DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

BART Application Analysis

AP-6041

May 28, 2009

NAME OF FIRM: PacifiCorp

NAME OF FACILITY: Dave Johnston Plant

FACILITY LOCATION: Sections 7 and 18, T33N, R74W

UTM Zone: 13

Easting: 436,592 m, Northing: 4,742,918 m

Converse County, Wyoming

TYPE OF OPERATION: Coal-Fired Electric Generating Plant

RESPONSIBLE OFFICIAL: Gary Slanina, Managing Director

MAILING ADDRESS: 1591 Tank Farm Road

Glenrock, WY 82637

TELEPHONE NUMBER: (307) 436-2001

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 22, 2007 and on January 29, 2007, in accordance with the requirements of WAQSR Chapter 6 

Section 9(e)(i), the Division received BART applications for two existing coal-fired boilers, Units 3 and 

4, respectively, at the PacifiCorp Dave Johnston Power Plant. A map showing the location of 

PacifiCorp‟s Dave Johnston Power Plant is attached as Appendix A.

On June 5, 2007, PacifiCorp submitted additional copies of the January applications for the two (2) units 

subject to BART at Dave Johnston.

On October 15, 2007, PacifiCorp submitted updated applications for the two (2) units subject to BART at 

Dave Johnston. Additional modeling performed after the June 5, 2007 submittal and revised emissions 

reduction calculations were included.

On December 5, 2007, PacifiCorp submitted revised applications incorporating changes to the postprocessing of the visibility model runs for each of the two (2) Dave Johnston units.

On March 31, 2008, PacifiCorp submitted addendums to each of the BART applications for Dave 

Johnston Units 3 and 4. Revised cost estimates and updated visibility modeling for two (2) NOx control 

scenarios were included in the addendums.

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. Two

existing coal-fired boilers at PacifiCorp‟s Dave Johnston Power Plant, Units 3 and 4, 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 Dave Johnston Power Plant is comprised of four (4) units burning pulverized subbituminous Powder River Basin coal for a total net generating capacity of a nominal 772 megawatts 

(MW). Dave Johnston Units 1 and 2 are nominal 106 MW pulverized coal-fired units. Unit 1 began 

operation in 1958 and Unit 2 in 1960. Since both units were in operation before August 7, 1962 they are 

not subject to BART regulation. However, Dave Johnston Units 3 and 4 are subject to BART review. 

Dave Johnston Unit 3 is a nominal 230 MW pulverized coal-fired boiler that commenced service in 1964. 

It was manufactured by Babcock & Wilcox and equipped with burners in a cell configuration. It is the 

only boiler in Wyoming subject to BART with burners in a cell configuration. The original burners have 

not been replaced or upgraded to low NOx burners. Dave Johnston Unit 3 is not equipped with any SO2

control equipment. Particulate matter (PM) emissions from Unit 3 are controlled using a Lodge-Cottrell 

single-chamber electrostatic precipitator (ESP) installed in 1976. Dave Johnston Unit 4 is a nominal 330 

MW pulverized coal-fired boiler that commenced service in 1972. It is a tangential-fired boiler and was

manufactured by Combustion Engineering, now Alstom. The original burners were replaced in 1976 with 

concentric-firing first generation low NOx burners (LNB). A Venturi scrubber is used to control PM 

emissions. Additional SO2 emission control is achieved in the scrubber by adding lime to the scrubber 

liquor.

Table 1: Dave Johnston Units 3 & 4 Pre-2005 Emission Limits (a)

Source

Firing Rate 

(MMBtu/hour)

Existing 

Controls

NOx

(lb/MMBtu)

SO2

(lb/MMBtu)

PM/PM10

(lb/MMBtu) (c)(d)

Unit 3 2,464 (b) ESP 0.75 (3-hour rolling)

0.59 (annual)

1.2 (2-hour block) 0.23

Unit 4 4,100 LNB, 

Venturi Scrubber

0.75 (3-hour rolling)

0.53 (annual)

1.2 (3-hour block)

0.5 (30-day rolling)

0.21

(a) Emissions taken from Operating Permit 31-148-1 which does not include the most recent New Source Review construction 

permit limits.

(b) Boiler heat input reported in the Operating Permit 31-148-1.

(c) Based on PM limit calculation of 0.8963/I0.1743 lb/MMBtu where I=boiler heat input in MMBtu/hr.

(d) Averaging period is 1 hour as determined by the appropriate test method.
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AP-6041 BART Application Analysis

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On June 27, 2008, Air Quality Permit MD-5098 was issued to PacifiCorp to replace the original burners 

on Unit 3 with a new low NOx firing system including additional advanced overfire air (OFA). In 

addition, Unit 4‟s first generation LNB will be replaced with Alstom TFS 2000TM LNB with overfire air. 

Installation of dry flue gas desulfurization control equipment on both Units 3 and 4 is also authorized by 

this permitting action. Finally, the replacement of the existing ESP on Unit 3 with a baghouse and the 

installation of a new baghouse on Unit 4 are authorized by MD-5098. The emission levels established for 

Dave Johnston Units 3 and 4 in MD-5098 are summarized in Table 2.

Table 2: Dave Johnston Units 3 & 4 MD-5098 Emission Limits (a)

Source Permitted Controls NOx SO2 PM/PM10

Unit 3

New LNB with 

advanced OFA, 

Dry FGD, 

Baghouse

0.28 lb/MMBtu

(12-month rolling)

784 lb/hr

(12-month rolling)

0.15 lb/MMBtu

(12-month rolling)

0.5 lb/MMBtu

(30-day rolling)

0.5 lb/MMBtu

(3-hr block)

420 lb/hr

(24-hr rolling)

0.015 lb/MMBtu

42.1 lb/hr

184 tpy

Unit 4

New LNB with 

advanced OFA, 

Dry FGD, 

Baghouse

0.15 lb/MMBtu

(12-month rolling)

697 lb/hr

(12-month rolling)

0.15 lb/MMBtu

(12-month rolling)

0.5 lb/MMBtu

(30-day rolling)

0.5 lb/MMBtu

(3-hr block)

615 lb/hr

(24-hr rolling)

0.015 lb/MMBtu

61.5 lb/hr

269 tpy

(a) Emissions limits effective upon installation or upgrade of the applicable control equipment.

By letter dated July 18, 2008, PacifiCorp notified the Division that construction activities for installation 

of the FGD/baghouse control equipment on Units 3 and 4 were anticipated to begin July 28, 2008. March 

31, 2009, PacifiCorp notified the Division of the anticipated startup of Unit 4, with new LNB and 

advanced OFA installed, on May 23, 2009. The construction activities are in line with the construction 

schedule proposed by PacifiCorp in the application for permit MD-5098. A construction summary is 

provided in Table 3.

Table 3: MD-5098 Permitted Upgrades to Dave Johnston Units 3 & 4

Source

New Low NOx Burners 

with advanced Overfire Air 

(status, year)

New Dry 

FGD/baghouse

(status, year)

Unit 3 Planned, 2010 Initiated, 2008

Unit 4 Initiated, 2009 Initiated, 2008
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AP-6041 BART Application Analysis

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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 Dave Johnston Units 3 

and 4 thereby conducting a comprehensive BART analysis for NOx, SO2 and PM/PM10.

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 

 

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.”

3

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

PacifiCorp‟s Dave Johnston Power Plant generates a cumulative nominal 772 MW from all four units. 

Unit 3, a nominal 230 MW unit, and Unit 4, a nominal 330 MW unit, qualify for presumptive limits. Unit 

3 does not have SO2 controls installed. Unit 4 controls SO2 emissions using the existing Venturi 

scrubber. Neither unit currently operates with NOx post-combustion controls. Presumptive SO2 limits of 

95% reduction or 0.15 lb/MMBtu and presumptive NOx limits of 0.45 lb/MMBtu and 0.15 lb/MMBtu, 

based on unit type and coal type, could apply to Unit 3 and Unit 4, respectively. 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: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

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

advanced overfire air, (2) rotating opposed fire air (ROFA), (3) selective non-catalytic reduction (SNCR), 

and (4) selective catalytic reduction (SCR). LNB with advanced 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 

 

4

Ibid. (70 Federal Register 39171).
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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.

1. Low NOx Burners with Advanced 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 advanced 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 advanced 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 advanced OFA in combination with 

both SNCR and SCR add-on controls.
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NOx: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

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

infeasible by PacifiCorp.

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 advanced 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 Dave Johnston units and to collect data from boiler vendors. Based on results from 

the study, PacifiCorp indicates that new LNB with advanced OFA on Dave Johnston Units 3 and 4 would 

result in a NOx emission rate of 0.24 lb/MMBtu and 0.15 lb/MMBtu, respectively. On page 3-5 of the 

December 2007 submittal for Dave Johnston Unit 3 and on page 3-4 of the December 2007 submittal for 

Dave Johnston Unit 4 PacifiCorp states: “PacifiCorp has indicated that this rate [0.24 lb/MMBtu for Unit 

3 and 0.15 lb/MMBtu for Unit 4] corresponds to a vendor guarantee plus an added operating margin, 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 on Unit 3 equipped with cell burners, PacifiCorp proposes an additional 

NOx increase of 0.04 lb/MMBtu on Unit 3 for a final proposed emission rate of 0.28 lb/MMBtu.

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

Johnston Power Plant with Mobotec‟s ROFA. Mobotec analyzed the operation of existing burners and 

OFA ports. Typically the existing burner 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 0.15

lb/MMBtu was achievable on Units 3 and 4 using ROFA technology. PacifiCorp added an additional 

operating margin of 0.04 lb/MMBtu to Unit 3 to account for site specific issues, such as burner 

configuration, for total proposed emission rate of 0.19 lb/MMBtu. No additional operating margin was

applied to Unit 4 so the anticipated emission rate is 0.15 lb/MMBtu.

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

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

emission rate of 0.24 lb/MMBtu on Unit 3 and 0.15 lb/MMBtu on Unit 4, S&L concluded that SNCR can 

reduce emissions by 20% resulting in projected emission rates of 0.19 lb/MMBtu for Unit 3 and 0.12 

lb/MMBtu for Unit 4. 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. PacifiCorp did not model visibility 

improvement from installing SNCR on Unit 3 on account of the expected marginal emission rate 

improvement, the burden of significant ongoing parasitic costs, the operating difficulties, and the potential 

ammonia slip. 
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S&L prepared the design conditions and cost estimates for installing SCR on Dave Johnston Units 3 and 

4. 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 reactor containing the catalyst to increase physical space occupied by the 

catalyst to improve the NOx removal rate. Additional catalyst would be added to accommodate nitrogen 

levels in the coal feedstock. Based on the S&L design, which included installing both LNB with 

advanced OFA and SCR, PacifiCorp concluded Units 3 and 4 can achieve a NOx emission rate of 0.07 

lb/MMBtu.

Table 4: NOx Emission Rates Per Boiler

Control Technology

Unit 3

Resulting NOx

Emission Rate 

(lb/MMBtu)

Unit 4

Resulting NOx

Emission Rate 

(lb/MMBtu)

Combustion Control 0.70/0.59 (a) 0.40/0.53 (a)

New LNB with advanced OFA 0.28 0.15

ROFA 0.19 0.15

New LNB with advanced OFA and SNCR 0.19 0.12

New LNB with advanced OFA and SCR 0.07 0.07

(a) PacifiCorp proposed emission rate/annual averaged NOx emissions established through 40 CFR part 76 in 

Operating Permit 31-148-1.

NOx: EVALUATE IMPACTS AND DOCUMENT RESULTS

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

technologies. Installing new LNB with advanced OFA on Dave Johnston Units 3 and 4 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 a significant energy impact on Dave Johnston. One 1,900 

horsepower (hp) ROFA fan on Unit 3 and one 3,000-3,700 hp ROFA fan on Unit 4 are required to induct 

a sufficient volume of air into each boiler to cause rotation of the combustion air throughout the boiler. 

The annual energy impact from operating the proposed ROFA fans is 21,800 Mega Watt-hour (MW-hr)

for Unit 3 and 34,100 MW-hr for Unit 4.

PacifiCorp determined the SNCR system would require between 200 kilo Watt (kW) and 300 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 

requirement for SCR installation on Unit 3 would be approximately 1.6 MW and 2.1 MW for Unit 4.
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PacifiCorp evaluated the environmental impacts from the proposed NOx control technologies. Installing 

LNB with advanced 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.

PacifiCorp anticipates operating Dave Johnston Units 3 and 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 Dave Johnston Unit 3 and Unit 4 are summarized in 

the following tables.
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Table 5: Dave Johnston Unit 3 Economic Costs

Cost

Combustion

Control

New LNB with 

advanced OFA ROFA

New LNB with 

advanced OFA 

and SNCR

New LNB with 

advanced OFA 

and SCR

Control Equipment Capital 

Cost $0 $17,500,000 $12,054,022 $24,035,544 $129,700,000

Capital Recovery Factor N/A 0.09513 0.09513 0.09513 0.09513

Annual Capital Recovery 

Costs $0 $1,664,775 $1,146,699 $2,286,501 $12,338,361

Annual O&M Costs $0 $100,000 $1,237,992 $392,691 $4,009,159

Annual Cost of Control $0 $1,764,775 $2,384,691 $2,679,192 $16,347,519

Table 6: Dave Johnston Unit 3 Environmental Costs

Combustion

Control

New LNB with 

advanced OFA

Existing 

burners with 

ROFA

New LNB with 

advanced OFA 

and SNCR

New LNB with 

advanced OFA 

and SCR

NOx Emission Rate (lb/MMBtu) 0.59 0.28 0.19 0.19 0.07

Annual NOx Emission (tpy) 5,814(a) 3,091 (b)

2,097 (b)2,097 (b)773 (b)

Annual NOx Reduction (tpy) N/A 2,723 3,717 3,717 5,041

Annual Cost of Control $0 $1,764,775 $2,384,691 $2,679,192 $16,347,519

Cost per ton of Reduction N/A $648 $642 $721 $3,243

Incremental Cost per 

ton of Reduction N/A $648 $623 $920 (c) $10,324

(a) Annual emissions based on unit heat input rate of 2,500 MMBtu/hr and 7,884 hours of operation per year.

(b) Annual emissions based on unit heat input rate of 2,800 MMBtu/hr and 7,884 hours of operation per year. 

(c)

Incremental cost from installing ROFA cannot be calculated since the reduced tons of NOx are anticipated to be the same. 

Therefore, the incremental cost from installing new LNB with advanced OFA was calculated.

Table 7: Dave Johnston Unit 4 Economic Costs

Cost

Combustion

Control

New LNB with 

advanced OFA

Existing 

burners with 

ROFA

New LNB with 

advanced OFA 

and SNCR

New LNB

with advanced 

OFA and SCR

Control Equipment 

Capital Cost $0 $7,900,000 $14,719,868 $17,905,780 $151,900,000 

Capital Recovery Factor N/A 0.09513 0.09513 0.09513 0.09513

Annual Capital Recovery 

Costs $0 $751,527 $1,400,301 $1,703,377 $14,450,247 

Annual O&M Costs $0 $90,000 $1,841,886 $438,409 $1,980,281 

Annual Cost of Control $0 $841,527 $3,242,187 $2,141,786 $16,430,528 
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Table 8: Dave Johnston Unit 4 Environmental Costs

Combustion

Control

New LNB with 

advanced OFA

Existing 

burners with 

ROFA

New LNB with 

advanced OFA 

and SNCR

New LNB

with advanced 

OFA and SCR

NOx Emission Rate (lb/MMBtu) 0.53 0.15 0.15 0.12 0.07

Annual NOx Emission (tpy) (a)

8,566 2,424 2,424 1,940 1,131

Annual NOx Reduction (tpy) N/A 6,142 6,142 6,626 7,435

Annual Cost of Control $0 $841,527 $3,242,187 $2,141,786 $16,430,528 

Cost per ton of Reduction N/A $137 $528 $323 $2,210 

Incremental Cost per 

ton of Reduction N/A $137 $528 (b)-$2,274 (c) $17,662

(a) Annual emissions based on individual heat input rate of 4,100 MMBtu/hr for 7,884 hours of operation per year.

(b)

Incremental cost from installing new LNB with advanced OFA cannot be calculated since the reduced tons of NOx are 

anticipated to be the same. Therefore, the incremental cost from combustion control was calculated.

(c)

Incremental cost is negative because the annual cost of control for existing burners with ROFA is significantly higher than new 

LNB with advanced OFA and SNCR.

The cost effectiveness of the four proposed BART technologies for NOx are all reasonable. The 

incremental cost effectiveness is reasonable for all NOx control technologies except new LNB with 

advanced OFA and SCR. PacifiCorp modeled the range of anticipated visibility improvement from the 

company-proposed BART controls for Units 3 and 4 by modeling LNB with advanced OFA and LNB 

with advanced OFA and SCR. While the installation of SNCR and 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 Dave Johnston Units 3 and 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. Table 23 on page 34 and Table 24 on page 35 list the modeled control scenarios and associated 

emission rates.
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PM10: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Dave Johnston Unit 3 is currently equipped with an electrostatic precipitator (ESP) to control PM 

emissions from the boiler. As discussed below in more detail below, ESPs control PM from the flue gas 

stream by creating a strong electro-magnetic field in which fly ash particles gain an electric charge. The 

existing ESP controls PM emissions to 0.030 lb/MMBtu. Dave Johnston Unit 4 is equipped with a 

Venturi particulate scrubber. This technology is no longer the state-of-art and Pacific did not propose 

keeping the unit in service as an additional particulate control device. Venturi scrubbers are designed

with a decreasing throat diameter that mechanically forces particles in the flue gas and water droplets 

together. They are similar to cyclone systems in that particle momentum greatly influences the control 

efficiency. A Venturi scrubber is less effective as a control device for smaller particles because they have 

less momentum. Operating cost is greatly affected by increasing either the water-side or air-side pressure 

drop, which increases the removal efficiency, but results in increased electricity cost and operating cost 

from the pump and/or motor power providing the additional pressure. PacifiCorp reports 2001 to 2006 

PM emissions data indicate that the Dave Johnston Unit 4 Venturi particulate scrubber controls PM10

emissions to 0.061 lb/MMBtu. PacifiCorp analyzed three state-of-the-art PM control technologies for 

application on Units 3 and 4: fabric filters or baghouses, ESPs, and flue gas conditioning.

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.
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PM10: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

PacifiCorp did not eliminate the use of either the baghouse or an ESP to control PM emissions as 

technically infeasible. However, PacifiCorp did not further analyze the use of FGC. According to 

PacifiCorp, the existing ESP on Unit 3 is well designed and provides adequate space and residence time 

for the flue gas particles to gain an electric charge and migrate to the collection plate. The application of 

FGC is not expected to significantly improve PM/PM10 removal efficiency. PacifiCorp did not evaluate 

the application of FGC on Unit 4 because it is typically used to enhance the removal efficiency of an 

existing, constrained ESP. The existing Venturi scrubber will likely be replaced by an entirely new PM 

control device and the co-benefit of enhancing dry flue gas desulfurization makes the installation of a 

more effective state-of-the-art fabric filter the company-preferred PM control measure over installing a 

FGC system.

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 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.

Unit 3 has an existing ESP and rather than evaluate costs of replacing the unit, PacifiCorp evaluated 

additional controls to improve the PM removal efficiency. An ESP is an effective PM control device, as 

the existing units are already capable of controlling PM10 emissions from Unit 3 to 0.030 lb/MMBtu. The 

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

control particulate emissions from new PC boilers. In addition to maintaining the existing ESP, 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 full-size 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 ESP on Unit 3 can reduce emissions an 

additional 50% resulting in a PM emission rate of 0.015 lb/MMBtu. PacifiCorp did not further evaluate 

the installation on a new full-scale fabric filter on Unit 3 since there is a substantial capital cost associated 

with the control and no anticipated benefit when compared to COHPAC.

Unit 4 has an existing Venturi scrubber. PacifiCorp determined that continued operation of this control 

technology was not cost effective. In place of the scrubber, a new ESP or a new FF was evaluated for 

additional PM control. Due to the higher electrical resistivity of western coals, the ESP is not able to 

reduce PM emissions as well as a FF. An ESP is not as effective as a FF at capturing small particles. For 

these reasons, a fabric filter is the company-preferred particulate control device, especially for use with a 

dry FGD system. PacifiCorp‟s proposed emission rates for each technology as applied to Units 3 and 4 

are shown in Table 9.
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Table 9: PM10 Emission Rates Per Boiler

Source

Existing ESP

PM10 Emission 

(lb/MMBtu)

Polishing FF &

Existing ESP

PM10 Emission 

(lb/MMBtu)

Existing 

Venturi Scrubber

PM10 Emission 

(lb/MMBtu)

New ESP

PM10 Emission 

(lb/MMBtu)

New Full-scale FF

PM10 Emission 

(lb/MMBtu)

Unit 3 0.030 0.015 -- -- --

Unit 4 -- -- 0.061 0.030 0.015

PM10: EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impact of installing the COHPAC retrofit on Unit 3. 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 an 85 percent 

annual plant capacity factor. The installation of a COHPAC fabric filter would require approximately 1.4 

MW of power, equating to an annual power usage of approximately 10.3 million kW-hr. Similar to the 

installation of the COHPAC on Unit 3, the installation of a full-scale fabric filter on Unit 4 would incur 

energy losses from the additional pressure drop. PacifiCorp calculated the additional energy costs from 

the installation of the fabric filter based on a 90 percent annual plant capacity factor. The fabric filter

would require approximately 2.4 MW of power, equating to an annual power usage of approximately 18.5 

million kW-hr. PacifiCorp‟s proposed PM control on Unit 4 is the full-scale fabric filter. No costs were 

provided for the installation and operation of a new ESP on Unit 4.

PacifiCorp evaluated the environmental impacts from the proposed installation of COHPAC on Unit 3 

and the installation of a new fabric filter on Unit 4. PacifiCorp did not anticipate negative environmental 

impacts from the addition of either control technologies on the two units.

PacifiCorp anticipates operating Dave Johnston Units 3 and 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 
PacifiCorp Dave Johnston Plant

AP-6041 BART Application Analysis

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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 PM/PM10 emission control. Economic 

and environmental costs for additional PM/PM10 controls on Dave Johnston Unit 3 and Unit 4 are 

summarized in the following tables.

Table 10: Dave Johnston Unit 3 Economic Costs

Cost Existing ESP

Existing ESP and

New COHPAC

Fabric Filter

Control Equipment Capital Cost $0 $29,795,555

Capital Recovery Factor N/A 0.09513

Annual Capital Recovery Costs $0 $2,834,451

Annual O&M Costs $0 $809,282

Annual Cost of Control $0 $3,643,733

Table 11: Dave Johnston Unit 3 Environmental Costs

Existing ESP

Existing ESP and

New COHPAC

Fabric Filter

PM10 Emission Rate (lb/MMBtu) 0.030 0.015

Annual PM10 Emission (tpy) (a)

331 165

Annual PM10 Reduction (tpy) N/A 166

Annual Cost of Control $0 $3,643,733

Cost per ton of Reduction N/A $21,950

Incremental Cost per ton of Reduction N/A $21,950

(a) Annual emissions based on unit heat input rate of 2,800 MMBtu/hr and 7,884 hours of operation per year. 
PacifiCorp Dave Johnston Plant

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Table 12: Dave Johnston Unit 4 Economic Costs

Cost

Existing 

Venturi Scrubber New Fabric Filter

Control Equipment Capital Cost $0 $50,073,428

Capital Recovery Factor N/A 0.09513

Annual Capital Recovery Costs $0 $4,763,485

Annual O&M Costs $0 $1,284,088

Annual Cost of Control $0 $6,047,573

Table 13: Dave Johnston Unit 4 Environmental Costs

Existing 

Venturi Scrubber New Fabric Filter

PM10 Emission Rate (lb/MMBtu) 0.061 0.015

Annual PM10 Emission (tpy) (a)

986 242

Annual PM10 Reduction (tpy) N/A 744

Annual Cost of Control $0 $6,047,573

Cost per ton of Reduction N/A $8,129

Incremental Cost per ton of Reduction N/A $8,129

(a) Annual emissions based on unit heat input rate of 4,100 MMBtu/hr and 7,884 hours of operation per year. 

The cost effectiveness and incremental cost effectiveness of applying a new polishing fabric filter to Unit

3 and a new full-scale fabric filter on Unit 4 are not reasonable. However, the controls were included in 

the final step in the PM/PM10 BART determination process for Dave Johnston Units 3 and 4, Step 5: 

Evaluate visibility impacts, which 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. Table 23 on page 34 and Table 24 on page 35 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 Dave Johnston 

Units 3 and 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.
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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 

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 control technology listed above as technically infeasible. Both dry 

FGD and wet FGD are proven SO2 control technologies. PacifiCorp analyzed the impact of both SO2

emission reduction technologies on Dave Johnston Units 3 and 4.

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 Dave Johnston Plant

AP-6041 BART Application Analysis

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PacifiCorp evaluated the application of DFGD on Unit 3 using the existing ESP to remove particulates 

formed by injecting the lime slurry into the flue gas. This combination of control devices is projected to 

achieve 81.7 % SO2 removal resulting in a SO2 emission rate of 0.22 lb/MMBtu, based on a average 

sulfur content of 0.47% by weight in the feed coal. The combination of the existing ESP and a new 

polishing fabric filter is projected to reduce SO2 emissions by 87.5%, resulting in a controlled SO2

emission rate of 0.15 lb/MMBtu from Unit 3 using a 0.47% coal sulfur content. If the existing ESP on 

Unit 3 is replaced with a new full-scale fabric filter, DFGD is anticipated to reduce SO2 emissions down 

to 0.12 lb/MMBtu. PacifiCorp did not provide cost information for installing a full-scale fabric filter on 

Unit 3, so the technology was not considered any further in the SO2 analysis.

DFGD with a new full-scale fabric filter capable of treating the entire flue gas stream on Unit 4 is 

projected to achieve 87.5% SO2 removal, resulting in an emission rate of 0.15 lb/MMBtu. An average 

coal sulfur content of 0.47% by weight was used to calculate the emission reduction.

The application of wet FGD on Unit 3 would likely use lime/limestone scrubbing, which is available in 

several variations from vendors. Wet lime/limestone scrubbing is projected to achieve a SO2 removal rate 

of 95% and an outlet SO2 emission rate of 0.058 lb/MMBtu, based on a sulfur content of 0.47% by weight 

in the feed coal.

A new wet lime/limestone FGD system with a new full-scale fabric filter applied to Unit 4 is projected to 

achieve 91.7% SO2 removal, resulting in an outlet emission rate of 0.10 lb/MMBtu based on a sulfur 

content of 0.47% by weight. PacifiCorp noted in the analysis for Unit 4 that they consider it to be 

technically infeasible for a new wet FGD system to achieve a 95% SO2 removal, 0.06 lb/MMBtu, on a

continuous basis. PacifiCorp evaluated SO2 controls for Unit 4 to meet presumptive levels for SO2. The 

application of wet FGD with a new full-scale fabric filter on Unit 4 is capable of continuously reducing 

SO2 emissions by 90% resulting in a SO2 emission rate of 0.10 lb/MMBtu, below the 0.15 lb/MMBtu 

presumptive SO2 limit.

Table 14: Dave Johnston Unit 3 SO2 Emission Rates

Control Technology

SO2

Emission Rate 

(lb/MMBtu)

Combustion Control 1.20

Dry FGD with existing ESP 0.22

Dry FGD with existing ESP and 

Polishing Fabric Filter 0.15

Dry FGD with Fabric Filter 0.12

Wet Lime FGD with existing ESP 0.06
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Table 15: Dave Johnston Unit 4 SO2 Emission Rates

Control Technology

SO2

Emission Rate 

(lb/MMBtu)

Combustion Control 1.20

Dry FGD with Fabric Filter 0.15

Wet FGD with Fabric Filter 0.10

SO2: EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impacts of applying a dry FGD system with the existing ESP on Unit 3. 

DFGD requires less electric power than a wet FGD system. A dry FGD system on Dave Johnston 3 using 

the existing ESP would require approximately 2.5 MW of power, while a wet FGD would require

approximately 3.5 MW. This equates to an annual power savings of approximately 7.5 million kW-hr for 

dry FGD, when the plant operates at 90% capacity for the year. Applying a dry FGD system with a new 

full-scale fabric filter to Dave Johnston Unit 4 requires 4.5 MW of power, compared to approximately 6.3 

MW for wet FGD with a new fabric filter. Dry FGD on Unit 4 to control SO2 emission could generate a 

power savings of approximately 13.8 million kW-hr if the unit operates for 90% of its annual capacity.

PacifiCorp compared the environmental impacts of dry FGD versus wet FGD technology. PacifiCorp 

concluded that dry FGD has five significant environmental advantages over wet FGD. These advantages 

are taken directly from PacifiCorp‟s environmental analyses for SO2 controls on Dave Johnston Units 3 

and 4 and listed below.

Sulfuric Acid Mist Sulfur trioxide (SO3) in the flue gas, which condenses to liquid sulfuric acid 

at temperatures below the acid dew point, is removed efficiently with a lime spray dryer system. 

Wet scrubbers capture less than 40 to 60 percent of SO3 and may require the addition of a wet 

electrostatic precipitator (ESP) or hydrated lime injection when medium to high sulfur coal is 

burned in a unit to remove the balance of SO3. Otherwise, the emission of sulfuric acid mist, if 

above a threshold value, may result in a visible plume after the vapor plume dissipates.

Plume Buoyancy Flue gas following a dry FGD system is not saturated with water (gas 

temperature 30°F to 50°F above dew point), which reduces or eliminates a visible moisture 

plume. Wet FGD scrubbers produce flue gas saturated with water, which would require a gas-gas 

heat exchanger to reheat the flue gas if it were to operate as a dry stack. Because of the high 

capital and operating costs associated with heating the flue gas, all recent wet FGD systems in the 

United States have used wet stack operation.

Liquid Waste Disposal There is no liquid waste from a dry FGD system. However, wet FGD 

systems produce a wastewater blowdown stream that must be treated to limit chloride buildup in 

the absorber scrubbing loop. In some cases, a wastewater treatment plant must be installed to 

treat the liquid waste prior to disposal. The wastewater treatment plant would produce a small 

volume of solid waste, which may be contaminated with toxic metals (including mercury), 

requiring proper disposal. 
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AP-6041 BART Application Analysis

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Solid Waste Disposal The creation of a wet sludge from the wet FGD process creates a solid 

waste handling and disposal challenge. This sludge must be handled properly to prevent 

groundwater contamination. Wet FGD systems can produce saleable gypsum if a gypsum market 

is available, reducing the quantity of solid waste from the power plant to be disposed.

Makeup Water Requirements Dry FGD has advantages over a wet scrubber, producing a dry 

waste material and requiring less makeup water in the absorber. Given that water is a valuable 

commodity in Wyoming, the reduced water consumption required for dry FGD is major 

advantage for this technology.

PacifiCorp anticipates operating Dave Johnston Units 3 and 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 SO2 emission control. Economic and 

environmental costs for additional SO2 controls on Dave Johnston Unit 3 and Unit 4 are summarized in 

the following tables.
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Table 16: Dave Johnston Unit 3 Economic Costs

Cost

Existing 

Combustion 

Control

Dry FGD 

with ESP

Dry FGD with 

ESP and 

Polishing 

Fabric Filter

Wet FGD 

with ESP

Control Equipment Capital 

Cost $0 $91,499,734 $169,500,000 $144,300,464 

Capital Recovery Factor N/A 0.09513 0.09513 0.09513

Annual Capital Recovery 

Costs $0 $8,704,370 $16,124,535 $13,727,303 

Annual O&M Costs $0 $4,455,188 $5,295,598 $6,044,908 

Annual Cost of Control $0 $13,159,558 $21,420,133 $19,772,211 

Table 17: Dave Johnston Unit 3 Environmental Costs

Existing 

Combustion 

Control

Dry FGD 

with ESP 

Dry FGD with 

ESP and 

Polishing 

Fabric Filter

Wet FGD 

with ESP

SO2 Emission Rate (lb/MMBtu) 1.2 0.22 0.15 0.06

Annual SO2 Emission (tpy) (a) 13,316 2,428 1,656 662

Annual SO2 Reduction (tpy) N/A 10,888 11,660 12,654

Annual Cost of Control $0 $13,159,558 $21,420,133 $19,772,211 

Cost per ton of Reduction N/A $1,209 $1,837 $1,563 

Incremental Cost per ton of 

Reduction N/A $1,209 $10,700 -$1,658 (b)

(a) Annual emissions based on unit heat input rate of 2,800 MMBtu/hr and 7,884 hours of operation per year. 

(b) Incremental cost from dry FGD with ESP and fabric filter is negative as a result of the lower annual cost of control for wet 

FGD with ESP.

Table 18: Dave Johnston Unit 4 Economic Costs

Cost

Existing

Combustion 

Control

Dry FGD with

Full-scale 

Fabric Filter

Wet FGD with

Full-scale 

Fabric Filter

Control Equipment Capital Cost $0 $243,100,000 $289,166,335 

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $23,126,103 $27,508,393 

Annual O&M Costs $0 $5,318,117 $6,961,183 

Annual Cost of Control $0 $28,444,220 $34,469,576 
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Table 19: Dave Johnston Unit 4 Environmental Costs

Existing 

Combustion 

Control

Dry FGD with

Full-scale 

Fabric Filter

Wet FGD with

Full-scale 

Fabric Filter

SO2 Emission Rate (lb/MMBtu) 0.5 (a) 0.15 0.10

Annual SO2 Emission (tpy) (b)8,081 2,424 1,616

Annual SO2 Reduction (tpy) 0 5,657 6,465

Annual Cost of Control $0 $28,444,220 $34,469,576 

Cost per ton of Reduction N/A $5,028 $5,332 

Incremental Cost per ton of 

Reduction N/A $5,028 $7,457

(a) 30-day rolling average SO2

limit from Operating Permit 31-148-1 used as baseline.

(b) Annual emissions based on unit heat input rate of 4,100 MMBtu/hr and 7,884 hours of operation per year.

The cost effectiveness and incremental cost effectiveness of the proposed wet FGD and dry FGD controls 

for Units 3 and 4 are reasonable, except for the incremental cost effectiveness of installing a new 

polishing fabric filter with dry FGD on Unit 3. The final step in the SO2 BART determination process for 

Dave Johnston Units 3 and 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. Table 23 on 

page 34 and Table 24 on page 35 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 Dave Johnston

plant with an EPA-approved dispersion modeling system (CALPUFF) to predict the changes 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 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. 

Wind Cave and Badlands National Parks (NP) in South Dakota are Class I areas located to the northeast 

of the plant at a distance of approximately 200 kilometers (km) and 290 km, respectively. Toward the 

south in Colorado, Rawah Wilderness Area (WA) and Mount Zirkel WA are both located approximately 

220 km from the plant, with Rocky Mountain NP located beyond Rawah WA. 
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Only those Class I areas most likely to be impacted by the Dave Johnston sources were modeled, as 

determined by source/Class I area locations and professional judgment considering meteorological and 

terrain factors. Those areas chosen for modeling the Dave Johnston sources were the following:

Wind Cave NP

Badlands NP

Rawah WA

Mount Zirkel WA

Rocky Mountain National Park (RMNP) was not modeled because it is located along a similar direction 

from the plant as Rawah WA (a path of less frequent plume transport), and it can be reasonably assumed 

that RMNP would experience lower predicted impacts than those at Rawah WA. Figure 1 shows the 

relative locations of the plant and the nearest Class I areas. 
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Figure 1

Dave Johnston Power Plant and Class I Areas

#*

Carbon Albany

Campbell

Converse Natrona

Johnson

Platte

Crooke

Laramie

Weston

Niobrara

Goshen

Sheridan

Mount Zirkel WildernessRawah Wilderness

Rocky Mountain NP

Badlands/Sage Creek Wilderness 1

Wind Cave National Park

Wyoming

Colorado

Nebraska

South Dakota

Casper Lusk

Laramie

Douglas

Buffalo

Sundance

Gillette

Cheyenne

Wheatland

Newcastle

Torrington

Dave Johnston Power Plant

102°0'0"W

103°0'0"W

103°0'0"W

104°0'0"W

104°0'0"W

105°0'0"W

105°0'0"W

106°0'0"W

106°0'0"W

107°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

40°0'0"N
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SCREENING MODELING

To determine if the Dave Johnston plant would be subject to BART, the Division conducted CALPUFF 

visibility modeling for the closest Class I areas downwind of predominant wind flows (Wind Cave NP 

and Badlands NP) using three years of meteorological data. These data, from 2001-2003, consisted of 

surface and upper-air observations from individual weather stations and gridded output from the 

Mesoscale Model (MM5). Resolution of the MM5 data was 36-km for all three of the modeled years. 

Potential emissions for current operation from the two BART-eligible, coal-fired boilers at the Dave 

Johnston plant were input to the model.

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 Badlands NP and Wind Cave NP 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 20: Results of the Class I Area Screening Modeling

Class I Area

Maximum 

Modeled 

Value (Δdv)

98th

Percentile 

Value (Δdv)

2001

Badlands NP 4.3 2.6

Wind Cave NP 4.5 2.5

2002

Badlands NP 4.0 2.0

Wind Cave NP 4.7 2.2

2003

Badlands NP 3.5 2.4

Wind Cave NP 4.3 3.3

Δdv = delta deciview

NP = national park

REFINED MODELING

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

analysis that included refined 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). Pacificorp‟s modeling included assessments of the impacts at Wind Cave NP and 

Badlands NP, as required by the Division‟s BART modeling protocol. The Division supplemented 

PacifiCorp‟s analyses with model runs for Rawah and Mount Zirkel Wilderness Areas in Colorado. 
PacifiCorp Dave Johnston Plant

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CALPUFF System

Predicted visibility impacts from the Dave Johnston plant 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.

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 21: 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 observations 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 the figure below. 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 22: 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 2

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

Dave 

Johnston
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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 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 3-6 show the receptor configurations that were

used for Badlands NP, Wind Cave NP, Rawah WA, and Mount Zirkel WA. Receptor spacing 

within Wind Cave NP is approximately 0.7 km in the east-west direction and approximately 0.9 

km in the north-south direction. For Badlands NP, the receptor spacing is approximately 1.3 km 

in the east-west direction and approximately 1.8 km in the north-south direction. For the 

Colorado Class I areas (Rawah and Mount Zirkel), the spacing is approximately 1.4 km in the 

east-west direction and approximately 1.9 km in the north-south direction.
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Figure 3

Receptors for Wind Cave NP

Figure 4

Receptors for Badlands NP
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Figure 5

Receptors for Rawah 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 Unit 3 and Unit 4 at 

the Dave Johnston plant are shown in the tables below. 
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Table 23: CALPUFF Inputs for Dave Johnston Unit 3

DAVE JOHNSTON UNIT 3 Baseline

PostControl 

Scenario 1

PostControl 

Scenario 2

PostControl 

Scenario 3

PostControl 

Scenario 4

PostControl 

Scenario A

PostControl 

Scenario B

Model Input Data

Current 

Operation 

with 

Electrostatic 

Precipitator 

(ESP)

Low-NOx 

Burners 

(LNBs) with 

advanced 

Over-fire 

Air (OFA), 

Dry FGD, 

ESP

LNB with 

advanced 

OFA, Dry 

FGD, New 

Fabric Filter

LNB with 

advanced 

OFA and 

Selective 

Catalytic 

Reduction 

(SCR), Dry 

FGD, New 

Fabric Filter

LNB with 

advanced 

OFA and 

SCR, Wet 

FGD, 

Existing 

ESP, New 

Stack

Committed 

Controls: 

LNB with 

advanced 

OFA, Dry 

FGD, New 

Fabric Filter

Committed 

Controls 

and SCR

Hourly Heat Input (mmBtu/hour) 2,500 2,800 2,800 2,800 2,800 2,800 2,800

Sulfur Dioxide (SO2) (lb/mmBtu) 1.20 0.22 0.12 0.12 0.06 0.15 0.15

Sulfur Dioxide (SO2) (lb/hr) 3,000 616 336 336 162 420 420

Nitrogen Oxide (NOx) (lb/mmBtu) 0.70 0.24 0.24 0.07 0.07 0.28 0.07

Nitrogen Oxide (NOx) (lb/hr) 1,750 672 672 196 196 784 196

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

PM10 (lb/hr) 75.0 75.0 42.0 42.0 75.0 42.0 42.0

Coarse Particulate (PM2.5 <diameter < PM10) 

(lb/hr)(a) 32.3 32.3 23.9 23.9 32.3 23.9 23.9

Fine Particulate (diameter < PM2.5) (lb/hr)(b) 42.8 42.8 18.1 18.1 42.8 18.1 18.1

Sulfuric Acid (H2SO4) (lb/hr) 46.0 2.6 2.6 3.6 43.9 2.6 3.7

Ammonium Sulfate [(NH4)2SO4] (lb/hr) -- -- -- 0.7 3.3 -- 0.7

(NH4)HSO4 (lb/hr) -- -- -- 1.1 5.8 -- 1.2

H2SO4 as Sulfate (SO4) (lb/hr) 45.1 2.5 2.5 3.6 43.1 2.5 3.6

(NH4)2SO4 as SO4 (lb/hr) -- -- -- 0.5 2.4 -- 0.5

(NH4)HSO4 as SO4 (lb/hr) -- -- -- 0.9 4.8 -- 1.0

Total Sulfate (SO4) (lb/hr)(c) 45.1 2.5 2.5 5.0 50.3 2.5 5.1

Stack Conditions

Stack Height (meters) 152.4 152.4 152.4 152.4 152.4 152.4 152.4

Stack Exit Diameter (meters) 4.57 4.57 4.57 4.57 4.57 4.57 4.57

Stack Exit Temperature (Kelvin) 445 350 355 355 322 348 348

Stack Exit Velocity (meters per second) 32.0 25.1 25.5 25.5 16.7 25.5 25.5

(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:

(c) Total Sulfate (SO4) (lb/hr) = H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4 as SO4 Stack Emissions (lb/hr) + (NH4)HSO4 as SO4 Stack 

Emissions (lb/hr).
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Table 24: CALPUFF Inputs for Dave Johnston Unit 4

DAVE JOHNSTON UNIT 4 Baseline Post-control 

Scenario 1

PostControl 

Scenario 2

PostControl 

Scenario 3

Post-Control 

Scenario 4

PostControl 

Scenario A

Post-Control 

Scenario B

Model Input Data

Existing 

Operations 

with 

Venturi 

Scrubber

Low-NOx 

Burner 

(LNB) with 

advanced 

Over-Fire 

Air (OFA), 

Dry FGD, 

Fabric Filter

LNB with 

advanced 

OFA, Wet 

FGD, Fabric 

Filter

LNB with 

advanced 

OFA and 

Selective 

Catalytic 

Reduction 

(SCR), Dry 

FGD, New 

Fabric Filter

LNB with 

advanced 

OFA and 

SCR, Wet 

FGD, Fabric 

Filter

Committed 

Controls: 

LNB with 

advanced 

OFA, Dry 

FGD, New 

Fabric Filter

Committed 

Controls and 

SCR

Hourly Heat Input (mmBtu/hour) 4,100 4,100 4,100 4,100 4,100 4,100 4,100

Sulfur Dioxide (SO2) (lb/mmBtu) 0.50 0.15 0.10 0.15 0.10 0.15 0.15

Sulfur Dioxide (SO2) (lb/hr) 2,050 615 410 615 410 615 615

Nitrogen Oxide (NOx) (lb/mmBtu) 0.40 0.15 0.15 0.07 0.07 0.15 0.07

Nitrogen Oxide (NOx) (lb/hr) 1,640 615 615 287 287 615 287

PM10 (lb/mmBtu) 0.061 0.015 0.015 0.015 0.015 0.015 0.015

PM10 (lb/hr) 250.0 61.5 61.5 61.5 61.5 61.5 61.5

Coarse Particulate (PM2.5 <diameter < 

PM10) (lb/hr)(a) 107.5 35.1 35.1 35.1 35.1 35.1 35.1

Fine Particulate (diameter < PM2.5) 

(lb/hr)(b) 142.5 26.4 26.4 26.4 26.4 26.4 26.4

Sulfuric Acid (H2SO4) (lb/hr) 37.7 3.7 37.7 5.3 64.1 3.8 5.8

Ammonium Sulfate [(NH4)2SO4] (lb/hr) -- -- -- 1.0 4.8 -- 0.8

(NH4)HSO4 (lb/hr) -- -- -- 1.6 8.5 -- 1.4

H2SO4 as Sulfate (SO4) (lb/hr) 37.0 3.6 37.0 5.2 63.1 3.7 5.6

(NH4)2SO4 as SO4 (lb/hr) -- -- -- 0.7 3.5 -- 0.6

(NH4)HSO4 as SO4 (lb/hr) -- -- -- 1.4 7.1 -- 1.2

Total Sulfate (SO4) (lb/hr)(c) 37.0 3.6 37.0 7.3 73.6 3.7 7.4

Stack Conditions

Stack Height (meters) 76 152 152 152 152 152 152

Stack Exit Diameter (meters) 9.75 5.79 7.01 5.79 7.01 5.79 5.79

Stack Exit Temperature (Kelvin) 322 350 322 350 322 350 350

Stack Exit Velocity (meters per second) 8.5 25.7 16.5 25.7 16.5 25.7 25.7

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.

(c) Total Sulfate (SO4) (lb/hr) = H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4 as SO4 Stack Emissions (lb/hr) + (NH4)HSO4 as SO4 Stack 

Emissions (lb/hr).
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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 this analysis are shown in the table below. 

Table 25: Relative Humidity Factors for CALPOST

Month

Rawah 

WA

Mount 

Zirkel WA

Badlands 

NP &

Wind Cave 

NP

January 2.10 2.20 2.65

February 2.10 2.20 2.65

March 2.00 2.00 2.65

April 2.10 2.10 2.55

May 2.30 2.20 2.70

June 2.00 1.80 2.60

July 1.80 1.70 2.30

August 2.00 1.80 2.30

September 2.00 2.00 2.20

October 1.90 1.90 2.25

November 2.10 2.10 2.75

December 2.00 2.10 2.65

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 Badlands NP. From Appendix B in the EPA natural visibility 

guidance document, the deciview value for the 20 percent best days at Badlands NP is 2.18 dv. To obtain 

the speciated background concentrations representative of the 20 percent best days, the deciview value 

(2.18 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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where: bext = light extinction expressed in inverse megameters (Mm-1).

Using this relationship with the known deciview value of 2.18, one obtains an equivalent light extinction 

value of 12.44 Mm-1. Next, the annual average natural visibility concentrations were set equal to a total 

extinction value of 12.44 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 Badlands NP, 

and including a coefficient for scaling, one obtains:

12.44 = (3)(2.55)[0.12]X + (3)(2.55)[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 0.402. Table 26 presents the annual average natural background concentrations, the calculated 

scaling factor, and the calculated background concentrations for the 20 percent best days for Badlands 

NP. 

Table 26: Calculated Background Components for Badlands NP

Component

Annual Average for 

West Region (μg/m3)

Calculated Scaling 

Factor

20% Best Days for 

Badlands NP

(μg/m3)

Ammonium Sulfate 0.12 0.402 0.048

Ammonium Nitrate 0.10 0.402 0.040

Organic Carbon 0.47 0.402 0.189

Elemental Carbon 0.02 0.402 0.008

Soil 0.50 0.402 0.201

Coarse Mass 3.00 0.402 1.205

The scaled aerosol concentrations were averaged for Badlands NP and Wind Cave NP because of their 

geographical proximity and similar annual background visibility. The 20 percent best days aerosol 

concentrations for the four Class I areas in question are listed in the table below.
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AP-6041 BART Application Analysis

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Table 27: Natural Background Aerosol Concentrations (μg/m3)

Aerosol 

Component Rawah WA

Mount 

Zirkel WA

Wind Cave 

NP &

Badlands NP

Ammonium Sulfate 0.045 0.046 0.047

Ammonium Nitrate 0.038 0.038 0.040

Organic Carbon 0.178 0.179 0.186

Elemental Carbon 0.008 0.008 0.008

Soil 0.189 0.190 0.198

Coarse Mass 1.135 1.141 1.191

Visibility Post-Processing Results

The results of the visibility modeling for each of the two units for the baseline and control scenarios are 

shown in the tables below. For each scenario, the 98

th 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. Note that the Division‟s modeling for the 

Class I areas in northern Colorado examined baseline, Scenario A (proposed BART), and Scenario B

(proposed BART + SCR) only. 
PacifiCorp Dave Johnston Plant

AP-6041 BART Application Analysis

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Table 28: CALPUFF Visibility Modeling Results for Dave Johnston Unit 3 (South Dakota Class I Areas)

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 – ESP

Badlands NP 1.635 59 1.176 37 1.652 47 1.488 48

Wind Cave NP 1.596 57 1.806 43 2.406 49 1.936 50

Post-Control Scenario 1 – LNB w/ advanced OFA, Dry FGD, ESP

Badlands NP 0.477 7 0.351 4 0.478 7 0.435 6

Wind Cave NP 0.567 10 0.488 7 0.748 11 0.601 9

Post-Control Scenario 2 – LNB w/ advanced OFA, Dry FGD, Fabric Filter

Badlands NP 0.378 6 0.305 0 0.401 3 0.361 3

Wind Cave NP 0.481 5 0.404 5 0.624 10 0.503 7

Post-Control Scenario 3 – LNB w/ advanced OFA and SCR, Dry FGD, Fabric Filter

Badlands NP 0.208 1 0.143 0 0.188 0 0.180 0

Wind Cave NP 0.213 1 0.211 0 0.305 1 0.243 1

Post-Control Scenario 4 – LNB w/ advanced OFA and SCR, Wet FGD, ESP, New Stack

Badlands NP 0.253 3 0.155 0 0.233 0 0.214 1

Wind Cave NP 0.269 1 0.205 0 0.312 1 0.262 1

Post-Control Scenario A – Committed Controls: LNB w/ advanced OFA, Dry FGD, Fabric Filter

Badlands NP 0.448 7 0.360 4 0.469 6 0.426 6

Wind Cave NP 0.570 10 0.480 5 0.735 11 0.595 9

Post-Control Scenario B – Committed Controls + SCR

Badlands NP 0.230 3 0.168 0 0.218 0 0.205 1

Wind Cave NP 0.249 1 0.241 0 0.345 2 0.278 1
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Table 29: CALPUFF Visibility Modeling Results for Dave Johnston Unit 4 (South Dakota Class I Areas)

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 – Venturi Scrubber

Badlands NP 1.347 50 1.100 29 1.449 45 1.299 41

Wind Cave NP 1.527 47 1.344 37 2.078 40 1.650 41

Post-Control Scenario 1 – LNB w/ advanced OFA, Dry FGD, Fabric Filter

Badlands NP 0.456 6 0.340 3 0.480 7 0.425 5

Wind Cave NP 0.467 7 0.465 7 0.751 10 0.561 8

Post-Control Scenario 2 – LNB w/ advanced OFA, Wet FGD, Fabric Filter

Badlands NP 0.454 7 0.336 2 0.437 5 0.409 5

Wind Cave NP 0.551 9 0.460 5 0.663 10 0.558 8

Post-Control Scenario 3 – LNB w/ advanced OFA and SCR, Dry FGD, Fabric Filter

Badlands NP 0.326 4 0.230 1 0.329 1 0.295 2

Wind Cave NP 0.353 3 0.347 3 0.492 7 0.397 4

Post-Control Scenario 4 – LNB w/ advanced OFA and SCR, Wet FGD, Fabric Filter

Badlands NP 0.409 4 0.262 0 0.327 1 0.333 2

Wind Cave NP 0.443 4 0.339 3 0.518 8 0.433 5

Post-Control Scenario A – Committed Controls: LNB w/ advanced OFA, Dry FGD, Fabric Filter

Badlands NP 0.456 6 0.340 3 0.480 7 0.425 5

Wind Cave NP 0.469 7 0.465 7 0.751 10 0.562 8

Post-Control Scenario B – Committed Controls + SCR

Badlands NP 0.326 4 0.230 1 0.327 1 0.294 2

Wind Cave NP 0.354 3 0.347 3 0.492 7 0.398 4
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AP-6041 BART Application Analysis

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Table 30: CALPUFF Visibility Modeling Results for Dave Johnston Unit 3 (Colorado Class I Areas)

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 – ESP

Rawah WA 0.718 11 1.075 14 0.918 14 0.904 13

Mt Zirkel WA 0.515 8 0.707 14 0.802 16 0.675 13

Post-Control Scenario A – Committed Controls: LNB w/ advanced OFA, Dry FGD, Fabric Filter

Rawah WA 0.163 2 0.283 5 0.265 2 0.237 3

Mt Zirkel WA 0.125 0 0.191 1 0.245 0 0.187 0

Post-Control Scenario B – Committed Controls + SCR

Rawah WA 0.087 0 0.142 0 0.119 0 0.116 0

Mt Zirkel WA 0.066 0 0.100 0 0.109 0 0.092 0
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AP-6041 BART Application Analysis

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Table 31: CALPUFF Visibility Modeling Results for Dave Johnston Unit 4 (Colorado Class I Areas)

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 – Venturi Scrubber

Rawah WA 0.514 8 0.841 14 0.827 13 0.727 12

Mt Zirkel WA 0.387 6 0.659 11 0.654 11 0.567 9

Post-Control Scenario A – Committed Controls: LNB w/ advanced OFA, Dry FGD, Fabric Filter

Rawah WA 0.178 1 0.284 3 0.240 2 0.234 2

Mt Zirkel WA 0.127 0 0.190 0 0.238 0 0.185 0

Post-Control Scenario B – Committed Controls + SCR

Rawah WA 0.133 0 0.214 1 0.172 1 0.173 1

Mt Zirkel WA 0.103 0 0.142 0 0.164 0 0.136 0
PacifiCorp Dave Johnston Plant 

AP-6041 BART Application Analysis Page 43

Figure 7 

Modeled BART Impacts at South Dakota Class I Areas: 98th Percentile (delta-dv) 

0.00.20.40.60.81.01.21.41.61.82.0

DJ U3 DJ U4 DJ U3 

BaselinePost ConPost Con

‐‐‐‐‐‐Badlands NP‐‐‐‐‐‐‐

‐‐‐‐‐‐‐‐Wind Ca

DJ U3 = Dave Johnston Unit 3 (230 MW)

DJ U4 = Dave Johnston Unit 4 (330 MW)

(Modeling results represent the three‐year average of results using 2001‐2003 meteorology)

(Delta‐dv)
PacifiCorp Dave Johnston Plant 

AP-6041 BART Application Analysis Page 44

Figure 8 

Modeled BART Impacts at South Dakota Class I Areas: Number of Days > 0.5 delta-d

05

101520253035404550

DJ U3 DJ U4 DJ U3 DJ U4

BaselinePost Control Scenario APost Control Scenario B

‐‐‐‐‐‐‐‐‐‐Badlands NP‐‐‐‐‐‐‐‐‐‐ ‐‐‐‐‐‐‐‐‐‐‐Wind Cave NP‐‐‐‐‐‐‐‐‐‐

DJ U3 = Dave Johnston Unit 3 (230 MW)

DJ U4 = Dave Johnston Unit 4 (330 MW)

(Modeling results represent the three‐year average of results using 2001‐2003 meteorology)

(# Days)
PacifiCorp Dave Johnston Plant 

AP-6041 BART Application Analysis Page 45

Figure 9 

Modeled BART Impacts at Colorado Class I Areas: 98th Percentile (delta-dv) 

0.00.20.40.60.81.01.21.41.61.82.0

DJ U3 DJ U4 DJ U3 

BaselinePost ControPost Contro

‐‐‐‐‐‐Rawah Wilderness‐‐‐‐‐‐‐ ‐‐‐‐‐‐‐‐Mt Zirkel WA

DJ U3 = Dave Johnston Unit 3 (230 MW)

DJ U4 = Dave Johnston Unit 4 (330 MW)

(Modeling results represent the three‐year average of results using 2001‐2003 meteorology)

(Delta‐dv)
PacifiCorp Dave Johnston Plant 

AP-6041 BART Application Analysis Page 46

Figure 10 

Modeled BART Impacts at Colorado Class I Areas: Number of Days > 0.5 delta-dv 

05

101520253035404550

DJ U3 DJ U4 DJ U3 DJ U4

BaselinePost Control ScenarPost Control Scenar

‐‐‐‐‐‐‐‐‐‐Rawah WA‐‐‐‐‐‐‐‐‐‐ ‐‐‐‐‐‐‐‐‐‐‐Mt Zirkel WA‐‐‐‐‐‐‐‐‐‐

DJ U3 = Dave Johnston Unit 3 (230 MW)

DJ U4 = Dave Johnston Unit 4 (330 MW)

(Modeling results represent the three‐year average of results using 2001‐2003 meteorology)

(# Days)
PacifiCorp Dave Johnston Plant

AP-6041 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 two units subject to BART at the Dave Johnston Power Plant.

NOx

LNB with advanced OFA is determined to be BART for Units 3 and 4 for NOx based, in part, on the 

following conclusions:

1. LNB with advanced OFA on Units 3 and 4 was cost effective with a capital cost of $17,500,000 

and $7,900,000 per unit, respectively. The average cost effectiveness, over a twenty year 

operational life, is $648 per ton of NOx removed for Unit 3 and $137 per ton for Unit 4.

2. Combustion control using LNB with advanced 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 0.28 lb/MMBtu on a 30-day rolling 

average, below EPA‟s applicable presumptive limit of 0.45 lb/MMBtu for cell-fired boilers 

burning sub-bituminous coal, is justified for Unit 3.

4. After careful consideration of the five statutory factors, especially the costs of compliance and the 

existing pollution control equipment, a NOx control level of 0.15 lb/MMBtu on a 30-day rolling 

average, equal to EPA‟s applicable presumptive limit for tangential-fired boilers burning subbituminous coal, is justified for Unit 4.

5. Visibility impacts were addressed in a comprehensive visibility analysis covering all three 

visibility impairing pollutants and associated control options. The cumulative 3-year averaged 

98th percentile visibility improvement from the baseline summed across all four Class I areas 

achieved with LNB with advanced OFA, dry FGD, and a new full-scale fabric filter, Post-Control 

Scenario A for each unit, was 3.558 Δdv from Unit 3 and 1.963 Δdv from Unit 4.

6. Annual NOx emission reductions from baseline achieved by applying LNB with advanced OFA 

on Units 3 and 4 are 2,723 tons and 6,142 tons, respectively.

LNB with advanced OFA and SCR was not determined to be BART for Units 3 and 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 

advanced OFA. Capital cost for SCR on Unit 3 is $129,700,000 and $151,900,000 for Unit 4. 

Annual SCR O&M costs for Unit 3 are $4,009,159 and $1,980,281 for Unit 4.
PacifiCorp Dave Johnston Plant

AP-6041 BART Application Analysis

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2. Additional non-air quality environmental mitigation is required for the use of chemical reagents.

3. Operation of LNB with advanced OFA and SCR is parasitic and requires an estimated 1.6 MW 

from Unit 3 and 2.1 MW from Unit 4.

4. While visibility impacts were addressed in a cumulative analysis of all three pollutants, PostControl Scenario B is directly comparable to Post-Control Scenario A as the only difference is 

directly attributable to the installation of SCR. Subtracting the modeled 98th percentile values 

from each other yield the incremental 98th percentile visibility improvement from SCR. The 

cumulative 3-year averaged 98th percentile visibility improvement from Post-Control Scenario A 

summed across all four Class I areas achieved with Post-Control Scenario B was 0.754 Δdv from 

Unit 3 and 0.405 Δdv from Unit 4.

The Division considers the installation and operation of the BART-determined NOx controls, new LNB 

with advanced OFA on Units 3 and 4 to meet corresponding emission limits on a continuous basis, to 

meet the statutory requirements of BART.

Unit-by-unit NOx BART determinations:

Dave Johnston Unit 3: Installing new LNB with advanced OFA and meeting NOx emission 

limits of 0.28 lb/MMBtu (30-day rolling average), 784 lb/hr (30-day 

rolling average), and 3,434 tpy as BART for NOx. 

Dave Johnston Unit 4: Installing new LNB with advanced OFA and meeting NOx emission 

limits of 0.15 lb/MMBtu (30-day rolling average), 615 /hr (30-day 

rolling average), and 2,694 tpy as BART for NOx.

PM/PM10

A new full-scale fabric filter is determined to be BART for Units 3 and 4 for PM/PM10 based, in part, on 

the following conclusions:

1. While the Division considers the costs of compliance for full-scale fabric filters on Units 3 and 4

not reasonable, PacifiCorp is committed to installing this control device and has permitted the 

installation of a full-scale fabric filter Unit 3 and Unit 4 in Air Quality Permit MD-5098. A fullscale fabric filter is the most stringent PM/PM10 control technology and therefore the Division 

will accept it as BART.

The Division considers the installation and operation of the BART-determined PM/PM10 controls, new 

full-scale fabric filter on Units 3 and 4 to meet corresponding emission limits on a continuous basis, to 

meet the statutory requirements of BART.

Unit-by-unit PM/PM10 BART determinations:

Dave Johnston Unit 3: Installing a new full-scale fabric filter and meeting PM/PM10 emission 

limits of 0.015 lb/MMBtu, 42.1 lb/hr, and 184 tpy as BART for 

PM/PM10.
PacifiCorp Dave Johnston Plant

AP-6041 BART Application Analysis

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Dave Johnston Unit 4: Installing a new full-scale fabric filter and meeting PM/PM10 emission 

limits of 0.015 lb/MMBtu, 61.5 lb/hr, and 269 tpy as BART for 

PM/PM10.

SO2: WESTERN BACKSTOP SULFUR DIOXIDE 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 proposed dry FGD, and a full-scale fabric filter as 

SO2 BART controls on both Units 3 and 4.

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 in Table 32.

Table 32: 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 33 to underscore the 

improvements associated with SO2 reductions.
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AP-6041 BART Application Analysis

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Table 33: 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 
PacifiCorp Dave Johnston Plant

AP-6041 BART Application Analysis

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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 the installation costs of the pollution control 

systems. 

PacifiCorp‟s BART-eligible or subject-to-BART power plant fleet is shown in Table 34. 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 34: 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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AP-6041 BART Application Analysis

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Based on the cost of compliance and visibility improvement presented by PacifiCorp in the BART 

applications for Dave Johnston Units 3 and 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 not requiring additional controls under the Long-Term 

Strategy of the Wyoming Regional Haze State Implementation Plan in this permitting action. Additional 

controls may be required in future actions related to the Long-Term Strategy of the Wyoming Regional 

Haze State Implementation Plan.

CHAPTER 6, SECTION 4 – PREVENTION OF SIGNIFICANT DETERIORATION (PSD):

PacifiCorp‟s Dave Johnston 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 Dave Johnston Units 3 and 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 Dave Johnston Units 3 and 4.

CHAPTER 6, SECTION 3 – OPERATING PERMIT:

The Dave Johnston Power Plant is a major source under Chapter 6, Section 3 of the Wyoming Air Quality 

Standards and Regulations. The most recent Operating Permit, 3-2-148, was issued for the facility on 

September 2, 2008. 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 the changes 

authorized in this permitting action.

CONCLUSION:

The Division is satisfied that PacifiCorp‟s Dave Johnston 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 to install new LNB with advanced OFA and a new full-scale fabric filter on Units

3 and 4.
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PROPOSED PERMIT CONDITIONS:

The Division proposes to issue an Air Quality Permit to PacifiCorp for the modification of the Dave 

Johnston 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, 152 North Durbin Street, Suite 100, Casper, WY 82601.

5. Effective upon completion of the initial performance tests to verify the emission levels below, as 

required by Condition 6 of this permit, emissions from Dave Johnston Units 3 and 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 oil into 

the boiler and ends no later than the point in time when coal is introduced as fuel.

Unit Pollutant lb/MMBtu lb/hr tpy

3 NOx 0.28 (30-day rolling) 784 (30-day rolling) 3,434

4 NOx 0.15 (30-day rolling) 615 (30-day rolling) 2,694

3 PM/PM10

(a) 0.015 42.1 184

4 PM/PM10

(a) 0.015 61.5 269

(a) Filterable portion only

6. That initial performance tests be conducted, 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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AP-6041 BART Application Analysis

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7. Performance tests shall consist of the following:

Coal-fired Boilers (Dave Johnston Units 3 and 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.

8. 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.

9. 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.

10. Compliance with the NOx limits set forth in this permit for the coal-fired boilers (Dave Johnston 

Units 3 and 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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AP-6041 BART Application Analysis

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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).

11. 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).

12. Compliance with the PM/PM10 limits set forth in this permit for the coal-fired boilers (Dave 

Johnston Units 3 and 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.

13. 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.

14. PacifiCorp shall install new low NOx burners with advanced overfire air on Units 3 and 4, in 

accordance with the Division‟s BART determination, and conduct the initial performance tests 

required in Condition 6 no later than December 31, 2010 and December 31, 2009, respectively.

15. PacifiCorp shall install new full-scale fabric filters on Units 3 and 4, in accordance with the 

Division‟s BART determination, and conduct the initial performance tests required in Condition 6

no later than December 31, 2010 and December 31, 2012, respectively.
Appendix A

Facility Location