DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

BART Application Analysis

AP-6042

May 28, 2009

NAME OF FIRM: PacifiCorp

NAME OF FACILITY: Naughton Power Plant

FACILITY LOCATION: Sections 32 and 33, T21N, R116W

UTM Zone: 12

Easting: 533,450 m, Northing: 4,622,700 m

Lincoln County, Wyoming

TYPE OF OPERATION: Coal-Fired Electric Generating Plant

RESPONSIBLE OFFICIAL: Angie Skinner, Plant Managing Director

MAILING ADDRESS: P.O. Box 191

Kemmerer, WY 83101

TELEPHONE NUMBER: (307) 828-4211

REVIEWERS: Cole Anderson, Air Quality Engineer

James (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 February 12, 2007, in accordance with the requirements of WAQSR Chapter 6 Section 9(e)(i), 

PacifiCorp submitted three (3) BART applications, one for each existing coal-fired boiler at the Naughton

Power Plant. A map showing the location of PacifiCorp‟s Naughton Power Plant is attached as Appendix 

A.

October 16, 2007, PacifiCorp submitted updated applications for each of the three (3) Naughton units 

subject to BART. Additional modeling performed after the February 12, 2007 submittal and revised 

visibility control effectiveness calculations were included.

December 5, 2007, PacifiCorp submitted revised applications incorporating changes to the postprocessing of the visibility model runs for each of the three (3) Naughton units.

March 31, 2008, PacifiCorp submitted addendums to each of the BART applications for Naughton Units 

1-3. Revised cost estimates and updated visibility modeling for two (2) NOx control scenarios were 

included in the addendums.

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

rates for the three (3) coal-fired boilers at the Naughton Power Plant. The information addresses the type 

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

BART ELIGIBILITY DETERMINATION:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

three existing coal-fired boilers at PacifiCorp‟s Naughton Power Plant were determined to be subject to 

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

DESCRIPTION OF BART ELIGIBLE SOURCES:

PacifiCorp‟s Naughton Power Plant is comprised of three (3) pulverized coal-fired units with a total net 

generating capacity of 700 megawatts (MW). Naughton Unit 1 generates a nominal 160 MW and 

commenced operation in 1963. The boiler on Unit 1 is tangential fired and was manufactured by 

Combustion Engineering (now ALSTOM). The unit uses good combustion practices (GCP) to control 

NOx emissions. It was originally constructed with a Research Cottrell mechanical dust collector to 

control particulate matter emissions, and in 1974 a Lodge Cottrell electrostatic precipitator (ESP) was 

added to further reduce particulate emissions. SO2 emissions are controlled using low sulfur coal to

maintain emissions below 1.2 lb per million British thermal units (MMBtu). Naughton Unit 2 generates a 

nominal 210 MW and commenced operation in 1968. The boiler on Unit 2 is also tangential fired and 

was manufactured by ALSTOM. The unit uses GCP to control NOx emissions. It was originally 

constructed with a United Conveyor mechanical dust collector to control particulate matter emissions and 

in 1976 a Lodge Cottrell ESP was added to further reduce particulate emissions. SO2 emissions are 

controlled using low sulfur coal to maintain emissions below 1.2 lb/MMBtu. Naughton Unit 3 generates

a nominal 330 MW and commenced operation in 1971. The boiler on Unit 3 is tangential fired and was

manufactured by ALSTOM. The unit was retrofitted with ALSTOM LCCFS II low NOx burners (LNB) 

in 1999. Particulate emissions are controlled using a Buell weighted wire ESP and flue gas conditioning

(FGC). SO2 emissions are controlled using low sulfur coal and a UOP LLC two-tower sodium based wet 

flue gas desulfurization (WFGD) system that was installed in 1997.
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Table 1: Naughton Units 1-3 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 1 1,850 GCP, ESP 0.75 (3-hour block)

0.58 (annual) (b) 1.2 (2-hour block) 0.24

Unit 2 2,400 GCP, ESP 0.75 (3-hour block)

0.54 (annual) (b) 1.2 (2-hour block) 0.23

Unit 3 3,700 LNB, ESP, 

FGC, WFGD

0.75 (3-hour block)

0.49 (annual) (b) 0.5 (2-hour block) 0.21

(a) Emissions taken from Operating Permit 31-121.

(b) Limit established through the 40 CFR part 76 (Acid Rain Program).

(c) Based on the equation: 0.8963/I0.1743 lb/MMBtu of heat input where I=boiler heat input in MMBtu/hr.

(d) Averaging period is 1 hour as determined by the appropriate test method.

PacifiCorp recently received an Air Quality permit to modify the three Naughton units. Units 1 and 2 will 

be equipped with new state-of-the-art low NOx systems with advanced overfire air (OFA) and flue gas 

conditioning systems to help improve the particulate removal efficiency of the existing ESPs on each of 

the units. New wet flue gas desulfurization systems will be installed on Naughton Units 1 and 2. The 

existing ESP on Naughton Unit 3 will be replaced with a new full-scale fabric filter (FF) at which time 

the existing FGC system will be removed. Table 2 lists the new emission limits for the Naughton units. 

They become effective after the corresponding controls are installed and the applicable initial

performance tests are completed.

Table 2: Naughton Units 1-3 Proposed Emission Limits (a)

Source

Permitted 

Controls NOx SO2 PM/PM10

Unit 1

New LNB with 

advanced OFA, 

FGC, ESP,

WFGD

0.75 lb/MMBtu

(3-hr rolling)

0.26 lb/MMBtu 

(12-month rolling)

481 lb/hr

(12-month rolling)

0.15 lb/MMBtu

(12-month rolling)

1.2 lb/MMBtu

(2-hr rolling)

833 lb/hr

(3-hr block)

0.042 lb/MMBtu (b)

78 lb/hr (b)

340 tpy (b)

Unit 2

New LNB with 

advanced OFA, 

FGC, ESP, 

WFGD

0.75 lb/MMBtu

(3-hr rolling)

0.26 lb/MMBtu 

(12-month rolling)

624 lb/hr

(12-month rolling)

0.15 lb/MMBtu

(12-month rolling)

1.2 lb/MMBtu

(2-hr rolling)

1,080 lb/hr

(3-hr block)

0.054 lb/MMBtu (b)

130 lb/hr (b)

568 tpy (b)

Unit 3

Existing LNB 

with OFA, FF, 

WFGD

0.75 lb/MMBtu

(3-hr rolling)

0.45 lb/MMBtu

(12-month rolling)

1,665 lb/hr

(12-month rolling)

0.5 lb/MMBtu

(2-hour rolling)

1,850 lb/hr

(3-hr block)

0.015 lb/MMBtu

(24-hour block)

56 lb/hr

(24-hour block)

243 tpy

(a) Emissions limits taken from recent New Source Review construction permit for Naughton Units 1-3.

(b) Averaging period is 1 hour as determined by 40 CFR 60.46 and EPA Reference Test Methods 1-4 and 5.
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A construction schedule for installing new LNB with advanced OFA, FGC, and WFGD on Naughton 

Units 1 and 2, and a full-scale FF on Unit 3 was submitted in the permit application. The installation of 

FGC on Units 1 and 2 was originally proposed to occur in 2008, however since the authorization to install 

the controls is dependent on the issuance of the pending Air Quality permit, installation will be delayed 

until permit issuance. A construction summary is provided in Table 3.

Table 3: Upgrades to Naughton Units 1-3

Source

NOx

Control Equipment,

Installation year

SO2

Control Equipment, 

Installation year

PM/PM10

Control Equipment,

Installation year

Unit 1 New LNB with OFA, 2012 WFGD, 2012 FGC, 2009 (a)

Unit 2 New LNB with OFA, 2011 WFGD, 2011 FGC, 2009 (a)

Unit 3 LNB with OFA, Existing WFGD, Existing FF, 2014

(a) PacifiCorp originally proposed installing FGC on Units 1 and 2 in 2008, however the installation date has been moved to the 

date of permit issuance.

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

 

1

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

2

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

option and a reasonable set of options for analysis that reflects a comprehensive list of available technologies.”
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The Division acknowledges that BART is intended to identify retrofit technology for existing sources and 

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

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

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

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

(Units 1-3) at the Naughton Power Plant 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 

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 

 

3

40 CFR Part 51 Appendix Y: Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 39133).
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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 Naughton Power Plant consists of three units with a total generating capacity of 700 MW. 

Naughton Unit 1, generating nominal 160 MW, Unit 2, generating a nominal 210 MW, and Unit 3, 

generating a nominal 330 MW, are tangentially fired pulverized coal boilers. SO2 emissions from Units 1 

and 2 are controlled by burning low sulfur coal without the use of add-on controls. Unit 3 SO2 emissions 

are control using an existing UOP LLC two-tower sodium based WFGD system that was installed in 

1997. NOx emissions from Units 1 and 2 are not controlled using either NOx combustion controls (LNB) 

or add-on controls. ALSTOM LCCFS II LNB were installed on Unit 3 in 1999. Presumptive SO2 limits 

of 95% reduction or 0.15 lb/MMBtu and presumptive NOx limits based on unit type and coal type, do not 

apply to the three Naughton units because the total generating capacity of the facility is below 750 MW. 

However, the Division required additional analysis of potential retrofit controls for NOx, SO2, and 

PM/PM10, taking into consideration all five statutory factors, before making a BART determination.

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

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

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

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

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

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

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

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

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

reported that Naughton Units 1-3 burned sub-bituminous coal. Subsequent to the ICR PacifiCorp further 

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

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

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

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

Classification of Coals by Rank is shown as Figure 1.

 

4

Ibid. (70 Federal Register 39171).
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Figure 1

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

able to meet presumptive NOx levels of 0.15 lb/MMBtu for tangential boilers firing sub-bituminous coal. 

Air Quality Permit MD-1552 authorized the installation of new ALSTOM TFS 2000TM LNB with 

separated OFA systems on all four units at PacifiCorp‟s Jim Bridger Power Plant. Units 2-4 are currently 

equipped with this combustion control system. Recent monitoring data supplied by the continuous 

emissions monitoring systems on the three units indicate that a NOx emission rate of 0.15 lb/MMBtu is 

not achievable on a continuous basis. Fuel characteristics of the coal burned at the Naughton Power Plant 

are similar to the coal fed to the Jim Bridger units, which are also tangentially-fired boilers. In the 

absence of site-specific operational data, it is reasonable to anticipate NOx reductions from the application 

of new state-of-the-art LNB on the Naughton units will be comparable to the Jim Bridger units.

Naughton was included in EPA‟s presumptive limits analyses for NOx and SO2. As a result of the final 

publication of 40 CFR part 51, Appendix Y establishing BART presumptive limits for facilities with a 

generating capacity greater than 750 MW, Naughton is not subject to presumptive limits. The Division 

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

addition to combustion control, taking into consideration all five statutory factors, before making a BART 

determination. And while PacifiCorp addressed applicability of presumptive NOx limits for the Naughton

units in their BART applications, the effectiveness of the proposed combustion control for removing NOx

was evaluated in this analysis under Step 2: Eliminate technically infeasible options, Step 3: Evaluate 

control effectiveness of remaining control technologies, and Step 4: Evaluate impacts and document the 

results of the BART process.

NOx: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

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

advanced OFA, (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 by 

enhancing control of air-fuel mixing throughout the boiler‟s combustion zone. SNCR and SCR are addon controls that provide a chemical conversion mechanism for NOx to form molecular nitrogen (N2) in the 

flue gas after combustion occurs. These four technologies are proven emissions controls commonly used 

on coal-fired electric generating units.
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1. Low NOx Burners with 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.

NOx: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

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

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

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

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

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

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

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

variability. Complex emission control equipment, such as LNB with 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 Naughton units and to collect data from boiler vendors. Based on results from the 

study, PacifiCorp indicates that new LNB with advanced OFA on Naughton Units 1 and 2 would result in 

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

Naughton Units 1 and 2 PacifiCorp states: “PacifiCorp has indicated that this rate [0.24 lb/MMBtu] 

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, 

PacifiCorp proposes an additional NOx increase of 0.02 lb/MMBtu to total 0.26 lb/MMBtu. Naughton 

Unit 3 is equipped with LNB and has demonstrated compliance with a 0.40 lb/MMBtu NOx emission rate. 

PacifiCorp reviewed the option of tuning the existing LNB to further reduce NOx emissions and indicates 

that lowering emissions to 0.35 lb/MMBtu is possible. In the March 26, 2008 Addendum for Unit 3, 

PacifiCorp proposed a permitted rate of 0.37 lb/MMBtu to account for unforeseen operational issues and 

site specific challenges.

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

Naughton 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 0.24

lb/MMBtu was achievable on Units 1 and 2 using ROFA technology. Unit 3 may achieve 0.26 

lb/MMBtu. PacifiCorp added an additional operating margin to each anticipated emission rate of 0.02

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

proposed emission rates of 0.26 lb/MMBtu for Units 1 and 2, and 0.28 lb/MMBtu for Unit 3.

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 OFA capable of achieving a NOx emission 

rate of 0.26 lb/MMBtu on Units 1 and 2, S&L concluded that SNCR can reduce emissions by 20% 

resulting in a projected emission rate of 0.21 lb/MMBtu. Installing SNCR on Unit 3 can reduce the 

anticipated rate of 0.37 lb/MMBtu by 20% resulting in a NOx emission rate of 0.30 lb/MMBtu. 

PacifiCorp noted in the analysis that the economics of SNCR are greatly impacted by reagent utilization. 

When SNCR is used to achieve high levels of NOx reduction, lower reagent utilization can result in 

significantly higher operating cost.
PacifiCorp Naughton Plant

AP-6042 BART Application Analysis

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S&L prepared the design conditions and cost estimates for installing SCR in each of the Naughton units. 

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

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

would be routed to a separate large reactor containing the catalyst to increase the removal rate. 

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

included installing both new LNB with advanced OFA and SCR, PacifiCorp concluded the Naughton

units could achieve a NOx emission rate of 0.07 lb/MMBtu.

Table 4: NOx Emission Rates Per Boiler

Control Technology

Unit 1

Resulting NOx

Emission Rate 

(lb/MMBtu)

Unit 2

Resulting NOx

Emission Rate 

(lb/MMBtu)

Unit 3

Resulting NOx

Emission Rate 

(lb/MMBtu)

Existing Burners 0.58 (a) 0.54 (a) 0.45 (b)

Tune Existing LNB -- -- 0.37

New LNB with advanced OFA 0.26 0.26 --

Existing Burners with ROFA 0.26 0.26 0.28

New LNB with advanced OFA and SNCR 0.21 0.21 0.30

New LNB with advanced OFA and SCR 0.07 0.07 0.07

(a) Annual averaged NOx emissions listed in Operating Permit 31-121.

(b) Annual averaged NOx emission listed in Operating Permit 3-2-121.

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 Naughton Units 1 and 2 and tuning the existing 

LNB on Unit 3 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 Naughton. One (1) 1,900 

horsepower (hp) ROFA fan on Unit 1, one (1) 3,500 hp ROFA fan on Unit 2, and one (1) 6,000 hp ROFA 

fan on Unit 3 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 11,200 Mega Watt-hour (MW-hr), 20,600 MW-hr, and 35,300 MW-hr for Units 1, 2, and 3, 

respectively.

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 

requirements for SCR installation on each unit at the Naughton Power Plant ranged from approximately 

1.0 MW to 2.0 MW.
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AP-6042 BART Application Analysis

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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 Naughton Units 1-3 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 Naughton Units 1-3 are summarized in the following 

tables.
PacifiCorp Naughton Plant

AP-6042 BART Application Analysis

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Table 5: Naughton Unit 1 Economic Costs

Cost

Existing 

Burners 

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 $9,600,000 $9,068,746 $17,526,855 $94,600,000

Capital Recovery Factor N/A 0.09513 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $913,248 $862,710 $1,667,330 $8,999,298

Annual O&M Costs $0 $80,000 $679,764 $305,033 $1,231,912

Annual Cost of Control $0 $993,248 $1,542,474 $1,972,363 $10,231,210

Table 6: Naughton Unit 1 Environmental Costs

Existing 

Burners

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) 0.58 0.26 0.26 0.21 0.07

Annual NOx Emission (tpy) (a)

4,230 1,896 1,896 1,531 510

Annual NOx Reduction (tpy) N/A 2,334 2,334 2,699 3,720

Annual Cost of Control $0 $993,248 $1,542,474 $1,972,363 $10,231,210

Cost per ton of Reduction N/A $426 $661 $731 $2,750

Incremental Cost per ton of Reduction N/A $426 $661 (b) $1,178 $8,089

(a) Annual emissions based on individual heat input rate of 1,850 MMBtu/hr for 7,884 hours of operation per year.

(b) Incremental cost cannot be calculated as the reduced tons of NOx are anticipated to be the same as installing new LNB with advanced 

OFA.

Table 7: Naughton Unit 2 Economic Costs

Cost

Existing 

Burners

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 $9,100,000 $10,586,222 $19,878,765 $115,900,000

Capital Recovery Factor N/A 0.09513 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $865,683 $1,007,067 $1,891,067 $11,025,567

Annual O&M Costs $0 $80,000 $1,148,862 $369,890 $1,639,352

Annual Cost of Control $0 $945,683 $2,155,929 $2,260,957 $12,664,919
PacifiCorp Naughton Plant

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Table 8: Naughton Unit 2 Environmental Costs

Existing 

Burners

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) 0.54 0.26 0.26 0.21 0.07

Annual NOx Emission (tpy) (a)

5,109 2,460 2,460 1,987 662

Annual NOx Reduction (tpy) N/A 2,649 2,649 3,122 4,447

Annual Cost of Control $0 $945,683 $2,155,929 $2,260,957 $12,664,919

Cost per ton of Reduction N/A $357 $814 $724 $2,848

Incremental Cost per ton of Reduction N/A $357 $814 (b) $222 $7,852

(a) Annual emissions based on individual heat input rate of 2,400 MMBtu/hr for 7,884 hours of operation per year.

(b) Incremental cost cannot be calculated as the reduced tons of NOx are anticipated to be the same as installing new LNB with advanced 

OFA.

Table 9: Naughton Unit 3 Economic Costs

Cost

Existing 

LNB

Tuning 

Existing LNB

Existing LNB 

and SNCR

Existing LNB 

with ROFA

Existing LNB 

and SCR

Control Equipment Capital Cost $0 $1,000,000 $15,788,530 $14,747,608 $136,800,000

Capital Recovery Factor N/A 0.09513 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $95,130 $1,501,963 $1,402,940 $13,013,784

Annual O&M Costs $0 $0 $414,076 $1,882,074 $2,668,918

Annual Cost of Control $0 $95,130 $1,916,039 $3,285,014 $15,682,702

Table 10: Naughton Unit 3 Environmental Costs

Existing 

LNB

Tuning 

Existing LNB

Existing LNB 

and SNCR

Existing LNB 

with ROFA

Existing LNB 

and SCR

NOx Emission Rate (lb/MMBtu) 0.45 0.37 0.30 0.28 0.07

Annual NOx Emission (tpy) (a)

6,563 5,397 4,376 4,084 1,021

Annual NOx Reduction (tpy))

N/A 1,167 2,188 2,480 5,542

Annual Cost of Control $0 $95,130 $1,916,039 $3,285,014 $15,682,702

Cost per ton of Reduction N/A $82 $876 $1,325 $2,830

Incremental Cost per ton of Reduction N/A $1,783 $4,688 $4,049 $1,783

(a) Annual emissions based on individual heat input rate of 3,700 MMBtu/hr for 7,884 hours of operation per year.
PacifiCorp Naughton Plant

AP-6042 BART Application Analysis

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

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

company-proposed BART controls for Units 1 and 2 by modeling LNB with advanced OFA and LNB 

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

the company-proposed BART controls for Unit 3 by modeling tuning the existing LNB and OFA and 

tuning the existing LNB and OFA and installing 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 Naughton Units 1-3, Step 5: Evaluate visibility 

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

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

28-30, on pages 37-39, list the modeled control scenarios and associated emission rates.

PM10: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Naughton Units 1 and 2 are currently equipped with mechanical dust collectors and electrostatic 

precipitators to control PM emissions from the boilers to 0.056 lb/MMBtu and 0.064 lb/MMBtu, 

respectively. Unit 3 is equipped with an ESP using FGC to control PM emission to 0.094 lb/MMBtu. As 

discussed below in more detail, ESPs control PM/PM10 from the flue gas stream by creating a strong 

electro-magnetic field in which fly ash particles gain electric charge. Three PM control technologies were 

analyzed for application on the three Naughton units: 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.
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AP-6042 BART Application Analysis

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

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

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

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

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

flue gas residence time.

PM10: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

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

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

filter downstream of the existing ESPs on Naughton Units 1 and 2. PacifiCorp analyzed the impact of 

installing a full-scale fabric filter on Unit 3.

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 hot-side 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.

Naughton Units 1 and 2 have existing ESPs and rather than evaluate costs of replacing them, PacifiCorp 

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

device, as the existing units are already capable of controlling PM10 emissions to 0.056 lb/MMBtu, 0.064 

lb/MMBtu, and 0.094 lb/MMBtu for Units 1, 2, and 3, respectively. The technology continually 

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

from new PC boilers. Rather than demolishing the existing ESP and constructing an entirely new PM 

control device, PacifiCorp recognized the cost benefit of keeping the existing ESP and augmenting the 

control. Installing FGC on Units 1 and 2 can improve the PM removal efficiencies on the existing ESPs 

down to 0.040 lb/MMBtu. In addition to maintaining the existing ESPs, a polishing fabric filter can be 

installed downstream of the existing ESPs. PacifiCorp proposed the use of Compact Hybrid Particulate 

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

smaller than a full-scale fabric filter and has a higher air-to-cloth ratio (7 to 9:1), compared to a 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 ESPs can reduce emissions an additional 63% 

resulting in a PM emission rate of 0.015 lb/MMBtu. Demolishing the existing ESPs and installing a new 

full-scale fabric filter on Units 1 and 2 is anticipated to control emissions down to the same PM emission 

level, 0.015 lb/MMBtu, as installing a polishing fabric filter downstream of the existing ESP.
PacifiCorp Naughton Plant

AP-6042 BART Application Analysis

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Naughton Unit 3 is currently equipped with an ESP and FGC system. PacifiCorp analyzed the impact of 

upgrading the existing FGC and resulting impact of installing a new full-scale fabric filter. PacifiCorp‟s 

proposed emission rates for each technology as applied to Naughton Units 1-3 are shown in Table 11.

Table 11: PM10 Emission Rates Per Boiler

Control Technology

Resulting PM10 Emission Rate 

(lb/MMBtu)

Existing ESP 0.056, 0.064, 0.094 (a)

Existing ESP with FGC 0.040

Existing ESP and New Polishing Fabric Filter (b) 0.015

Full-scale Fabric Filter (c) 0.015

(a) Current achievable PM10 emissions from Unit 1, 2, and 3, respectively.

(b) Applied to Naughton Units 1 and 2.

(c) Applied to Naughton Unit 3.

PM10: EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impact of installing COHPAC on Units 1 and 2. The pressure drop 

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

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

annual plant capacity factor. The installation of a COHPAC fabric filter would require approximately 1.0

MW of power, equating to an annual power usage of approximately 8,000 MW-hr for Unit 1 and 1.4 MW 

of power, equal to an annual power usage of approximately 10,900 MW-hr for Unit 2. Installing a fullscale fabric filter on Unit 3 would require approximately 2.1 MW of power, equating to an annual power 

usage of approximately 16,240 MW-hr.

Installing FGC on Units 1 and 2 will require a minimal amount of additional power, about 100 kW which 

equates to an annual power consumption of 400 kW-hr. Upgrading the existing ESP on Unit 3 is not 

anticipated to require additional power.

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

COHPAC on Units 1and 2, and did not anticipate negative environmental impacts from the addition of 

either of these PM control technologies. Upgrading the existing FGC and installing a new full-scale 

fabric filter on Unit 3 are not anticipated to have significant negative environmental impacts.

PacifiCorp anticipates operating Naughton Units 1-3 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.
PacifiCorp Naughton Plant

AP-6042 BART Application Analysis

Page 19

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

costs for additional PM control on Naughton Units 1-3 are summarized in the following tables

Table 12: Naughton Unit 1 Economic Costs

Cost

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

Control Equipment Capital Cost $0 $1,298,352 $29,798,898

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $123,512 $2,834,769

Annual O&M Costs $0 $77,319 $601,825

Annual Cost of Control $0 $200,831 $3,436,594
PacifiCorp Naughton Plant

AP-6042 BART Application Analysis

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Table 13: Naughton Unit 1 Environmental Costs

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

PM10 Emission Rate (lb/MMBtu) 0.056 0.040 0.015

Annual PM10 Emission (tpy) (a)

408 292 109

Annual PM10 Reduction (tpy) N/A 117 299

Annual Cost of Control $0 $200,831 $3,436,594

Cost per ton of Reduction N/A $1,721 $11,494

Incremental Cost per ton of 

Reduction N/A $1,721 $17,748

(a) Annual emissions based on unit heat input rate of 1,850 MMBtu/hr and 7,884 hours of operation per year.

Table 14: Naughton Unit 2 Economic Costs

Cost

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

Control Equipment Capital Cost $0 $1,298,352 $34,898,710

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $123,512 $3,319,914

Annual O&M Costs $0 $91,904 $781,791

Annual Cost of Control $0 $215,416 $4,101,705

Table 15: Naughton Unit 2 Environmental Costs

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

Existing ESP With 

New Polishing Fabric Filter

PM10 Emission Rate (lb/MMBtu) 0.064 0.040 0.015

Annual PM10 Emission (tpy) (a)

605 378 142

Annual PM10 Reduction (tpy) N/A 227 464

Annual Cost of Control $0 $215,416 $4,101,705

Cost per ton of Reduction N/A $949 $8,848

Incremental Cost per ton of 

Reduction N/A $949 $16,431

(a) Annual emissions based on unit heat input rate of 2,400 MMBtu/hr and 7,884 hours of operation per year. 
PacifiCorp Naughton Plant

AP-6042 BART Application Analysis

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Table 16: Naughton Unit 3 Economic Costs

Cost

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

New Full-scale

Fabric Filter

Control Equipment Capital Cost $0 $13,299,508 $121,000,000 

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $1,265,182 $11,510,730 

Annual O&M Costs $0 $0 $1,120,813 

Annual Cost of Control $0 $1,265,182 $12,631,543 

Table 17: Naughton Unit 3 Environmental Costs

Existing 

ESP

Existing ESP With 

Flue Gas Conditioning

New Full-scale

Fabric Filter

PM10 Emission Rate (lb/MMBtu) 0.094 0.040 0.015

Annual PM10 Emission (tpy) (a)

1,371 583 219

Annual PM10 Reduction (tpy) N/A 788 1,152

Annual Cost of Control $0 $1,265,182 $12,631,543

Cost per ton of Reduction N/A $1,606 $10,963

Incremental Cost per ton of 

Reduction N/A $1,606 $31,172

(a) Annual emissions based on unit heat input rate of 3,700 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 Units 

1 and 2 are not reasonable. The cost effectiveness and incremental cost effectiveness of applying a new 

full-scale fabric filter to Unit 3 are also not reasonable. However, the control was included in the final 

step in the PM/PM10 BART determination process for Naughton Units 1-3, Step 5: Evaluate visibility 

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

pollutants and associated control options. The visibility analysis follows Steps 1-4 for SO2 emissions in 

this application analysis. Tables 28-30, on pages 37-39, list the modeled control scenarios and associated 

emission rates.

SO2: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

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

clearinghouse, in an effort to identify applicable SO2 emission control technologies for Naughton Units 1-

3. 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.
PacifiCorp Naughton Plant

AP-6042 BART Application Analysis

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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 of the two control technologies listed above as technically infeasible. 

PacifiCorp analyzed the impact of installing dry FGD using the existing ESP, installing dry FGD using a 

polishing fabric filter, and installing wet FGD using the existing ESP on Units 1 and 2. Upgrading the 

existing wet waste sodium liquor FGD system with the existing ESP and upgrading the existing wet FGD 

including switching to a soda ash reagent with the existing ESP were two SO2 control options analyzed by 

PacifiCorp for Unit 3.

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 Naughton Plant

AP-6042 BART Application Analysis

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Naughton Units 1 and 2 currently achieve emission rates of 1.20 lb/MMBtu. Both low sulfur coal, 0.58% 

sulfur by weight, and high sulfur coal, 1.02% by weight, are used to fuel the boilers in the Naughton 

units. Installing a new dry FGD system and utilizing the existing ESP on Naughton Units 1 and 2 may 

reduce uncontrolled SO2 emissions from each unit by 85%. Resulting SO2 emission rates for Units 1 and 

2 would be 0.18 lb/MMBtu, based on an average coal sulfur content of 0.58% by weight, and 0.41 

lb/MMBtu, based on an average coal sulfur content of 1.02% by weight. Replacing the existing ESP with 

a new full-scale fabric filter will increase the SO2 removal efficiency to 87.5%. SO2 emission rates for 

Units 1 and 2 from the new fabric filter would be 0.15 lb/MMBtu, based on an average coal sulfur content 

of 0.58% by weight, and 0.21 lb/MMBtu, based on an average coal sulfur content of 1.02% by weight.

As mentioned earlier in this analysis, BART presumptive SO2 levels do not apply to Naughton. However, 

PacifiCorp used the presumptive SO2 levels for uncontrolled units, 95% emissions reduction or 0.15 

lb/MMBtu, as a reference for comparison. PacifiCorp does not anticipate achieving presumptive SO2

emission levels using dry FGD. The application of wet FGD on Units 1 and 2 is anticipated to lower SO2

emissions to 0.10 lb/MMBtu, based on an average coal sulfur content of 0.58% by weight, and 0.15 

lb/MMBtu, based on an average coal sulfur content of 1.02% by weight, which meet presumptive SO2

levels.

The existing wet FGD system on Naughton Unit 3 reduces emissions by 83% to achieve a SO2 emissions 

rate of 0.50 lb/MMBtu when burning high sulfur coal, 1.02% by weight. Wet FGD is a state-of-the-art 

SO2 emissions control technology and continually improves over time. PacifiCorp evaluated potential 

changes to the existing wet FGD systems to improve the SO2 removal efficiencies. Improving inlet gas 

distribution, adding a second tray to improve gas/liquid contact, and upgrading the reagent and waste 

solids systems are projected to reduce emissions by 90% to achieve an emission rate of approximately 

0.21 lb/MMBtu. Switching to a refined soda ash reagent in the upgraded wet FGD system is anticipated 

to reduce uncontrolled emissions by 95%, resulting in a SO2 emission rate of 0.10 lb/MMBtu. 

PacifiCorp‟s proposed emission rates for each SO2 emission reduction technology applied to Naughton

Units 1-3 are shown in Table 18.

Table 18: SO2 Emission Rates Per Boiler (a)

Control Technology

Unit 1

SO2

Emission Rate 

(lb/MMBtu)

Unit 2

SO2

Emission Rate 

(lb/MMBtu)

Unit 3

SO2

Emission Rate 

(lb/MMBtu)

Existing Uncontrolled 1.2 1.2 --

Existing Wet FGD -- -- 0.50

New Dry FGD with Existing ESP 0.41 0.41 --

New Dry FGD with Polishing Fabric Filter 0.21 0.21 --

New Wet FGD with Existing ESP 0.15 0.15 --

Upgraded Wet FGD with Waste Liquor -- -- 0.21

Upgraded Wet FGD with Soda Ash Reagent -- -- 0.10

(a) SO2 emissions based on an average coal sulfur content of 1.02% by weight.
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SO2: EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impacts of installing both dry FGD and wet FGD systems on Units 1 and 

2. PacifiCorp noted that dry FGD systems using the existing ESP require the least amount of power. A 

dry FGD system using the existing ESP installed on Naughton Units 1 and 2 would require approximately 

1.6 MW and 2.2 MW of power, respectively. Wet FGD would require approximately 2.4 MW and 3.3 

MW of power for Units 1 and 2, respectively. Based on an annual operating factor of 90%, the cost 

savings of using dry FGD on Units 1 and 2 would equate to approximately 5,900 MW-hr and 8,300 MWhr, respectively.

PacifiCorp estimates that upgrading the existing wet sodium FGD system on Naughton Unit 3 would 

require approximately 330 kW of additional power. Using a 90% annual operating factor, the annual 

power cost is 2,602 MW-hr.

There are no anticipated environmental impacts from upgrading the existing wet sodium FGD system on 

Naughton Unit 3 except for an incremental addition to scrubber waste disposal and makeup water 

requirement. Recycling the waste liquor into the scrubber would save on disposal of these materials and 

conserve resources.

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 Naughton Units 1 and 2

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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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 Naughton Units 1-3 indefinitely and did not include life extension costs 

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

factor. The annual cost to control was determined using a capital recovery factor based on a 7.1% interest 

rate. PacifiCorp labor and service costs were used to calculate the annual operating and maintenance 

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

controls were included.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

emission control. Economic and environmental costs for additional controls on Naughton Units 1-3 are 

summarized in the following tables.
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Table 19: Naughton Unit 1 Economic Costs

Cost Existing

Dry FGD with 

Existing ESP

Dry FGD with 

Polishing Fabric Filter

Wet FGD with 

Existing ESP

Control Equipment Capital Cost $0 $64,297,623 $108,995,970 $89,400,000 

Capital Recovery Factor N/A 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $6,116,633 $10,368,787 $8,504,622 

Annual O&M Costs $0 $3,226,295 $4,006,095 $4,563,874 

Annual Cost of Control $0 $9,342,928 $14,374,882 $13,068,496 

Table 20: Naughton Unit 1 Environmental Costs

Existing

Dry FGD with 

Existing ESP

Dry FGD with 

Polishing Fabric Filter

Wet FGD with 

Existing ESP

SO2 Emission Rate (lb/MMBtu) 1.20 0.41 0.15 0.15

Annual SO2 Emission (tpy) (a)

8,7516 2,990 1,094 1,094

Annual SO2 Reduction (tpy) N/A 5,761 7,657 7,657

Annual Cost of Control $0 $9,342,928 $14,374,882 $13,068,496

Cost per ton of Reduction N/A $1,622 $1,877 $1,707

Incremental Cost per ton of 

Reduction N/A $1,622 $2,654 $1,965 (b)

(a) Annual emissions based on an average coal sulfur content of 1.02%, a heat input rate of 1,850 MMBtu/hr, and 7,884 hours of 

operation per year.

(b) Incremental cost from installing dry FGD with a polishing fabric filter cannot be calculated since the reduced tons of SO2 are

anticipated to be the same. Therefore, the incremental cost from installing dry FGD with the existing ESP was calculated.

Table 21: Naughton Unit 2 Economic Costs

Cost Existing

Dry FGD with 

Existing ESP

Dry FGD with 

Polishing Fabric Filter

Wet FGD with 

Existing ESP

Control Equipment Capital Cost $0 $88,896,713 $141,244,778 $117,400,000 

Capital Recovery Factor N/A 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $8,456,744 $13,436,616 $11,168,262 

Annual O&M Costs $0 $4,251,261 $5,259,175 $5,721,158 

Annual Cost of Control $0 $12,708,005 $18,695,791 $16,889,420 
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Table 22: Naughton Unit 2 Environmental Costs

Existing

Dry FGD with 

Existing ESP

Dry FGD with 

Polishing Fabric Filter

Wet FGD with 

Existing ESP

SO2 Emission Rate (lb/MMBtu) 1.20 0.41 0.15 0.15

Annual SO2 Emission (tpy) (a)

11,353 3,879 1,419 1,419

Annual SO2 Reduction (tpy) N/A 7,474 9,934 9,934

Annual Cost of Control $0 $12,708,005 $18,695,791 $16,889,420

Cost per ton of Reduction N/A $1,700 $1,882 $1,700

Incremental Cost per ton of 

Reduction N/A $1,700 $2,434 $1,700 (b)

(a) Annual emissions based on an average coal sulfur content of 1.02%, a heat input rate of 2,400 MMBtu/hr, and 7,884 hours of 

operation per year.

(b) Incremental cost from installing dry FGD with a polishing fabric filter cannot be calculated since the reduced tons of SO2 are

anticipated to be the same. Therefore, the incremental cost from installing dry FGD with the existing ESP was calculated.

Table 23: Naughton Unit 3 Economic Costs

Cost

Existing

Wet FGD

Upgraded 

Wet FGD with 

Waste Liquor

Upgraded 

Wet FGD with 

Soda Ash Reagent

Control Equipment Capital Cost $0 $6,000,000 $27,798,972 

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $570,780 $2,644,516 

Annual O&M Costs $0 $615,513 $1,656,269 

Annual Cost of Control $0 $1,186,293 $4,300,785 

Table 24: Naughton Unit 3 Environmental Costs

Existing 

Wet FGD

Upgrade

Wet FGD Using

Waste Liquor

Upgrading

Wet FGD Using

Soda Ash Reagent

SO2 Emission Rate (lb/MMBtu) 0.50 0.21 0.15

Annual SO2 Emission (tpy) (a)

7,293 3,063 2,188

Annual SO2 Reduction (tpy) N/A 4,230 5,105

Annual Cost of Control $0 $1,186,293 $4,300,785

Cost per ton of Reduction N/A $280 $842

Incremental Cost per ton of Reduction N/A $280 $3,559

(a) Annual emissions based on an average coal sulfur content of 1.02%, a heat input rate of 3,700 MMBtu/hr, and 7,884 hours 

of operation per year.
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AP-6042 BART Application Analysis

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

for Units 1 – 3 are reasonable. The final step in the SO2 BART determination process for Naughton Units 

1-3, Step 5: Evaluate visibility impacts, is addressed in a comprehensive visibility analysis presented in 

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

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

technology in relation to all three visibility impairing pollutants. Tables 28-30, on pages 37-39, list the

modeled control scenarios and associated emission rates.

VISIBILITY IMPROVEMENT DETERMINATION:

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

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

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

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

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

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

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

is described in detail below. 

Bridger Wilderness Area (WA) and Fitzpatrick WA in Wyoming are the closest Class I areas to the 

PacifiCorp Naughton facility, as shown in Figure 2 below. Bridger WA is located approximately 140

kilometers (km) northeast of the facility and Fitzpatrick WA is located approximately 165 km northeast of 

the facility.

Only those Class I areas most likely to be impacted by the Naughton Power Plant sources were modeled, 

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

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

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

predicted for the modeled areas. 
PacifiCorp Naughton Plant

AP-6042 BART Application Analysis

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Figure 2

Naughton Power Plant and Class I Areas

#*

Sweetwater

Sublette

Lincoln

Fremont

Uinta

Teton

Hot Springs

Bridger Wilderness

Fitzpatrick Wilderness

Wyoming

Utah

Idaho

Colorado

Lander

Jackson

Pinedale

Kemmerer

Evanston

Green River

109°0'0"W

109°0'0"W

110°0'0"W

110°0'0"W

111°0'0"W

111°0'0"W

43°0'0"N

43°0'0"N

42°0'0"N

42°0'0"N

41°0'0"N

41°0'0"N

Naughton

Power Plant
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AP-6042 BART Application Analysis

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SCREENING MODELING

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

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

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

Resolution of the MM5 data was 36-km for all three of the modeled years. Potential emissions for current 

operation from the three coal-fired boilers at the Naughton 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 Bridger WA and Fitzpatrick WA for all three years of 

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

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

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

Table 25: Results of the Class I Area Screening Modeling

Class I Area

Maximum 

Modeled 

Value (Δdv)

98th

Percentile 

Value (Δdv)

1995

Bridger WA 5.984 3.119

Fitzpatrick WA 3.305 1.632

1996

Bridger WA 6.185 4.364

Fitzpatrick WA 5.253 2.378

2001

Bridger WA 7.331 4.277

Fitzpatrick WA 4.789 2.428

 Δdv = delta deciview

 WA = wilderness area

REFINED MODELING

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

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

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

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

September 2006). 

CALPUFF System

Predicted visibility impacts from the PacifiCorp Naughton 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.
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AP-6042 BART Application Analysis

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

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

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

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

removal. 

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

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

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

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

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

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

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

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

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

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

CALPUFF model in a refined mode.

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

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

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

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

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

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

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

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

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

Table 26: Key Programs in CALPUFF System

Program Version Level

CALMET 5.53a 040716

CALPUFF 5.711a 040716

CALPOST 5.51 030709
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Meteorological Data Processing (CALMET)

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

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

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

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

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

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

input to CALMET, including surface, upper-air, and precipitation stations, are shown in 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 27: Key User-Defined CALMET Settings

Variable Description Value 

PMAP Map projection LCC 

DGRIDKM Grid spacing (km) 4 

NZ Number of layers 10 

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

580, 1020, 1480, 2220, 3400 

RMIN2 Minimum distance for extrapolation -1 

IPROG Use gridded prognostic model output 14 

RMAX 1 Maximum radius of influence (surface 

layer, km) 

30 

RMAX 2 Maximum radius of influence (layers 

aloft, km) 

50 

TERRAD Radius of influence for terrain (km) 15 

R1 Relative weighting of first guess wind 

field and observations (km) 

5 

R2 Relative weighting aloft (km) 25 
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Figure 3

Observations Input to CALMET

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

LCC E (km)

-300

-200

-100

0

100

200

300

400

LCC N (km)

KWX

AIA

AKO

APA

ASE

BFF

BIL

BPI

BTM

BYG

BYI

BZN

CAG

CPR CDR

CUT

CYS

D07

DEN

DGW

DLN

EEO

EVW

GCC

GEY

GJT

IDA

IEN

ITR

LAR

LGU

LIC

LND

LVM

LXV

OGD

P60

PHP

PIH

PUC

RAP

RIL

RIW

RKS

RWL

RXE

SHR

SLC

SNY

TOR

VEL

WRL

RAP

DEN

SLC

RIW

Naughton

Precipitation Station = green

Surface Station = white 3-letter

Upper-Air (+ surface) = red 3-letter
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CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry 

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

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

Rocky Mountain National Park (NP), Colorado

Craters of the Moon National Monument, Idaho

Highland, Utah

Thunder Basin, Wyoming

Yellowstone NP, Wyoming

Centennial, Wyoming

Pinedale, Wyoming

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

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

ppb was used. 

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

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

Lambert Conformal Conic coordinates. Figures 4 and 5 show the receptor configurations that 

were used for Bridger WA and Fitzpatrick WA. Receptor spacing for the modeled areas was

approximately 1.3 km in the east-west direction and approximately 1.8 km in the north-south 

direction. 
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Figure 4

Receptors for Bridger WA
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Figure 5

Receptors for Fitzpatrick WA

CALPUFF Inputs – Baseline and Control Options

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

Naughton Plant are shown in the tables below. 
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Table 28: CALPUFF Inputs for Naughton Unit 1

Naughton Unit 1 Baseline Post-Control 

Scenario 1

PostControl 

Scenario 2

PostControl 

Scenario 3

PostControl 

Scenario 4

Post-Control 

Scenario A

PostControl 

Scenario B

Model Input Data

Current 

Operation 

with ESP

LNB with 

advanced 

OFA, Dry 

FGD, ESP 

with Flue Gas 

Conditioning 

LNB with 

advanced 

OFA, Dry 

FGD, New 

Fabric Filter

LNB with 

advanced 

OFA and 

SCR, Dry 

FGD, New 

Fabric Filter

LNB with 

advanced 

OFA and 

SCR, Wet 

FGD, ESP 

with Sulfur 

Trioxide 

Injection, 

New Stack

PacifiCorp 

Committed 

Controls: 

LNB with 

advanced 

OFA, Wet 

FGD, ESP 

with Flue Gas 

Conditioning, 

New Stack

PacifiCorp 

Committed 

Controls 

and SCR 

Hourly Heat Input (mmBtu/hour) 1,850 1,850 1,850 1,850 1,850 1,850 1,850

Sulfur Dioxide (SO2) (lb/mmBtu) 1.20 0.41 0.15 0.15 0.10 0.15 0.15

Sulfur Dioxide (SO2) pounds per hour 

(lb/hr) 2,220 759 278 278 185 278 278

Nitrogen Oxide (NOx) (lb/mmBtu) 0.58 0.24 0.24 0.07 0.07 0.26 0.07

Nitrogen Oxide (NOx) (lb/hr) 1,073 444 444 130 130 481 130

PM10 (lb/mmBtu) 0.056 0.040 0.015 0.015 0.040 0.040 0.040

PM10 (lb/hr) 103.6 74.0 27.8 27.8 74.0 77.7 77.7

Coarse Particulate (PM2.5<diameter< PM10) 

(lb/hr)(a) 44.5 31.8 15.8 15.8 31.8 33.4 33.4

Fine Particulate (diameter<PM2.5) (lb/hr)(b) 59.1 42.2 11.9 11.9 42.2 44.3 44.3

Sulfuric Acid (H2SO4) (lb/hr) 34.0 1.7 1.7 2.4 29.2 17.0 29.3

Ammonium Sulfate [(NH4)2SO4] (lb/hr) -- -- -- 0.4 2.1 -- 2.1

Ammonium Bisulfate (NH4)HSO4 (lb/hr) -- -- -- 0.7 3.7 -- 3.7

H2SO4 as Sulfate (SO4) (lb/hr) 33.3 1.6 1.6 2.4 28.6 16.7 28.7

(NH4)2SO4 as SO4 (lb/hr) -- -- -- 0.3 1.6 -- 1.5

(NH4)HSO4 as SO4 (lb/hr) -- -- -- 0.6 3.1 -- 3.1

Total Sulfate (SO4) (lb/hr) 33.3 1.6 1.6 3.3 33.2 16.7 33.3

Stack Conditions

Stack Height (meters) 61 61 61 61 152 145 145

Stack Exit Diameter (meters) 4.27 4.27 4.27 4.27 4.88 4.88 4.88

Stack Exit Temperature (Kelvin) 411 350 342.6 342.6 323 323 323

Stack Exit Velocity (meters per second) 28.1 19.7 24.6 24.6 18.1 18.1 18.1

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

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

Notes:
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Table 29: CALPUFF Inputs for Naughton Unit 2

Naughton Unit 2 Baseline Post-Control 

Scenario 1

PostControl 

Scenario 2

PostControl 

Scenario 3

PostControl 

Scenario 4

Post-Control 

Scenario A

PostControl 

Scenario B

Model Input Data

Current 

Operations 

with ESP

LNB with 

advanced 

OFA, Dry 

FGD, ESP 

with Flue Gas 

Conditioning

LNB with 

advanced 

OFA, Dry 

FGD, New 

Fabric 

Filter

LNB with 

advanced 

OFA and 

SCR, Dry 

FGD, 

Fabric Filter

LNB with 

advanced 

OFA and 

SCR, Wet 

FGD, ESP, 

New Stack

PacifiCorp 

Committed 

Controls: LNB 

with advanced 

OFA, Wet 

FGD, ESP 

with Flue Gas 

Conditioning, 

New Stack

PacifiCorp 

Committed 

Controls 

and SCR

Hourly Heat Input (mmBtu/hour) 2,400 2,400 2,400 2,400 2,400 2,400 2,400

Sulfur Dioxide (SO2) (lb/mmBtu) 1.20 0.41 0.15 0.15 0.10 0.15 0.15

Sulfur Dioxide (SO2) pounds per hour 

(lb/hr) 2,868 984 360 360 240 360 360

Nitrogen Oxide (NOx) (lb/mmBtu) 0.54 0.24 0.24 0.07 0.07 0.26 0.07

Nitrogen Oxide (NOx) (lb/hr) 1,291 576 576 168 168 624 168

PM10 (lb/mmBtu) 0.064 0.040 0.015 0.015 0.040 0.050 0.040

PM10 (lb/hr) 153.6 96.0 36.0 36.0 96.0 129.6 129.6

Coarse Particulate (PM2.5<diameter< PM10) 

(lb/hr)(a) 65.8 41.3 20.5 20.5 41.3 55.7 55.7

Fine Particulate (diameter<PM2.5) (lb/hr)(b) 87.2 54.7 15.5 15.5 54.7 73.9 73.9

Sulfuric Acid (H2SO4) (lb/hr) 44.2 2.2 2.2 3.1 37.9 22.1 38.0

Ammonium Sulfate [(NH4)2SO4] (lb/hr) -- -- -- 0.6 2.8 -- 2.8

Ammonium Bisulfate (NH4)HSO4 (lb/hr) -- -- -- 1.0 4.8 -- 4.8

H2SO4 as Sulfate (SO4) (lb/hr) -- -- -- 0.4 2.0 -- 2.0

(NH4)2SO4 as SO4 (lb/hr) 43.3 2.1 2.1 3.1 37.2 21.6 37.2

(NH4)HSO4 as SO4 (lb/hr) 0.8 4.0 4.0

Total Sulfate (SO4) (lb/hr) 43.3 2.1 2.1 4.3 43.2 21.6 43.2

Stack Conditions

Stack Height (meters) 68 68 68 68 152 145 145

Stack Exit Diameter (meters) 4.88 4.88 4.88 4.88 5.49 5.49 5.49

Stack Exit Temperature (Kelvin) 411 350 343 343 323 323 323

Stack Exit Velocity (meters per second) 27.8 20.2 24.3 24.3 18.5 18.5 18.5

Notes:

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

(b) AP-42, Table 1.1-6: fine PM counted as a percentage of PM10. This equates to 57 percent for ESP and 43 percent for Baghouse.
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Table 30: CALPUFF Inputs for Naughton Unit 3

Naughton 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 

Operations 

with Wet 

FGD and 

ESP

Tuning 

Existing 

LNB with 

OFA, Wet 

FGD with 

Waste 

Liquor, 

Existing 

ESP

Tuning 

Existing 

LNB with 

OFA & 

SCR, Wet 

FGD with 

Waste 

Liquor, 

Enhanced 

ESP 

Tuning 

Existing 

LNB with 

OFA and 

SCR, Wet 

FGD with 

Waste 

Liquor, 

Fabric Filter

Tuning 

Existing 

LNB with 

OFA and 

SCR, Wet 

FGD with 

Soda Ash, 

Fabric Filter

PacifiCorp 

Committed 

Controls: 

Tuning 

Existing 

LNB with 

OFA, Wet 

Sodium 

FGD, New 

Fabric Filter

PacifiCorp 

Committed 

Controls 

and SCR

Hourly Heat Input (mmBtu/hour) 3,700 3,700 3,700 3,700 3,700 3,700 3,700

Sulfur Dioxide (SO2) (lb/mmBtu) 0.50 0.21 0.21 0.21 0.10 0.22 0.22

Sulfur Dioxide (SO2) pounds per hour 

(lb/hr) 1,840 777 777 777 370 814 814

Nitrogen Oxide (NOx) (lb/mmBtu) 0.45 0.35 0.07 0.07 0.07 0.37 0.07

Nitrogen Oxide (NOx) (lb/hr) 1,656 1,295 259 259 259 1,369 259

PM10 (lb/mmBtu) 0.094 0.040 0.040 0.015 0.015 0.015 0.015

PM10 (lb/hr) 348.0 148.0 148.0 55.5 55.5 55.5 55.5

Coarse Particulate (PM2.5<diameter< PM10) 

(lb/hr)(a) 149.6 63.6 63.6 31.6 31.6 23.9 23.9

Fine Particulate (diameter<PM2.5) (lb/hr)(b) 198.4 84.4 84.4 23.9 23.9 31.6 31.6

Sulfuric Acid (H2SO4) (lb/hr) 34.0 34.0 58.7 58.7 58.7 34.0 58.5

Ammonium Sulfate [(NH4)2SO4] (lb/hr) -- -- 4.3 4.3 4.3 -- 4.3

Ammonium Bisulfate (NH4)HSO4 (lb/hr) -- -- 7.4 7.4 7.4 -- 7.4

H2SO4 as Sulfate (SO4) (lb/hr) 33.4 33.4 57.3 57.3 57.3 33.3 57.3

(NH4)2SO4 as SO4 (lb/hr) -- -- 3.1 3.1 3.1 -- 3.1

(NH4)HSO4 as SO4 (lb/hr) -- -- 6.2 6.2 6.2 -- 6.2

Total Sulfate (SO4) (lb/hr) 33.2 33.4 66.6 66.6 66.6 33.3 66.6

Stack Conditions

Stack Height (meters) 145 145 145 145 145 145 145

Stack Exit Diameter (meters) 8.08 8.08 8.08 8.08 8.08 8.08 8.08

Stack Exit Temperature (Kelvin) 323 322 322 322 323 322 322

Stack Exit Velocity (meters per second) 23.8 20.2 20.2 20.2 18.6 20.2 20.2

Notes:

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

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

The changes in visibility were modeled using Method 6 within the CALPOST post-processor. Method 6 

requires input of monthly relative humidity factors [f(RH)] for each Class I area. Monthly f(RH) factors 

that were used for Bridger WA and Fitzpatrick WA are shown in the table below. 

Table 31: Relative Humidity Factors for CALPOST

Month

Bridger WA

&

Fitzpatrick 

WA

January 2.50

February 2.30

March 2.30

April 2.10

May 2.10

June 1.80

July 1.50

August 1.50

September 1.80

October 2.00

November 2.50

December 2.40

According to the final BART rule, natural background conditions as a reference for determination of the 

modeled Δdv change should be representative of the 20 percent best natural visibility days in a given 

Class I area. EPA BART guidance provides the 20 percent best days deciview values for each Class I 

area on an annual basis, but does not provide the individual species concentration data required for input 

to CALPOST.

Species concentrations corresponding to the 20 percent best days were calculated for each Class I area by 

scaling back the annual average (natural background) concentrations given in Table 2-1 of the EPA 

document Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule. A 

separate scaling factor was derived for each Class I area such that, when multiplied by the guidance table 

annual concentrations, the 20% best days deciview values for that particular Class I area would be 

calculated. 

The scaling procedure is illustrated here for Bridger WA. From Appendix B in the EPA natural visibility 

guidance document, the deciview value for the 20 percent best days at Bridger WA is 1.96 dv. To obtain 

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

(1.96 dv) was first converted to light extinction. The relationship between deciviews and light extinction 

is expressed as follows:

dv = 10 ln (bext/10) or bext = 10 exp (dv/10)
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where: bext = light extinction expressed in inverse megameters (Mm-1).

Using this relationship with the known deciview value of 1.96, one obtains an equivalent light extinction 

value of 12.17 Mm-1. Next, the annual average natural visibility concentrations were set equal to a total 

extinction value of 12.17 Mm-1. The relationship between total light extinction and the individual 

components of the light extinction is as follows:

bext = (3)f(RH)[ammonium sulfate] + (3)f(RH)[ammonium nitrate] + (0.6)[coarse mass] + (4)[organic 

carbon] + (1)[soil] + (10)[elemental carbon] + bray

where:

bracketed quantities represent background concentrations in μg/m3

values in parenthesis represent scattering efficiencies

f(RH) is the relative humidity adjustment factor (applied to hygroscopic species only)

bray is light extinction due to Rayleigh scattering (10 Mm-1used for all Class I areas)

Substituting the annual average natural background concentrations, the average f(RH) for Bridger WA, 

and including a coefficient for scaling, one obtains:

12.17 = (3)(2.1)[0.12]X + (3)(2.1)[0.1]X + (0.6)[3.0]X + (4)[0.47]X + (1)[0.5]X + (10)[0.02]X + 10

In the equation above, X represents a scaling factor needed to convert the annual average natural 

background concentrations to values representative of the 20 percent best days. Solving for X provides a 

value of 0.376. Table 32 presents the annual average natural background concentrations, the calculated 

scaling factor, and the calculated background concentrations for the 20 percent best days for Bridger WA. 

Table 32: Calculated Background Components for Bridger WA 

Component

Annual Average for 

West Region (μg/m3)

Calculated Scaling 

Factor

20% Best Days for 

Bridger WA

(μg/m3)

Ammonium Sulfate 0.12 0.376 0.045

Ammonium Nitrate 0.10 0.376 0.038

Organic Carbon 0.47 0.376 0.176

Elemental Carbon 0.02 0.376 0.008

Soil 0.50 0.376 0.188

Coarse Mass 3.00 0.376 1.127

The scaled aerosol concentrations were averaged for Bridger WA and Fitzpatrick WA because of their 

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

concentrations for the two Class I areas in question are listed in the table below.
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Table 33: Natural Background Aerosol Concentrations (μg/m3)

Aerosol 

Component 

Fitzpatrick 

WA &

Bridger WA 

Ammonium Sulfate 0.045 

Ammonium Nitrate 0.038 

Organic Carbon 0.178 

Elemental Carbon 0.008 

Soil 0.189 

Coarse Mass 1.136 

Visibility Post-Processing Results

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

shown in the tables below. For each scenario, the 98th percentile Δdv results are reported along with the 

total number of days for which the predicted impacts exceeded 0.5 dv. Following the tables are figures 

that present the results graphically for baseline, the BART configuration proposed by PacifiCorp, and for 

the proposed BART configuration with the addition of SCR.
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Table 34: CALPUFF Visibility Modeling Results: Unit 1

Class I Area

2001 2002 2003 3-Year Average

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 0.5 

Δdv

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

Baseline – Current Operations with ESP

Bridger WA 1.777 48 1.763 41 1.797 45 1.779 45

Fitzpatrick WA 0.966 23 0.881 18 0.840 20 0.896 20

Post-Control Scenario 1 – LNB with advanced OFA, Dry FGD, ESP with Flue Gas Conditioning

Bridger WA 0.644 14 0.741 14 0.694 16 0.693 15

Fitzpatrick WA 0.357 3 0.314 5 0.361 5 0.344 4

Post-Control Scenario 2 – LNB with advanced OFA, Dry FGD, New Fabric Filter

Bridger WA 0.479 7 0.635 9 0.493 7 0.536 8

Fitzpatrick WA 0.235 2 0.205 2 0.266 3 0.235 2

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

Bridger WA 0.217 1 0.274 1 0.234 3 0.242 2

Fitzpatrick WA 0.119 0 0.105 0 0.123 0 0.116 0

Post-Control Scenario 4 – LNB with advanced OFA and SCR, Wet FGD, ESP with Sulfur Trioxide Injection, New Stack

Bridger WA 0.387 4 0.288 3 0.397 4 0.357 4

Fitzpatrick WA 0.153 1 0.108 1 0.135 0 0.132 1

Post-Control Scenario A – Committed Controls: LNB with advanced OFA, Wet FGD, ESP with Flue Gas Conditioning

Bridger WA 0.733 14 0.623 9 0.698 12 0.685 12

Fitzpatrick WA 0.320 3 0.221 2 0.280 2 0.274 2

Post-Control Scenario B – Committed Controls and SCR

Bridger WA 0.406 5 0.370 4 0.413 5 0.396 5

Fitzpatrick WA 0.175 1 0.131 1 0.168 0 0.158 1
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Table 35: CALPUFF Visibility Modeling Results: Unit 2

Class I Area

2001 2002 2003 3-Year Average

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

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 – Current Operations with ESP

Bridger WA 2.127 61 1.860 56 2.087 55 2.025 57

Fitzpatrick WA 1.158 26 1.099 24 1.110 22 1.122 24

Post-Control Scenario 1 – LNB with advanced OFA, Dry FGD, ESP with flue gas conditioning

Bridger WA 0.838 28 0.926 18 0.882 19 0.882 22

Fitzpatrick WA 0.462 6 0.413 5 0.448 6 0.441 6

Post-Control Scenario 2 – LNB with advanced OFA, Dry FGD, New Fabric Filter

Bridger WA 0.642 14 0.745 11 0.614 12 0.667 12

Fitzpatrick WA 0.312 3 0.286 4 0.313 4 0.304 4

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

Bridger WA 0.284 2 0.321 3 0.291 3 0.299 3

Fitzpatrick WA 0.158 1 0.141 1 0.148 0 0.149 1

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

Bridger WA 0.482 7 0.354 4 0.526 8 0.454 6

Fitzpatrick WA 0.208 2 0.138 1 0.162 0 0.169 1

Post-Control Scenario A – Committed Controls: LNB with advanced OFA, Wet FGD, ESP with Flue Gas Conditioning

Bridger WA 0.944 20 0.757 14 0.921 15 0.874 16

Fitzpatrick WA 0.404 4 0.288 4 0.326 2 0.339 3

Post-Control Scenario B – Committed Controls and SCR

Bridger WA 0.544 10 0.450 7 0.555 9 0.516 9

Fitzpatrick WA 0.221 2 0.167 1 0.186 0 0.191 1
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Table 36: CALPUFF Visibility Modeling Results: Unit 3

Class I Area

2001 2002 2003 3-Year Average

98th 

Percentile 

Value 

(Δdv)

No. of 

Days > 

0.5 Δdv

98th 

Percentile 

Value 

(Δdv)

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 – Current Operations with Wet FGD and ESP

Bridger WA 1.978 66 1.618 56 2.171 53 1.922 58

Fitzpatrick WA 1.126 24 0.893 21 0.871 21 0.963 22

Post-Control Scenario 1 – Tuning Existing LNB with OFA, Wet FGD with Waste Liquor, Existing ESP

Bridger WA 1.413 12 1.175 32 1.555 39 1.381 28

Fitzpatrick WA 0.735 16 0.564 11 0.549 9 0.616 12

Post-Control Scenario 2 – Tuning Existing LNB with OFA & SCR, Wet FGD with Waste Liquor, Enhanced ESP

Bridger WA 0.716 19 0.650 10 0.828 14 0.731 14

Fitzpatrick WA 0.371 4 0.290 3 0.260 1 0.307 3

Post-Control Scenario 3 – Tuning Existing LNB with OFA and SCR, Wet FGD with Waste Liquor, Fabric Filter

Bridger WA 0.697 16 0.635 10 0.810 14 0.714 13

Fitzpatrick WA 0.363 4 0.279 3 0.253 1 0.298 3

Post-Control Scenario 4 – Tuning Existing LNB with OFA and SCR, Wet FGD with Soda Ash, Fabric Filter

Bridger WA 0.553 12 0.494 7 0.662 11 0.570 10

Fitzpatrick WA 0.265 2 0.203 3 0.214 0 0.227 2

Post-Control Scenario A – Committed Controls: Tuning Existing LNB with OFA, Wet FGD, New Fabric Filter

Bridger WA 1.460 45 1.21 34 1.583 40 1.418 40

Fitzpatrick WA 0.766 17 0.586 11 0.572 11 0.641 13

Post-Control Scenario B – Committed Controls and SCR

Bridger WA 0.710 17 0.650 10 0.830 14 0.730 14

Fitzpatrick WA 0.372 4 0.287 3 0.259 1 0.306 3
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Figure 6

Modeled BART Impacts: 98th Percentile (delta-dv)
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Figure 7

Modeled BART Impacts: Number of Days > 0.5 delta-dv
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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 three units subject to BART at the Naughton Power Plant.

NOx

LNB with advanced OFA is determined to be BART for Units 1 and 2 for NOx based, in part, on the 

following conclusions:

1. LNB with advanced OFA on Units 1and 2 was cost effective with a capital cost of $9,600,000

and $9,100,000 per unit, respectively. The average cost effectiveness, over a twenty year 

operational life, is $426 per ton of NOx removed for Unit 1 and $357 per ton for Unit 2.

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 0.26 lb/MMBtu on a 30-day rolling 

average, above EPA‟s established presumptive limit of 0.15 lb/MMBtu for tangential-fired 

boilers burning sub-bituminous coal, though not applicable, is justified.

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

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

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

achieved with LNB with advanced OFA, wet FGD, and existing ESP with FGC (Post-Control 

Scenario A) was 1.716 Δdv from Unit 1 and 1.934 Δdv from Unit 2.

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

on Units 1 and 2 are 2,334 tons and 2,649 tons, respectively.

LNB with advanced OFA and SCR was not determined to be BART for Units 1and 2 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 1 is $94,600,000 and $115,900,000 for Unit 2. 

Annual SCR O&M costs for Unit 1 are $1,231,912 and $1,639,352 for Unit 2.

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 1.0 MW

from Unit 1 and 1.3 MW from Unit 2.
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AP-6042 BART Application Analysis

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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 

across both Class I areas achieved with Post-Control Scenario B was 0.405 Δdv from Unit 1 and 

0.506 Δdv from Unit 2.

Tuning the existing LNB with OFA and installing SCR is determined to be BART for Unit 3 for NOx

based, in part, on the following conclusions:

1. The cost effectiveness of tuning the existing LNB with OFA and installing SCR on Unit 3 was 

reasonable at $2,830 per ton of NOx removed. The incremental cost effectiveness when 

compared to existing LNB with ROFA was $1,783 per ton of NOx and reasonable as well. Both 

the cost effectiveness and average cost effectiveness were based on a twenty year operational life

for the proposed controls.

2. The cumulative 3-year averaged 98th percentile visibility improvement from the baseline summed 

across both Class I areas achieved by tuning the existing LNB with OFA, wet FGD and installing 

a new full-scale fabric filter, Post-Control Scenario A, was 0.826 Δdv from Unit 3. Units 1 and 2 

yielded notably higher visibility improvements from baseline, 1.716 Δdv and 1.934 Δdv, 

respectively, using Post-Control Scenario A which included new LNB with advanced OFA, but 

not SCR.

3. Modeled 98th percentile visibility results from Unit 3 Post-Control Scenario B are directly 

comparable to those from Post-Control Scenario A, as the only difference is directly attributable 

to the installation of SCR. The cumulative 3-year averaged 98th percentile visibility improvement 

across the two Class I areas achieved by installing SCR on Unit 3 was 1.023 Δdv, approximately 

twice the 98th percentile visibility improvements, 0.405 Δdv from Unit 1 and 0.506 Δdv from 

Unit 2, using Post-Control Scenario B which included installing SCR.

4. The cumulative 3-year averaged 98th percentile visibility improvement from the baseline summed 

across both Class I areas achieved by tuning the existing LNB with OFA, SCR, wet FGD, and 

installing a new full-scale fabric filter, Post-Control Scenario B, was 1.849 Δdv. This visibility 

improvement is less than the improvement achieved by Post-Control Scenario A using new LNB 

and advanced OFA on Unit 2, 1.934 Δdv, but higher than Post-Control Scenario A using new 

LNB and advanced OFA on Unit 1, 1.716 Δdv.

5. Annual NOx emission reductions from baseline achieved by tuning existing LNB with OFA and 

installing SCR are 5,542 tons as compared to only 1,167 tons from tuning existing LNB with 

OFA.

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

existing pollution control equipment, a NOx control level of 0.37 lb/MMBtu on a 30-day rolling 

average for Unit 3, above EPA‟s established presumptive limit of 0.15 lb/MMBtu for tangentialfired boilers burning sub-bituminous coal, though not applicable, is not justified.
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AP-6042 BART Application Analysis

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

with advanced OFA on Units 1 and 2 and tuning existing LNB with OFA and installing SCR on Unit 3 to 

meet corresponding emission limits on a continuous basis, to meet the statutory requirements of BART.

Unit-by-unit NOx BART determinations:

Naughton Unit 1: Installing new LNB with advanced OFA and meeting NOx emission 

limits of 0.26 lb/MMBtu (30-day rolling average), 481 lb/hr (30-day 

rolling average), and 2,107 tpy as BART for NOx. 

Naughton Unit 2: Installing new LNB with advanced OFA and meeting NOx emission 

limits of 0.26 lb/MMBtu (30-day rolling average), 624 /hr (30-day 

rolling average), and 2,733 tpy as BART for NOx.

Naughton Unit 3: Tuning existing LNB with OFA and installing SCR meeting NOx

emission limits of 0.07 lb/MMBtu (30-day rolling average), 259 lb/hr 

(30-day rolling average), and 1,134 tpy as BART for NOx.

PM/PM10

Existing ESP with FGC is determined to be BART for Units 1 and 2 for PM/PM10 based, in part, on the 

following conclusions:

1. Recognizing the cost benefit associated with using the existing ESPs and the minimal energy 

impact of installing FGC, the cost of compliance for the control technology is cost effective for 

each unit, over a twenty year operational life, for reducing PM emissions. The cost effectiveness 

for existing ESP with FGC is $1,721 for Unit 1 and $949 for Unit 2. 

2. No negative non-air environmental impacts are anticipated from existing ESPs with FGC.

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

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

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

achieved with LNB with advanced OFA, wet FGD, and existing ESP with FGC (Post-Control 

Scenario A) was 1.716 Δdv from Unit 1 and 1.934 Δdv from Unit 2. While the visibility 

improvement attributable to the installation of FGC on existing ESPs can‟t be directly determined 

from the visibility modeling, the Division does not anticipate the PM contribution to be 

significant when compared to NOx and SO2 contributions.

Existing ESP with FGC and a polishing fabric filter was not determined to be BART for Units 1 and 2 for 

PM/PM10 based, in part, on the following conclusions:

1. The cost of compliance for a polishing fabric filter on each unit is not reasonable over a twenty 

year operational life. The cost effectiveness for installing a new polishing fabric filter on the 

existing ESP is $8,848 for Unit 1 and, $11,494 for Unit 2. Incremental cost effectiveness is 

$17,748 for Unit 1 and $16,431 for Unit 2.
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2. The cumulative 3-year averaged 98th percentile visibility improvement from applying a polishing 

fabric filter can be calculated by subtracting Post-Control Scenario 2 results from Post-Control 

Scenario 1 results and summing across both Class I areas. The achieved 98th percentile visibility 

improvement was 0.266 Δdv from Unit 1 and 0.352 Δdv from Unit 2.

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

following conclusions:

1. While the Division considers the cost of compliance for a full-scale fabric filter on Unit 3 not 

reasonable, PacifiCorp is committed to installing this control device and has permitted the 

installation of a full-scale fabric filter on Unit 3 in a recently issued New Source Review 

construction permit. A full-scale 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, 

existing ESP with FGC on Units 1 and 2 and a new full-scale fabric filter on Unit 3 to meet corresponding 

emission limits on a continuous basis, to meet the statutory requirements of BART.

Unit-by-unit PM/PM10 BART determinations:

Naughton Unit 1: Installing FGC on the existing ESP and meeting PM/PM10 emission 

limits of 0.040 lb/MMBtu, 74 lb/hr, and 324 tpy as BART for PM/PM10.

Naughton Unit 2: Installing FGC on the existing ESP and meeting PM/PM10 emission 

limits of 0.040 lb/MMBtu, 96 lb/hr, and 421 tpy as BART for PM/PM10.

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

limits of 0.015 lb/MMBtu, 56 lb/hr, and 243 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 SO2 BART controls are installing 

wet FGD with FGC using the existing ESPs on Units 1 and 2, and upgrading the existing wet FGD using 

waste liquor and removing the existing ESP and installing a new full-scale fabric filter on Unit 3.

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).”
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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 37.

Table 37: 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 38 to underscore the 

improvements associated with SO2 reductions.
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Table 38: 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.
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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 

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 39. 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.
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Table 39: 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.

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

applications for Naughton Units 1-3 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 Naughton 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 Naughton Units 1-3.

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 Naughton Units 1-3.
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CHAPTER 6, SECTION 3 – OPERATING PERMIT:

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

Standards and Regulations. The most recent Operating Permit, 3-2-121, was issued for the facility on 

March 19, 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 Naughton 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 on Naughton Units 1 and 2, and install 

FGC in combination with the existing ESPs to meet the statutory requirements of BART. Before 

December 31, 2014, PacifiCorp shall tune the existing LNB and OFA on Naughton Unit 3 and install

SCR and a new full-scale fabric filter to meet the statutory requirements of BART.

PROPOSED PERMIT CONDITIONS:

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

Power Plant with the following conditions:

1. Authorized representatives of the Division of Air Quality be given permission to enter and inspect 

any property, premise or place on or at which an air pollution source is located or is being 

constructed or installed for the purpose of investigating actual or potential sources of air 

pollution, and for determining compliance or non-compliance with any rules, standards, permits 

or orders.

2. All substantive commitments and descriptions set forth in the application for this permit, unless 

superseded by a specific condition of this permit, are incorporated herein by this reference and are 

enforceable as conditions of this permit.

3. That PacifiCorp shall modify their Operating Permit in accordance with Chapter 6, Section 

9(e)(iv) and Chapter 6, Section 3 of the WAQSR.

4. All notifications, reports and correspondence associated with this permit shall be submitted to the 

Stationary Source Compliance Program Manager, Air Quality Division, 122 West 25th Street, 

Cheyenne, WY 82002 and a copy shall be submitted to the District Engineer, Air Quality 

Division, 510 Meadowview Drive, Lander, WY 82520.
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5. Effective upon completion of the performance tests to verify the emission levels below, as 

required by Condition 6 of this permit, emissions from Naughton Units 1 and 2 shall not exceed 

the levels below. The lb/hr and tpy limits shall apply during all operating periods. The 

lb/MMBtu limits shall apply during all operating periods, except startup. Startup begins with the 

introduction of natural gas into the boiler and ends no later than the point in time when the ESP 

reaches a temperature of 225 F.

Unit Pollutant lb/MMBtu lb/hr tpy

1 PM/PM10

(a) 0.040 74 324

2 PM/PM10

(a) 0.040 96 421

(a) Filterable portion only.

6. That no later than 90 days after the installation of new low NOx burners with advanced overfire 

air PM/PM10 performance tests shall be conducted and a written report of the results shall be 

submitted. If a maximum design rate is not achieved within 90 days of installing new low NOx

burners with advanced overfire air, the Administrator may require testing be done at the rate 

achieved and again when a maximum rate is achieved.

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

required by Condition 8 of this permit, emissions from Naughton Units 1-3 shall not exceed the 

levels below. The NOx limits shall apply during all operating periods. Unit 3 PM/PM10 lb/hr and 

tpy limits shall apply during all operating periods. Unit 3 PM/PM10 lb/MMBtu limit shall apply 

during all operating periods except startup. Startup begins with the introduction of natural gas 

into the boiler and ends when the boiler is switched over to coal as fuel.

Unit Pollutant lb/MMBtu lb/hr tpy

1 NOx 0.26 (30-day rolling) 481 (30-day rolling) 2,107

2 NOx 0.26 (30-day rolling) 624 (30-day rolling) 2,733

3 NOx 0.07 (30-day rolling) 259 (30-day rolling) 1,134

3 PM/PM10

(a) 0.015 (b) 56 (b) 243

(a) Filterable portion only.

(b) Upon installation of a PM continuous emissions monitoring system, the averaging period shall become a 24-hour 

block average.

8. 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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9. Performance tests shall consist of the following:

Coal-fired Boilers (Naughton Units 1 through 3):

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. If a PM CEMS is installed on Unit 3, PM CEMS monitoring 

data collected in accordance with 40 CFR part 60, subpart Da may be submitted to satisfy the 

testing required by this condition for Unit 3.

10. Prior to any testing required by this permit, a test protocol shall be submitted to the Division for 

approval, at least 30 days prior to testing. Notification should be provided to the Division at least 

15 days prior to any testing. Results of the tests shall be submitted to this office within 45 days of 

completing the tests.

11. PacifiCorp shall comply with all requirements of the Regional SO2 Milestone and Backstop 

Trading Program in accordance with Chapter 14, Sections 2 and 3, of the WAQSR.

12. Compliance with the NOx limits set forth in this permit for the coal-fired boilers (Naughton Units 

1-3) shall be determined with data from the continuous monitoring systems required by 40 CFR 

Part 75 as follows:

a. Exceedances of the NOx limits shall be defined as follows:

i. Any 30-day rolling average of NOx emissions which exceeds the lb/MMBtu 

limits calculated in accordance with the compliance provisions and monitoring 

requirements of §60.48Da and §60.49Da. The definition of “boiler operating 

day” shall be consistent with the definition as specified in 40 CFR part 60, 

subpart Da.

ii. Any 30-day rolling average calculated using valid data (output concentration and 

average hourly volumetric flowrate) from the existing CEM equipment which 

exceeds the lb/hr NOx limit established in this permit. Valid data shall meet the 

requirements of WAQSR, Chapter 5, Section 2(j) and follow the compliance 

provisions and monitoring requirements of §60.48Da and §60.49Da. The 30-day 

average emission rate shall be calculated as the arithmetic average of hourly 

emissions with valid data during the previous 30-day period. The definition of 

“boiler operating day” shall be consistent with the definition as specified in 40 

CFR part 60, subpart Da.
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b. PacifiCorp shall comply with all reporting and record keeping requirements as specified 

in WAQSR, Chapter 5, Section 2(g) and 40 CFR part 60, subpart D. All excess 

emissions shall be reported using the procedures and reporting format specified in 

WAQSR, Chapter 5, Section 2(g).

13. PacifiCorp shall use EPA‟s Clean Air Markets reporting program to convert the monitoring 

system data to annual emissions. PacifiCorp shall provide substituted data according to the 

missing data procedures of 40 CFR, Part 75 during any period of time that there is not monitoring 

data. All monitoring data must meet the requirements of WAQSR, Chapter 5, Section 2(j).

14. Compliance with the PM/PM10 limits set forth in this permit for Naughton Units 1-3 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. If a PM CEMS is installed on Unit 3, PM CEMS monitoring data 

collected in accordance with 40 CFR part 60, subpart Da may be submitted to satisfy the testing 

required by this condition for Unit 3.

15. Records required by this permit shall be maintained for a period of at least five (5) years and shall 

be made available to the Division upon request.

16. PacifiCorp shall install new low NOx burners with advanced overfire air on Units 1 and 2, in 

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

in Conditions 6 and 8 no later than December 31, 2012 and June 1, 2012, respectively.

17. PacifiCorp shall, for Units 1 and 2, install flue gas conditioning on the existing ESPs, in 

accordance with the Division‟s BART determination, within 90 days of permit issuance.

18. PacifiCorp shall tune the existing low NOx burners with overfire air and install selective catalytic 

reduction and a full-scale fabric filter on Unit 3, in accordance with the Division‟s BART 

determination, and conduct the initial performance tests required in Condition 8 no later than 

December 31, 2014.
Appendix A

Facility Location