DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION

BART Application Analysis

AP

- 604 0

May 2 8 , 200 9

NAME OF FIRM: PacifiCorp

NAME OF FACILITY: Jim Bridger Power Plant

FACILITY LOCATION: Section 3, T20N, R101W

UTM Zone: 12 Easting: 684,0 55 m, Northing: 4,622,745 m Sweetwater County, Wyoming

TYPE OF OPERATION: Coal

- Fired Electric Generating Plant

RESPONSIBLE OFFICIAL: Robert Arambel, Plant Managing Director

MAILING ADDRESS: P.O. Box 158 Point of Rocks, WY 82942

TELEPHONE NUMBER: ( 307) 352

- 4220

REVIEW ERS : Cole Anderson , Air Quality Engineer Josh Nall, Air Quality Modeler

PURPOSE OF APPLICATION:

Sections 169A and 169B of the 1990 Clean Air Act Amendments require states to improve visibility at Class I areas. On July 1, 1999, E PA 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 r educe emissions of three (3) visibility impairing pollutants, nitrogen oxides (NO

x ), particulate matter (PM), and sulfur dioxide (SO 2 ). EPA published Appendix Y to part 51

- Guidelines for BART Determinations Under the Regional Haze Rule in the July 6, 20 05 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 D ecember 5, 2006. The Wyoming Department of Environmental Quality, Air Quality Division (Division) will

determine BART for NO

x and PM 10 for each source subject to BART and include each determination in the §308 Wyoming Regional Haze State Implementation Pl an (SIP).PacifiCorp Jim Bridger Power Plant

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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 SO 2 emissions, which include a m arket t rading program and a provision for a series of SO 2

m ilestone s . 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 2 1 , 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 SO 2 emissions as part of the BART analysis even though the control strategy has been identified in the Wyoming § 309 Regional Haze SIP

.

On January 16 , 2007

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

, PacifiCorp submitted four (4) BART application s, one for each existing coal

- fired boiler at the Jim Bridger Power Plant. A map show ing the location of PacifiCorp‟s Jim Bridger Power Plant is attached as Appendix A.

October 16, 2007, PacifiCorp subm itted updated applications for each of the four (4) Jim Bridger units subject to BART

. Additional modeling performed after the January 16, 2007 submittal and revised visibility control effectiveness calculations w ere included.

December 5

, 2007, PacifiCor p submitted revised application s incorporating changes to the post

processing of the visibility model runs for each of the four (4) Jim Bridger units

.

March 31 , 2008

, PacifiCorp submitted addendum s to each of the BART application s for Jim Bridger

U nits 1

- 4. Revised cost estimates and updated visibility modeling for two (2) NO

x control scenarios were included in the addendums.

February 2, 2009, PacifiCorp submitted addition al information addressing presumptive BART emission rates for the four (4) coal

- fir ed boilers at the Jim Bridger Power Plant. The information addresses the type of coal fired in the four boilers and its impact on NO

x 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 ton s 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.PacifiCorp Jim Bridger Power Plant

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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, Ap pendix Y as visibility impairing pollutants. They are sulfur dioxide (SO 2 )

, nitrogen oxides (NO

x ), and particulate matter (PM). Particulate matter with an aerodynamic diameter of 10 microns or less (PM 10 ) was used as an indicator of PM. In order to dete rmine visibility impairment of each source, a screening analysis was performed using CALPUFF. Sources that

emitted over 40 tons of SO 2 or NO

x or 15 tons of PM 10 were included in the screening analysis. Using three years of meteorological data, the screen ing analysis calculated visibility impacts from sources at nearby Class I areas. Sources whose modeled 98 th percentile 24

- hour impact or 8 th highest modeled impact, by year, was equal to or greater than 0.5 deciviews (dv) above natural background conditio ns (Δdv) were determined to be subject to BART. For additional information on the Division‟s screening analysis see the Visibility Improvement Determination: Screening Modeling section of this analysis

. The

four existing coal

- fired boiler s at PacifiCorp‟ s Jim Bridger Power Plant w ere determined to be subject to BART. PacifiCorp was notified in a letter dated June 14, 2006 of the Division‟s finding.

DESCRIPTION OF BART ELIGIBLE SOURCES:

PacifiCorp‟s Jim Bridger Power Plant is comprised of four (4) ident ically sized nominal 530 M ega W atts (MW) tangentially fired boilers burning pulverized coal for a tota l net generating capacity of 2, 120 MW. Jim Bridger Unit 1 was placed in service in 1974

. Unit 2 commenced service in 1975. Unit 3 entered

service in 19 76 followed by Unit 4, which commenced serv ice in 1979. Each unit was initially equipped

with early generation low NO

x burners (LNB) manufactured by Combustion Engineering to control emission of nitrogen oxides ( NO

x )

. The y are also equipped with dry Flak t wire frame electrostatic precipitator s (ESP s ) to control particulate matter emissions (PM), for which particulate matter less than 10 microns ( PM 10 ) is used as a surrogate. Finally, to control sulfur dioxide ( SO 2 ) emissions, each unit is equipped with a three absorber tower wet sodium flue gas desulfurization ( W FGD) system made by

Babcock & Wilcox

.

Table 1: Jim Bridger Units 1

- 4 Pre

- 2005 Emission Limits

Source Firing Rate

(MMBtu/hour) Existing

Controls NO

x

(lb/MMBtu) (a) SO 2

(lb/MMBtu) (a) PM/PM 10 (lb /MMBtu) (a)

Unit 1 6,000 LNB , ESP,

WFGD 0.7 0 ( 3

- hour block )

0.42 ( an nual) 0.3 (2

- hour block ) 0. 10 (2

- hour block )

Unit 2 6,000 LNB , ESP,

WFGD 0.7 0 ( 3

- hour block )

0.40 ( annual) 0.3 (2

- hour block) 0. 10 (2

- hour block )

Unit 3 6,000 LNB , ESP,

WFGD 0. 7 0 ( 3

- hour block )

0.41 (annual) 0.3 (2

- hour block) 0. 10 (2

- hour block )

Unit 4 6,000 LNB , ESP,

WFGD 0.7 0 ( 3

- hour block )

0.45 (annual) 3,514 lb/hr 0.2 (2

- hour block)

1,004 lb/hr (2

- hour block) 0. 10 (2

- hour block )

502 lb/hr (2

- hour block)

(a) Emiss ions taken from Operating Permit 3

- 1

- 120 which does not include the most recent New Source Review construction
permit limits

.PacifiCorp Jim Bridger Power Plant

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On April 1, 2005, Air Quality Permit MD

- 1138 was issued to PacifiCorp to replac e the first generation

low NO

x burners (LNB) on Jim Bridger Unit 2 with a new ALSTOM TFS 2000 TM low NO

x firing system including two elevations of separated overfire air (OFA)

. The Division received written notification from PacifiCorp on June 13, 2005 that the new LNB were installed and placed into service May 29, 2005. The permitted NO

x emission limit of 0.26 lb/MMBtu, annual average, authorized in MD

- 1138 for Jim Bridger

Unit 2 went into effect in 2005.

On October 6, 2006, a fter the LNB modification to Unit 2 was completed , PacifiCorp submitted a construction permit application to modify Jim Bridger Units 1, 2, 3 and 4 by replacing the existing first generation low NO

x burners on Units 1, 3 and 4 with Alstom TFS 2000 TM LNB with two elevations of separated overfire air , install a flue gas condition ing (FGC) system which injects SO 3 gas into the flue gas to improve the efficiency of the electrostatic precipitator on Units 1

- 4

, and upgrade the existing flue gas

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

- 1552 was issued April 9, 2007 authorizing the new LNB , FGC, and W FGD modifications to the Jim Bridger Power Plant

. PacifiCorp notified t he Division that the LNB upgrades to Unit 3 were completed and the unit started up May 30, 2007. June 18, 2008, the Division received notification from PacifiCorp that the new low NO

x burners on Unit 4 were installed during a recent ten week outage and the unit s tarted up June 8, 2008. Modifications to the scrubber vessels on Unit 4 were

n ot necessary in order to meet the SO 2 emission limits permitted in MD

- 1552. Unit 4 can meet the limits by reducing the amount of flue gas bypassing the scrubber. However, this would increase the moisture content of the gas entering the exhaust stack and modifications to the stack drain system were required to

accommodate the increased moisture. Current emission limits for Jim Bridger Units 1

- 4 are listed in

Table 2 below.

Table 2: Jim Bridger Units 1

- 4 Current Emission Limits (a)

Source Controls NO

x S O 2 PM/PM 10 (b)

Unit 1 Existing LNB,

ESP with FGC

, WFGD 0. 45 lb/MMBtu

( 12

- month rolling ) 0.3 lb/MMBtu (2

- hour block )

1,600 lb/hr ( 24

- hr rolling ) 0.03 lb/MMBtu

180 lb/hr

Unit 2 New LNB with

OFA , ESP with

FGC

, WFGD 0 .26 lb/MMBtu

( 12

- month rolling ) 0.3 lb /MMBtu (2

- hour block )

1,600 lb/hr (24

- hr rolling) 0.03 lb/MMBtu

180 lb/hr

Unit 3 New LNB with

OFA , ESP with

FGC

, WFGD 0.26 lb/MMBtu

( 12

- month rolling ) 0.3 lb/MMBtu (2

- hour block )

1,600 lb/hr (24

- hr rolling) 0.03 lb/MMBtu

180 lb/hr

Unit 4 New LNB with

OFA , ESP with

FGC

, WFGD 0.26 lb/MMBtu

( 12

- month rolling ) 0.2 lb/MMBtu (2

- hour block )

0. 15 lb/MMBtu ( 1 2

- month rolling ) 1,00 4 lb/hr ( 2

- hr block )

900 lb/hr (24

- hr rolling) 0.03 lb/MMBtu

180 lb/hr

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

- 1552.

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

- 5

.

PacifiCorp is currently evaluating the upgrade d stack drain system on the Unit 4 exhaust stack . Upon completion of a wet scrubber upgrade s pe rmitted in MD

- 1552, the SO 2 limits for the corresponding u nit

become s 0.15 lb/MMBtu on a 12

- month rolling average and 900 lb/hr on a 24

- hr rolling average

. A

construction schedule for the LNB and WFGD upgrades was submitted in the permit application for M D

1552. PacifiCorp provided an update on the proposed construction schedule in a letter received on September 17, 2008. A construction summary is provided in Table 3.PacifiCorp Jim Bridger Power Plant

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Table 3 : MD

- 1552 Permitted Upgrades to Jim Bridger Units 1

- 4

Source New Low NO

x Burner s with

Separate Overfire Air (status, year) Upgrades to the Existing Wet Scrubber (status, year)

Unit 1 Planned, 2010 Planned, 2010

Unit 2 Completed, 2005 Planned, 2009

Unit 3 Completed, 2007 Planned, 2011

Unit 4 Completed, 2008 Completed, 2008

CH APTER 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 “...establish ed, on a case

- by

case 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 t he 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

metho dology 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 all 2 available retrofit control technologies Step 2: Eliminate technically infeasible options Step 3: Evaluate control effectiveness of remaining control technologies Step 4: Evaluate impacts and document the results Step 5: Evaluate visibility impacts

The Division acknowledges that BART is intended to identify retrofit technology for existing sources and is not the same as a top down analysis required for new sources under the Prevention of Significant Deterioration (PSD) rules known as Best Available Control Technology (BACT). Although BART is not the same as BACT, it is possible that BART m ay be equivalent to BACT on a case

- by

- case basis. The Division applied all five steps to each visibility impairing pollutant emitted from each coal

- fired boiler (Units 1

- 4) at the Jim Bridger Power Plant thereby conducting a comprehensive BART analysis fo r NO

x , SO 2 and PM/PM 10

.

1 40 CFR Part 51 Appendix Y: Guidelines for BART Determinations under the Regional Haze Rule (70 Feder al 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.”PacifiCorp Jim Bridger Power Plant

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PRESUMPTIVE LIMITS FOR SO 2 AND NO X FROM UTILITY BOILERS

EPA conducted detailed analyses of available retrofit technology to control NO

x and SO 2 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 SO 2 limits analysis considered coal

- fired units with existing SO 2 controls and

un its 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 SO 2 cont rol 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

un its were identified and included in the presumptive BART analysis for SO 2 . 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 calcul ated projected SO 2 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 SO 2 control can meet the presumptive limits at a cost of $400 to $2,000 per ton of SO 2 removed.

A presumptive BART NO

x limits analysis was performed using the same 491 BART

- eligible coal

- fired

units identified in the SO 2 presumptive BART analysis. EPA considered the same four key elements and established presumptive NO

x 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 NO

x burners and overfire air). Presumptive NO

x limit s 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

r otating o pposed f

ire a ir. National average cost effectiveness values for presumptive NO

x limits ranged from $281 to $1,296 per ton removed.

Based on th e results of the analyses for presumptive NO

x and SO 2 limits, EPA established presumptive limits for EGUs greater than 200 MW operating without NO

x post combustion controls or existing SO 2 controls located at facilities with a generating capacity greater t han 750 MW. 40 CFR part 51 Appendix Y states that the presumptive SO 2 level for an uncontrolled unit is either 95% control or 0.15 lb/MMBtu. Presumptive NO

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

boiler bu rner configuration (unit type) and coal type. NO

x emission values range from 0.62 lb/MMBtu down to 0.15 lb/MMBtu. While Appendix Y establishes presumptive SO 2 limits and says that states should require presumptive NO

x , it also clearly gives states discre tion 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 analys i s for NO

x , SO 2 , and PM/PM 10 take s into account each of the five statutory factors.

3 40 CFR Part 51 Appendix Y: Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 39133).

4 Ibid. (70 Federal Register 39171).PacifiCorp Jim Bridger Power Plant

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PacifiCorp‟s Jim Bridger Power Plant consists of four units with a total generating capacity of 2,120 MW. Jim Bridger Units 1

- 4 are identical nominal 530 MW unit s with tangentially fired pulverized coal boiler s

. SO 2 emissions from all units are contro lled with existing Babcock & Wilcox three absorber tower wet sodium flue gas desulfurization system s that were installed in 1982, 1986, 1988, and 1990 on Units 4, 2, 3, and 1, respectively. NO

x emissions from Units 1

- 4 were initially controlled using firs t generations low

NO

x burners. In 2005, the existing low NO

x burners were replaced with Alstom TFS 2000 TM low NO

x firing system including two elevations of separated overfire air (OFA) on Unit 2. Subsequent to PacifiCorp‟s filing of the Jim Bridger BART applications for all four units, Air Quality Permit MD

- 1552

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

low NO

x firing system s. As of the date of this analysis, two additional new LNB systems are ins talled on

Units 3 a nd 4. The final Jim Bridger LNB upgrade is planned for 2010 on Unit 1 , as shown in Table 3. Presumptive SO 2 limits of 95% reduction or 0.15 lb/MMBtu and presumptive NO

x limits based on unit type and coal type, could apply to all four J im Bridger units . However, the Division required additional analysis of potential retrofit controls for N O

x , SO 2 , and PM/PM 10 , taking into consideration all five statutory factors, before making a BART determination.

NO

x emissions from coal combustion ar e 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 com bustion controls

such as LNB and OFA systems. This is evidenced by EPA‟s decision to classify presumptive NO

x emission levels based on specific controls as applied to differen t boiler types firing various types of coal. In EPA‟s analysis for establishing presumptive NO

x 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 E missions

Information Collection Effort

, OMB Control Number 2060

- 0396

. In responding to the ICR PacifiCorp reported that Jim Bridger Units 1

- 4 burne d sub

- bituminous coal. Subsequent to the ICR PacifiCorp

further evaluated the coal classification using AS TM method D 388

- 05 Standard Classification of Coals by Rank , an industrial standard for classifying coal. After reviewing method D 388 coal classification s, PacifiCorp noted that high volatile C bituminous coal and sub

- bituminous A coal s have similar he ating values, but differen t agglomeration character istics . Table 3 from ASTM method D 388

- 05 Standard Classification of Coals by Rank is shown as Figure 1.PacifiCorp Jim Bridger Power Plant

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Figure 1

PacifiCorp contracted with CH2M Hill and ALSTOM , a boiler manufactur er, to further research the impact of coal characteristics on NO

x emissions. Laboratory t ests

, including tests using a bench

- scale

d rop t ube f

urnace run by ALSTOM

, showed the influence of both fuel type and stoichiometry on NO

x emissions. Additional test ing examined the impact of coal volatility on NO

x 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 nitrog en released during the devolatilization phase of combustion, and thus will produce have [ sic ] somewhat higher NO

x than will

true PRB coals when fired under low

- NO

x staged conditions. ”PacifiCorp Jim Bridger Power Plant

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PacifiCorp also examined how fuel

- bound NO

x evolves from solid c oal char after the volatile component

of the coal is combusted. After reviewing laboratory test data on NO

x conversion from fuel

- bound nitrogen during volatilization and during char combustion, PacifiCorp concluded: “ Typically, lower rank (more reactive) fuels have more fuel NO

x associated with the volatiles than the char, so low

- rank coals

overall have the lowest NO

x 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 NO

x reduction potential below eastern bituminous coa ls, but not as low as true PRB coals. ”

Co al characteristics affect the design and efficiency of pollution control equipment, as well as boiler design. Based on the information presented by PacifiCorp, it is likely that the Jim Bridger units will not

be a ble to achieve presumptive NO

x levels of 0.15 lb/MMBtu for tangential boilers firing sub

- bituminous

coal. As mentioned earlier, Air Quality Permit MD

- 1552 authorized the installation of new ALSTOM

T F S 2000 TM LNB and separated OFA systems

. Jim Bridger Uni t s 2

- 4 are currently equipped with th is combustion control system. Fourth quarter 2008 continuous emissions monitor (CEM) values for NO

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

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

Jim Bridger

Source Q4 2008 NO

x Emissions

(lb/MMBtu, 12

- month rolling average) August September October November December

Unit 2 0.23 0.23 0.23 0.22 0.22

Unit 3 0.20 0.20 0.20 0.20 0.20

Unit 4 0.26 0.25 0.23 0.22 0.21

The Division re quired additional analysis of potential retrofit controls for NO

x , which included add

- on controls in addition to combustion control , taking into consideration all five statutory factors, before making a BART determination. W hile the Division noted the app licable presumptive NO

x levels for the Jim Bridger units, the effectiveness of the proposed combustion co ntrol for removing NO

x was evaluated

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

contro l technologies, and Step 4: Evaluate impacts and document the results of the BA RT process.

NO

x : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

PacifiCorp identified four control technologies to control NO

x emissions: (1) low NO

x burners with two

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

non

- catalytic reduction (SNCR), and (4) selective catalytic reduction (SCR). LNB with separated OFA and ROFA are two combustion control technologies that reduce NO

x emissions by controlling the combustion process within the boiler. These two technologies have been demonstrated to effectively

control NO

x emissions by reducing the amount of oxygen directly accessible to the fuel during combustion creating a fuel

- r ich environment and by enhancing control of air

- fuel mixing throughout the

boiler‟s combustion zone. SNCR and SCR are add

- on controls that provide a chemical conversion

mechanism for NO

x to form molecular nitrogen (N 2 ) in the flue gas after combustion occ urs. These four technologies are proven emissions controls commonly used on coal

- fired electric generating units.PacifiCorp Jim Bridger Power Plant

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1. Low NO

x Burners with Separated Overfire Air

– LNB technologies can rely on a combination of fuel staging and combustion air control to supp ress the formation of thermal NO

x . 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 oxyg en available to the fuel during combustion creating a fuel rich zone that reduces the nitrogen to molecular nitrogen (N 2 ) rather than using oxygen in the combustion air to oxidize the nitrogen to NO

x . The addition of separated overfire air provides additi onal NO

x control by injecting air into the lower temperature combustion zone when NO

x is less likely to form. This allows complete combustion of the fuel while reducing both thermal and chemical NO

x formation.

2. Rotating Opposed Fire Air

– ROFA can be used with LNB technology to control the combustion process inside the boiler. Similar to the separated overfire air technology discussed above, ROFA manipulates the flow of combustion air to enhance fuel

- mixing and air

- flow characteristics within

the boiler. By inducing rotation of the combustion air within the boiler, ROFA can reduce the number of high temperature combustion zones in the boiler and increase the effective heat absorption. Both of which effectively reduce the formation of NO

x caused by fuel c ombustion

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 NO

x 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. S elective 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. NO

x entrained in the flue gas is reduced to molecular nitrogen (N 2 ) 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 in

jected 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 add ition to applying these control technologies separately, they can be combined to increase overall

NO

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

both SNCR and SCR add

- on controls.

NO

x : ELIMINATE TECHNICA LLY INFEASIBLE OPTIONS

None of the four control technologies proposed to control NO

x emissions were deemed technically infeasible by PacifiCorp.PacifiCorp Jim Bridger Power Plant

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NO

x : EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

The Division considers the control effective ness 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

pract ices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit it is important to consider that even well maintained and operated equipment will have some emissions variability. Complex emission control equipment, such as LNB with separated OFA , generally have inherent variability that must be considered when establishing the limit. Otherwise, the source will be out of compliance even though the equipment is operated and maintained as well as possible

.

PacifiCorp cont

racted with Sargent and Lundy ( S&L ) to conduct a s tudy of applicable NO

x control technologies for the Jim Bridger u nits and to collect data from boiler vendors . Based on results from the study, PacifiCorp i ndicates that new LNB with separated OFA on the J im Bridger u nits would result in a

NO

x emission rate as low as 0.24 lb / MMBtu. On p age s 3

- 9 of the December 2007 submit t al s for Jim Bridger Units 1 and 3 and on pages 3

- 10 of the December 2007 submittals for Jim Bridger Units 2 and 4 PacifiCorp states: “Pa cifiCorp has indicated that this rate [0.24 lb/MMBtu] corresponds to a vendor guarantee, not a vendor prediction, and they believe that this emission rate can be sustained as an average

between overhauls.” However

, due to unforeseen operational issues ass ociated with retrofitting the boilers, including site specific challenges

, PacifiCorp proposes an additional NO

x increase of 0.02

lb/MMBtu to total 0.26 lb/MMBtu.

PacifiCorp worked with Mobotec to conduct an analysis of retrofitting the existing boiler s a t the Jim Bridger Power Plant with Mobotec‟s ROFA. Mobotec analyzed the operation of existing LNB and OFA

ports

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

not used by a new ROFA system. Instead, compu tational fluid modeling is performed to determine the location of the new ROFA ports. Mobotec concluded that a NO

x emission rate of 0.18 lb / MMBtu was achievable using ROFA technology. PacifiCorp added an additional operating margin of 0.04 lb/M MBtu

to ac count for site specific issues, including the typ e of coal burned in the boilers

, to total 0.22 lb/MMBtu.

S&L evaluate d emission reductions associated with installing SNCR in addition to retrofit ting the boilers

with LNB with OFA. Based on installing LNB with separated OFA capable of achieving a NO

x emission rate of 0.24 lb/MMBtu, S&L concluded that SNCR can reduce emissions another 15 % resulting in a projected emission rate of 0.20 lb/MMBtu. PacifiCorp noted in the analysis that the economics of SNCR

a re greatly impacted by reagent utilization. When SNCR is used to achieve high levels of NO

x reduction, lower reagent utilization can result in significantly higher operating cost.

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

u nits. 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

. T he

flue gas ducts would be routed to a separate large reactor containing the catalyst to increase the removal rate. Additional catalyst would be added to accommodate the coal feedstock. Based on the S&L design

, which included installing both LNB with separated OFA and SCR

, PacifiCorp con cluded the Jim Bridger

u nits could achieve a NO

x emission rate of 0.07 lb / MMBtu.PacifiCorp Jim Bridger Power Plant

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Table 5 : NO

x Emission Rates Per Boiler

Control Technology Resulting NO

x Emission Rate (lb/MMBtu)

Existing LNB 0.45 (a)

New LNB with separated OFA 0. 26 (b)

Existing LNB with R OFA 0.22

New LNB with separated OFA and SNCR 0. 20

New LNB with separated OFA and SCR 0. 07

( a) Annual averaged NO

x emissions established through 40 CFR part 7 6 which vary among the four Jim Bridger units from 0.40

- 0.45 lb/MMBtu

. (b) Jim Bridger Un it s 2

- 4 ha ve installed n ew LNB with separated OFA and are subject to a new NO

x emission limit of 0.26 lb/MMBtu , annual average

, established in MD

- 1552

.

NO

x : EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the e nergy i mpacts associated with ins talling each of the proposed control technologies

. Replacing the existing LNB with new LNB including separated OFA will not significantly impact the boiler efficiency o r forced draft fan power usage, two common potential areas for adverse energy impact of

ten affected by changes in boiler combustion. Installing the Mobotec ROFA system has the highest energy impact on Jim Bridger. T wo (2) 4,000 to 4,300 horsepower ROFA fans (6,410 kilo

W atts [kW] total) are required to induct a sufficient volume of air int o each boiler to cause rotation of the combustion air throughout the boiler

. PacifiCorp determined the SNCR system would require approximately 530 kW of additional power to operate p retreatment and injection equipment, pumps, compressors, and control syst ems. In addition to energy costs associated with the reagent handling and injection, installation of the SCR catalyst will require additional power from the existing flue gas fan

systems to overcome the pressure drop across the catalyst

. Based on the S&L study, PacifiCorp estimated

the additional power requirements for SCR installation on each unit at the Jim Bridger Power Plant ranged from approximately 3.22 MW to 3.3 6 MW.

PacifiCorp evaluated the environmental impacts of the proposed NO

x control techno logies. Installing

LNB with separated OFA may increase carbon monoxide (CO) emissions and unburned carbon in the ash, commonly referred to as loss on ignition (LOI). Mobotec has predicted CO emissions and LOI would be the same or lower than prior levels for the ROFA system. The installation of SNCR and SCR could impact the saleability and disposal of fly ash due to higher ammonia levels, and could potentially create a visible stack plume sometimes referred to as a blue plume, if the ammonia injection rat e 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 Jim Bridger Power Plant

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PacifiCorp anticipates operating Jim Bridger Units 1

- 4 indefinit ely 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% inter est 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 a pplication 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 compar ing emission controls under the BACT process. While the BART and the BACT process es are not necessarily equivalent, control determinations from either process are based on cost effectiveness

and incremental cost effectiveness and are indicative of the eco nomic 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 t he presumptive BART l imits analyses

for NO

x and SO 2 , 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 improvem ents 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 vi sibility 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 effe ctiveness in the evaluation of each proposed NO

x emission control. Economic and

environmental costs for additional NO

x controls on Unit s 1

- 4 are summarized in the following tables.

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

Cost Exis ting

LNB New LNB with

separated OFA Existing LNB

with ROFA New LNB with

separated OFA

and SNCR New LNB with

separated OFA

and SCR

Control Equipment Capital Cost $0 $ 11

, 300 ,0 00 $ 20,528,122 $ 22,127,239 $177,800,000

Capital Recovery Factor N/A 0. 09513 0. 095 1 3 0. 0951 3 0.09513

Annual Capital Recovery Costs $0 $1,074,969 $ 1,952

, 840 $ 2

, 104

, 964 $16,914,114

Annual O&M Costs $0 $ 70

, 000 $ 2,633,012 $ 605,837 $3,382,286

Annual Cost of Control $0 $ 1,144,969 $ 4

, 585 ,85 2 $ 2

, 710

, 8 01 $20,296,400PacifiCorp Jim Bridger Power Plant

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- 6040 BART Applic ation Analysis Page 14

Table 7 : Jim Bridger Units 1, 3, & 4 Environmental Costs Per Boiler

Existing

LNB New LNB with

separated OFA Existing LNB

with ROFA New LNB with

separated OFA

and SNCR New LNB with

separated OFA

and SCR

NO

x Emission Rate (lb/MMBtu) 0. 45 (a) 0. 26 0.2 2 0. 20 0.07

Annual NO

x E mission (tpy) ( b ) 10,643 6,150 5,203 4,730 1,656

Annual NO

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

Annual Cost of Control $0 $ 1,144,969 $ 4

, 585 ,85 2 $ 2

, 710,801 $20,296,400

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

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

, 721

(a) Annual averaged emissions established by 40 CFR Part 76 vary from 0.40

- 0.45 lb/MMBtu and using 0.45 lb/MMBtu is conservative.

( b ) Annual emissions based on individual heat input rate of 6,000 MMBtu/hr for 7

, 884 hours of operation per year.

( c ) Incremental cost from instal ling new LNB with separated OFA since the incremental cost using existing LNB with ROFA is negative as a result of the higher annual cost of control.

Table 8 : Jim Bridger Unit 2 Economic Costs

Cost Existing L NB with separated OFA Existing LNB

with ROFA Existing LNB

with separated

OFA and SNCR Existing LNB

with separated

OFA and SCR

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

Capital Recovery Factor N/A 0. 09513 0. 09513 0.09513

Annual Capital Recovery Costs $0 $1,952, 840 $1,277,3 33 $15,83 9

, 145

Annual O&M Costs $0 $ 2,63 1

, 822 $ 605,837 $3,3 70

, 460

Annual Cost of Control $0 $4,584,6 62 $1,883,1 70 $19,209, 605PacifiCorp Jim Bridger Power Plant

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- 6040 BART Applic ation Analysis Page 15

Table 9 : Jim Bridger Unit 2 Environment al Costs

Existing LNB with separated OFA Existing LNB

with ROFA Existing LNB

with separated

OFA and SNCR Existing LNB

with separated

OFA and SCR

NO

x Emission Rate (lb/MMBtu) 0. 26 0.2 2 0. 20 0.07

Annual NO

x Emission (tpy) (a) 6,150 5,203 4,730 1,656

Ann ual NO

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

Annual Cost of Control $ 0 $4,584,6 62 $1,883,1 70 $19,209, 605

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

Incremental Cost per ton of Reduction N/A $ 4,841 $ 1,326 ( b ) $ 5

, 636

(a) Annual emissions based on individual heat input rate of 6,000 MMBtu/hr for 7

, 884 hours of operation per year.

( b ) Incremental cost from existing LNB with separated OFA since the incremental cost using existing LNB with ROFA is negative as a result of the higher annual cost of cont rol

.

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

NO

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

company

- proposed BART controls by modeling LNB w ith separated OFA and LNB with separated OFA

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

evaluated in Step 5: Evaluate visibility impact , t he anticipated degree of visibility improvement from applying either c ontrol lies within the modeled range of visibility impacts

.

The final step in the NO

x BART determination process for Jim Bridger Units 1

- 4 , Step 5: Evaluate visibility impacts, is addressed in a comprehensive visibility analysis covering all three visibil ity impairing pollutants

. The visibility analysis follows Steps 1

- 4 for SO 2 emissions in this application analysis

. Tables 27

- 30, on pages 36

- 39, list the modeled control scenarios and associated emission r ate s.

PM 10 : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Jim Bridger Units 1

- 4 are currently equipped with electrostatic precipitator s to control PM emissions

from the boiler s . As discussed in more detail below, ESPs control PM/PM 10 from the flue gas stream by creating a strong electro

- magnetic f ield in which fly ash particles gain electric charge. PacifiCorp states

the existing ESP s are able to control PM/PM 10 emissions to 0.0 45 lb/MMBtu , 0.074 lb/MMBtu, 0.057 lb/MMBtu, and 0.030 lb/MMBtu from Units 1, 2, 3, and 4, respectively. T hree PM contro l technologies were analyzed for application on the four Jim Bridger units : fabric filters or baghouses, ESPs, and flue gas conditioning.PacifiCorp Jim Bridger Power Plant

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- 6040 BART Applic ation Analysis Page 16

1. Fabric filters (FF)

– FF are woven pieces of material that collect particles with sizes ranging from

submicro n 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 cak e 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 colle ction 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 ho pper for disposal. Wet ESPs use water to wash the particles from the collector plates into a sump. The efficiency of an ESP is primarily determined by the resistivity of the particle, which is dependent on chemical composition, and also by the ability to clean the collector plates without reintroducing the particles back into the flue gas stream.

3. Flue Gas Conditioning (FGC)

– Injecting a conditioning medium, typically SO 3 , into the flue gas can lower the resistivity of the fly ash, improving the particle s‟ 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.

PM 10 : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

PacifiCorp did not eliminate any of the three control technolog ies listed above as technically infeasible. PacifiCorp analyzed the impact of installing FGC using the existing ESPs and installing a polishing fabric filter downstream of the existing ESPs on Jim Bridger Units 1

- 4

.

PM 10 : EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

The Division considers the co ntrol 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 pollutio n control practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit it is important to consider that even well maintained and operated equipment will have some emissions variability. Complex emission control equipment, such as dry electrostatic precipitators, generally have inherent variability that must be considered when establishing the limit. Otherwise, the source will be out of compliance even though the equipment is operated and maintained as well as po ssible.PacifiCorp Jim Bridger Power Plant

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- 6040 BART Applic ation Analysis Page 17

Jim Bridger Units 1

- 4 ha ve existing ESP s and rather than evaluate costs of replacing the m , PacifiCorp evaluated additional controls to improve the PM 10 removal efficiency. An ESP is an effective PM control device, as the existing unit s are alr eady capable of controlling PM 10 emissions to 0.0 45 lb/MMBtu , 0. 0 74 lb/MMBtu, 0.057 lb/MMBtu, and 0.030 lb/MMBtu for Units 1, 2, 3, and 4, respectively . The technology continually improves and is commonly proposed for consideration in BACT analyse s to con trol particulate emissions from new PC boiler s . Rather than demolishing the existing ESP and constructing an entirely new PM control device, PacifiCorp recognized the cost benefit of keeping the existing unit and augmenting the control. Installing FGC on Units 1

- 4 can improve the PM removal efficiencies on the existing ESPs down to 0.030 lb/MMBtu. In addition to maintaining the existing ESP s , a polishing fabric

filter can be installed downstream of the existing ESP s . PacifiCorp proposed the use of Compa ct 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 t o 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/PM 10 emissions. PacifiCorp estimates the application of the

COHPAC unit in addition to using FGC with the existing ESPs can reduce emissions an additional 50% resulting in a PM 10 emission rate of 0.015 lb/MMBtu. PacifiCorp‟s proposed emission rates for each technology as applied to Unit s 1

- 4 are shown in Table 10 below.

Table 10 : PM 10 Emission Rates Per Boiler

Control Technology Resulting PM 10 Emission Rate (lb/MMBtu)

Existing ESPs 0.030

- 0. 074 (a)

Existing ESPs with FGC 0. 030

E xisting ESP and New Polishing Fabric Filter 0.015

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

- 4

.

PM 10 : EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy im pact of installing COHPAC on each of the four units . The pressure drop created by the fabric filter and associated ductwork requires additional energy from the existing draft fan, which will have to be upgraded. PacifiCorp calculated the additional energ y costs based on a 90 percent annual plant capacity factor. The installation of a COHPAC fabric filter would require approximately 3.4 MW of power, equating to an annual power usage of approximate ly 26.7 million kW

h r for Unit 1. Installing a COHPAC on U nit 2 would require approximately 3.4 MW of power, equating to an annual power usage of approximately 26.5 million kW

- h r . Unit 3 would require approximately 3.3 MW of power, equating to an annual power usage of approximately 26.3 million kW

- hr and Unit 4 would require approximately 3.4 MW of power, equating to an annual power usage of approximately 26.7

million kW

- hr.

Installing FGC on each of the four units will require a minimal amount of additional power. PacifiCorp estimates that FGC will require an additional 50 kW per unit.PacifiCorp Jim Bridger Power Plant

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- 6040 BART Applic ation Analysis Page 18

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

COHPAC on Units 1

- 4 and did not anticipate negative environmental impacts from the addition of either

of these PM control tech nologies.

PacifiCorp anticipates operating Jim Bridger Units 1

- 4 indefinitely and did not include life extension costs in the economic analysis. A standard control life of 20 years was used to calculate the capital recovery factor. The annual cost to co ntrol 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 menti oned: 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. Incremen tal cost effectiveness is also used extensively by the Division when comparing emission controls under the BACT process. While the BART and the BACT process es are not necessarily equivalent, control determinations from either process are based on cost eff ectiveness

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 a pplying 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 t he overall effectiveness of pollution control equipment. When performing the presumptive BART limit s analyses

for NO

x and SO 2 , EPA addressed cost effectiveness and incremental cost effectiveness separate from visibility improvement. The dollars per deciv iew 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

vis ibility 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, an nual cost, cost effectiveness

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

costs for additional PM control on Jim Bridger Units 1

- 4 are summarized in the following tables.

Table 1 1 : Jim Bridger Unit s 1 Economic Costs

Cost Existing

ESP Existing ESP With

Flue Gas Conditioning Existing ESP With

New Polishing Fabric Filter

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

Capital Recovery Factor N/A 0.09513 0.09513

Annual C apital Recovery Costs $0 $ 371,007 $4,602,992

Annual O&M Costs $0 $1 75

, 564 $1,764,126

Annual Cost of Control $0 $ 546

, 571 $6,367,118PacifiCorp Jim Bridger Power Plant

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- 6040 BART Applic ation Analysis Page 19

Table 1 2 : Jim Bridger Unit 1 Environmental Costs Existing

ESP Existing ESP With

Flue Gas Conditioning Existing ESP Wi th

New Polishing Fabric Filter

PM 10 Emission Rate (lb/MMBtu) 0.0 45 0.0 30 0.015

Annual PM 10 Emission (tpy) (a) 1,064 710 3 55

Annual PM 10 Reduction (tpy) N/A 354 709

Annual Cost of Control $0 $ 546

, 571 $6,367,118

Cost per ton of Reduction N/A $1

, 5 44 $ 8, 980 Incremental Cost per ton of

Reduction N/A $1, 544 $1 6

, 396

(a) Annual emissions based on unit heat input rate of 6

, 0 00 MMBtu/hr and 7,884 hours of operation per year.

Table 1 3 : Jim Bridger Unit 2 Economic Costs

Cost Existing

ESP Existing ESP With

F lue Gas Conditioning Existing ESP With

New Polishing Fabric Filter

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

Capital Recovery Factor N/A 0.09513 0.09513

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

Annual O&M Costs $0 $175,564 $ 1,7 5 4, 666

Annual Cost of Control $0 $546,571 $6,3 57

, 658

Table 1 4 : Jim Bridger Unit 2 Environmental Costs Existing

ESP Existing ESP With

Flue Gas Conditioning Existing ESP With

New Polishing Fabric Filter

PM 10 Emission Rate (lb/MMBtu) 0.0 74 0.030 0. 015

Annual PM 10 Emission (tpy) (a) 1, 750 710 355

Annual PM 10 Reduction (tpy) N/A 1,040 1,3 95

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

Cost per ton of Reduction N/A $5 26 $4, 557 Incremental Cost per ton of

Reduction N/A $526 $1 6

, 369

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

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- 6040 BART Applic ation Analysis Page 20

Table 1 5 : Jim Bridger Unit 3 Economic Costs

Cost Existing

ESP Existing ESP With

Flue Gas Conditioning Existing ESP With

New Polishing Fabric Filter

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

Capital Recovery Factor N/A 0.09513 0.09513

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

Annual O&M Costs $0 $175,564 $1,7 34

, 442

Annual Cost of Control $0 $546,571 $6,3 3 7, 434

Table 1 6 : Jim B ridger Unit 3 Environmental Costs Existing

ESP Existing ESP With

Flue Gas Conditioning Existing ESP With

New Polishing Fabric Filter

PM 10 Emission Rate (lb/MMBtu) 0.0 5 7 0.030 0.015

Annual PM 10 Emission (tpy) (a) 1,348 710 3 55

Annual PM 10 Reduction ( tpy) N/A 638 9 93

Annual Cost of Control $0 $546,571 $6,3 3 7, 434

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

Reduction N/A $ 857 $ 16,312

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

Table 1 7 : Jim Bridger Unit 4 Economic Costs

Cost Existing

ESP Existing ESP With

Flue Gas Conditioning Existing ESP With

New Polishing Fabric Filter

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

Capital Recovery Factor N/A 0.09513 0.09513

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

Annual O&M Costs $0 $175,564 $1,7 64

, 126

Annual Cost of Control $0 $ 175

, 564 $6,3 6 7, 118PacifiCorp Jim Bridger Power Plant

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- 6040 BART Applic ation Analysis Page 21

Table 1 8 : Jim Bridger Unit 4 Environmental Costs Existing

ESP Existing ESP With

Flue Gas Conditioni ng Existing ESP With

New Polishing Fabric Filter

PM 10 Emission Rate (lb/MMBtu) 0.0 30 0.030 0.015

Annual PM 10 Emission (tpy) (a) 710 710 3 55

Annual PM 10 Reduction (tpy) N/A 0 355

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

, 118

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

, 936 Incremental Cost per ton of

Reduction N/A N/A $1 7

, 936

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

The cost effectiveness and incremental cost effectiveness of applying a ne w polishing fabric filter are not reasonable. However, the control was included in t he final step in the PM/PM 10 BART determination process for Jim Bridger Units 1

- 4 , Step 5: Evaluate visibility impacts, which is addressed in a comprehensive visibility an alysis covering all three visibility impairing pollutants and associate d control options. The visibility analysis follows Steps 1

- 4 for SO 2 emissions in this application analysis

. Tables

27

- 30, on pages 36

- 39, list the modeled control scenarios and assoc iated emission r ate s.

SO 2 : 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 SO 2 emission control technologies for Jim Bridger Units

1

- 4 . Based on the results of this review, PacifiCorp proposed wet flue gas desulfurization (WFGD) and dry flue gas desulfurization (DFGD) as potential retrofit technologies to reduced SO 2 emissions.

1. Wet FGD

– SO 2 is removed through abso rption by mass transfer as soluble SO 2 in the exhaust gas mixture is dissolved in an alkaline water solvent that has low volatility under process conditions.

SO 2 diffuses from the gas into the scrubber water when the liquid contains less than the equilibr ium concentration of the gaseous SO 2 . The rate of SO 2 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 SO 2 . Once the SO 2 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 (SO 4 ) or sulfite (SO 3 ). The acid/alka li chemical reaction prevents the SO 2 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. SO 2 removal

efficiencies for wet scr ubbers 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 adsorp tion 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 SO 2 into a weak acid, wh ich reactsPacifiCorp Jim Bridger Power Plant

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- 6040 BART Applic ation Analysis Page 22

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%.

SO 2 : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

PacifiCorp did not eliminate either of the two control technolog ies l isted above as technically infeasible. PacifiCorp analyzed the impact of installing dry FGD on each of the units using the existing ESPs, optimizing the existing wet FGDs, and upgrading the existing wet FGDs.

SO 2 : EVALUATE EFFECTIVENESS OF REMAINING CONT ROL 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 operate d 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 em issions 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 m aintained as well as possible.

PacifiCorp determined that Jim Bridger Units 1

- 4 have an uncontrolled SO 2 emission rate , per unit, of 1. 2

lb / MMBtu

, based on an average coal sulfur content of 0.5 8 % by weight. The existing three column



### Babcock & Wilcox wet FGD system s on Jim Bridger Units 1

- 3 currently reduce SO 2 emissions by approximately 78 % to achieve a SO 2 emission limit of 0. 27 lb per MMBtu. The Babcock & Wilcox wet FGD system on Jim Bridger Unit 4 currently reduces emission by 86% resulting in a SO 2 e mission rate of 0.17 lb/MMBtu, based on an average coal sulfur content of 0.5 8 % by weight

.

Installing a new dry FGD system and utilizing the existing ESP on each of the Jim Bridger units may reduce uncontrolled SO 2 emissions by 82.5% resulting in an emiss ion rate of 0.21 lb/MMBtu of SO 2 , based on an average coal sulfur content of 0.5 8 % by weight. Presumptive SO 2 levels for uncontrolled units are 95% emissions reduction or 0.15 lb/MMBtu. PacifiCorp does not anticipate achieving presumptive SO 2 emission le vels using dry FGD. Additionally, PacifiCorp‟s experience evaluating the application of dry FGD to coal

- fired boilers indicates there will be a substantial capital cost involved in removing the existing wet FGD units and replacing them with the new dry FG D. For these reasons and

the fact that wet FGD is an effective, modern SO 2 emissions control technology capable of reducing emissions lower than 0.21 lb/MMBtu, PacifiCorp did not further evaluate and document the cost s associated with installing dry FGD o n Jim Bridger Units 1

- 4 or quantify the resulting visibility improvement

.PacifiCorp Jim Bridger Power Plant

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PacifiCorp evaluated potential changes to the existing wet FGD systems on Jim Bridger Units 1

- 4 to improve the SO 2 removal efficiencies. The first option was to optimize the exist ing equipment. Partially

c losing the bypass damper will reduce the amount of flue gas that is not treated by the wet FGD system and is instead used to reheat the treated flue gas exiting the scrubber. Relocating the opacity monitor and modifying the syst em to minimize scaling problems will also help reduce SO 2 emissions. PacifiCorp anticipates the reduction in SO 2 emissions from applying the above optimization changes on Units 1

- 3

will be an additional 0.07 lb/MMBtu emission reduction, resulting in a 0.2 0 lb/MMBtu emission rate. The wet FGD system on Unit 4 is achieving an emission rate of 0.17 lb/MMBtu and any minor optimization changes to the system are not expected to significantly reduce emissions. PacifiCorp did not further evaluate optimizing the existing wet FGD systems on Units 1

- 4 because the anticipated emission

rate s
, 0.20 lb/MMBtu for Units 1

- 3 and 0.17 lb/MMBtu for Unit 4

, are above the presumptive SO 2 l imit

of 0.15 lb/MMBtu and do not achieve a 95% SO 2 removal efficiency.

The final propose d option is u pgrading the wet FGD system s . This would involve completely closing the bypass damper to eliminate bypass flue gas flow, relocating the opacity monitor, adding new induction fans, adding a liner and drains to the existing exhaust stack for we t operation, and using a refined soda ash

reagent in place of the existing sodium reagent

. Applying the proposed upgrades is anticipated to reduce

total SO 2 emissions by approximately 92% resulting in an emission rate of 0.10 lb/MMBtu, based on an

average coal sulfur content of 0.5 8 % by weight

. PacifiCorp consider s it to be technically infeasible for the present wet FGD system s to achieve a 95% SO 2 r emoval efficiency, which equates to 0.06 lb / MMBtu for the Jim Bridger units, on a continuous basis

. Pacifi Corp‟s proposed emission rates for each SO 2 emission reduction technology applied to Jim Bridger Units 1

- 4 are shown in Table 1 9

.

Table 1 9 : SO 2 Emission Rates Per Boiler

Control Technology SO 2 Emission Rate (lb/MMBtu)

Existing W et FGD 0. 27 (a)

New Dry FGD with E xisting ESP 0.2 1

Optimized Wet FGD 0. 20 (b)

Upgraded Wet FGD 0. 10

(a) Unit 4 currently achieves a 0.17 lb/MMBtu SO 2 emission rate.

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

SO 2 : EVALUATE IMPACTS AND DOCUMENT RESULTS

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

T he upgrad es require 530 kW on Units 1 and 2, and 520 kW of additional power on Units 3 an d 4. Using a 90% annual plant capacity factor, the additional power amounts to approximately 4.2 million kW

- h r per unit.PacifiCorp Jim Bridger Power Plant

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PacifiCorp‟s environmental evaluation of installing additional SO 2 controls noted that u pgrading the existing wet FGD systems on th e four units results in additional scrubber waste disposal and makeup

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

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

.

PacifiCorp an ticipates operating Jim Bridger Units 1

- 4 indefinitely and did not include life extension costs in the economic analysis

. A standard control life of 20 years was used to calculate the capital recovery factor. The annual cost to control was determined usi ng 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 po llution 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 i s also used extensively by the Division when comparing emission controls under the BACT process. While the BART and the BACT process es are not necessarily equivalent, control determinations from either process are based on cost effectiveness

and increment al 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 control s 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 l imit s analyses

for NO

x and SO 2 , 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 effec tiveness

, and incremental cost effectiveness in the evaluation of each proposed SO 2 emission control. Economic and environmental costs for additional controls on Jim Bridger Units 1

- 4 are summarized in the following tables.

Table 20 : Jim Bridger Units 1

- 3 Economic Costs

Cost Existing

Wet FGD Upgraded

Wet FGD

Control Equipment Capital Cost $0 $ 12 ,9 99

, 990

Capital Recovery Factor N/A 0.09513

Annual Capital Recovery Costs $0 $ 1

, 236

, 681

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

Annual Cost of Control $0 $ 2

, 4 94

, 857

(a) Annual maintenance costs for Unit 3 are $4,518 less per year than Units 1 and 2.PacifiCorp Jim Bridger Power Plant

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Table 21 : Jim Bridger Units 1

- 3 Environmental Costs Existing

Wet FGD Upgraded

Wet FGD

SO 2 Emission Rate (lb/MMBtu) 0. 27 0. 1 0

Annual SO 2 Emission (tpy) (a) 6

, 386 2

, 365

Annual SO 2 Reduction (tpy) N/A 4

, 021

Annual Cost of Control $0 $ 2

, 494

, 857

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

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

(a) Annual emissions based on unit heat input rate of 6

, 0 00 MMBtu/hr and 7 ,884 hours of operation per year.

( b ) Cost per ton of SO 2 reduction on Unit 3 is $619 because annual maintenance costs are $4,518 less.

Table 2 2 : Jim Bridger Unit 4 Economic Costs

Cost Existing

Wet FGD Upgraded

Wet FGD

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

Capital Recovery Factor N/A 0.09513

Annual Capital Recovery Costs $0 $54 7

, 931

Annual O&M Costs $0 $ 658,683

Annual Cost of Control $0 $ 1 ,2 06

, 614

Table 2 3 : Jim Bridger Unit 4 Environmental Costs Existing

Wet FGD Upgraded

Wet FGD

SO 2 E mission Rate (lb/MMBtu) 0. 1 7 0.1 0

Annual SO 2 Emission (tpy) (a) 4,021 2

, 365

Annual SO 2 Reduction (tpy) N/A 1

, 656

Annual Cost of Control $0 $ 1 ,2 06

, 614

Cost per ton of Reduction N/A $ 729

Incremental Cost per ton of Reduction N/A $ 729

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

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

units is reasonable. The final step in the SO 2 BART deter mination process for Jim Bridger Units 1

- 4

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

next section of this BART application analysis . T he Division evaluated the amount of visibility improveme nt gained from the application of additional NO

x , PM/ PM 10 , and SO 2 emission control technology in relation to all three visibility impairing pollutants

. Tables 27

- 30, on pages 36

- 39, list the

modeled control scenarios and associated emission r ate s.

VISI BILITY 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 vari ous options for control technology. This factor was evaluated for the PacifiCorp Jim Bridger facility by using an EPA

- approved dispersion modeling system (CALPUFF) to predict the change in Class I area visibility. The Division had previously determined t hat the f acility 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 m ore refined modeling conducted by the applicant

, is descri bed in detail below.

Bridger Wilderness Area (WA) and Fitzpatrick WA in Wyoming and Mount Zirkel WA in Colorado are the closest Class I areas to the PacifiCorp Jim Bridger facility, as shown in F igure 2 below. Bridger W A is located approximately 98 kil ometers (km) north west of the facility and Fitzpatrick WA is located approximately 15 1 km north west of the facility. Mount Zirkel WA is located approximately 185 km southeast of the facility.

Only those Class I areas most likely to be impacted by the J im Bridger Power Plant sources were modeled, as determined by source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. I t can be reasonably assumed that areas at greater dista nce s and in directions of less frequent plume transport will experience lower impacts than

those predicted for the three modeled areas

. All source

- Class I area distances from Jim Bridger Power

Plant to Bridger WA

, Fitzpatrick WA , and Mount Zirkel WA excee d 50 km and are less than 300 km, thus falling within the range recommended for CALPUFF application.

Screening modeling that was conducted to determine if the Jim Bridger plant sources would be subject to BART, as described below, included receptors for the two closest Class I areas only (Bridger WA and Fitzpatrick WA). Subsequent refined modeling, as described later in this document, was conducted for all three of the closest Class I areas (Bridger WA, Fitzpatrick WA, and Mount Zirkel WA).PacifiCorp Jim Bridger Power Plant

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F igure 2 Jim Bridger Power Plant and Class I AreasPacifiCorp Jim Bridger Power Plant

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SCREENING MODELING

To determine if the PacifiCorp Jim Bridger facility would be subject to BART, the Division conducted CALPUFF modeling using three years of meteorological data. These data, from 1 995

- 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. S ources input to the modeling

included the potential emissions for current operation from the four coal

- fired boilers at the Jim Bridger facility

.

Results of the modeling showed that the 98 th percentile value for the change in visibility ( in units of delta deciview [Δdv]) was above 0.5 Δ dv for Bridger W A and Fitzpatrick WA for all three years of meteorolog y . A s defined in EPA‟s final BART rule, a predicted 98 th percentile impact equal to or greater

than 0.5 Δ dv fr om a given source indicates that the s ource contributes to visibility impairment, and therefore is subject to BART. The results of the screening modeling are shown in the table below.

Table 2 4 : Results of the Class I Area Screening Modeling

Class I Area Maximum

Modeled Value (Δdv) 98 th

Per centile Value (Δdv)

1995 Bridger WA 9.7 3.1 Fitzpatrick WA 3.3 1.5

1996 Bridger WA 8.7 2.0 Fitzpatrick WA 3.8 1.1

2001 Bridger WA 4.6 2.8 Fitzpatrick WA 4.3 1.5

Δdv = delta deciview

WA = wilderness area

REFINED MODELING

Because of the res ults 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 pro tocol, BART Air Modeling

Protocol

- Individual Source Visibility Assessments for BART Control Analyses (WDEQ

- AQD, September 2006).

CALPUFF System

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

CALPUFF m odeling 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 p art 51), long

- range transport is defined as modeling with source

- receptor distances greater than 50 km . Because all modeled

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

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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 three

dimensional, 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

h eight, 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 upp er

- air stations.

CALPUFF is a multi

- layer, Lagrangian puff dispersion model. CALPUFF can be driven by the three

dimensional wind fields developed by the CALMET model (refined mode), or by data from a single surface and upper

- air station in a format con sistent with the meteorological file s 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 multip le 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 s um, scale, and/or compute species derived from those that are modeled , and outputs selected species to a file for further post

- processing . C ALPOST is a post

- processing program that can read the CALPUFF (or POSTUTIL or CALSUM) output files and calculate th e 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 o f the key programs are listed in the table below.

Table 2 5 : Key Programs in CALPUFF System
Program Version Level

CALMET 5.53a 040716

CALPUFF 5.711a 040716

CALPOST 5.51 030709PacifiCorp Jim Bridger Power Plant

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Meteorological Data Processing (CALMET)

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

three

- dimensional windfield using data from the MM5 model . Surface and upper

- air data were input to CALMET to adjust the initial windfield, but because of the relative scarcity of wind observations in the modeling domain, the influence of the observations on the initial windfield was minimized . Because the MM5 data were afforded a high degree of influence on the CALMET windfields, the Division obtained

MM5 data at 12

- km resolution that spanned the years 2001

- 2003. Locations of the observations that were input to CALMET , including surface, upper

- air, and precipitation stations, are shown in Figure 3

. Default settings were used in the CALMET input files for most of the technical opt ions. The following table lists the key user

- defined CALMET settings that were selected.

Table 2 6 : Key User

- Defined CALMET Settings

Variable Description Value

PMAP Map projection LCC

DGRIDKM Grid spacing (km) 4

NZ Number of layers 10

Z FACE Cell face heights (m) 0, 20, 40, 100, 140, 320, 580, 1020, 1480, 2220, 3 4 00

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 Maxi mum 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) 25PacifiCorp Jim Bridger Power Plant

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Figure 3 Observations Input to CALM ETPacifiCorp Jim Bridger Power Plant

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CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry

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

concentrations . For ozone, hourly data collected from the foll owing 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 dat a 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 d iscrete receptors were taken f rom the National Park Service ( NPS ) Class I Receptors database and converted to the appropriate

Lambert Conformal Conic coordinates. Figure s 4

- 6 show the receptor configuration s that w ere used for Bridger WA , Fitzpatrick WA, and Mount Zirkel WA

. Receptor spacing for the three modeled areas is approximately 1.3 km in the east

- west direction and approximately 1.8 km in the

north

- south direction.PacifiCorp Jim Bridger Power Plant

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Figure 4 Receptors for Bridger WAPacifiCorp Jim Bridger Power Plant

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Figure 5 Receptors for Fitzpatrick WAPacifiCorp Jim Bridger Power Plant

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Figure 6 Receptors for Mount Zirkel WA

CALPUFF Inputs

– Baseline and Control Options

S ource release parameters and emissions for baseline and control options for each unit at the Jim Bridger Plant are shown in the table s below

.PacifiCorp Jim Bridger Power Plant

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Table 2 7 : CALPUFF Inputs for Jim Bridger Unit 1PacifiCorp Jim Bridger Power Plant

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Table 2 8 : CALPUFF Inputs for Jim Bridger Unit 2PacifiCorp Jim Bridger Power Plant

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Table 2 9 : CALPUFF Inputs for Jim Bridger Unit 3PacifiCorp Jim Bridger Power Plant

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Table 30 : CALPUFF In puts for Jim Bridger Unit 4PacifiCorp Jim Bridger Power Plant

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V isibility 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)] f or each Class I area. Monthly f(RH) factors that were used for Bridger WA

, Fitzpatrick WA , and Mount Zirkel WA are shown in the table below.

Table 3 1 : Relative Humidity Factors for CALPOST

Month Mount

Zirkel

WA Bridger

WA & Fitzpatrick

WA January 2 .20 2.50

February 2.20 2.30

March 2.00 2.30

April 2.10 2.10

May 2.20 2.10

June 1.80 1.80

July 1.70 1.50

August 1.80 1.50

September 2.00 1.80

October 1.90 2.00

November 2.10 2.50

December 2.10 2.40

According to the final BART rule, n atural back ground conditions as a reference for determination of the

modeled Δdv change s hould 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 Clas s I area on an annual basis, but does not provide the individual species concentration data required for input

to CALPOST

.

S pecies 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 b y the g uidance table annual concentrations, the 20 percent best days deciview value s 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 d ocument, 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 rel ationship between deciviews and light extinction is expressed as follows:

dv = 10 ln (b ext

/10) or b ext = 10 exp (dv/10)PacifiCorp Jim Bridger Power Plant

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where: b ext = light extinction expressed in inverse megameters (Mm

- 1 ).

Using this relationship with the known deciview value of 1.96, one obtains a n 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

compon ents of the light extinction is as follows:

b ext = (3)f(RH)[ammonium sulfate] + (3)f(RH)[ammonium nitrate] + (0.6)[coarse mass] + (4)[organic carbon] + (1)[soil] + (10)[elemental carbon] + b ray

where: bracketed quantities represent background concentrati ons in μg/m 3

values in parenthesis represent scattering efficiencies f(RH) is the relative humidity adjustment factor (applied to hygroscopic species only)

b ray is light extinction due to Rayleigh scattering (10 Mm

- 1 used for all Class I areas)

Substituti ng 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 equ ation 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 3 2 : Calculated Background Components for Bridger WA

Component Annual Average for

West Region 

### (μg/m 3 

### ) Calculated Scaling

Factor 20% Best Days for

Bridger WA 

### (μg/m 3 

### )

Ammonium Sulfate 0.12 0.376 0.045

Ammonium Nitrate 0.10 0.376 0.038

Organic Carbon 0.47 0.376 0.176

Elemental Carbon 0.02 0.376 0.008

Soil 0.50 0.376 0.188

Coarse Mass 3.00 0.376 1.127

The scaled aerosol concentrations were averaged for Bridger WA and Fitzpatrick WA because of their geographical proximity and similar annual background visibility. The 20 percent best days aerosol

concentrations for all three Class I areas in question a re listed in the table below.PacifiCorp Jim Bridger Power Plant

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Table 3 3 : Natural Background Aero sol Concentrations (μg/m 3 )

Aerosol Component Mount

Zirkel

WA Fitzpatrick

WA & Bridger WA

Ammonium Sulfate 0.046 0 .045

Ammonium Nitrate 0.038 0 .038

Organic Carbon 0.179 0 .178

Elemental Carbon 0.008 0 .008

Soil 0.190 0 .189

Coarse Mass 1.141 1.136

Visibility Post

- Processing Results

The results of the visibility modeling for each of the four units for the baseline and control scenarios are shown in the table s below. For each scenario, the 98 th percentile Δdv results are reported along with the

tot al 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.PacifiCorp Jim Bridger Power Plant

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Table 3 4 : CALPUFF Visibility Modeling Results: Unit 1

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days > 0.5

Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– Wet FGD, ESP
Bridger WA 0.746 14 1.448 2 6 0.761 16 0.985 19
Fitzpatrick WA 0.418 7 0.704 11 0.373 7 0.498 8

Mt Zirkel WA 1.236 27 1.496 34 1.232 35 1.321 32

Post

- Control Scenario 1

– LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP
Bridger WA 0.384 7 0.845 14 0.411 5 0.547 9

Fitz patrick WA 0.221 3 0.378 5 0.199 2 0.266 3

Mt Zirkel WA 0.736 16 0.816 13 0.736 16 0.763 15

Post

- Control Scenario 2

– LNB w/ separated OFA, Upgrade Wet FGD, New Fabric Filter
Bridger WA 0.372 6 0.780 13 0.408 5 0.520 8
Fitzpatrick WA 0.211 3 0.347 6 0. 186 2 0.248 4

Mt Zirkel WA 0.676 15 0.777 13 0.686 15 0.713 14

Post

- Control Scenario 3

– LNB w/ separated OFA and SCR, Upgrade Wet FGD, Enhanced ESP
Bridger WA 0.279 3 0.519 9 0.258 3 0.352 5
Fitzpatrick WA 0.127 1 0.226 1 0.118 2 0.157 1

Mt Zirkel WA 0.453 5 0.473 4 0.433 5 0.453 5

Post

- Control Scenario 4

– LNB w/ separated OFA and SCR, Upgrade Wet FGD, New Fabric Filter
Bridger WA 0.268 3 0.500 8 0.248 3 0.339 5
Fitzpatrick WA 0.125 1 0.223 1 0.114 2 0.154 1

Mt Zirkel WA 0.436 2 0.465 4 0.422 5 0 .441 4

Post

- Control Scenario A

– Committed Controls: LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP
Bridger WA 0.442 7 0.930 14 0.466 6 0.613 9
Fitzpatrick WA 0.256 3 0.417 6 0.222 3 0.298 4

Mt Zirkel WA 0.797 18 0.917 14 0.755 18 0.823 17

Post

- Control Scenario B

– Committed Controls + SCR
Bridger WA 0.342 3 0.619 9 0.285 4 0.415 5
Fitzpatrick WA 0.155 3 0.284 2 0.138 2 0.192 2

Mt Zirkel WA 0.477 7 0.562 9 0.461 6 0.500 7PacifiCorp Jim Bridger Power Plant

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Table 3 5 : CALPUFF Visibility Modeling Results: Unit 2

Class I Ar ea 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) 98th

Percentile

Value (Δdv) 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– Wet FGD, LNB w/ separated OFA , ESP
Bridger WA 0.530 10 0.990 20 0.533 9 0.684 13
Fitzpatrick WA 0.298 4 0.534 8 0.263 3 0.365 5

Mt Zirkel WA 0.842 23 1.008 18 0.803 20 0.884 20

Post

- Control Scenario 1

– LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP
Bridger WA 0.385 7 0.847 14 0.416 5 0.549 9
Fitzpatrick WA 0.223 3 0.377 5 0.200 2 0.267 3

Mt Zirkel WA 0.733 16 0.815 13 0.735 16 0.761 15

Post

- Control Scenario 2

– LNB w/ separated OFA, Upgrade Wet FGD, New Fabric Filter
Bridger WA 0.3 75 6 0.784 13 0.409 5 0.523 8
Fitzpatrick WA 0.210 3 0.348 6 0.188 2 0.249 4

Mt Zirkel WA 0.681 15 0.777 13 0.688 15 0.715 14

Post

- Control Scenario 3

– LNB w/ separated OFA and SCR, Upgrade Wet FGD, Enhanced ESP
Bridger WA 0.279 3 0.516 9 0.258 3 0.351 5
Fitzpatrick WA 0.127 1 0.226 1 0.118 2 0.157 1

Mt Zirkel WA 0.455 5 0.474 5 0.435 5 0.455 5

Post

- Control Scenario 4

– LNB w/ separated OFA and SCR, Upgrade Wet FGD, New Fabric Filter
Bridger WA 0.268 3 0.499 7 0.248 3 0.338 4
Fitzpatrick WA 0.125 1 0.222 1 0.115 2 0.154 1

Mt Zirkel WA 0.439 2 0.465 4 0.423 5 0.442 4

Post

- Control Scenario A

– Committed Controls: LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP
Bridger WA 0.442 7 0.930 14 0.466 6 0.613 9
Fitzpatrick WA 0.256 3 0.417 6 0 .222 3 0.298 4

Mt Zirkel WA 0.797 18 0.917 14 0.755 18 0.823 17

Post

- Control Scenario B

– Committed Controls + SCR
Bridger WA 0.342 3 0.619 9 0.285 4 0.415 5
Fitzpatrick WA 0.155 3 0.284 2 0.138 2 0.192 2

Mt Zirkel WA 0.477 7 0.562 9 0.461 6 0.500 7PacifiCorp Jim Bridger Power Plant

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Table 3 6 : CALPUFF Visibility Modeling Results: Unit 3

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) 98th

Percentile

Value (Δdv) 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δd v 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– Wet FGD, ESP
Bridger WA 0.741 15 1.447 27 0.759 16 0.982 19
Fitzpatrick WA 0.418 7 0.713 11 0.378 7 0.503 8

Mt Zirkel WA 1.226 27 1.498 34 1.228 35 1.317 32

Post

- Control Scenario 1

– LN B w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP
Bridger WA 0.386 7 0.854 14 0.414 5 0.551 9
Fitzpatrick WA 0.223 3 0.377 4 0.192 2 0.264 3

Mt Zirkel WA 0.733 16 0.815 13 0.734 16 0.761 15

Post

- Control Scenario 2

– LNB w/ separated OFA, Upgrad e Wet FGD, New Fabric Filter
Bridger WA 0.376 6 0.782 13 0.41 0 5 0.523 8
Fitzpatrick WA 0.214 3 0.349 6 0.188 2 0.250 4

Mt Zirkel WA 0.677 15 0.778 13 0.686 15 0.714 14

Post

- Control Scenario 3

– LNB w/ separated OFA and SCR, Upgrade Wet FGD, Enhanced E SP
Bridger WA 0.279 3 0.509 9 0.258 3 0.349 5
Fitzpatrick WA 0.128 1 0.226 1 0.118 2 0.157 1

Mt Zirkel WA 0.451 5 0.473 4 0.432 5 0.452 5

Post

- Control Scenario 4

– LNB w/ separated OFA and SCR, Upgrade Wet FGD, New Fabric Filter
Bridger WA 0.268 3 0.4 98 7 0.248 3 0.338 4
Fitzpatrick WA 0.126 1 0.222 1 0.115 2 0.154 1

Mt Zirkel WA 0.437 2 0.464 4 0.42 0 5 0.440 4

Post

- Control Scenario A

– Committed Controls: LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP
Bridger WA 0.442 7 0.93 0 14 0.466 6 0.613 9
Fitzpatrick WA 0.256 3 0.417 6 0.222 3 0.298 4

Mt Zirkel WA 0.797 18 0.917 14 0.755 18 0.823 17

Post

- Control Scenario B

– Committed Controls + SCR
Bridger WA 0.342 3 0.619 9 0.285 4 0.415 5
Fitzpatrick WA 0.155 3 0.284 2 0.138 2 0.192 2

Mt Zirkel WA 0.477 7 0.562 9 0.461 6 0.500 7PacifiCorp Jim Bridger Power Plant

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Table 3 7 : CALPUFF Visibility Modeling Results: Unit 4

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

V alue (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) 98th

Percentile

Value (Δdv) 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– Wet FGD, ESP
Bridger WA 0.695 12 1.33 0 23 0.736 1 3 0.920 16
Fitzpatrick WA 0.406 5 0.615 11 0.346 7 0.456 8

Mt Zirkel WA 1.129 24 1.38 0 25 1.201 33 1.237 27

Post

- Control Scenario 1

– LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP
Bridger WA 0.386 7 0.821 14 0.429 5 0.545 9
Fitzpatrick W A 0.223 3 0.379 3 0.207 2 0.270 3

Mt Zirkel WA 0.688 16 0.8 00 14 0.688 17 0.725 16

Post

- Control Scenario 2

– LNB w/ separated OFA, Upgrade Wet FGD, New Fabric Filter
Bridger WA 0.383 7 0.802 14 0.425 5 0.537 9
Fitzpatrick WA 0.232 3 0.361 3 0.202 2 0.2 65 3

Mt Zirkel WA 0.671 15 0.79 0 13 0.678 17 0.713 15

Post

- Control Scenario 3

– LNB w/ separated OFA and SCR, Upgrade Wet FGD, Enhanced ESP
Bridger WA 0.285 3 0.472 7 0.275 2 0.344 4
Fitzpatrick WA 0.143 2 0.233 1 0.129 2 0.168 2

Mt Zirkel WA 0.426 4 0.442 5 0.409 5 0.426 5

Post

- Control Scenario 4

– LNB w/ separated OFA and SCR, Upgrade Wet FGD, New Fabric Filter
Bridger WA 0.273 3 0.466 7 0.263 2 0.334 4
Fitzpatrick WA 0.136 1 0.23 0 1 0.124 1 0.163 1

Mt Zirkel WA 0.41 0 3 0.434 5 0.399 4 0.414 4

P ost

- Control Scenario A

– Committed Controls: LNB w/ separated OFA, Upgrade Wet FGD, FGC for Enhanced ESP
Bridger WA 0.448 7 0.893 14 0.489 6 0.610 9
Fitzpatrick WA 0.273 3 0.428 6 0.226 2 0.309 4

Mt Zirkel WA 0.743 17 0.892 15 0.77 0 19 0.802 17

Post

- Co ntrol Scenario B

– Committed Controls + SCR
Bridger WA 0.343 4 0.579 8 0.301 4 0.408 5
Fitzpatrick WA 0.164 3 0.288 1 0.139 2 0.197 2

Mt Zirkel WA 0.444 5 0.538 8 0.46 0 6 0.481 6PacifiCorp Jim Bridger Power Plant

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- 6040 BART Application Analysis Page 47 Figure 7 Modeled BART Impacts: 98th Percentile (delta

- dv)PacifiCorp Jim Bridger Power Plant

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Fi gure 8

Mo deled BART Impacts: Number of Days > 0.5 delta

- dvPacifiCorp Jim Bridger Power Plant

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BART CONCLUSIONS:

After considering (1) the costs of compliance, (2) the energy and non

- air quality environmental impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) the remaining useful life of the source, and (5) the degree of improvement in visibility (all five statutory factors) from each proposed control technology, the Division determined BART for each visibility impairing pollutant

emitted from the four unit s subject to BART at the Jim Bridger Power Plant.

NO

x

LNB with separated OFA is determined to be BART for Units 1

- 4 for NO

x based, in part, on the following conclusions:

1. LNB with separated OFA on Units 1, 3, and 4 was cost effective with a capital cost of $11,300 ,000 per unit and a $ 255 per ton of NO

x removed average cost effective ness for each unit

over a twenty year operational life. LNB with separated OFA on Unit 2 did not require any

additional capital cost or annual O&M cost

.

2. Com bustion control us ing LNB with separated OFA does not require non

- air quality environmental mitigation for the use of chemical reagents (i.e.

, ammonia or urea) and there is a

minimal ene rgy impact.

3. After careful consideration of the five statutory factors, especially the c osts of compliance and the existing pollution control equipment

, a NO

x control level of 0.26 lb/MMBtu on a 30

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

- fired boilers burning sub

- bituminous coal, is justi fied

.

4. V isibility impacts were addressed in a comprehensive visibility analysis covering all three visibility impairing pollutants and associate d control options. The cumulative 3

- year averaged visibility improvement from the baseline summed across the th ree Class I areas achieved with

LNB with separated OFA, upgraded w et FGD

, and FGC for en hanced ESP ( P ost

- C ontrol

S cenario A) was 1.070 Δdv from Unit 1, 0.199 Δdv from Unit 2, 1.068 Δdv from Unit 3, and

0.892 Δdv from Unit 4.

5. Annual NO

x emission reductions from LNB with separated OFA on Unit 1, 3, and 4 are 4,493 tons per unit for a total annual reduction at the Jim Bridger Power P lant of 13

, 479 tons. There are

no NO

x reductions from Unit 2 as LNB with separated OFA is baseline for the unit.

LNB with separated OFA and SCR was not determined to be BART for Units 1

- 4 for NO

x based, in part, on the following conclusions:

1. The cost of compliance for installing SCR on each unit is significantly high er than LNB with separated OFA . C apital costs for SCR on Units 1

- 4 are $166,500,000 per unit

. A nnual operating

costs for Units 1, 3, and 4 are $3,382,286 per unit and Unit 2 is $3,370,466.PacifiCorp Jim Bridger Power Plant

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- 6040 BAR T Application Analysis Page 50

2. Additional non

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

3. Operation of LNB with separated OFA and SCR is parasitic and requires an estimated 3.22 MW

to 3.36 MW of power from each unit.

4. While visibility impacts w ere addressed in a cumulative analysis of all three pollutants, Post

Control Scenario B is directly comparable to Post

- Control A as the only difference is directly

attributable to the installation of SCR. Subtracting the modeled values from each other yie ld the incremental visibility improvement from SCR. The cumulative 3

- year averaged visibility improvement from Post

- Control Scenario A a cross the three Class I areas achieved with P ost

C ontrol S cenario B was 0.62 7 Δdv per unit from Unit s 1

- 3 and 0.635 Δdv from Unit 4.

The Division considers the installation and operation of the BART

- determined NO

x controls , LNB with separated OFA, to meet the corresponding emission limits of 0.26 lb/MMBtu, 30

- day rolling average,
1, 560 lb/hr, 30

- day rolling average

, and 6 ,833 tpy on a continuous basis to meet the statutory requirements of BART.

Unit

- by

- unit NO

x BART determinations:

Jim Bridger Unit 1 : LNB with separated OFA and meeting NO

x emission limits of 0.2 6

lb/ MMBtu (30

- day rolling average)

, 1, 560 lb/hr (30

- day rol ling average ) and 6,833 tpy as BART for NO

x .

Jim Bridger Unit 2 : LNB with separated OFA and meeting NO

x emission limits of 0.2 6

lb/ MMBtu (30

- day rolling average), 1, 560 lb/hr (30

- day rolling average ) and 6,833 tpy as BART for NO

x .

Jim Bridger Unit 3 : L NB with separated OFA and meeting NO

x emission limits of 0.2 6

lb/ MMBtu (30

- day rolling average), 1, 560 lb/hr (30

- day rolling average ) and 6,833 tpy as BART for NO

x .

Jim Bridger Unit 4 : LNB with separated OFA and meeting NO

x emission limits of 0.2 6

lb/ MMB tu (30

- day rolling average), 1, 560 lb/hr (30

- day rolling average ) and 6,833 tpy as BART for NO

x .

PM/PM 10

Existing ESP with FGC is determined to be BART for Units 1

- 4 for PM/PM 10 based, in part, on the following conclusions:

1. Recognizing the cost benefit associated with using the existing ESPs and the minimal energy impac t 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 effectiven ess for e xisting ESP with FGC is $1,544 for Unit 1 , $526 for Unit 2, $857 for Unit 3 . Unit 4 did not require additional capital cost

.PacifiCorp Jim Bridger Power Plant

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2. No negative non

- air environmental impacts are anticipated from existing ESP s with FGC.

3. V isibility impacts were address ed in a comprehensive visibility analysis covering all three visibility impairing pollutants and associate d control options. The cumulative 3

- year averaged visibility improvement from the baseline across the three Class I areas achieved with LNB with

sepa rated OFA, upgraded w et FGD

, and FGC for en hanced ESP ( P ost

- C ontrol S cenario A) was 1.070 Δdv from Unit 1, 0.199 Δdv from Unit 2, 1.068 Δdv from Unit 3, and 0.892 Δdv from Unit 4. While the visibility improvement attributable to the installation of FGC on existing ESP s can‟t be directly determined from the visibility modeling, the Division does not anticipate the PM contribution to be significant when compared to NO

x and SO 2 contributions.

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

- 4 for PM/PM 10 based, in part, on the following conclusions:

1. The cost of compliance for a polishing fabric filter on each unit is not reasonable over a twenty year operational life. The cost effectiveness for installing a new polishing fabric filter on the existing ESP is $8,980 for Unit 1, $4,557 for Unit 2, $6,382 for Unit 3, and $17,936 for Unit 4. Incremental cost effectiveness is $16,396, $16,369, $16,312, and $17,936 for Units 1, 2, 3, and 4, respectively.

2. The cumulative 3

- year averaged visibility improvement from new LNB with separated OFA, upgraded wet FGD, and FGC for enhanced ESP with FGC (Post

- Control Scenario 1) across the

three Class I areas achieved with LNB and separated OFA, upgraded wet FGD, and adding a polishing fabr ic filter (Post

- Control Scenario 2) was 0. 095 Δdv from Unit 1 , 0.090 Δdv from Unit 2, 0.089 Δdv from Unit 3 and 0. 025 Δdv from Unit 4.

The Division considers the installation and operation of the BART

- determined PM/PM 10 controls

, existing ESP with FGC, to meet the corresponding emission limits of 0.030 lb/MMBtu

, 180 lb/hr , and 788 tpy on a continuous basis to meet the statutory requirements of BART.

Unit

- by

- unit PM/PM 10 BART determinations:

Jim Bridger Unit 1 : Continuing to use the existing ESP and addi ng FGC to meet an

established PM/PM 10 emission limit s of 0.030 lb/MMBtu

, 180 lb/hr , and 788 tpy a s BART for PM/ PM 10

.

Jim Bridger Unit 2 : Continuing to use the existing ESP and adding FGC to meet an

established PM/PM 10 emission limit s of 0.030 lb/MMBtu , 1 80 lb/hr, and 788 tpy a s BART for PM/ PM 10

.

Jim Bridger Unit 3 : Continuing to use the existing ESP and adding FGC to meet an

established PM/PM 10 emission limit s of 0.030 lb/MMBtu , 180 lb/hr, and 788 tpy a s BART for PM/ PM 10

.

Jim Bridger Unit 4 : Continuin g to use the existing ESP and adding FGC to meet an

established PM/PM 10 emission limit s of 0.030 lb/MMBtu , 180 lb/hr, and 788 tpy a s BART for PM/ PM 10

.PacifiCorp Jim Bridger Power Plant

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SO 2 : REGIONAL SO 2 MILESTONE AND BACKSTOP TRADING PROGRAM

PacifiCorp evaluated control SO 2 control techno logies that can achieve a SO 2 emission rate of 0.1 5

lb/MMBtu or lower from the coal

- fired boilers. PacifiCorp ‟s proposed BART control s are upgrading the existing wet FGD on each of the units

.

Wyoming is a §309 state participat ing in the Regional SO 2 Mile stone 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 maint ain 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 progr am can achieve greater reasonable progress is prescribed by §308(e)(2)(i). Since the pollutant of concern is SO 2 , this demonstration has been performed under §309 as part of the state implementation plan. §309(d)(4)(i) requires that the SO 2 milestones

es tablished under the plan “...must be shown to provide for greater reasonable progress than would be achieved by application of BART pursuant to §51.308(e)(2).”

Wyoming participated in creating a detailed report entitled Demonstration that the SO 2 Milestones Provide Greater Reasonable Progress than BART covering SO 2 emissions from all states participating

in the Regional SO 2 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 filin g these reports since 2003. Each year, states have been

able to demonstrate that actual SO 2 emissions are well below the milestones. The actual emissions and their respective milestones are shown below:

Table 38 : Regional Sulfur Dioxide Emissions and Mi lestone Report Summary

Year Reported SO 2 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 SO 2 emission r eductions, § 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 visib i lity improvement section of the § 309 SIP, but the SO 2 portion of the demonstration has been included as Table 39 to underscore the improvements associated with SO 2 reductions.PacifiCorp Jim Bridger Power Plant

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Table 3 9 : 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 (PRP18 a ) 2018 1

Base Case (Base 18b) 2018 2

Preliminary

Reasonable Progress Case (PRP18 a )

B ridger, 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 . N o BART or S O 2 M ilestone assumptions were included.

2 Represents 20 18 Preliminary Reasonable Progress growth estimates and established S O 2 limits

.

All Class I areas in the surrounding states show a projected visibility improvement for 2018 with respect

to SO 2 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,

Se ction 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

SO 2 Milestone and Backstop Trading Program author ized under Chapter 14 of the WAQSR.

LONG

- TERM STRATEGY FOR REGIONAL HAZE :

In this BART analysis, the technology available, the costs of compliance, the energy and non

- air quality environmental impacts of compliance, any pollution control equipment in use at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated

to result from the use of such technology were taken into consideration when determining BART. When evaluating the cos ts of complia nce the Division recognized a time limitation to install BART

- determined controls imposed by the R egional H aze R ule. In addressing the required elements , including

documentation for all required analyses

, to be submitted in the s tate i mplemen tation p lan

, 40 CFRPacifiCorp Jim Bridger Power Plant

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51.308(e)(1)(iv) states: “A requirement that each source subject to BART be required to install and operate BART as expeditiously as practicable, but in no event later than 5 years after approval of the implementation plan revision. ” A s 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 ma nual. 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

retrofi t factor in their cost analys e s

. PacifiCorp estimated that the installation of SCR requires a minimum of 6 years of advanced planning and engineering before the control can be succ essfully installed and operated. This planning horizon would necessarily be considered in the scheduled maintenance turnarounds for existing units to minimize installation costs of the pollution control systems.

PacifiCorp‟s BART

- eligible or subject

- to

- BART power plant fleet is shown in Table 40

. While the majority of affected units are in Wyoming, there are four units in Utah and one in Arizona. Since the 5

- year control installation requirement is stated in the federal rule it applies to all of Pacif iCorp‟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 mor e tha n one control installation , which are indirect retrofit costs, was afforded

under the statutory factor: costs of compliance.

Table 40 : PacifiCorp’s BART

- Eligible/Subject Units

Source State

Hunter Unit 1 (a) Utah

Hunter Unit 2 (a) Utah Huntington Unit 1 (a) Utah Huntington Unit 2 (a) Utah

Cholla Unit 4 (b) Arizona

Dave Johnston Unit 3 Wyoming

Dave Johnston Unit 4 Wyoming Jim Bridger Unit 1 Wyoming Jim Bridger Unit 2 Wyoming Jim Bridger Unit 3 Wyoming Jim Bridger Unit 4 Wyoming Naughton Unit 1 Wy oming 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.PacifiCorp Jim Bridger Power Plant

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Ther efore, based on the cost of compliance and visibility improvement presented by PacifiCorp in the BART applications for Jim Bridger Units 1

- 4 and taking into consideration the logistical challenge of managing multiple pollution control installations with in the regulatory time allotted for installation of

BART by the Regional Haze Rule , the Division is requiring the installation of SCR on Jim Bridger Unit 3

in 2015 and on Jim Bridger Unit 4 in 2016 for the Long

- Term Strategy of the Wyoming Regional Haze

State Implementation Plan. The Division is also requiring PacifiCorp to submit a permit application to
install additional add

- on NO

x control on Units 1 and 2 that includes an analysis of: (1) the costs of compliance; (2) the time necessary for compliance; (3) the energy and non

- air quality environmental impacts of compliance; and (4) the remaining useful life of existing sources that contribute to visibility impairment (i.e., the four statutory factors taken into consideration when establishing reasonable progr ess goals 5 ) and the associated visibility impacts from the application of each proposed NO

x control. Each proposed add

- on NO

x control shall achieve an emission rate , on an individual unit basis, at or below 0.07

lb/MMBtu on a 30

- day rolling average. The permit application shall be submitted by January 1, 2015

. Additional a dd

- on NO

x control shall be installed and operational no later than the end of 202 3 calendar

year on Jim Bridger Unit s 1 and 2

.

CHAPTER 6, SECTION 4

– PREVENTION OF SIGNIFICANT DETERIOR ATION (PSD):

PacifiCorp‟s Jim Bridger Power Plant is a “major emitting facility” under Chapter 6, Section 4, of the Wyoming Air Quality Standards and Regulations because emissions of a criteria pollutant are greater than

100 tpy for a listed categorical s ource

. 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

a pplicability for Jim Bridger Units 1

- 4.

CHAPTER 5, SECTION 3

– NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAPs) AND CHAPTER 6, SECTION 6

– HAZARDOUS AIR POLLUTANT ( HAP) EMISSIONS AND MAXIMUM AVAILABLE CONTROL TECHNOLOGY (MACT):

The installation of controls determined to meet BART will not change Nation Emission Standards For

Hazardous Air Pollutants a pplicability for Jim Bridger Units 1

- 4.

CHAPTER 6, SECTION 3

– OP ERATING PERMIT:

The Jim Bridger Power Plant is a major source under Chapter 6, Section 3 of the Wyoming Air Quality Standards and Regulations. The most recent Operating Permit, 3

- 1

- 120

- 2 , was issued for the facility on September 6, 2005 . In accordance w ith Chapter 6, Section 3 of the Wyoming Air Quality Standards and Regulations (WAQSR), PacifiCorp will need to modify their operating permit to include changes authorized in this permitting action.

5 40 CFR 51.308(d)(1)(i)(A).PacifiCorp Jim Bridger Power Plant

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CONCLUSION:

The Division is satisfied that PacifiCorp‟ s Jim Bridger Power Plant will comply with all applicable Wyoming Air Quality Standards and Regulations. The Division proposes to issue a BART Air Quality

Permit for modification of the Jim Bridger Power Plant to install new LNB with separated OFA and

ins tall FGC in combination with the existing ESP on Unit s 1

- 4 to meet the statutory requirements of

BART. Jim Bridger Units 3 and 4 shall be equipped with SCR before December 31 , 2015 and December 31, 2016, respectively, for the Long

- Term Strategy of the Wyo ming §308 Regional Haze State Implementation Plan.

I n accordance with Long

- Term Strategy, P acifiCorp shall submit an application to install additional add

on NO

x control on Jim Bridger Units 1 and 2 that achieve s an emission rate, on an individual unit ba sis, at
or below 0.07 lb/MMBtu on a 30

- day rolling average by January 1, 2015 . It shall include an analysis of the four statutory factors and the associated visibility impacts from the application of each proposed NO

x control. Additional a dd

- on NO

x contr ol shall be installed and operational no later than the end of 202 3 calendar year on Unit s 1 and 2

.

PROPOSED PERMIT CONDITIONS:

The Division proposes to issue an Air Quality Permit to PacifiCorp for the modification of the Jim Bridger Power Plant with th e 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 pur pose 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) a nd 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.PacifiCorp Jim Bridger Power Plant

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- 6040 BAR T Application Analysis Page 57

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

req uired by Condition 6 of this permit , e missions from Jim Bridger Units 1 through 4 shall not

exceed the levels below. The NO

x limits shall apply during all operating periods. PM/PM 10 lb/hr and tpy limits shall apply during all operating periods. PM/PM 10 lb/MMBtu limits shall apply during all operating periods except startup. Startup begins with the introduction of fuel into the boiler and ends no later than the point in time when two (2) pulverizers (coal mills) have been placed into service and the flue gas temperature at the inlet ducts to the electrostatic precipitator reaches a temperature of 220 F, as defined as the average flue gas outlet temperature from the air preheaters.

Units Pollutant lb/MMBtu lb/hr tpy

2, 3, & 4 NO

x 0.2 6 (30

- day rolling) 1, 560 (30

- day rolling) 6,833

1, 2, 3 ,& 4 PM/PM 10 (a) 0.030 180 788

(a) Filterable portion only

6. That no later than 90 days after permit issuance NO

x performance tests shall be conducted on Units 2

- 4 and PM/PM 10 performance tests shall be conducted on Units 1

- 4 and a written report of

the results be submitted. If a maximum design rate is not achieved within 90 days of permit

issuance , the Administrator may require testing be done at the rate achieved and again when a

maximum rate is achieved.

7

. Effective upon completion of the initial pe rformance tests to verify the emission levels below, as required by Condition 8 of this permit , emissions from Jim Bridger Unit 1 shall not exceed the levels below. The limits shall apply during all operating periods.

Pollutant lb/MMBtu lb/hr tpy

NO

x 0

. 26 (30

- day rolling) 1,560 (30

- day rolling) 6,833

8. That initial NO

x performance tests shall be conducted on Unit 1after the installation of low NO

x burners and separated overfire air in accordance with Chapter 6, Section 2(j) of the WAQSR,

within 30 da ys 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 do ne at the rate achieved and again when a maximum rate is achieved.PacifiCorp Jim Bridger Power Plant

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- 6040 BAR T Application Analysis Page 58

9

. P erformance tests shall consist of the following :

Coal

- fired Boilers (Units 1 through 4 ):

NO

x Emissions

– Compliance with the NO

x 30

- day rolling average shall be

determined using a continuous emissions monitoring system (CEMS) certified in accordance with 40 CFR part 60.

PM/PM 10 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 Per mit may be s ubmitted to satisfy the testing required by this condition.

10

. Prior to any testing required by this permit, a test protocol shall be submitted to the Division for approval, at least 30 days prior to testing. Notification should be provided to the Division at least 15 days prior to any testing. Results of the tests shall be submitted to this office within 45 days of completing the tests.

1 1

. PacifiCorp shall comply with all requirements of the Regional SO 2 Milestone and Backstop Trading Pro gram in accordance with Chapter 14 , Sections 2 and 3, of the WAQSR.

1 2

. C ompliance with the NO

x limits set forth in this permit for the coal

- fired boilers (Jim Bridger

Units 1

- 4) shall be determined with data from the continuous monitoring systems require d by 40

CFR Part 75 as follows:

a. Exceedances of the NO

x limits shall be defined as follows:

i. Any 30

- day rolling average of NO

x emissions which exceeds the lb/MMBtu limits calculated in accordance with the compliance provisions and monitoring requirement s 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 volum etric flowrate) from the existing CEM equipment which

exceeds the lb/hr NO

x 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 req uirements 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 th e definition as specified in 40 CFR part 60, subpart Da.PacifiCorp Jim Bridger Power Plant

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- 6040 BAR T Application Analysis Page 59

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 reporte d using the procedures and reporting format specified in WAQSR, Chapter 5, Section 2(g).

1 3

. PacifiCorp shall use EPA‟s Clean Air Markets reporting program to convert the monitoring system data to annual emissions. PacifiCorp shall provide substituted da ta 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).

1 4

. C ompliance with the PM/PM 10 limits set forth in this permit for the coal

- fired boilers (Jim Bridger Units 1

- 4) shall be determined with data from t esting 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.

1 5

. 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.

1 6

. PacifiCorp shall install new low NO

x burners with separated overfire air on Unit 1, in accordance with the Division‟s BART determination, and conduct the initial performance tests required in

Condition 8 no later than De cember 31, 201 0.

1 7

. PacifiCorp shall submit a permit application for the installation of selective catalytic reduction (SCR) on Jim Bridger Units 3 and 4 to the Division under the Long

- Term Strategy of the Wyoming §308 Regional Haze State Implementation Plan. This application shall address SCR as a system of continuous emissions reduction achieving 0.07 lb/MMBtu on a 30

- day rolling average as measured by a certified CEM. SCR shall be installed and operational on Jim Bridger Unit 3 by December 31, 2015 a nd on Jim Bridger Unit 4 by December 31, 2016.

1 8

. PacifiCorp shall submit a permit application for the installation of additional add

- on NO

x control on Jim Bridger Units 1 and 2 to the Division no later than January 1, 2015

, under the Long

- Term Strategy of the Wyoming §308 Regional Haze State Implementation Plan. It shall include an analysis of the four statutory factors and the associated visibility impacts from the application of each proposed NO

x control and resulting emission levels

. This applicatio n shall address each

add

- on NO

x control as a system of continuous emissions reduction achieving the lowest viable

NO

x emission

, not to exceed a maximum of 0.07 lb/MMBtu on a 30

- day rolling average as measured by a certified CEM. Additional a dd

- on NO

x cont rol shall be installed and operational on both Jim Bridger Unit 1 and Unit 2 no later than December 31, 202 3

.

# Appendix A Facility Location