for long-range transport. As 

described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR part 51), long-range 

transport is defined as modeling with source-receptor distances greater than 50 km. Because all modeled 

areas are located more than 50 km from the facility, the CALPUFF system was appropriate for use.
PacifiCorp Jim Bridger Power Plant

AP-6040 BART Application Analysis

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The CALPUFF modeling system consists of a meteorological data pre-processor (CALMET), an air 

dispersion model (CALPUFF), and post-processor programs (POSTUTIL, CALSUM, CALPOST). The 

CALPUFF model was developed as a non-steady-state air quality modeling system for assessing the 

effects of time- and space-varying meteorological conditions on pollutant transport, transformation, and 

removal. 

CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a threedimensional, gridded modeling domain. Meteorological inputs to CALMET can include surface and 

upper-air observations from multiple meteorological monitoring stations. Additionally, the CALMET 

model can utilize gridded analysis fields from various mesoscale models such as MM5 to better represent 

regional wind flows and complex terrain circulations. Associated two-dimensional fields such as mixing 

height, land use, and surface roughness are included in the input to CALMET. The CALMET model 

allows the user to “weight” various terrain influence parameters in the vertical and horizontal directions 

by defining the radius of influence for surface and upper-air stations. 

CALPUFF is a multi-layer, Lagrangian puff dispersion model. CALPUFF can be driven by the threedimensional wind fields developed by the CALMET model (refined mode), or by data from a single 

surface and upper-air station in a format consistent with the meteorological files used to drive steady-state 

dispersion models. All far-field modeling assessments described here were completed using the 

CALPUFF model in a refined mode.

CALSUM is a post-processing program that can operate on multiple CALPUFF output files to combine 

the results for further post-processing. POSTUTIL is a post-processing program that processes 

CALPUFF concentrations and wet/dry flux files. The POSTUTIL model operates on one or more output 

data files from CALPUFF to sum, scale, and/or compute species derived from those that are modeled, and 

outputs selected species to a file for further post-processing. CALPOST is a post-processing program that 

can read the CALPUFF (or POSTUTIL or CALSUM) output files and calculate the impacts to visibility. 

All of the refined CALPUFF modeling was conducted with the version of the CALPUFF system that was 

recognized as the EPA-approved release at the time of the development of the Division‟s modeling 

protocol. Version designations of the key programs are listed in the table below.

Table 25: Key Programs in CALPUFF System

Program Version Level

CALMET 5.53a 040716

CALPUFF 5.711a 040716

CALPOST 5.51 030709
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Meteorological Data Processing (CALMET)

As required by the Division‟s modeling protocol, the CALMET model was used to construct an initial 

three-dimensional windfield using data from the MM5 model. Surface and upper-air data were input to 

CALMET to adjust the initial windfield, but because of the relative scarcity of wind observations in the 

modeling domain, the influence of the observations on the initial windfield was minimized. Because the 

MM5 data were afforded a high degree of influence on the CALMET windfields, the Division obtained 

MM5 data at 12-km resolution that spanned the years 2001-2003. Locations of the observations that were 

input to CALMET, including surface, upper-air, and precipitation stations, are shown in Figure 3. Default 

settings were used in the CALMET input files for most of the technical options. The following table lists 

the key user-defined CALMET settings that were selected. 

Table 26: Key User-Defined CALMET Settings

Variable Description Value 

PMAP Map projection LCC 

DGRIDKM Grid spacing (km) 4 

NZ Number of layers 10 

ZFACE Cell face heights (m) 0, 20, 40, 100, 140, 320, 

580, 1020, 1480, 2220, 3400 

RMIN2 Minimum distance for extrapolation -1 

IPROG Use gridded prognostic model output 14 

RMAX 1 Maximum radius of influence (surface 

layer, km) 

30 

RMAX 2 Maximum radius of influence (layers 

aloft, km) 

50 

TERRAD Radius of influence for terrain (km) 15 

R1 Relative weighting of first guess wind 

field and observations (km) 

5 

R2 Relative weighting aloft (km) 25 
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Figure 3

Observations Input to CALMET

-500 -400 -300 -200 -100 0 100 200 300 400 500

LCC E (km)

-300

-200

-100

0

100

200

300

400

LCC N (km)

KWX

AIA

AKO

APA

ASE

BFF

BIL

BPI

BTM

BYG

BYI

BZN

CAG

CPR CDR

CUT

CYS

D07

DEN

DGW

DLN

EEO

EVW

GCC

GEY

GJT

IDA

IEN

ITR

LAR

LGU

LIC

LND

LVM

LXV

OGD

P60

PHP

PIH

PUC

RAP

RIL

RIW

RKS

RWL

RXE

SHR

SLC

SNY

TOR

VEL

WRL

RAP

DEN

SLC

RIW

Precipitation Station = green

Surface Station = white 3-letter

Upper-Air (+ surface) = red 3-letter

Jim Bridger

Power Plant
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CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry 

mechanism (MESOPUFF II), the model required input of background ozone and ammonia

concentrations. For ozone, hourly data collected from the following stations were used:

Rocky Mountain National Park (NP), Colorado

Craters of the Moon National Monument, Idaho

Highland, Utah

Thunder Basin, Wyoming

Yellowstone NP, Wyoming

Centennial, Wyoming

Pinedale, Wyoming

For any hour that was missing ozone data from all stations, a default value of 44 parts per billion 

(ppb) was used by the model as a substitute. For ammonia, a domain-wide background value of 2 

ppb was used. 

Latitude and longitude coordinates for Class I area discrete receptors were taken from the 

National Park Service (NPS) Class I Receptors database and converted to the appropriate 

Lambert Conformal Conic coordinates. Figures 4-6 show the receptor configurations that were

used for Bridger WA, Fitzpatrick WA, and Mount Zirkel WA. Receptor spacing for the three 

modeled areas is approximately 1.3 km in the east-west direction and approximately 1.8 km in the 

north-south direction. 
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Figure 4

Receptors for Bridger WA
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Figure 5

Receptors for Fitzpatrick WA
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Figure 6

Receptors for Mount Zirkel WA

CALPUFF Inputs – Baseline and Control Options

Source release parameters and emissions for baseline and control options for each unit at the Jim 

Bridger Plant are shown in the tables below. 
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Table 27: CALPUFF Inputs for Jim Bridger Unit 1

JIM BRIDGER 1 Baseline

PostControl 

Scenario 1

PostControl 

Scenario 2

PostControl 

Scenario 3

PostControl 

Scenario 4

Post-Control 

Scenario A

PostControl 

Scenario B

Model Input Data

Current 

Operation 

with Wet 

FGD and 

ESP

LNB with 

separated 

OFA, 

Upgrade 

Wet FGD, 

Enhanced 

ESP 

LNB with 

separated 

OFA, 

Upgrade 

Wet FGD, 

New Fabric 

Filter

LNB with 

separated 

OFA and 

SCR, 

Upgrade 

Wet FGD, 

and 

Enhanced 

ESP 

LNB with 

separated 

OFA and 

SCR, 

Upgrade 

Wet FGD, 

New Fabric 

Filter

Committed 

Controls: 

LNB with 

separated 

OFA, 

Upgrade 

FGD, 

Enhanced 

ESP 

Committed 

Controls 

with SCR 

Hourly Heat Input (mmBtu/hour) 6,000 6,000 6,000 6,000 6,000 6,000 6,000

Sulfur Dioxide (SO2) (lb/mmBtu) 0.27 0.10 0.10 0.10 0.10 0.15 0.15

Sulfur Dioxide (SO2) pounds per hour 

(lb/hr) 1,602 600 600 600 600 900 900

Nitrogen Oxide (NOx) (lb/mmBtu) 0.45 0.24 0.24 0.07 0.07 0.26 0.07

Nitrogen Oxide (NOx) (lb/hr) 2,700 1,440 1,440 420 420 1,560 420

PM10 (lb/mmBtu) 0.045 0.030 0.015 0.030 0.015 0.030 0.030

PM10 (lb/hr) 270.0 180.0 90.0 180.0 90.0 180.0 180.0

Coarse Particulate (PM2.5<diameter< PM10) 

(lb/hr)(a) 116.1 77.4 51.3 77.4 51.3 77.4 77.4

Fine Particulate (diameter<PM2.5) (lb/hr)(b) 153.9 102.6 38.7 102.6 38.7 102.6 102.6

Sulfuric Acid (H2SO4) (lb/hr) 55.2 55.2 55.2 94.8 94.8 55.2 94.7

Ammonium Sulfate [(NH4)2SO4] (lb/hr) -- -- -- 7.0 7.0 -- 7.0

Ammonium Bisulfate (NH4)HSO4 (lb/hr) -- -- -- 12.2 12.2 -- 12.2

H2SO4 as Sulfate (SO4) (lb/hr) 54.1 54.1 54.1 92.9 92.9 54.1 92.8

(NH4)2SO4 as SO4 (lb/hr) -- -- -- 5.1 5.1 -- 5.1

(NH4)HSO4 as SO4 (lb/hr) -- -- -- 10.2 10.2 -- 10.2

Total Sulfate (SO4) (lb/hr) 54.1 54.1 54.1 108.2 108.2 54.1 108.1

Stack Conditions

Stack Height (meters) 152 152 152 152 152 152 152

Stack Exit Diameter (meters) 7.32 7.32 7.32 7.32 7.32 7.32 7.32

Stack Exit Temperature (Kelvin) 333 322 333 333 333 328 328

Stack Exit Velocity (meters per second) 25.6 24.7 27.4 27.4 27.4 24.7 24.7

(a) AP-42, Table 1.1-6: coarse PM counted as a percentage of PM10. This equates to 43 percent for ESP and 57 percent for Baghouse. 

(b) AP-42, Table 1.1-6: fine PM counted as a percentage of PM10. This equates to 57 percent for ESP and 43 percent for Baghouse.

Notes:
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Table 28: CALPUFF Inputs for Jim Bridger Unit 2

JIM BRIDGER 2 Baseline

PostControl 

Scenario 1

PostControl 

Scenario 2

PostControl 

Scenario 3

PostControl 

Scenario 4

PostControl 

Scenario A

PostControl 

Scenario B

Model Input Data

Current 

Operations 

with LNB 

with 

separated 

OFA, Wet 

FGD, and 

ESP

LNB with 

separated 

OFA, 

Upgrade 

Wet FGD, 

and 

Enhanced 

ESP 

LNB with 

separated 

OFA, 

Upgrade 

Wet FGD, 

New Fabric 

Filter

LNB with 

separated 

OFA and 

SCR, 

Upgrade 

Wet FGD, 

and 

Enhanced 

ESP 

LNB with 

separated 

OFA and 

SCR, 

Upgrade 

Wet FGD, 

New Fabric 

Filter

Committed 

Controls: 

LNB with 

separated 

OFA, 

Upgrade 

FGD, 

Enhanced 

ESP

Committed 

Controls 

with SCR 

Hourly Heat Input (mmBtu/hour) 6,000 6,000 6,000 6,000 6,000 6,000 6,000

Sulfur Dioxide (SO2) (lb/mmBtu) 0.27 0.10 0.10 0.10 0.10 0.15 0.15

Sulfur Dioxide (SO2) pounds per hour 

(lb/hr) 1,602 600 600 600 600 900 900

Nitrogen Oxide (NOx) (lb/mmBtu) 0.24 0.24 0.24 0.07 0.07 0.26 0.07

Nitrogen Oxide (NOx) (lb/hr) 1,440 1,440 1,440 420 420 1,560 420

PM10 (lb/mmBtu) 0.074 0.030 0.015 0.030 0.015 0.030 0.030

PM10 (lb/hr) 444.0 180.0 90.0 180.0 90.0 180.0 180.0

Coarse Particulate (PM2.5<diameter< PM10) 

(lb/hr)(a) 190.9 77.4 51.3 77.4 51.3 77.4 77.4

Fine Particulate (diameter<PM2.5) (lb/hr)(b) 253.1 102.6 38.7 102.6 38.7 102.6 102.6

Sulfuric Acid (H2SO4) (lb/hr) 55.2 55.2 55.2 94.8 94.8 55.2 94.7

Ammonium Sulfate [(NH4)2SO4] (lb/hr) -- -- -- 7.0 7.0 -- 7.0

Ammonium Bisulfate (NH4)HSO4 (lb/hr) -- -- -- 12.2 12.2 -- 12.2

H2SO4 as Sulfate (SO4) (lb/hr) 54.1 54.1 54.1 92.9 92.9 54.1 92.8

(NH4)2SO4 as SO4 (lb/hr) -- -- -- 5.1 5.1 -- 5.1

(NH4)HSO4 as SO4 (lb/hr) -- -- -- 10.2 10.2 -- 10.2

Total Sulfate (SO4) (lb/hr) 54.1 54.1 54.1 108.2 108.2 54.1 108.1

Stack Conditions

Stack Height (meters) 152 152 152 152 152 152 152

Stack Exit Diameter (meters) 7.32 7.32 7.32 7.32 7.32 7.32 7.32

Stack Exit Temperature (Kelvin) 333 322 333 333 333 328 328

Stack Exit Velocity (meters per second) 27.4 24.7 27.4 27.4 27.4 24.7 24.7

Notes:

(a) AP-42, Table 1.1-6: coarse PM counted as a percentage of PM10. This equates to 43 percent for ESP and 57 percent for Baghouse. 

(b) AP-42, Table 1.1-6: fine PM counted as a percentage of PM10. This equates to 57 percent for ESP and 43 percent for Baghouse.
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Table 29: CALPUFF Inputs for Jim Bridger Unit 3

JIM BRIDGER 3 Baseline

PostControl 

Scenario 1

PostControl 

Scenario 2

PostControl 

Scenario 3

PostControl 

Scenario 4

PostControl 

Scenario A

PostControl 

Scenario B

Model Input Data

Current 

Operations 

with Wet 

FGD and 

ESP

LNB with 

separated 

OFA, 

Upgrade 

Wet FGD, 

and 

Enhanced 

ESP 

LNB with 

separated 

OFA, 

Upgrade 

Wet FGD, 

New Fabric 

Filter

LNB with 

separated 

OFA and 

SCR, 

Upgrade 

Wet FGD, 

and 

Enhanced 

ESP 

LNB with 

separated 

OFA and 

SCR, 

Upgrade 

Wet FGD, 

New Fabric 

Filter

Committed 

Controls: 

LNB with 

separated 

OFA, 

Upgrade 

FGD, 

Enhanced 

ESP

Committed 

Controls 

with SCR 

Hourly Heat Input (mmBtu/hour) 6,000 6,000 6,000 6,000 6,000 6,000 6,000

Sulfur Dioxide (SO2) (lb/mmBtu) 0.27 0.10 0.10 0.10 0.10 0.15 0.15

Sulfur Dioxide (SO2) pounds per hour 

(lb/hr) 1,602 600 600 600 600 900 900

Nitrogen Oxide (NOx) (lb/mmBtu) 0.45 0.24 0.24 0.07 0.07 0.26 0.07

Nitrogen Oxide (NOx) (lb/hr) 2,700 1,440 1,440 420 420 1,560 420

PM10 (lb/mmBtu) 0.057 0.030 0.015 0.030 0.015 0.030 0.030

PM10 (lb/hr) 342.0 180.0 90.0 180.0 90.0 180.0 180.0

Coarse Particulate (PM2.5<diameter< PM10) 

(lb/hr)(a) 147.1 77.4 51.3 77.4 51.3 77.4 77.4

Fine Particulate (diameter<PM2.5) (lb/hr)(b) 194.9 102.6 38.7 102.6 38.7 102.6 102.6

Sulfuric Acid (H2SO4) (lb/hr) 55.2 55.2 55.2 94.8 94.8 55.2 94.7

Ammonium Sulfate [(NH4)2SO4] (lb/hr) -- -- -- 7.0 7.0 -- 7.0

Ammonium Bisulfate (NH4)HSO4 (lb/hr) -- -- -- 12.2 12.2 -- 12.2

H2SO4 as Sulfate (SO4) (lb/hr) 54.1 54.1 54.1 92.9 92.9 54.1 92.8

(NH4)2SO4 as SO4 (lb/hr) -- -- -- 5.1 5.1 -- 5.1

(NH4)HSO4 as SO4 (lb/hr) -- -- -- 10.2 10.2 -- 10.2

Total Sulfate (SO4) (lb/hr) 54.1 54.1 54.1 108.2 108.2 54.1 108.1

Stack Conditions

Stack Height (meters) 152 152 152 152 152 152 152

Stack Exit Diameter (meters) 7.32 7.32 7.32 7.32 7.32 7.32 7.32

Stack Exit Temperature (Kelvin) 333 322 333 333 333 328 328

Stack Exit Velocity (meters per second) 25.6 24.8 27.4 27.4 27.4 24.7 24.7

Notes:

(a) AP-42, Table 1.1-6: coarse PM counted as a percentage of PM10. This equates to 43 percent for ESP and 57 percent for Baghouse. 

(b) AP-42, Table 1.1-6: fine PM counted as a percentage of PM10. This equates to 57 percent for ESP and 43 percent for Baghouse.
PacifiCorp Jim Bridger Power Plant

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Table 30: CALPUFF Inputs for Jim Bridger Unit 4

JIM BRIDGER 4 Baseline

PostControl 

Scenario 1

PostControl 

Scenario 2

PostControl 

Scenario 3

PostControl 

Scenario 4

Post-Control 

Scenario A

PostControl 

Scenario B

Model Input Data

Current 

Operations 

with Wet 

FGD and 

ESP

LNB with 

separated 

OFA, 

Upgrade 

Wet FGD, 

and 

Enhanced 

ESP 

LNB with 

separated 

OFA, 

Upgrade 

Wet FGD, 

New Fabric 

Filter

LNB with 

separated 

OFA and 

SCR, 

Upgrade 

Wet FGD, 

and 

Enhanced 

ESP 

LNB with 

separated 

OFA and 

SCR, 

Upgrade 

Wet FGD, 

New Fabric 

Filter

Committed 

Controls: 

LNB with 

separated 

OFA, 

Upgrade 

FGD, 

Enhanced 

ESP

Committed 

Controls 

with SCR 

Hourly Heat Input (mmBtu/hour) 6,000 6,000 6,000 6,000 6,000 6,000 6,000

Sulfur Dioxide (SO2) (lb/mmBtu) 0.17 0.10 0.10 0.10 0.10 0.15 0.15

Sulfur Dioxide (SO2) pounds per hour 

(lb/hr) 1,002 600 600 600 600 900 900

Nitrogen Oxide (NOx) (lb/mmBtu) 0.45 0.24 0.24 0.07 0.07 0.26 0.07

Nitrogen Oxide (NOx) (lb/hr) 2,700 1,440 1,440 420 420 1,560 420

PM10 (lb/mmBtu) 0.030 0.030 0.015 0.030 0.015 0.030 0.030

PM10 (lb/hr) 180.0 180.0 90.0 180.0 90.0 180.0 180.0

Coarse Particulate (PM2.5<diameter< PM10) 

(lb/hr)(a) 77.4 77.4 51.3 77.4 51.3 77.4 77.4

Fine Particulate (diameter<PM2.5) (lb/hr)(b) 102.6 102.6 38.7 102.6 38.7 102.6 102.6

Sulfuric Acid (H2SO4) (lb/hr) 55.2 55.2 55.2 94.8 94.8 55.2 94.7

Ammonium Sulfate [(NH4)2SO4] (lb/hr) 7.0 7.0 7.0

Ammonium Bisulfate (NH4)HSO4 (lb/hr) 12.2 12.2 12.2

H2SO4 as Sulfate (SO4) (lb/hr) 54.1 54.1 54.1 92.9 92.9 54.1 92.8

(NH4)2SO4 as SO4 (lb/hr) 5.1 5.1 5.1

(NH4)HSO4 as SO4 (lb/hr) 10.2 10.2 10.2

Total Sulfate (SO4) (lb/hr) 54.1 54.1 54.1 108.2 108.2 54.1 108.1

Stack Conditions

Stack Height (meters) 152 152 152 152 152 152 152

Stack Exit Diameter (meters) 9.45 9.45 9.45 9.45 9.45 9.45 9.45

Stack Exit Temperature (Kelvin) 322 322 322 322 322 322 322

Stack Exit Velocity (meters per second) 12.9 12.9 12.9 12.9 12.9 12.9 12.9

Notes:

(a) AP-42, Table 1.1-6: coarse PM counted as a percentage of PM10. This equates to 43 percent for ESP and 57 percent for Baghouse. 

(b) AP-42, Table 1.1-6: fine PM counted as a percentage of PM10. This equates to 57 percent for ESP and 43 percent for Baghouse.
PacifiCorp Jim Bridger Power Plant

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Visibility Post-Processing (CALPOST)

The changes in visibility were modeled using Method 6 within the CALPOST post-processor. Method 6 

requires input of monthly relative humidity factors [f(RH)] for each Class I area. Monthly f(RH) factors 

that were used for Bridger WA, Fitzpatrick WA, and Mount Zirkel WA are shown in the table below. 

Table 31: Relative Humidity Factors for CALPOST

Month

Mount 

Zirkel 

WA

Bridger 

WA &

Fitzpatrick 

WA

January 2.20 2.50

February 2.20 2.30

March 2.00 2.30

April 2.10 2.10

May 2.20 2.10

June 1.80 1.80

July 1.70 1.50

August 1.80 1.50

September 2.00 1.80

October 1.90 2.00

November 2.10 2.50

December 2.10 2.40

According to the final BART rule, natural background conditions as a reference for determination of the 

modeled Δdv change should be representative of the 20 percent best natural visibility days in a given 

Class I area. EPA BART guidance provides the 20 percent best days deciview values for each Class I 

area on an annual basis, but does not provide the individual species concentration data required for input 

to CALPOST. 

 

Species concentrations corresponding to the 20 percent best days were calculated for each Class I area by 

scaling back the annual average (natural background) concentrations given in Table 2-1 of the EPA 

document Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule. A 

separate scaling factor was derived for each Class I area such that, when multiplied by the guidance table 

annual concentrations, the 20 percent best days deciview values for that particular Class I area would be 

calculated. 

The scaling procedure is illustrated here for Bridger WA. From Appendix B in the EPA natural visibility 

guidance document, the deciview value for the 20 percent best days at Bridger WA is 1.96 dv. To obtain 

the speciated background concentrations representative of the 20 percent best days, the deciview value 

(1.96 dv) was first converted to light extinction. The relationship between deciviews and light extinction 

is expressed as follows:

dv = 10 ln (bext/10) or bext = 10 exp (dv/10)
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AP-6040 BART Application Analysis

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where: bext = light extinction expressed in inverse megameters (Mm-1).

Using this relationship with the known deciview value of 1.96, one obtains an equivalent light extinction 

value of 12.17 Mm-1. Next, the annual average natural visibility concentrations were set equal to a total 

extinction value of 12.17 Mm-1. The relationship between total light extinction and the individual 

components of the light extinction is as follows:

bext = (3)f(RH)[ammonium sulfate] + (3)f(RH)[ammonium nitrate] + (0.6)[coarse mass] + (4)[organic 

carbon] + (1)[soil] + (10)[elemental carbon] + bray

where:

bracketed quantities represent background concentrations in μg/m3

values in parenthesis represent scattering efficiencies

f(RH) is the relative humidity adjustment factor (applied to hygroscopic species only)

bray is light extinction due to Rayleigh scattering (10 Mm-1used for all Class I areas)

Substituting the annual average natural background concentrations, the average f(RH) for Bridger WA, 

and including a coefficient for scaling, one obtains:

12.17 = (3)(2.1)[0.12]X + (3)(2.1)[0.1]X + (0.6)[3.0]X + (4)[0.47]X + (1)[0.5]X + (10)[0.02]X + 10

In the equation above, X represents a scaling factor needed to convert the annual average natural 

background concentrations to values representative of the 20 percent best days. Solving for X provides a 

value of 0.376. Table 32 presents the annual average natural background concentrations, the calculated 

scaling factor, and the calculated background concentrations for the 20 percent best days for Bridger WA. 

Table 32: Calculated Background Components for Bridger WA 

Component

Annual Average for 

West Region (μg/m3)

Calculated Scaling 

Factor

20% Best Days for 

Bridger WA

(μg/m3)

Ammonium Sulfate 0.12 0.376 0.045

Ammonium Nitrate 0.10 0.376 0.038

Organic Carbon 0.47 0.376 0.176

Elemental Carbon 0.02 0.376 0.008

Soil 0.50 0.376 0.188

Coarse Mass 3.00 0.376 1.127

The scaled aerosol concentrations were averaged for Bridger WA and Fitzpatrick WA because of their 

geographical proximity and similar annual background visibility. The 20 percent best days aerosol 

concentrations for all three Class I areas in question are listed in the table below.
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Table 33: Natural Background Aerosol Concentrations (μg/m3)

Aerosol 

Component 

Mount 

Zirkel 

WA

Fitzpatrick 

WA &

Bridger WA 

Ammonium Sulfate 0.046 0.045

Ammonium Nitrate 0.038 0.038

Organic Carbon 0.179 0.178

Elemental Carbon 0.008 0.008

Soil 0.190 0.189

Coarse Mass 1.141 1.136

Visibility Post-Processing Results

The results of the visibility modeling for each of the four units for the baseline and control scenarios are 

shown in the tables below. For each scenario, the 98th percentile Δdv results are reported along with the 

total number of days for which the predicted impacts exceeded 0.5 dv. Following the tables are figures 

that present the results graphically for baseline, the BART configuration proposed by PacifiCorp, and for 

the proposed BART configuration with the addition of SCR. 
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Table 34: CALPUFF Visibility Modeling Results: Unit 1

Class I Area

2001 2002 2003 3-Year Average

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 0.5 

Δdv

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

Baseline – Wet FGD, ESP

Bridger WA 0.746 14 1.448 26 0.761 16 0.985 19

Fitzpatrick WA 0.418 7 0.704 11 0.373 7 0.498 8

Mt Zirkel WA 1.236 27 1.496 34 1.232 35 1.321 32

Post-Control Scenario 1 – LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP

Bridger WA 0.384 7 0.845 14 0.411 5 0.547 9

Fitzpatrick WA 0.221 3 0.378 5 0.199 2 0.266 3

Mt Zirkel WA 0.736 16 0.816 13 0.736 16 0.763 15

Post-Control Scenario 2 – LNB w/ separated OFA, Upgrade Wet FGD, New Fabric Filter

Bridger WA 0.372 6 0.780 13 0.408 5 0.520 8

Fitzpatrick WA 0.211 3 0.347 6 0.186 2 0.248 4

Mt Zirkel WA 0.676 15 0.777 13 0.686 15 0.713 14

Post-Control Scenario 3 – LNB w/ separated OFA and SCR, Upgrade Wet FGD, Enhanced ESP

Bridger WA 0.279 3 0.519 9 0.258 3 0.352 5

Fitzpatrick WA 0.127 1 0.226 1 0.118 2 0.157 1

Mt Zirkel WA 0.453 5 0.473 4 0.433 5 0.453 5

Post-Control Scenario 4 – LNB w/ separated OFA and SCR, Upgrade Wet FGD, New Fabric Filter

Bridger WA 0.268 3 0.500 8 0.248 3 0.339 5

Fitzpatrick WA 0.125 1 0.223 1 0.114 2 0.154 1

Mt Zirkel WA 0.436 2 0.465 4 0.422 5 0.441 4

Post-Control Scenario A – Committed Controls: LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP

Bridger WA 0.442 7 0.930 14 0.466 6 0.613 9

Fitzpatrick WA 0.256 3 0.417 6 0.222 3 0.298 4

Mt Zirkel WA 0.797 18 0.917 14 0.755 18 0.823 17

Post-Control Scenario B – Committed Controls + SCR

Bridger WA 0.342 3 0.619 9 0.285 4 0.415 5

Fitzpatrick WA 0.155 3 0.284 2 0.138 2 0.192 2

Mt Zirkel WA 0.477 7 0.562 9 0.461 6 0.500 7
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Table 35: CALPUFF Visibility Modeling Results: Unit 2

Class I Area

2001 2002 2003 3-Year Average

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

98th 

Percentile 

Value 

(Δdv)

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

Baseline – Wet FGD, LNB w/ separated OFA, ESP

Bridger WA 0.530 10 0.990 20 0.533 9 0.684 13

Fitzpatrick WA 0.298 4 0.534 8 0.263 3 0.365 5

Mt Zirkel WA 0.842 23 1.008 18 0.803 20 0.884 20

Post-Control Scenario 1 – LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP

Bridger WA 0.385 7 0.847 14 0.416 5 0.549 9

Fitzpatrick WA 0.223 3 0.377 5 0.200 2 0.267 3

Mt Zirkel WA 0.733 16 0.815 13 0.735 16 0.761 15

Post-Control Scenario 2 – LNB w/ separated OFA, Upgrade Wet FGD, New Fabric Filter

Bridger WA 0.375 6 0.784 13 0.409 5 0.523 8

Fitzpatrick WA 0.210 3 0.348 6 0.188 2 0.249 4

Mt Zirkel WA 0.681 15 0.777 13 0.688 15 0.715 14

Post-Control Scenario 3 – LNB w/ separated OFA and SCR, Upgrade Wet FGD, Enhanced ESP

Bridger WA 0.279 3 0.516 9 0.258 3 0.351 5

Fitzpatrick WA 0.127 1 0.226 1 0.118 2 0.157 1

Mt Zirkel WA 0.455 5 0.474 5 0.435 5 0.455 5

Post-Control Scenario 4 – LNB w/ separated OFA and SCR, Upgrade Wet FGD, New Fabric Filter

Bridger WA 0.268 3 0.499 7 0.248 3 0.338 4

Fitzpatrick WA 0.125 1 0.222 1 0.115 2 0.154 1

Mt Zirkel WA 0.439 2 0.465 4 0.423 5 0.442 4

Post-Control Scenario A – Committed Controls: LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP

Bridger WA 0.442 7 0.930 14 0.466 6 0.613 9

Fitzpatrick WA 0.256 3 0.417 6 0.222 3 0.298 4

Mt Zirkel WA 0.797 18 0.917 14 0.755 18 0.823 17

Post-Control Scenario B – Committed Controls + SCR

Bridger WA 0.342 3 0.619 9 0.285 4 0.415 5

Fitzpatrick WA 0.155 3 0.284 2 0.138 2 0.192 2

Mt Zirkel WA 0.477 7 0.562 9 0.461 6 0.500 7
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Table 36: CALPUFF Visibility Modeling Results: Unit 3

Class I Area

2001 2002 2003 3-Year Average

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

98th 

Percentile 

Value 

(Δdv)

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

Baseline – Wet FGD, ESP

Bridger WA 0.741 15 1.447 27 0.759 16 0.982 19

Fitzpatrick WA 0.418 7 0.713 11 0.378 7 0.503 8

Mt Zirkel WA 1.226 27 1.498 34 1.228 35 1.317 32

Post-Control Scenario 1 – LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP

Bridger WA 0.386 7 0.854 14 0.414 5 0.551 9

Fitzpatrick WA 0.223 3 0.377 4 0.192 2 0.264 3

Mt Zirkel WA 0.733 16 0.815 13 0.734 16 0.761 15

Post-Control Scenario 2 – LNB w/ separated OFA, Upgrade Wet FGD, New Fabric Filter

Bridger WA 0.376 6 0.782 13 0.410 5 0.523 8

Fitzpatrick WA 0.214 3 0.349 6 0.188 2 0.250 4

Mt Zirkel WA 0.677 15 0.778 13 0.686 15 0.714 14

Post-Control Scenario 3 – LNB w/ separated OFA and SCR, Upgrade Wet FGD, Enhanced ESP

Bridger WA 0.279 3 0.509 9 0.258 3 0.349 5

Fitzpatrick WA 0.128 1 0.226 1 0.118 2 0.157 1

Mt Zirkel WA 0.451 5 0.473 4 0.432 5 0.452 5

Post-Control Scenario 4 – LNB w/ separated OFA and SCR, Upgrade Wet FGD, New Fabric Filter

Bridger WA 0.268 3 0.498 7 0.248 3 0.338 4

Fitzpatrick WA 0.126 1 0.222 1 0.115 2 0.154 1

Mt Zirkel WA 0.437 2 0.464 4 0.420 5 0.440 4

Post-Control Scenario A – Committed Controls: LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP

Bridger WA 0.442 7 0.930 14 0.466 6 0.613 9

Fitzpatrick WA 0.256 3 0.417 6 0.222 3 0.298 4

Mt Zirkel WA 0.797 18 0.917 14 0.755 18 0.823 17

Post-Control Scenario B – Committed Controls + SCR

Bridger WA 0.342 3 0.619 9 0.285 4 0.415 5

Fitzpatrick WA 0.155 3 0.284 2 0.138 2 0.192 2

Mt Zirkel WA 0.477 7 0.562 9 0.461 6 0.500 7
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Table 37: CALPUFF Visibility Modeling Results: Unit 4

Class I Area

2001 2002 2003 3-Year Average

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

98th 

Percentile 

Value 

(Δdv)

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

Baseline – Wet FGD, ESP

Bridger WA 0.695 12 1.330 23 0.736 13 0.920 16

Fitzpatrick WA 0.406 5 0.615 11 0.346 7 0.456 8

Mt Zirkel WA 1.129 24 1.380 25 1.201 33 1.237 27

Post-Control Scenario 1 – LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP

Bridger WA 0.386 7 0.821 14 0.429 5 0.545 9

Fitzpatrick WA 0.223 3 0.379 3 0.207 2 0.270 3

Mt Zirkel WA 0.688 16 0.800 14 0.688 17 0.725 16

Post-Control Scenario 2 – LNB w/ separated OFA, Upgrade Wet FGD, New Fabric Filter

Bridger WA 0.383 7 0.802 14 0.425 5 0.537 9

Fitzpatrick WA 0.232 3 0.361 3 0.202 2 0.265 3

Mt Zirkel WA 0.671 15 0.790 13 0.678 17 0.713 15

Post-Control Scenario 3 – LNB w/ separated OFA and SCR, Upgrade Wet FGD, Enhanced ESP

Bridger WA 0.285 3 0.472 7 0.275 2 0.344 4

Fitzpatrick WA 0.143 2 0.233 1 0.129 2 0.168 2

Mt Zirkel WA 0.426 4 0.442 5 0.409 5 0.426 5

Post-Control Scenario 4 – LNB w/ separated OFA and SCR, Upgrade Wet FGD, New Fabric Filter

Bridger WA 0.273 3 0.466 7 0.263 2 0.334 4

Fitzpatrick WA 0.136 1 0.230 1 0.124 1 0.163 1

Mt Zirkel WA 0.410 3 0.434 5 0.399 4 0.414 4

Post-Control Scenario A – Committed Controls: LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP

Bridger WA 0.448 7 0.893 14 0.489 6 0.610 9

Fitzpatrick WA 0.273 3 0.428 6 0.226 2 0.309 4

Mt Zirkel WA 0.743 17 0.892 15 0.770 19 0.802 17

Post-Control Scenario B – Committed Controls + SCR

Bridger WA 0.343 4 0.579 8 0.301 4 0.408 5

Fitzpatrick WA 0.164 3 0.288 1 0.139 2 0.197 2

Mt Zirkel WA 0.444 5 0.538 8 0.460 6 0.481 6
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AP-6040 BART Application Analysis

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Figure 7

Modeled BART Impacts: 98th Percentile (delta-dv)

0

0.2

0.4

0.6

0.8

1

1.2

1.4

JB U1 JB U2 JB U3 JB U4 JB U1 JB U2 JB U3 JB U4 JB U1 JB U2 JB U3 JB U4

Baseline

Post Control Scenario A

Post Control Scenario B

JB U1 = Jim Bridger Unit 1 (530 MW)

JB U2 = Jim Bridger Unit 2 (530 MW)

JB U3 = Jim Bridger Unit 3 (530 MW)

JB U4 = Jim Bridger Unit 4 (530 MW)

Bridger Wilderness

-----------Fitzpatrick Wilderness-----------

Mt Zirkel Wilderness

(Modeling results represent the three-year average using 2001-2003 meteorology) (Delta-dv)
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AP-6040 BART Application Analysis

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Figure 8

Modeled BART Impacts: Number of Days > 0.5 delta-dv

0

5

10

15

20

25

30

35

JB U1 JB U2 JB U3 JB U4 JB U1 JB U2 JB U3 JB U4 JB U1 JB U2 JB U3 JB U4

Baseline

Post Control Scenario A

Post Control Scenario B

JB U1 = Jim Bridger Unit 1 (530 MW)

JB U2 = Jim Bridger Unit 2 (530 MW)

JB U3 = Jim Bridger Unit 3 (530 MW)

JB U4 = Jim Bridger Unit 4 (530 MW)

Bridger Wilderness ---------Fitzpatrick Wilderness------------

Mt Zirkel Wilderness

(Modeling results represent the three-year average using 2001-2003 meteorology) (# Days)
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AP-6040 BART Application Analysis

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BART CONCLUSIONS:

After considering (1) the costs of compliance, (2) the energy and non-air quality environmental impacts of 

compliance, (3) any pollution equipment in use or in existence at the source, (4) the remaining useful life 

of the source, and (5) the degree of improvement in visibility (all five statutory factors) from each 

proposed control technology, the Division determined BART for each visibility impairing pollutant 

emitted from the four units subject to BART at the Jim Bridger Power Plant.

NOx

LNB with separated OFA is determined to be BART for Units 1-4 for NOx based, in part, on the 

following conclusions:

1. LNB with separated OFA on Units 1, 3, and 4 was cost effective with a capital cost of 

$11,300,000 per unit and a $255 per ton of NOx removed average cost effectiveness for each unit 

over a twenty year operational life. LNB with separated OFA on Unit 2 did not require any 

additional capital cost or annual O&M cost.

2. Combustion control using LNB with separated OFA does not require non-air quality 

environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is a 

minimal energy impact.

3. After careful consideration of the five statutory factors, especially the costs of compliance and the 

existing pollution control equipment, a NOx control level of 0.26 lb/MMBtu on a 30-day rolling 

average, above EPA‟s established presumptive limit of 0.15 lb/MMBtu for tangential-fired 

boilers burning sub-bituminous coal, is justified.

4. Visibility impacts were addressed in a comprehensive visibility analysis covering all three 

visibility impairing pollutants and associated control options. The cumulative 3-year averaged 

visibility improvement from the baseline summed across the three Class I areas achieved with 

LNB with separated OFA, upgraded wet FGD, and FGC for enhanced ESP (Post-Control 

Scenario A) was 1.070 Δdv from Unit 1, 0.199 Δdv from Unit 2, 1.068 Δdv from Unit 3, and

0.892 Δdv from Unit 4.

5. Annual NOx emission reductions from LNB with separated OFA on Unit 1, 3, and 4 are 4,493 

tons per unit for a total annual reduction at the Jim Bridger Power Plant of 13,479 tons. There are 

no NOx reductions from Unit 2 as LNB with separated OFA is baseline for the unit.

LNB with separated OFA and SCR was not determined to be BART for Units 1-4 for NOx based, in part, 

on the following conclusions:

1. The cost of compliance for installing SCR on each unit is significantly higher than LNB with 

separated OFA. Capital costs for SCR on Units 1-4 are $166,500,000 per unit. Annual operating 

costs for Units 1, 3, and 4 are $3,382,286 per unit and Unit 2 is $3,370,466.
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2. Additional non-air quality environmental mitigation is required for the use of chemical reagents.

3. Operation of LNB with separated OFA and SCR is parasitic and requires an estimated 3.22 MW 

to 3.36 MW of power from each unit.

4. While visibility impacts were addressed in a cumulative analysis of all three pollutants, PostControl Scenario B is directly comparable to Post-Control A as the only difference is directly 

attributable to the installation of SCR. Subtracting the modeled values from each other yield the 

incremental visibility improvement from SCR. The cumulative 3-year averaged visibility 

improvement from Post-Control Scenario A across the three Class I areas achieved with PostControl Scenario B was 0.627 Δdv per unit from Units 1-3 and 0.635 Δdv from Unit 4.

The Division considers the installation and operation of the BART-determined NOx controls, LNB with 

separated OFA, to meet the corresponding emission limits of 0.26 lb/MMBtu, 30-day rolling average,

1,560 lb/hr, 30-day rolling average, and 6,833 tpy on a continuous basis to meet the statutory 

requirements of BART.

Unit-by-unit NOx BART determinations:

Jim Bridger Unit 1: LNB with separated OFA and meeting NOx emission limits of 0.26

lb/MMBtu (30-day rolling average), 1,560 lb/hr (30-day rolling average)

and 6,833 tpy as BART for NOx.

Jim Bridger Unit 2: LNB with separated OFA and meeting NOx emission limits of 0.26

lb/MMBtu (30-day rolling average), 1,560 lb/hr (30-day rolling average)

and 6,833 tpy as BART for NOx.

Jim Bridger Unit 3: LNB with separated OFA and meeting NOx emission limits of 0.26

lb/MMBtu (30-day rolling average), 1,560 lb/hr (30-day rolling average)

and 6,833 tpy as BART for NOx.

Jim Bridger Unit 4: LNB with separated OFA and meeting NOx emission limits of 0.26

lb/MMBtu (30-day rolling average), 1,560 lb/hr (30-day rolling average)

and 6,833 tpy as BART for NOx.

PM/PM10

Existing ESP with FGC is determined to be BART for Units 1-4 for PM/PM10 based, in part, on the 

following conclusions:

1. Recognizing the cost benefit associated with using the existing ESPs and the minimal energy 

impact of installing FGC, the cost of compliance for the control technology is cost effective for 

each unit, over a twenty year operational life, for reducing PM emissions. The cost effectiveness 

for existing ESP with FGC is $1,544 for Unit 1, $526 for Unit 2, $857 for Unit 3. Unit 4 did not 

require additional capital cost.
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2. No negative non-air environmental impacts are anticipated from existing ESPs with FGC.

3. Visibility impacts were addressed in a comprehensive visibility analysis covering all three 

visibility impairing pollutants and associated control options. The cumulative 3-year averaged 

visibility improvement from the baseline across the three Class I areas achieved with LNB with

separated OFA, upgraded wet FGD, and FGC for enhanced ESP (Post-Control Scenario A) was 

1.070 Δdv from Unit 1, 0.199 Δdv from Unit 2, 1.068 Δdv from Unit 3, and 0.892 Δdv from Unit 

4. While the visibility improvement attributable to the installation of FGC on existing ESPs can‟t 

be directly determined from the visibility modeling, the Division does not anticipate the PM 

contribution to be significant when compared to NOx and SO2 contributions.

Existing ESP with a polishing fabric filter was not determined to be BART for Units 1-4 for PM/PM10

based, in part, on the following conclusions:

1. The cost of compliance for a polishing fabric filter on each unit is not reasonable over a twenty 

year operational life. The cost effectiveness for installing a new polishing fabric filter on the 

existing ESP is $8,980 for Unit 1, $4,557 for Unit 2, $6,382 for Unit 3, and $17,936 for Unit 4. 

Incremental cost effectiveness is $16,396, $16,369, $16,312, and $17,936 for Units 1, 2, 3, and 4, 

respectively.

2. The cumulative 3-year averaged visibility improvement from new LNB with separated OFA, 

upgraded wet FGD, and FGC for enhanced ESP with FGC (Post-Control Scenario 1) across the 

three Class I areas achieved with LNB and separated OFA, upgraded wet FGD, and adding a 

polishing fabric filter (Post-Control Scenario 2) was 0.095 Δdv from Unit 1, 0.090 Δdv from Unit 

2, 0.089 Δdv from Unit 3 and 0.025 Δdv from Unit 4.

The Division considers the installation and operation of the BART-determined PM/PM10 controls, 

existing ESP with FGC, to meet the corresponding emission limits of 0.030 lb/MMBtu, 180 lb/hr, and 

788 tpy on a continuous basis to meet the statutory requirements of BART.

Unit-by-unit PM/PM10 BART determinations:

Jim Bridger Unit 1: Continuing to use the existing ESP and adding FGC to meet an

established PM/PM10 emission limits of 0.030 lb/MMBtu, 180 lb/hr, and 

788 tpy as BART for PM/PM10.

Jim Bridger Unit 2: Continuing to use the existing ESP and adding FGC to meet an

established PM/PM10 emission limits of 0.030 lb/MMBtu, 180 lb/hr, and 

788 tpy as BART for PM/PM10.

Jim Bridger Unit 3: Continuing to use the existing ESP and adding FGC to meet an

established PM/PM10 emission limits of 0.030 lb/MMBtu, 180 lb/hr, and 

788 tpy as BART for PM/PM10.

Jim Bridger Unit 4: Continuing to use the existing ESP and adding FGC to meet an

established PM/PM10 emission limits of 0.030 lb/MMBtu, 180 lb/hr, and 

788 tpy as BART for PM/PM10.
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SO2: REGIONAL SO2 MILESTONE AND BACKSTOP TRADING PROGRAM

PacifiCorp evaluated control SO2 control technologies that can achieve a SO2 emission rate of 0.15

lb/MMBtu or lower from the coal-fired boilers. PacifiCorp‟s proposed BART controls are upgrading the 

existing wet FGD on each of the units.

Wyoming is a §309 state participating in the Regional SO2 Milestone and Backstop Trading Program. 

§308(e)(2) provides States with the option to implement or require participation in an emissions trading 

program or other alternative measure rather than to require sources subject to BART to install, operate, 

and maintain additional control technology to meet an established emission limit on a continuous basis. 

However, the alternate program must achieve greater reasonable progress than would be accomplished by 

installing BART. A demonstration that the alternate program can achieve greater reasonable progress is 

prescribed by §308(e)(2)(i). Since the pollutant of concern is SO2, this demonstration has been performed 

under §309 as part of the state implementation plan. §309(d)(4)(i) requires that the SO2 milestones 

established under the plan “...must be shown to provide for greater reasonable progress than would be 

achieved by application of BART pursuant to §51.308(e)(2).”

Wyoming participated in creating a detailed report entitled Demonstration that the SO2 Milestones

Provide Greater Reasonable Progress than BART covering SO2 emissions from all states participating 

in the Regional SO2 Milestone and Backstop Trading Program. The document was submitted to EPA in 

support of the §309 Wyoming Regional Haze SIP in November of 2008.

As part of the §309 program, participating states, including Wyoming, must submit an annual Regional 

Sulfur Dioxide Emissions and Milestone Report that compares actual emissions to pre-established 

milestones. Participating states have been filing these reports since 2003. Each year, states have been 

able to demonstrate that actual SO2 emissions are well below the milestones. The actual emissions and 

their respective milestones are shown below:

Table 38: Regional Sulfur Dioxide Emissions and Milestone Report Summary

Year Reported SO2 Emissions

(tons)

3-year Milestone Average

(tons)

2003 330,679 447,383

2004 337,970 448,259

2005 304,591 446,903

2006 279,134 420,194

2007 273,663 420,637

In addition to demonstrating successful SO2 emission reductions, §309 states have also relied on visibility 

modeling conducted by the WRAP to demonstrate improvement at Class I areas. The complete modeling 

demonstration showing deciview values was included as part of the visibility improvement section of the

§309 SIP, but the SO2 portion of the demonstration has been included as Table 39 to underscore the 

improvements associated with SO2 reductions.
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Table 39: Visibility - Sulfate Extinction Only

Class I Area Monitor

(Class I Areas Represented)

20% Worst Visibility Days 

(Monthly Average, Mm-1)

20% Best Visibility Days

(Monthly Average, Mm-1)

2018 1

Base Case

(Base 18b)

2018 2

Preliminary

Reasonable

Progress Case

(PRP18a)

2018 1

Base Case

(Base 18b)

2018 2

Preliminary

Reasonable

Progress Case

(PRP18a)

Bridger, WY

(Bridger WA and Fitzpatrick WA) 5.2 4.3 1.6 1.3

North Absaroka, WY

(North Absaroka WA and Washakie WA) 4.8 4.5 1.1 1.1

Yellowstone, WY

(Yellowstone NP, Grand Teton NP and Teton WA) 4.3 3.9 1.6 1.4

Badlands, SD 17.8 16.0 3.5 3.1

Wind Cave, SD 13.0 12.1 2.7 2.5

Mount Zirkel, CO

(Mt. Zirkel WA and Rawah WA) 4.6 4.1 1.4 1.3

Rocky Mountain, CO 6.8 6.2 1.3 1.1

Gates of the Mountains, MT 5.3 5.1 1.0 1.0

UL Bend, MT 9.7 9.6 1.8 1.7

Craters of the Moon, ID 5.8 5.5 1.5 1.5

Sawtooth, ID 3.0 2.8 1.2 1.1

Canyonlands, UT

(Canyonlands NP and Arches NP) 5.4 4.8 2.1 1.9

Capitol Reef, UT 5.7 5.4 1.9 1.8

1 Represents 2018 Base Case growth plus all established controls as of Dec. 2004. No BART or SO2 Milestone assumptions were included.

2 Represents 2018 Preliminary Reasonable Progress growth estimates and established SO2

limits.

All Class I areas in the surrounding states show a projected visibility improvement for 2018 with respect 

to SO2 on the worst days and no degradation on the best days. More discussion on the visibility 

improvement of the §309 program can be found in the Wyoming §309 Regional Haze SIP revision 

submitted to EPA in November 2008.

Therefore, in accordance with §308(e)(2), Wyoming‟s §309 Regional Haze SIP, and WAQSR Chapter 6, 

Section 9, PacifiCorp will not be required to install the company-proposed BART technology and meet 

the corresponding achievable emission limit. Instead, PacifiCorp is required to participate in the Regional 

SO2 Milestone and Backstop Trading Program authorized under Chapter 14 of the WAQSR.

LONG-TERM STRATEGY FOR REGIONAL HAZE:

In this BART analysis, the technology available, the costs of compliance, the energy and non-air quality 

environmental impacts of compliance, any pollution control equipment in use at the source, the remaining

useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated 

to result from the use of such technology were taken into consideration when determining BART. When 

evaluating the costs of compliance the Division recognized a time limitation to install BART-determined 

controls imposed by the Regional Haze Rule. In addressing the required elements, including

documentation for all required analyses, to be submitted in the state implementation plan, 40 CFR 
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51.308(e)(1)(iv) states: “A requirement that each source subject to BART be required to install and 

operate BART as expeditiously as practicable, but in no event later than 5 years after approval of the 

implementation plan revision.” As a practical measure, the Division anticipates the requirement to install 

the BART-determined controls to occur as early as 2015.

PacifiCorp used the EPA Air Pollution Control Cost Manual, which is identified in 40 CFR part 51 

Appendix Y(IV)(D)(4)(a)(5) as a reference source, to estimate capital costs and calculate cost 

effectiveness. Section 1 Chapter 2 of the EPA Air Pollution Control Cost Manual - Sixth Edition 

(EPA 452/B-02-001) describes the concepts and methodology of cost estimation used in the manual. 

Beginning on page 2-28 of Chapter 2.5.4.2, the manual discusses retrofit cost consideration including the 

practice of developing a retrofit factor to account for unanticipated additional costs of installation not 

directly related to the capital cost of the controls themselves. However, PacifiCorp did not present a 

retrofit factor in their cost analyses. PacifiCorp estimated that the installation of SCR requires a 

minimum of 6 years of advanced planning and engineering before the control can be successfully 

installed and operated. This planning horizon would necessarily be considered in the scheduled 

maintenance turnarounds for existing units to minimize installation costs of the pollution control systems. 

PacifiCorp‟s BART-eligible or subject-to-BART power plant fleet is shown in Table 40. While the 

majority of affected units are in Wyoming, there are four units in Utah and one in Arizona. Since the 5-

year control installation requirement is stated in the federal rule it applies to all of PacifiCorp‟s units 

requiring additional BART-determined controls. Although BART is determined on a unit-by-unit basis 

taking into consideration the statutory factors, consideration for additional installation costs related to the 

logistics of managing more than one control installation, which are indirect retrofit costs, was afforded 

under the statutory factor: costs of compliance.

Table 40: PacifiCorp’s BART-Eligible/Subject Units

Source State

Hunter Unit 1 (a) Utah

Hunter Unit 2 (a) Utah

Huntington Unit 1 (a) Utah

Huntington Unit 2 (a) Utah

Cholla Unit 4 (b) Arizona

Dave Johnston Unit 3 Wyoming

Dave Johnston Unit 4 Wyoming

Jim Bridger Unit 1 Wyoming

Jim Bridger Unit 2 Wyoming

Jim Bridger Unit 3 Wyoming

Jim Bridger Unit 4 Wyoming

Naughton Unit 1 Wyoming

Naughton Unit 2 Wyoming

Naughton Unit 3 Wyoming

Wyodak Wyoming

(a) Units identified in Utah‟s §308 Regional Haze SIP.

(b) Unit identified on the Western Regional Air Partnership‟s BART Clearinghouse.
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Therefore, based on the cost of compliance and visibility improvement presented by PacifiCorp in the 

BART applications for Jim Bridger Units 1-4 and taking into consideration the logistical challenge of 

managing multiple pollution control installations within the regulatory time allotted for installation of 

BART by the Regional Haze Rule, the Division is requiring the installation of SCR on Jim Bridger Unit 3 

in 2015 and on Jim Bridger Unit 4 in 2016 for the Long-Term Strategy of the Wyoming Regional Haze 

State Implementation Plan. The Division is also requiring PacifiCorp to submit a permit application to 

install additional add-on NOx control on Units 1 and 2 that includes an analysis of: (1) the costs of 

compliance; (2) the time necessary for compliance; (3) the energy and non-air quality environmental 

impacts of compliance; and (4) the remaining useful life of existing sources that contribute to visibility 

impairment (i.e., the four statutory factors taken into consideration when establishing reasonable progress 

goals5) and the associated visibility impacts from the application of each proposed NOx control. Each 

proposed add-on NOx control shall achieve an emission rate, on an individual unit basis, at or below 0.07 

lb/MMBtu on a 30-day rolling average. The permit application shall be submitted by January 1, 2015. 

Additional add-on NOx control shall be installed and operational no later than the end of 2023 calendar 

year on Jim Bridger Units 1 and 2.

CHAPTER 6, SECTION 4 – PREVENTION OF SIGNIFICANT DETERIORATION (PSD):

PacifiCorp‟s Jim Bridger Power Plant is a “major emitting facility” under Chapter 6, Section 4, of the 

Wyoming Air Quality Standards and Regulations because emissions of a criteria pollutant are greater than 

100 tpy for a listed categorical source. PacifiCorp should comply with the permitting requirements of 

Chapter 6, Section 4 as they apply to the installation of controls determined to meet BART.

CHAPTER 5, SECTION 2 – NEW SOURCE PERFORMANCE STANDARDS (NSPS):

The installation of controls determined to meet BART will not change New Source Performance Standard 

applicability for Jim Bridger Units 1-4.

CHAPTER 5, SECTION 3 – NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS (NESHAPs) AND CHAPTER 6, SECTION 6 – HAZARDOUS AIR POLLUTANT 

(HAP) EMISSIONS AND MAXIMUM AVAILABLE CONTROL TECHNOLOGY (MACT):

The installation of controls determined to meet BART will not change Nation Emission Standards For 

Hazardous Air Pollutants applicability for Jim Bridger Units 1-4.

CHAPTER 6, SECTION 3 – OPERATING PERMIT:

The Jim Bridger Power Plant is a major source under Chapter 6, Section 3 of the Wyoming Air Quality 

Standards and Regulations. The most recent Operating Permit, 3-1-120-2, was issued for the facility on 

September 6, 2005. In accordance with Chapter 6, Section 3 of the Wyoming Air Quality Standards and 

Regulations (WAQSR), PacifiCorp will need to modify their operating permit to include changes 

authorized in this permitting action.

 

5

40 CFR 51.308(d)(1)(i)(A).
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CONCLUSION:

The Division is satisfied that PacifiCorp‟s Jim Bridger Power Plant will comply with all applicable 

Wyoming Air Quality Standards and Regulations. The Division proposes to issue a BART Air Quality 

Permit for modification of the Jim Bridger Power Plant to install new LNB with separated OFA and

install FGC in combination with the existing ESP on Units 1-4 to meet the statutory requirements of 

BART. Jim Bridger Units 3 and 4 shall be equipped with SCR before December 31, 2015 and December 

31, 2016, respectively, for the Long-Term Strategy of the Wyoming §308 Regional Haze State 

Implementation Plan.

In accordance with Long-Term Strategy, PacifiCorp shall submit an application to install additional addon NOx control on Jim Bridger Units 1 and 2 that achieves an emission rate, on an individual unit basis, at 

or below 0.07 lb/MMBtu on a 30-day rolling average by January 1, 2015. It shall include an analysis of

the four statutory factors and the associated visibility impacts from the application of each proposed NOx

control. Additional add-on NOx control shall be installed and operational no later than the end of 2023

calendar year on Units 1 and 2.

PROPOSED PERMIT CONDITIONS:

The Division proposes to issue an Air Quality Permit to PacifiCorp for the modification of the Jim 

Bridger Power Plant with the following conditions:

1. Authorized representatives of the Division of Air Quality be given permission to enter and inspect 

any property, premise or place on or at which an air pollution source is located or is being 

constructed or installed for the purpose of investigating actual or potential sources of air 

pollution, and for determining compliance or non-compliance with any rules, standards, permits 

or orders.

2. All substantive commitments and descriptions set forth in the application for this permit, unless 

superseded by a specific condition of this permit, are incorporated herein by this reference and are 

enforceable as conditions of this permit.

3. That PacifiCorp shall modify their Operating Permit in accordance with Chapter 6, Section 

9(e)(iv) and Chapter 6, Section 3 of the WAQSR.

4. All notifications, reports and correspondence associated with this permit shall be submitted to the 

Stationary Source Compliance Program Manager, Air Quality Division, 122 West 25th Street, 

Cheyenne, WY 82002 and a copy shall be submitted to the District Engineer, Air Quality 

Division, 510 Meadowview Drive, Lander, WY 82520.
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5. Effective upon completion of the performance tests to verify the emission levels below, as

required by Condition 6 of this permit, emissions from Jim Bridger Units 1 through 4 shall not 

exceed the levels below. The NOx limits shall apply during all operating periods. PM/PM10 lb/hr 

and tpy limits shall apply during all operating periods. PM/PM10 lb/MMBtu limits shall apply 

during all operating periods except startup. Startup begins with the introduction of fuel into the 

boiler and ends no later than the point in time when two (2) pulverizers (coal mills) have been 

placed into service and the flue gas temperature at the inlet ducts to the electrostatic precipitator 

reaches a temperature of 220 F, as defined as the average flue gas outlet temperature from the air 

preheaters.

Units Pollutant lb/MMBtu lb/hr tpy

2, 3, & 4 NOx 0.26 (30-day rolling) 1,560 (30-day rolling) 6,833

1, 2, 3,& 4 PM/PM10

(a) 0.030 180 788

(a) Filterable portion only

6. That no later than 90 days after permit issuance NOx performance tests shall be conducted on 

Units 2-4 and PM/PM10 performance tests shall be conducted on Units 1-4 and a written report of 

the results be submitted. If a maximum design rate is not achieved within 90 days of permit 

issuance, the Administrator may require testing be done at the rate achieved and again when a 

maximum rate is achieved.

7. Effective upon completion of the initial performance tests to verify the emission levels below, as

required by Condition 8 of this permit, emissions from Jim Bridger Unit 1 shall not exceed the 

levels below. The limits shall apply during all operating periods.

Pollutant lb/MMBtu lb/hr tpy

NOx 0.26 (30-day rolling) 1,560 (30-day rolling) 6,833

8. That initial NOx performance tests shall be conducted on Unit 1after the installation of low NOx

burners and separated overfire air in accordance with Chapter 6, Section 2(j) of the WAQSR, 

within 30 days of achieving a maximum design rate but not later than 90 days following initial 

start-up, and a written report of the results be submitted. If a maximum design rate is not 

achieved within 90 days of start-up, the Administrator may require testing be done at the rate 

achieved and again when a maximum rate is achieved.
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9. Performance tests shall consist of the following:

Coal-fired Boilers (Units 1 through 4):

NOx Emissions – Compliance with the NOx 30-day rolling average shall be 

determined using a continuous emissions monitoring system (CEMS) certified in 

accordance with 40 CFR part 60.

PM/PM10 Emissions – Testing shall follow 40 CFR 60.46 and EPA Reference 

Test Methods 1-4 and 5.

Testing required by the Chapter 6, Section 3, Operating Permit may be submitted to satisfy the 

testing required by this condition.

10. Prior to any testing required by this permit, a test protocol shall be submitted to the Division for 

approval, at least 30 days prior to testing. Notification should be provided to the Division at least 

15 days prior to any testing. Results of the tests shall be submitted to this office within 45 days of 

completing the tests.

11. PacifiCorp shall comply with all requirements of the Regional SO2 Milestone and Backstop 

Trading Program in accordance with Chapter 14, Sections 2 and 3, of the WAQSR.

12. Compliance with the NOx limits set forth in this permit for the coal-fired boilers (Jim Bridger 

Units 1-4) shall be determined with data from the continuous monitoring systems required by 40 

CFR Part 75 as follows:

a. Exceedances of the NOx limits shall be defined as follows:

i. Any 30-day rolling average of NOx emissions which exceeds the lb/MMBtu 

limits calculated in accordance with the compliance provisions and monitoring 

requirements of §60.48Da and §60.49Da. The definition of “boiler operating 

day” shall be consistent with the definition as specified in 40 CFR part 60, 

subpart Da.

ii. Any 30-day rolling average calculated using valid data (output concentration and 

average hourly volumetric flowrate) from the existing CEM equipment which 

exceeds the lb/hr NOx limit established in this permit. Valid data shall meet the 

requirements of WAQSR, Chapter 5, Section 2(j) and follow the compliance 

provisions and monitoring requirements of §60.48Da and §60.49Da. The 30-day 

average emission rate shall be calculated as the arithmetic average of hourly 

emissions with valid data during the previous 30-day period. The definition of 

“boiler operating day” shall be consistent with the definition as specified in 40 

CFR part 60, subpart Da. 
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b. PacifiCorp shall comply with all reporting and record keeping requirements as specified 

in WAQSR, Chapter 5, Section 2(g) and 40 CFR part 60, subpart D. All excess 

emissions shall be reported using the procedures and reporting format specified in 

WAQSR, Chapter 5, Section 2(g).

13. PacifiCorp shall use EPA‟s Clean Air Markets reporting program to convert the monitoring 

system data to annual emissions. PacifiCorp shall provide substituted data according to the 

missing data procedures of 40 CFR, Part 75 during any period of time that there is not monitoring 

data. All monitoring data must meet the requirements of WAQSR, Chapter 5, Section 2(j).

14. Compliance with the PM/PM10 limits set forth in this permit for the coal-fired boilers (Jim 

Bridger Units 1-4) shall be determined with data from testing for PM conducted annually, or 

more frequently as specified by the Administrator, following 40 CFR 60.46 and EPA Reference 

Test Methods 1-4 and 5. Testing required by the Chapter 6, Section 3, Operating Permit may be 

submitted to satisfy the testing required by this condition.

15. Records required by this permit shall be maintained for a period of at least five (5) years and shall 

be made available to the Division upon request.

16. PacifiCorp shall install new low NOx burners with separated overfire air on Unit 1, in accordance 

with the Division‟s BART determination, and conduct the initial performance tests required in 

Condition 8 no later than December 31, 2010.

17. PacifiCorp shall submit a permit application for the installation of selective catalytic reduction 

(SCR) on Jim Bridger Units 3 and 4 to the Division under the Long-Term Strategy of the 

Wyoming §308 Regional Haze State Implementation Plan. This application shall address SCR as 

a system of continuous emissions reduction achieving 0.07 lb/MMBtu on a 30-day rolling 

average as measured by a certified CEM. SCR shall be installed and operational on Jim Bridger 

Unit 3 by December 31, 2015 and on Jim Bridger Unit 4 by December 31, 2016.

18. PacifiCorp shall submit a permit application for the installation of additional add-on NOx control

on Jim Bridger Units 1 and 2 to the Division no later than January 1, 2015, under the Long-Term 

Strategy of the Wyoming §308 Regional Haze State Implementation Plan. It shall include an 

analysis of the four statutory factors and the associated visibility impacts from the application of 

each proposed NOx control and resulting emission levels. This application shall address each

add-on NOx control as a system of continuous emissions reduction achieving the lowest viable

NOx emission, not to exceed a maximum of 0.07 lb/MMBtu on a 30-day rolling average as 

measured by a certified CEM. Additional add-on NOx control shall be installed and operational 

on both Jim Bridger Unit 1 and Unit 2 no later than December 31, 2023.
Appendix A

Facility Location