DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION

BART Application Analysis

AP

- 604 1

May 2 8 , 2009

NAME OF FIRM: PacifiCorp

NAME OF FACILITY: Dave Johnston Plant

FACILITY LOCATION: Section s 7 and 18 , T 33 N, R 74 W

UTM Zone: 1 3 Easting: 436, 592 m

, Northing: 4, 742

, 918 m

Converse County, Wyoming

TYPE OF OPERATION: Coal

- Fired Electric Generating Plant

RESPONSIBLE OFFICIAL: Gary Slanina , Managing Director

MAILING ADDRESS: 1591 Tank Farm Road Glenrock, WY 82637

TELEPHONE NUMBER: (307) 4 36

- 2001

REVIEWER S : Cole Anderson , Air Quality Engineer Josh Nall, Air Quality Modeler

PURPOSE OF APPLICATION:

Sections 169A and 169B of the 1990 Clean Air Act Amendments require states to improve visibility at Class I areas. On July 1, 1999, EPA fir st published the Regional Haze Rule, which provided specific details regarding the overall program requirements to improve visibility. The goal of the regional haze program is to achieve natural conditions by 2064.

Section 308 of the Regional Haze Rule ( 40 CFR part 51) includes discussion on control strategies for improving visibility impairment. One of these strategies is the requirement under 40 CFR 51.308(e) for certain stationary sources to install Best Available Retrofit Technology (BART) to reduce emissions of three (3) visibility impairing pollutants, nitrogen oxides (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, 2005 Fed eral 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 Decembe r 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 Plan (SI P).PacifiCorp Dave Johnston 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 Commis sion (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

ad dressing SO 2 emissions, which include a market trading program and a provision for a series of SO 2 milestones. Wyoming submitted a §309 Regional Haze SIP to EPA on December 29, 2003. As of the date of this analysis, EPA has not taken action on the SIP. National litigation issues related to the Regional Haze Rule, including BART, required states to submit revisions. On November 21, 2008, the State of Wyoming submitted revisions to the 2003 §309 Regional Haze SIP submittal. Sources that are subject to BA RT 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 22 , 2007 and on January 29, 2007 , in accordance with the requirements of WAQSR Cha pter 6 Section 9(e)(i), the Division received BART applications for two existing coal

- fired boiler s, Units 3 and
4, respectively, at the PacifiCorp Dave Johnston Power Plant . A map showing the location of PacifiCorp‟s Dave Johnston Power Plant is attached as Appendix A.

On June 5, 2007, PacifiCorp submitted additional copies of the January applications for the two (2) units subject to BART at Dave Johnston

.

On October 15, 2007, PacifiCorp submitted updated applications for the two (2) units subject to BA RT at
Dave Johnston . Additional modeling performed after the June 5 , 2007 submittal and revised emissions

reduction calculations were included.

On December 5, 2007, PacifiCorp submitted revised applications incorporating changes to the post

processing of the visibility model runs for each of the two (2) Dave Johnston units.

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

Johnston Units 3 and 4 . Revised cost estimates and updated visibility modeling for two (2) NO

x control

scenarios were included in the addendums.

BART ELIGIBILITY DETERMINATION:

In August of 2005 the Wyoming Air Quality Division began an internal review of sources that could be subject to BART. This initial effort followed the methods prescri bed in 40 CFR part 51, Appendix Y: Guidelines for BART Determinations Under the Regional Haze Rule to identify sources and facilities. The rule requires that States identify and list BART

- eligible sources, which are sources that fall within the

26 source categories, have emission units which were in existence on August 7, 1977 but not in operation before August 7, 1962 and have the potential to emit more than 250 tons per year (tpy) of any visibility impairing pollutant when emissions are aggregated from a ll 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 Dave Johnston 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, Appendix Y as visibility impairing pollutants. They are sulfur dioxide (SO 2 )

, nitrogen oxid es (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 determine visibility impairment of each source, a screening analysis was performed using CALPU FF. 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 screening 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 conditions (Δdv) were determined to be subject to BART. For additional information on the Divisio n‟s screening analysis see the Visibility Improvement Determination: Screening Modeling section of this analysis. Two existing coal

- fired boilers at PacifiCorp‟s Dave Johnston Power Plant , Units 3 and 4, were determined to be subject to BART. PacifiCorp was notified in a letter dated June 14, 2006 of the Division‟s finding.

DESCRIPTION OF BART ELIGIBLE SOURCES:

PacifiCorp‟s Dave Johnston Power Plant is comprised of four (4) units burning pulverized sub

bituminous Powder River Basin coal for a total net generating capacity of a nominal 772 megawatts ( MW )

. Dave Johnston Units 1 and 2 are nominal 106 MW pulverized coal

- fired units . Unit 1 began operation in 1958 and Unit 2 in 1960. Since both units were in operation before August 7, 1962 they are not sub ject to BART regulation. However, Dave Johnston Units 3 and 4 are subject to BART review

. Dave Johnston Unit 3 is a nominal 230 MW pulverized coal

- fired boiler that commenced service in 1964

. It was manu factured by Babcock & Wilcox and equipped with bur ners in a cell configuration

. It is the only boiler in Wyoming subject to BART with burners in a cell configuration . The original burners have not been replaced or upgraded to low NO

x burners

. Dave Johnston Unit 3 is not equipped with any SO 2 control eq uipment

. Particulate matter (PM) emissions from Unit 3 are controlled using a Lodge

- Cottrell single

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

MW pulverized coal

- fired boiler that commenced service i n 1 972

. It is a tangential

- fired boiler and was

manufac tured by Combustion Engineering , now Alstom

. The original burners were replaced in 1976 with

concentric

- firing first generation low NO

x burners (LNB). A Venturi scrubber is used to control PM

emissi ons. Additional SO 2 emission control is achieved in the scrubber by adding lime to the scrubber liquor.

Table 1: Dave Johnston Units 3 & 4 Pre

- 2005 Emission Limits (a)

Source Firing Rate

(MMBtu/hour) Existing

Controls NO

x

(lb/MMBtu) SO 2

(lb/MMBtu) PM/PM 10

(lb/MMBtu) (c)(d)

Unit 3 2, 464 (b) ESP 0.7 5 (3

- hour rolling)
0. 59 (annual) 1.2 (2

- hour block ) 0. 23

Unit 4 4,100 LNB,

Venturi Scrubber 0.7 5 (3

- hour rolling)

0.53 (annual) 1.2 ( 3

- hour block )

0.5 (30

- day rolling) 0.21

(a) Emissions taken from O perating Permit 3 1

- 1 48

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

( b ) Boiler heat input reported in the Operating Permit 3 1

- 148

- 1

. (c) Base d on PM limi t calculation of 0.8963/I 0.1743 lb/MMBtu where I=boiler heat input in MMBtu/hr

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

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On June 27, 2008 , Air Quality Permit MD

- 5098 was issued to PacifiCorp to replace the original burners

on Unit 3 with a new low NO

x firing system including ad ditional advanced overfire air (OFA). In addition, Unit 4‟s first generation LNB will be replaced with Alstom TFS 2000 TM LNB with overfire air

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

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

installation of a new baghouse on Unit 4 are authorized by MD

- 5098. The emission levels established for

Dave Johnston Units 3 and 4 in MD

- 5098 are summari zed in Table 2.

Table 2: Dave Johnston Units 3 & 4 MD

- 5098 Emission Limits (a)

Source Permitted Controls NO

x SO 2 PM/PM 10

Unit 3 New LNB with

advanced OFA, Dry FGD

, Baghouse 0. 28 lb/MMBtu

(12

- month rolling) 784 lb/hr

(12

- month rolling) 0.15 lb/MMBtu

(1 2

- month rolling )
0.5 lb/MMBtu

( 30

- day rolling )
0.5 lb/MMBtu

( 3

- hr block )
420 lb/hr

(24

- hr rolling ) 0.0 15 lb/MMBtu

42.1 lb/hr

18 4 tpy

Unit 4 New LNB with

advanced OFA, Dry FGD

, Baghouse 0. 15 lb/MMBtu

(12

- month rolling) 697 lb/hr

(12

- month rolling) 0.15 l b/MMBtu

( 12

- month rolling )
0.5 lb/MMBtu

( 30

- day rolling )
0.5 lb/MMBtu

(3

- hr block)
615 lb/hr

(24

- hr rolling ) 0.0 15 lb/MMBtu

61.5 lb/hr

269 tpy

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

.

By letter dated July 18, 2008, PacifiCorp notified the Division that construction activities for installation of the FGD/baghouse control equipment on Units 3 and 4 were anticipated to begin July 28, 2008. March
31, 2009 , PacifiCorp notified the Division of the ant icipated startup of Unit 4, with new LNB and advanced OFA installed, on May 23, 2009. The construction activities are in line with the construction schedule proposed by PacifiCo rp in the application for permit MD

- 5098. A construction summary is provided in Table 3.

Table 3: MD

- 5098 Permitted Upgrades to Dave Johnston Units 3 & 4

Source New Low NO

x Burners

with advanced Overfire Air (status, year) New Dry FGD/baghouse (status, year)

Unit 3 Planned, 2010 Initiated, 2008

Unit 4 Initiated , 2009 Initiate d , 2008PacifiCorp Dave Johnston Plant

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CHAPTER 6, SECTION 9

– BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

A BART determination is an emission limit based on the application of a continuous emission reduction technology for each visibility impairing pollutant emitted by a source. It is “...established, on a case

- 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 remainin g useful life of the source, and (5) the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.” 1 A BART analysis is a comprehensive evaluation of potential retrofit technologies with respect to the five criteria above. At the conclusion of the BART analysis, a technology and corresponding emission limit is chosen for each pollutant for each unit subject to BART.

Visibility control options presented in the application for each source were review ed using the methodology prescribed in 40 CFR 51 Appendix Y, as required in WAQSR Chapter 6 Section 9(c)(i). This methodology is comprised of five basic steps:

Step 1: Identify 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 techn ology 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 po ssible that BART may be equivalent to BACT on a case

- by

- case basis. The Division applied all five steps to each visibility impairing pollutant emitted from Dave Johnston Units 3

and 4 thereby conducting a comprehensive BART analysis for NO

x , SO 2 and PM/PM 10

.

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 effectivenes s, 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 units without existing con trol. 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 control options, (3) economi c analysis to determine cost effectiveness for each potentially BART

- eligible EGU, and (4) evaluation of historical emissions and forecast emission reduction for each potentially BART

- eligible EGU.” 3 491 BART

- eligible coal

- fired

units were identified and included in the presumptive BART analysis for SO 2 . Based on removal

1 40 CFR Par t 51 Appendix Y: Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 39163).

2 Footnote 12 of 40 CFR 51 Appendix Y defines the intended use of „all‟ by stating “...you must identify the most stringent option and a reasonable set of options for analysis that reflects a comprehensive list of available technologies.”

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

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efficiencies of 90% for spray dry lime dry flue gas desulfurization systems and 95% for limestone forced oxidation wet flue gas desulfurization systems, EPA calculated projected SO 2 emiss ion 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 $40 0 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 presumpt ive 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 limits for cyclone boilers ar e based on the installation of SCR, a post combustion add

- on control. EPA acknowledged that approximately 25% of the reviewed units could not meet the proposed limits based on current combustion control technology, but that nearly

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

ire air. National average cost effectiveness values for presumptive NO

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

Based on the results of the analyse s 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 than 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 burner 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 discretion to “...determine that an alternative [BART] control level is justified based on a careful consideration of the statutory factors.” 4 The Division‟s following BART analysis for NO

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

PacifiCorp‟s Dave John s ton Power P lant generates a cumulative nominal 772 MW from all four units

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

3 does not have SO 2 controls installed. Unit 4 controls SO 2 emissions using the existing Venturi

scrubber. Neither unit currently operates with NO

x post

- combustion control s . Presumptive SO 2 limits of 95% reduction or 0.15 lb/MMBtu and presumptive NO

x limits of 0.45 lb/MMBtu and 0.1 5 lb/MMBtu, based on unit type and coal type, c ould apply to Unit 3 and Unit 4, respectively. However, the Division required additional analysis of potential retrofit controls for NO

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

NO

x : IDE NTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

PacifiCorp identified four control technologies to control NO

x emissions: (1) low NO

x burners with advanced overfire air, (2) rotating opposed fire air (ROFA), (3) selective non

- catalytic reduction (SNCR),

and (4) selective cataly tic reduction (SCR). LNB with advanced 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 effective ly control NO

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

- rich environment and

4 Ibid. (70 Federal Register 39171).PacifiCorp Dave Johnston Plant

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by enhancing control of air

- fuel mixing throughout the boiler‟s combustion zone. SNCR and SCR are

add

- on contr ols that provide a chemical conversion mechanism for NO

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

used on coal

- fired electric generating units.

1. Low NO

x Burners with Advanced Overfire Air

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

x . Fuel staging occurs in the very beginning of combustion, where the pulverized coal is injected th rough the

burner into the furnace. Careful control of the fuel

- air mixture leaving the burner can limit the amount of oxygen available to the fuel during combustion creating a fuel rich zone that reduces the nitrogen to molecular nitrogen (N 2 ) rather than using oxygen in the combustion air to oxidize the nitrogen to NO

x . The addition of advanced overfire air provides additional NO

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

x is less likely to form. This allows complete co mbustion 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 advanced overfire air technology discussed a bove, 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 b oiler and increase the effective heat absorption. Both of which effectively reduce the formation of NO

x caused by fuel combustion

within the boiler.

3. Selective Non

- Catalytic Reduction

– SNCR is similar to SCR in that it involves the injection of a

reducin g 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 reten tion 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. Selective Catalytic Reduction

– SCR is a post combustion control technique in which vaporized ammonia or urea is injected into the flue gas upstream of a catalyst. 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 injected into the process, unreacted ammonia can be released to the atmosphere through the stack. This release is commonly referred to a s ammonia slip . A well controlled SCR system typically emits less ammonia than a comparable SNCR control system.

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

NO

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

both SNCR and SCR add

- on controls.PacifiCorp Dave Johnston Plant

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NO

x : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

None of the four control technologies proposed to control NO

x emissions were deemed technically infeasible by PacifiCorp.

NO

x : EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

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

BART

- determined permit limit. The limit is based on continuous compliance when the control equipment is well maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit it is important to consider that eve n well maintained and operated equipment will have some emissions variability. Complex emission control equipment, such as LNB with advanced OFA, generally have inherent variability that must be considered when establishing the limit. Otherwise, the sour ce will be out of compliance even though the equipment is operated and maintained as well as possible.

PacifiCorp contracted with Sargent and Lundy (S&L) to conduct a study of applicable NO

x control technologies for the Dave Johnston units and to collect data from boiler vendors. Based on results from the study, PacifiCorp i ndicates that new LNB with advanced OFA on Dave Johnston Units 3 and 4 would

result in a NO

x emission rate of 0.24 lb / MMBtu and 0.15 lb/MMBtu, respectively

. On page 3

- 5 of the

Decembe r 2007 submittal for Dave Johnston Unit 3 and on page 3

- 4 of the December 2007 submittal for

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

3 and 0.15 lb/MMBtu for Unit 4 ] corresponds to a vendor gu arantee plus an added operating margin, not a vendor prediction, and they believe that this emission rate can be sustained as an average between

overhauls.” However, due to unforeseen operational issues associated with retrofitting the boilers, including site specific challenges on Unit 3 equipped with cell burners, PacifiCorp proposes an additional

NO

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

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

Johnston Power Plant with Mobotec‟s ROFA. Mobotec analyzed the operation of existing burners and OFA ports. Typically the existing burner system does not require modification and the existing OFA ports are not used b y a new ROFA system. Instead, computational fluid modeling is performed to determine the location of the new ROFA ports. Mobotec concluded that a NO

x emission rate of 0. 15

lb/MMBtu was achievable on Units 3 and 4 using ROFA technology. PacifiCorp added an additional operating margin of 0.0 4 lb/MMBtu to Unit 3 to account for site specific issues, such as burner configuration , for total proposed emission rate of 0. 19 lb/MMBtu

. No additional operating margin w as applied to Unit 4 so the anticipated emissio n rate is 0.15 lb/MMBtu.

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

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

x emission rate of 0. 24 lb/M MBtu on Unit 3 and 0.15 lb/MMBtu on Unit 4, S&L concluded that SNCR can reduce emissions by 20% resulting in projected emission rate s of 0. 19 lb/MMBtu for Unit 3 and 0.12

lb/MMBtu for Unit 4 . PacifiCorp noted in the analysis that the economics of SNCR are greatly impacted by reagent utilization. When SNCR is used to achieve high levels of NO

x reduction, lower reagent utilization can result in significantly higher operating cost. PacifiCorp did not model visibility improvement from installing SNCR on Unit 3 o n account of the expected marginal emission rate improvement, the burden of significant ongoing parasitic costs, the operating difficulties, and the potential ammonia slip.PacifiCorp Dave Johnston Plant

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S&L prepared the design conditions and cost estimates for installing SCR on D ave Johnston Units 3 and

4 . A high

- dust SCR configuration

, where the catalyst is located downstream from the boiler economizer

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

. T he flue gas ducts

would be routed to a separate reactor containing the catalyst to increase physical space occupied by the catalyst to improve the NO

x removal rate. Additional catalyst would be added to accommodate nitrogen

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

advanced OFA and SCR , PacifiCorp concluded Units 3 and 4 c an achieve a NO

x emission rate of 0.07

lb / MMBtu.

Table 4 : NO

x Emission Rates Per Boiler

Control Technology Unit 3 Resulting NO

x Emission Rate (lb/MMBtu) Unit 4

Resulting NO

x Emission Rate (lb/MMBtu)

Combustion Control 0.7 0 /0.59 (a) 0. 40 /0.53 (a)

New LNB with advanced OFA 0. 2 8 0. 15

R OFA 0. 19 0.15

New LNB with advanced OFA and SNCR 0. 19 0. 12

New LNB with advanced OFA and SCR 0. 07 0. 07

( a) PacifiCorp proposed emission r ate/ a nnual averaged NO

x emissions established through 40 CFR part 7 6 in Operating Permit 31

- 148

- 1.

NO

x : EVALUATE IMPACTS AND DOCUMENT RESULTS

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

. I nstalling new LNB with advanced OFA on Dave Johnston Units 3 and 4 will not significantly impact the boiler efficiency o r forced draft fan power usage, two common potential areas for adverse energy impact often affected by changes in boiler combustion.

In stalling the Mobotec ROFA system has a significant energy impact on Dave Johnston . One 1,900 horsepower (hp) ROFA fan on Unit 3 and one 3,000

- 3,700 hp ROFA fan on Unit 4 are required to induct

a sufficient volume of air into each boiler to cause rotation of the combustion air throughout the boiler. The annual energy impact from operating the proposed ROFA fans is 2 1, 8 00 Mega Watt

- hour (MW

- hr)

for Unit 3 and 3 4

, 1 00 MW

- hr for Unit 4

.

PacifiCorp determined the SNCR system would require between 200 kilo Watt (kW) and 300 kW of additional power to operate pretreatment and injection equipment, pumps, compressors, and control systems. In addition to energy costs associated with the reagent handling and injection, installation of the SCR catalyst will require ad ditional power from the existing flue gas fan systems to overcome the pressure drop across the catalyst. Based on the S&L study, PacifiCorp estimated the additional power requirement for SCR installation on Unit 3 would be approximately 1.6 MW and 2.1 MW for Unit 4.PacifiCorp Dave Johnston Plant

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PacifiCorp evaluated the environmental impacts from the proposed NO

x control technologies. Installing LNB with advanced OFA may increase carbon monoxide (CO) emissions and unburned carbon in the ash, commonly referred to as loss on ignition (LOI). Mobotec has predicted CO emissions and LOI would be the same or lower than prior levels for the ROFA system. The installation of SNCR and SCR could impact the saleability and disposal of fly ash due to higher ammonia levels, and could potentially create a visible stack plume sometimes referred to as a blue plume, if the ammonia injection rate is not well controlled. Other environmental impacts involve the storage of ammonia, especially if anhydrous ammonia is used, and transportation of the ammon ia to the power plant site.

PacifiCorp anticipates operating Dave Johnston Units 3 and 4 indefinitely and did not include life extension costs in the economic analysis. A standard control life of 20 years was used to calculate the capital recovery factor . The annual cost to control was determined using a capital recovery factor based on a 7.1% interest rate. PacifiCorp labor and service costs were used to calculate the annual operating and maintenance costs. Annual power costs, including a cost escala tion 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 metric s are specifically mentioned: cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has extensive experience using cost effectiveness (i.e., dollars per ton of pollutant removed) to evaluate

different control technologies. Incremental cost effectiveness is also used extensively by the Division when comparing emission controls under the BACT process. While the BART and the BACT processes are not necessarily equivalent, control determinations from either proce ss are based on cost effectiveness

and incremental cost effectiveness and are indicative of the economic costs to control emissions. In addition to providing cost effectiveness and incremental cost effectiveness results, PacifiCorp provided

cost informati on 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 c ommonly used to assess the overall effectiveness of pollution control equipment. When performing the presumptive BART limits 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 improvements from the application of the analyzed control measures used to establish presumptive levels were addressed in a separate visibility analysis. As discuss ed in the comprehensive visibility analysis presented later in this analysis as Step 5: Evaluate visibility impacts, the Division evaluated the amount of anticipated visibility improvement gained by the application of additional emission control technology . The Division considered capital cost, annual cost, cost effectiveness, and incremental cost effectiveness in the evaluation of each proposed NO

x emission control. Economic and

environmental costs for additional NO

x controls on Dave Johnston Unit 3 and Unit 4 are summarized in the following tables.PacifiCorp Dave Johnston Plant

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Table 5 : Dave Johnston Unit 3 Economic Costs

Cost Combustion

Control New LNB with

advanced OFA ROFA New LNB with

advanced OFA

and SNCR New LNB with

advanced OFA

and SCR Control Equipment Capital

Cos t $0 $ 17

, 5 00 ,0 00 $ 12

, 054,0 22 $ 2 4

, 035

, 544 $1 29

, 7 00,000

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

Costs $0 $1, 664,775 $ 1, 146,699 $ 2

, 286,501 $1 2

, 338

, 361

Annual O&M Costs $0 $ 10 0

, 000 $ 1

, 237

, 992 $ 392,691 $ 4

, 009

, 159

Annual Cost of Control $0 $ 1, 764

, 775 $ 2

, 384

, 691 $ 2

, 679,192 $ 16

, 347

, 519

Table 6 : Dave Johnston Unit 3 Environmental Costs

Combustion

Control New LNB with

advanced OFA Existing

burners with

ROFA New LNB with

advanced OFA

and SNCR New LNB with

advanced O FA

and SCR

NO

x Emission Rate (lb/MMBtu) 0. 59 0. 2 8 0. 19 0. 19 0.07

Annual NO

x Emission (tpy) 5

, 814 (a) 3,091 ( b ) 2 ,0 97 ( b ) 2,097 ( b ) 773 ( b )

Annual NO

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

Annual Cost of Control $0 $ 1,764,775 $ 2

, 384

, 691 $ 2

, 679,192 $16,347,519

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

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

(a) Annual emissi ons based on unit heat input rate of 2,500 MMBtu/hr and 7

, 884 hours of operation per year

. (b ) Annua l emissi ons based on unit heat input rate of 2,800 MMBtu/hr and 7

, 884 hours of operation per year

. (c ) Incremental cost from installing ROFA cannot be calculated since the reduced tons of NO

x are anticipated to be the same.
Therefore, the incremental cos t from installing new LNB with advanced OFA was calculated.

Table 7 : Dave Johnston Unit 4 Economic Costs

Cost Combustion

Control New LNB with

advanced OFA Existing

burners with

ROFA New LNB with

advanced OFA

and SNCR New LNB

with advanced

OFA and SCR

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

Capital Recovery Factor N/A 0.09513 0.09513 0.09513 0.09513 Annual Capital Recovery

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

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

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

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- 6041 BART Application Analysis Page 12

Table 8 : Dave Johnston Unit 4 Environmental Costs

Combustion

Control New LNB with

advanced OFA Existing

burners with

ROFA New LNB with

advanced OFA

and SNCR New LNB

with advanced

OFA and SCR

NO

x Emission Rate (lb/MMBtu) 0. 53 0. 15 0. 15 0. 12 0.07

Annual NO

x Emission (tpy) (a) 8,566 2,424 2,424 1,940 1,131

Annual NO

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

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

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

ton of Reduction N/A $137 $528 (b)

- $2,274 (c) $17,662

(a) Annual emissions based on individual heat input rate of 4,1 00 MMBtu/hr for 7

, 8 84 hours of operation per year.

(b ) Incremental cost from installing new LNB with advanced OFA cannot be calculated since the reduced tons of NO

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

(c ) I ncremental cost is negative because the annual cost of control for existing burners with ROFA is significantly higher than new

LNB with advanced OFA and SNCR.

The cost effectiveness of the four proposed BART technologies for NO

x are all reasonable. The

i ncremental cost effectiveness is reasonable for all NO

x control technologies except n ew LNB with

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

company

- proposed BART controls for Units 3 and 4 by modeling LNB with advanced OFA and LNB with advanced OFA and SCR. While the installation of SNCR and ROFA were not individually evaluated in Step 5: Evaluate visibility impact, the anticipated degree of visibility improvement from applying either control lies wit hin the modeled range of visibility impacts.

The final step in the NO

x BART determination process for Dave Johnston Units 3 and 4 , Step 5: Evaluate visibility impacts, is addressed in a comprehensive visibility analysis covering all three visibility impai ring pollutants. The visibility analysis follows Steps 1

- 4 for SO 2 emissions in this application analysis. Table 23 on page 34 and Table 24 on page 35 list the modeled control scenarios and associated

emission r ate s.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 13

PM 10 : IDENTIFY AVAILAB LE RETROFIT CONTROL TECHNOLOGIES

Dave Johnston Unit 3 is currently equipped with an electrostatic precipitator ( ESP ) to control PM emissions from the boiler. As discussed below in more detail below, ESP s control PM from the flue gas stream by creating a strong electro

- magnetic field in which fly ash particles gain an electric charge. The existing ESP co ntrols PM emissions to 0.030 lb/ MMBtu. Dave Johnston Unit 4 is equipped with a Venturi particulate scrubber. This technology is no longer the state

- of

- a rt and Pacific did not propose keeping the unit in service as an additional particulate control device. Venturi scrubbers are design ed with a decreasing throat diameter that mechanically forces particles in the flue gas and water droplets together. They are similar to cyclone systems in that particle momentum greatly influences the control efficiency

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

less momentum

. Operating cost is greatly affected by incr easing either the water

- side or air

- side pressure drop, which increases the removal efficiency, but results in increase d electricity cost and operating cost

from the pump and/or motor power providing the additional pressure. PacifiCorp reports 2001 to 200 6

PM emissions data indicate that the Dave Johnston Unit 4 Venturi particulate scrubber controls PM 10 emissions to 0.061 lb/

MMBtu. PacifiCorp analyzed three state

- of

- the

- art PM control technologies for application on Units 3 and 4 : fabric filters or bagho uses, ESPs, and flue gas conditioning.

1. Fabric filters (FF)

– FF are woven pieces of material that collect particles with sizes ranging from submicron to several hundred microns in diameter at efficiencies generally in excess of 99%. The layer of dust tra pped on the surface of the fabric, commonly referred to as dust cake, is primarily responsible for such high efficiency. Joined pores within the cake act as barriers to trap particulate matter too large to flow through the pores as it travels through the cake. Limitations are imposed by the temperature and corrosivity of the gas and by adhesive properties of the particles. Most of the energy used to operate the system results from pressure drop across the bags and associated hardware and ducting.

2. Electr ostatic 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. Th e charged particles are acted upon by an induced electrical field from high voltage electrodes in the gas flow that forces them to the walls or collection plates. Once the particles couple with the collection plates, they must be

removed without re

- entrai ning them into the gas stream. In dry ESP applications, this is usually accomplished by physically knocking them loose from the plates and into a hopper for disposal. Wet ESPs use water to wash the particles from the collector plates into a sump. The ef ficiency 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 Co nditioning (FGC)

– Injecting a conditioning medium, typically SO 3 , into the flue gas can lower the resistivity of the fly ash, improving the particles‟ ability to gain an electric charge. If the material is injected upstream of an ESP the flue gas particl es 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.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 14

PM 10 : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

PacifiCorp did not eliminate the use o f either the baghouse or an ESP to control PM emissions as technically infeasible. However, PacifiCorp did not further analyze the use of FGC. According to PacifiCorp, the existing ES P on Unit 3 is well designed and provides adequate space and residence time for the flue gas particles to gain an electric charge and migrate to the collection plate. The application of FGC is not expected to significantly improve PM / PM 10 removal efficien cy. PacifiCorp did not evaluate the application of FGC on Unit 4 because it is typically used to enhance the removal efficiency of an existing, constrained ESP. The existing Venturi scrubber will likely be replaced by an entirely new PM

contro l device an d the co

- benefit of enhancing dry flue gas desulfurization makes the installation of a more effective state

- of

- the

- art fabric filter the company

- preferred PM control measure over installing a FGC system

.

PM 10 : EVALUATE EFFECTIVENESS OF REMAINING CONTROL T ECHNOLOGIES

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

BART

- determined permit limit. The limit is based on continuous compliance when the control equipment is well maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit it is important to consider that even well maintained and operated equipment will have some emissio ns variability. Complex emission control equipment, such as electrostatic precipitators, generally have inherent variability that must be considered when establishing the limit. Otherwise, the source will be out of compliance even though the equipment is operated and maintained as well as possible.

Unit 3 has an existing ESP and rather than evaluate costs of replacing the unit, PacifiCorp evaluated additional controls to improve the PM removal efficiency. An ESP is an effective PM control device, as

the existing units are already capable of controlling PM 10 emissions from Unit 3 to 0.0 30 lb/MMBtu. The technology continually improves and is commonly proposed for consideration in BACT analyses to control particulate emissions from new PC boilers. In addi tion to maintaining the existing ESP, a polishing fabric filter can be installed downstream of the existing ESPs. PacifiCorp proposed the use of Compact Hybrid Particulate Collector (COHPAC) licensed by Electric Power Research Institute (EPRI).

The COHPA C unit is smaller than a full

- scale fabric filter and has a higher air

- to

- cloth ratio (7 to 9:1), compared to a full

- size pulse jet fabric filter (3.5 to 4:1). COHPAC is effective at controlling particulates not captured by the primary PM control device, but is not designed to treat high PM concentrations in the entire flue gas stream immediately downstream of the boiler. The existing ESP must remain in service for the COHPAC fabric filter to effectively reduce PM/PM 10 emissions. PacifiCorp estimates the application of the COHPAC unit in addition to using FGC with the existing ESP on Unit 3 can reduce emissions an

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

the installation on a new full

- scale fab ric filter on Unit 3 since there is a substantial capital cost associated with the control and no anticipated benefit when compared to COHPAC.

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

technol ogy was not cost effective. In place of the scrubber, a new ESP or a new FF was evaluated for additional PM control. Due to the higher electrical resistivity of western c oals, the ESP is not able to

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

these reasons
, a fabric filter is the company

- pre ferred particulate control device , especially for use with a dry FGD system

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

are shown in Table 9.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 15

Table 9: PM 10 Emission Rates Per Boiler

Source Existing ESP

PM 10 Emission (lb/MMBtu) Polishing FF &

Existing ESP

PM 10 Emission (lb/MMBtu) Exis t ing

Venturi Scrubber

PM 10 Emission (lb/MMBtu) New ESP

PM 10 Emission (lb/MMBtu) N ew Full

- scale FF

PM 10 Emission (lb/MMBtu)

Unit 3 0.030 0.015

-- -- --

Unit 4

-- -- 0.061 0.030 0.015

PM 10 : EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impact of installing the COHPAC retrofit on Unit 3 . The pressure drop

cre ated by the fabric filter and associated ductwork requires additional energy from the existing draft fan, which will have to be upgraded. PacifiCorp calculated the additional energy costs based on an 85 percent annual plant capacity factor. The installat ion of a COHPAC fabric filter would require approximately 1.4 MW of power, equating to an annual power usage of approximately 10.3 million kW

- h r

. Similar to the installation of the COHPAC on Unit 3, the installation of a full

- scale fabric filter on Unit 4 would incur energy losses from the additional pressure drop. PacifiCorp calculated the additional energy costs from

the installation of the fabric filter based on a 90 percent annual plant capacity factor . The fabric filter would require approximately 2 .4 MW of power, equating to an annual power usage of approximately 18.5

million kW

- h r

. PacifiCorp‟s pr oposed PM control on Unit 4 is the full

- scale fabric filter . No costs were provided for the installa tion and operation of a new ESP on Unit 4.

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

and the installation of a new fabric filter on Unit 4. PacifiCorp did not antici p ate negative environmental impacts from the addition of either control technologies on the two units.

PacifiCorp anticipates operating Dave Johnston Units 3 and 4 indefinitely and did not include life extension costs in the economic analysis. A standard control life of 20 years was used to calculate the capital recovery factor. The ann ual cost to control was determined using a capital recovery factor based on a 7.1% interest rate. PacifiCorp labor and service costs were used to calculate the annual operating and maintenance costs. Annual power costs, including a cost escalation facto r, 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 spec ifically 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 technolog ies. Incremental cost effectiveness is also used extensively by the Division when comparing emission controls under the BACT process. While the BART and the BACT processes are not necessarily equivalent, control determinations from either process are bas ed on cost effectiveness

and incremental cost effectiveness and are indicative of the economic costs to control emissions. In addition to providing cost effectiveness and incremental cost effectiveness results, PacifiCorp provided

cost information in term s 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 us ed to assess the overall effectiveness of pollution control equipment. When performing the presumptive BART limits analysesPacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 16

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 improvements from the application of the analyzed control measures used to establish presumptive levels were addressed in a separate visibility analysis. As discussed in the comprehensive visibility analysis presented later in this analysis as Step 5: Evaluate visibility impacts, the Division evaluated the amount of anticipated visibility improvement gained by the application of additional emission control technology. The Div ision considered capital cost, annual cost, cost effectiveness, and incremental cost effectiveness in the evaluation of each proposed PM/PM 10 emission control. Economic

and environmental costs for additional PM/PM 10 controls on Dave Johnston Unit 3 and Un it 4 are summarized in the following tables.

Table 10 : Dave Johnston Unit 3 Economic Costs

Cost Existing ESP Existing ESP and

New COHPAC

Fabric Filter

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

Capital Recovery Factor N/A 0.09513

Annual Capital Rec overy Costs $0 $ 2

, 834

, 451

Annual O&M Costs $0 $ 809,282

Annual Cost of Control $0 $ 3

, 643

, 733

Table 11 : Dave Johnston Unit 3 Environmental Costs

Existing ESP Existing ESP and

New COHPAC

Fabric Filter

PM 10 Emission Rate (lb/MMBtu) 0.0 30 0.0 15

Annual P M 10 Emission (tpy) (a) 331 16 5

Annual PM 10 Reduction (tpy) N/A 1 66

Annual Cost of Control $0 $ 3,643

, 733

Cost per ton of Reduction N/A $ 21

, 950

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

(a) Annual emissi ons based on unit heat input rate of 2, 8 00 MMBtu/hr and 7

, 884 hours of operation per year

.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 17

Table 12 : Dave Johnston Unit 4 Economic Costs

Cost Existing

Venturi Scrubber New Fabric Filter

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

Capital Recovery Factor N/A 0.09513

Annual Capital R ecovery Costs $0 $ 4

, 763

, 485

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

Annual Cost of Control $0 $ 6

, 047

, 573

Table 13 : Dave Johnston Unit 4 Environmental Costs Existing

Venturi Scrubber New Fabric Filter

PM 10 Emission Rate (lb/MMBtu) 0.061 0.0 15

Annual PM 10 Em ission (tpy) (a) 986 242

Annual PM 10 Reduction (tpy) N/A 744

Annual Cost of Control $0 $ 6

, 047

, 573

Cost per ton of Reduction N/A $ 8

, 1 29

Incremental Cost per ton of Reduction N/A $ 8

, 1 29

(a) Annual emissi ons based on unit heat input rate of 4,100 MMBtu/h r and 7

, 884 hours of operation per year

.

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

3 and a new full

- scale fabric filter on Unit 4 are not reasonable. However, the control s w ere included i n the final step in the PM/PM 10 BART determination process for Dave Johnston Units 3 and 4 , Step 5: Evaluate visibility impacts, which is addressed in a comprehensive visibility analysis covering all three visibility impairing pollutants. The visibility a nalysis follows Steps 1

- 4 for SO 2 emissions in this application analysis. Table 23 on page 34 and Table 24 on page 35 list the modeled control scenarios and

associated emission r ate s.

SO 2 : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

PacifiCorp revi ewed a broad range of informat ive sources, including EPA‟s RACT/BACT/LAER clearinghouse, in an effort to identify applicable SO 2 emission control technologies for Dave Johnston Units 3 and 4. Based on the results of this review, PacifiCorp proposed wet fl ue gas desulfurization (W FGD) and dry flue gas desulfurization ( D FGD) as potential retrofit technologies to reduced SO 2 emissions.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 18

1. Wet FGD

– SO 2 is removed through absorption by mass transfer as soluble SO 2 in the exhaust gas

mixture is dissolved in a n 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 equilibrium concentration of the gaseous SO 2 . The rate of SO 2 mass transfer between the tw o 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/alkali 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 scrubbers can be as high as 99%.

2. Dry FGD

– Dry scrubbers are similar to sorbent injec tion systems in that both systems introduce media directly into the flue gas stream, however the addition of the dry scrubber vessel provides greater contact area for adsorption and enhances chemical reactivity. A spray dryer dry scrubber sprays an atomiz ed 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, which reacts with the alkali to form a sulfate or sulfite. The resulting dry product is captured in the particulate control and physically moved from the exhaust gas into a storage bin. The dry by

- product may be dissolved back into the lime slurry or dried and sold as a gypsum by

- product. Spray dryer dry scrubbers typically require lowe r 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 f or spray dryer dry scrubbers can range from 70% to 95%.

SO 2 : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

PacifiCorp did not eliminate either control technology listed above as technically infeasible. Both dry

FGD and wet FGD are proven SO 2 control technolo g ies. PacifiCorp analyzed the impact of both SO 2 emission reduction technologies on Dave Johnston Units 3 and 4.

SO 2 : EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

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

BART

- determined permit limit. The limit is based on continuous compliance when the control equipment is well maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit it is important to consider that even well maintained and operated equipment will have some emissions variability. Complex emission control equipment, such as wet FGD, generally have inhere nt variability that must be considered when establishing the limit. Otherwise, the source will be out of compliance even though the equipment is operated and maintained as well as possible.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 19

PacifiCorp evaluated the application of D FGD on Unit 3 using th e existing ESP to remove particulates formed by injecting the lime slurry into the flue gas. This combination of control devices is projected to

achieve 81.7 % SO 2 removal resulting in a SO 2 emission rate of 0.22 lb/MMBtu, based on a average

sulfur conten t of 0.47% by weight in the feed coal. The combination of the existing ESP and a new polishing fabric filter is projected to reduce SO 2 emissions by 87.5%, resulting in a controlled SO 2 emis sion rate of 0.15 lb/

MMBtu from Unit 3 using a 0.47% coal sulfur content. If the existing ESP on Unit 3 is replaced with a new full

- scale fabric filter, DFGD is anticipated to reduce SO 2 emissions down to 0.12 lb/MMBtu. PacifiCorp did not provide cost information for installing a full

- scale fabric filter on

Unit 3, so the technology was not considered any further in th e SO 2 analysis

.

DFGD with a new full

- scale fabric filter capable of treating the ent ire flue gas stream on Unit 4 is projected to achieve 87.5 % SO 2 removal , resulting in an emission rate of 0.15 lb/MMBtu . An average coal sulfur content of 0.47% by weight was used to calculate the emission reduction

.

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

several variations from vendors. Wet lime/limestone s cru bbing is projected to achieve a SO 2 removal rate

of 95% and an outlet SO 2 emis sion rate of 0.058 lb/MMBtu, based on a sulfur content of 0.47% by weight

in the feed coal.

A new wet lime/limestone FGD system with a new full

- scale fabric filter applied to Unit 4 is projected to

achieve 91.7% SO 2 removal, resulting in an outlet emission rate of 0.10 lb/ MMBtu based on a sulfur content of 0.47% by weight. PacifiCorp noted in the analysis for Unit 4 that they consider it to be technically infeasible for a new wet FGD system to achieve a 95% SO 2 removal

, 0.06 lb/ MMBtu

, on a continuous basis. PacifiCorp evaluated SO 2 controls for Unit 4 to meet presumptive levels for SO 2 . T he application of wet FGD with a new full

- scale fabric filter on Unit 4 is capable of co ntinuously reducing

SO 2 emissions by 90% resulting in a SO 2 emission rate of 0.10 lb/MMBtu , below the 0.15 lb/MMBtu presumptive SO 2 l imit

.

Table 14 : Dave Johnston Unit 3 SO 2 Emission Rates

Control Technology SO 2 Emission Rate (lb/MMBtu)

Combustion Cont rol 1.2 0

Dry FGD with existing ESP 0.22

Dry FGD with existing ESP and Polishing Fabric Filter 0.15

Dry FGD with Fabric Filter 0.12

Wet Lime FGD with existing ESP 0. 06PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 20

Table 15 : Dave Johnston Unit 4 SO 2 Emission Rates

Control Technology SO 2 E mission Rate (lb/MMBtu)

Combustion Control 1.2 0

Dry FGD with Fabric Filter 0.15

Wet FGD with Fabric Filter 0.10

SO 2 : EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impacts of applying a dry FGD system with the existing ESP on U nit 3. DFGD requires less electric power than a wet FGD system. A dry FGD system on Dave Johnston 3 using the existing ESP would require approximately 2.5 MW of power, while a wet FGD would require approximately 3.5 MW

. T his equate s to an annual power s avings of approximately 7.5 million kW

- h r for dry FGD, when the plant operates at 90 % ca pacity for the year. Applying a dry FGD system with a new

full

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

MW f or wet FGD with a new fabric filter

. D ry FGD on Unit 4 to control SO 2 emission could generate a power saving s of approximately 13.8 million kW

- h r if the unit operates for 90% of its annual capacity.

PacifiCorp compared the environmental i mpacts of dry FG D v ersus wet FGD technology. PacifiCorp concluded that dry FGD has five significant environmental advantages over wet FGD . These advantages are taken directly from PacifiCorp‟s environmental analyses for SO 2 controls on Dave Johnston Units 3

and 4 and li sted below.

Sulfuric Acid Mist Sulfur trioxide (SO 3 ) in the flue gas, which condenses to liquid sulfuric acid at temperatures below the acid dew point, is removed efficiently with a lime spray dryer system. Wet scrubbers capture less than 40 to 60 perce nt of SO 3 and may require the addition of a wet electrostatic precipitator (ESP) or hydrated lime injection when medium to high sulfur coal is

burned in a unit to remove the balance of SO 3 . Otherwise, the emission of sulfuric acid mist, if

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

Plume Buoyancy Flue gas following a dry FGD system is not saturated with water (gas temperature 30°F to 50°F above dew point), which reduces or eliminates a visible moisture plume. Wet FGD scrubbers produce flue gas saturated with water, which would require a gas

- gas heat exchanger to reheat the flue gas if it were to operate as a dry stack. Because of the high capital and operating costs associated with heating the flue gas, all recent wet FGD systems in the United States have used wet stack operation.

Liquid Waste Disposal There is no liquid waste from a dry FGD system. However, wet FGD systems produce a wastewater blowdown stream that must be treated to limit chloride buildup in the absorber scrubbing loop. In some cases, a wastewater treatment plant must be installed to treat the liquid waste prior to disposal. The wastewater treatment plant would produce a small volume of solid waste, which may be contaminated with toxic m etals (including mercury), requiring proper disposal.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 21

Solid Waste Disposal The creation of a wet sludge from the wet FGD process creates a solid waste handling and disposal challenge. This sludge must be handled properly to prevent groundwater contamina tion. Wet FGD systems can produce saleable gypsum if a gypsum market is available, reducing the quantity of solid waste from the power plant to be disposed.

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

waste mater ial and requiring less makeup water in the absorber. Given that water is a valuable commodity in Wyoming, the reduced water consumption required for dry FGD is major advantage for this technology.

PacifiCorp anticipates operating Dave Johnston Units 3 an d 4 indefinitely and did not include life extension costs in the economic analysis. A standard control life of 20 years was used to calculate the capital recovery factor. The annual cost to control was determined using a capital recovery factor based

on a 7.1% interest rate. PacifiCorp labor and service costs were used to calculate the annual operating and maintenance costs. Annual power costs, including a cost escalation factor, associated with the operation of pollution controls were included.

Sever al different metrics can be considered when evaluating the cost

- benefit relationships of different emission control technologies. In 40 CFR part 51 Appendix Y two metrics are specifically mentioned:

cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has extensive experience using cost effectiveness (i.e., dollars per ton of pollutant removed) to evaluate different control technologies. Incremental cost effectiveness is also used extensively by the Divisio n when comparing emission controls under the BACT process. While the BART and the BACT processes are not necessarily equivalent, control determinations from either process are based on cost effectiveness

and incremental cost effectiveness and are indicati ve of the economic costs to control emissions. In addition to providing cost effectiveness and incremental cost effectiveness results, PacifiCorp provided cost information in terms of cost of applying emission controls and the level of visibility improvem ent achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and visibility improvement differences between control options, it is not commonly used to assess the overall effectiveness of pollution control equipment. When performing the presumptive BART limits analyses

for 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.

Visibi lity improvements from the application of the analyzed control measures used to establish presumptive levels were addressed in a separate visibility analysis. As discussed in the comprehensive visibility analysis presented later in this analysis as Step 5 : Evaluate visibility impacts, the Division evaluated the amount of anticipated visibility improvement gained by the application of additional emission control technology. The Division considered capital cost, annual cost, cost effectiveness, and

incremen tal cost effectiveness in the evaluation of each proposed SO 2 emission control. Economic and

environmental costs for additional SO 2 controls on Dave Johnston Unit 3 and Unit 4 are summarized in the following tables.PacifiCorp Dave Johnston Plant

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Table 16 : Dave Johnston Unit 3 Economic Costs

Cost Existing

Combustion

Control Dry FGD

w ith ESP Dry FGD w ith

ESP and Polishing

Fabric Filter Wet FGD

w ith ESP Control Equipment Capital

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

Capital Recovery Factor N/A 0.09513 0.09513 0.0951 3

Annual Capital Recovery

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

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

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

Table 17 : Dave Johnston Unit 3 Environmental Costs

Exis ting

Combustion

Control Dry FGD

with ESP Dry FGD with

ESP and Polishing

Fabric Filter Wet FGD

with ESP

SO 2 Emission Rate (lb/MMBtu) 1.2 0.22 0.15 0.06

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

Annual SO 2 Reduction (tpy) N/A 10,888 11,660 12 ,654

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

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

Incremental Cost per ton of

Reduction N/A $1,209 $10,700

- $1,658 (b)

(a) Annual emissi ons based on unit heat input rate of 2,8 00 MMBtu/hr and 7

, 884 hours of operation per year

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

FGD with ESP

.

Table 18 : Dave Johnston Unit 4 Economic Costs

Cost Existing

Combustion

Control Dry FGD w ith

Full

- scale

Fabric Filter Wet FGD with

Full

- scale

Fabric Filter

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

Capital Recovery Factor N/A 0.09513 0.09513

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

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

Annual Cost of Control $0 $28,444,220 $34,469,576PacifiCorp Dave Johnston Plant

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Table 19 : Dave Johnston Unit 4 Environmental Costs Existing

Combustion

Control Dry FGD with

Full

- scale

Fabric Filter Wet FGD with

Full

- scale

Fabri c Filter

SO 2 Emission Rate (lb/MMBtu) 0.5 (a) 0.15 0.10

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

Annual SO 2 Reduction (tpy) 0 5,657 6,465

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

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

Increme ntal Cost per ton of

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

(a) 30

- day rolling average SO 2 limit from Operating Permit 3 1

- 1 48

- 1 used as baseline.

( b ) Annual emissi ons based on unit heat input rate of 4,100 MMBtu/hr and 7

, 884 hours of operation per year

.

The cost e ffectiveness and incremental cost effectiveness of the proposed wet FGD and dry FGD controls for Units 3 and 4 are reasonable, except for the incremental cost effectiveness of installing a new polishing fabric filter with dry FGD on Unit 3. The final step in the SO 2 BART determination process for

Dave Johnston Units 3 and 4 , Step 5: Evaluate visibility impacts, is addressed in a comprehensive visibility analysis presented in the next section of this BART application analysis. The Division

evaluated the am ount of visibility improvement 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. Table 23 on page 34 and Table 24 on page 35 list the modeled control scena rios and associated emission r ate s.

VISIBILITY IMPROVEMENT DETERMINATION :

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

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

of the various options for control technology. This factor was evaluated for the PacifiCorp Dave Johnston plant with an EPA

- approved dispersion modeling system (CALPUFF) to predict the change s in Class I area visibility. The Division had previously determined that the f acility was subject to BART based on the results of initial screening modeling using current (baseline) emissions from the facility. The screening modeling, as well as m ore refined modeling conducted by the ap plicant

, is described in detail

below.

Wind Cave and Badlands National Parks (NP) in South Dakota are Class I areas located to the northeast of the plant at a distance of approximately 200 kilometers (km) and 290 km, respectively. Toward the

south in C olorado, Rawah Wilderness Area (WA) and Mount Zirkel WA are both located approximately 220 km from the plant, with Rocky Mountain NP located beyond Rawah WA.PacifiCorp Dave Johnston Plant

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Only those Class I areas most likely to be impacted by the Dave Johnston sources were mode led, as determined by source/Class I area locations and professional judgment considering meteorological and

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

Wind Cave NP

Badlands NP

Rawah WA

Mount Zirkel WA

Rocky Mountain National Park (RMNP) was not modeled because it is located along a similar direction from the plant as Rawah WA (a path of less frequent plume transport ), and it can be reasonably assumed

that RMNP would experience lower predicted impacts t han those at Rawah WA. Figure 1 shows the relative locations of the plant and the nearest Class I areas.PacifiCorp Dave Johnston Plant

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Figure 1

Dave Johnston Power Plant and Class I AreasPacifiCorp Dave Johnston Plant

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SCREENING MODELING

To determine if the Dave Johnston pl ant would be subject to BART, the Division conducted CALPUFF visibility modeling for the closest Class I areas downwind of predominant wind flows (Wind Cave NP and Badlands NP) using three years of meteorological data. These data, from 2001

- 2003 , consiste d of surface and upper

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

Mesoscale Model ( MM5 ) . Resolution of the MM5 data was 36

- km for all three of the modeled years.

P otential emissions for current operation from the two BA RT

- eligible, coal

- fired boilers at the Dave

Johnston plant were input to the model

.

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 Badlands NP and Wind C ave NP 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 source contributes to visibility impairment, and therefore is subjec t to BART. The results of the screening modeling are shown in the table below.

Table 20 : Results of the Class I Area Screening Modeling

Class I Area Maximum

Modeled Value (Δdv) 98 th

Percentile Value (Δdv)

2001

Badlands NP 4.3 2.6

Wind Cave NP 4.5 2. 5

2002

Badlands NP 4.0 2.0

Wind Cave NP 4.7 2.2

200 3

Badlands NP 3.5 2.4

Wind Cave NP 4.3 3.3

Δdv = delta deciview

NP = national park

REFINED MODELING

Because of the results of the Division‟s screening modeling, PacifiCorp was required to co nduct a BART analysis that included refined CALPUFF visibility modeling for the facility. The modeling approach followed the requirements described in the Division‟s BART modeling protocol, BART Air Modeling

Protocol

- Individual Source Visibility Assessm ents for BART Control Analyses (WDEQ

- AQD, September 2006). Pacificorp‟s modeling included assessments of the impacts at Wind Cave NP and Badlands NP, as required by the Division‟s BART modeling protocol. The Division supplemented PacifiCorp‟s analyses wi th model runs for Rawah and Mount Zirkel Wilderness A reas in Colorado.PacifiCorp Dave Johnston Plant

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CALPUFF System

Predicted visibility impacts from the Dave Johnston plant sources were determined with the EPA CALPUFF modeling system, which is the EPA

- preferred modeling syst em 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.

The CALPUFF modeling system consists of a meteorological data pre

- processor (CALMET), an air dispersion model (CALPUFF), and post

- processor programs (POSTUTIL, CALSUM, CALPOST). T he 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 de velops 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 height, land use, and surface roughness are included in t he input to CALMET. The CALMET model allows the user to “weight” various terrain influence parameters in the vertical and horizontal directions by defining the radius of influence for surface and upper

- air stations.

CALPUFF is a multi

- layer, Lagrangian puff dispersion model. CALPUFF can be driven by the 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 consistent with the meteorological file s used to drive stea dy

- state dispersion models. All far

- field modeling assessments described here were completed using the

CALPUFF model in a refined mode.

CALSUM is a post

- processing program that can operate on multiple CALPUFF output files to combine

the results for furth er post

- processing. POSTUTIL is a post

- processing program that processes

CALPUFF concentrations and wet/dry flux files . The POSTUTIL model operates on one or more output data files from CALPUFF to sum, scale, and/or compute species derived from those tha t 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 the impacts to visibility.

All of the refined CALPUFF m odeling was conducted with the version of the CALPUFF system that was recognized as the EPA

- approved release at the time of the development of the Division‟s modeling protocol. Version designations of the key programs are listed in the table below.

Table 21 : Key Programs in CALPUFF System
Program Version Level

CALMET 5.53a 040716

CALPUFF 5.711a 040716

CALPOST 5.51 030709PacifiCorp Dave Johnston Plant

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Meteorological Data Processing (CALMET)

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

three

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

- air observations were input to CALMET to adjust the initial windfield, but because of the relative scarcity of wind observations in the modeling domain, the influence of the observations on the initial windfield was minimized

. Because the MM5 data were afforded a high degree of influence on the CALMET windfields, the

Division obtained MM5 data at 12

- km resolution that spanned the years 2001

- 2003.

Locations of the obs ervations that were input to CALMET , including surface, upper

- air, and precipitation stations, are shown in the figure below. Default settings were used in the CALMET input files for most of the technical options. The following table lists the key user

- d efined CALMET settings that were

selected.

Table 22 : Key User

- Defined CALMET Settings

Variable Description Value

PMAP Map projection LCC

DGRIDKM Grid spacing (km) 4

NZ Number of layers 10

ZFACE Cell face heights (m) 0, 20, 40, 100, 14 0, 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 Maximum radius of influence (layers

aloft, km) 50

TERRAD Radius of influence for terrain (km) 15

R1 Relative weighting of first guess wind field and observations (km) 5

R2 Relative weighting aloft (km) 25PacifiCorp Dave Johnston Plant

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Figure 2 Observations Input to CALMETPacifiCorp Dave Johnston Plant

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CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry

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

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

Rocky Mountain NP , C olorado
Craters of the Moon National Monument, Idaho Highland, Utah Thunder Basin, Wyoming Yellowstone NP, Wyoming Centennial, Wyoming Pinedale, Wyoming

For any hour that was missing ozone data from all stations, a default value of 44 parts per billion (p pb) 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 from the National Park Service ( NPS ) Class I Receptors database and converted to the appropriate

Lambert Conformal Conic coordinates. Figure s 3

- 6 show the receptor configuration s that w ere used for Badlands NP

, Wind Cave NP , Rawah WA, and Mount Zirkel WA

. Receptor spacing within Wind Cave NP is approximately 0.7 km i n the east

- west direction and approximately 0.9

km in the north

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

in the east

- west direction and approximately 1.8 km in the north

- south direction. For the

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

east

- west direction and approximately 1.9 km in the north

- south direction.PacifiCorp Dave Johnston Plant

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Figure 3 Receptors for Wind Cave NP

Figure 4 Receptors for Badlands NPPacifiCorp Dave Johnston Plant

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Figure 5

Re ceptors for Rawah WAPacifiCorp Dave Johnston 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 Unit 3 and Unit 4 at
the Dave Johnston p lant are show n in the table s below

.P acifiCorp Dave Johnston Plant

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Table 23 : CALPUFF Inputs for Dave Johnston Unit 3PacifiCorp Dave Johnston Plant

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Table 24 : CALPUFF Inputs for Dave Johnston Unit 4PacifiCorp Dave Johnston Plant

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V isibility Post

- Processing (CALPOST)

The changes in visibility were mo deled using Method 6 within the CALPOST post

- processor. Method 6 requires input of monthly relative humidity factors [f(RH)] for each Class I area. Monthly f(RH) factors

that were used for this analysis are shown in the table below.

Table 25 : Relative Humidity Factors for CALPOST

Month Rawah

WA Mount

Zirkel WA Badlands

NP &

Wind Cave

NP January 2.10 2.20 2.65

February 2.10 2.20 2.65

March 2.00 2.00 2.65

April 2.10 2.10 2.55

May 2.30 2.20 2.70

June 2.00 1.80 2.60

July 1.80 1.70 2.30

August 2.00 1.80 2.30

September 2.00 2.00 2.20

October 1.90 1.90 2.25

November 2.10 2.10 2.75

December 2.00 2.10 2.65

According to the final BART rule, n atural background 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 Class I area on an annual basis, but does not provide the individual s pecies 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 by the g uidance table annual concentrations, the 20 percent best da ys deciview value s for that particular Class I area would be

calculated.

The scaling procedure is illustrated here for Badlands NP . From Appendix B in the EPA natural visibility guidance document, the deciview value for the 20 percent best days at Badla nds NP is 2.18 dv. To obtain the speciated background concentrations representative of the 20 percent best days, the deciview value ( 2.18 dv) was first converted to light extinction. The relationship between deciviews and light extinction is expressed as follows:

dv = 10 ln (b ext

/10) or b ext = 10 exp (dv/10)PacifiCorp Dave Johnston 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 2

. 18 , one obtains a n equivalent light extinction

value of 12. 44 Mm - 1

. Next, the annual average natural visibility concentrations were set equal to a total

extinction value of 12. 44 Mm - 1 . The relationship between total light extinction and the individual components of the light extinction is as follows:

b ext = (3)f(RH)[ammo nium 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 concentrations in μg/m 3

values in parenthesis represent scattering efficienc ies 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)

Substituting the annual average natural background concentrations, the aver age f(RH) for Badlands NP

, and including a coefficient for scaling, one obtains:

12. 44 = (3)(2. 55 )[0.12]X + (3)(2. 55 )[0.1]X + (0.6)[3.0]X + (4)[0.47]X + (1)[0.5]X + (10)[0.02]X + 10

In the equation above, X represents a scaling factor needed to convert t he annual average natural background concentrations to values representative of the 20 percent best days. Solving for X provides a

value of 0. 402 . Table 26 presents the annual average natural background concentrations, the calculated scaling factor, and the calculated background concentrations for the 20 percent best days for Badlands

NP

.



### Table 26 : Calculated Background Components for Badlands NP

Component Annual Average for

West Region 

### (μg/m 3 

### ) Calculated Scaling

Factor 20% Best Days for

Badlands NP 

### (μ g/m 3 

### )

Ammonium Sulfate 0.12 0. 402 0.048

Ammonium Nitrate 0.10 0.402 0.040 Organic Carbon 0.47 0.402 0.189

Elemental Carbon 0.02 0.402 0.008

Soil 0.50 0.402 0.201

Coarse Mass 3.00 0.402 1.205

The scaled aerosol concentrations were averaged for Badla nds NP and Wind Cave NP because of their geographical proximity and similar annual background visibility. The 20 percent best days aerosol

concentrations for the four Class I areas in question are listed in the table below.PacifiCorp Dave Johnston Plant

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Table 27 : Natural Backgroun d Aerosol Concentrations (μg/m 3 )

Aerosol Component Rawah WA Mount

Zirkel WA Wind Cave

NP &

Badlands NP

Ammonium Sulfate 0.045 0.046 0.047

Ammonium Nitrate 0.038 0.038 0.040

Organic Carbon 0.178 0.179 0.186

Elemental Carbon 0.008 0.008 0.008

Soil 0.189 0.190 0.198

Coarse Mass 1.135 1.141 1.191

Visibility Post

- Processing Results

The results of the visibility modeling for each of the two units for the baseline and control scenarios are shown in the table s below. For each scenario, the 9 8 th percentile Δdv results are reported

, along with the total number of days for which the predicted impacts exceeded 0.5 dv. Following the tables are figures that present the results graphically for baseline, the BART configuration proposed by PacifiCorp, and for the p roposed BART configuration with the addition of SCR. Note that t he Division‟s modeling for the
Class I areas in northern Colorado examined baseline, Scenario A (proposed BART) , and Scenario B (proposed BART + SCR) only.P acifiCorp Dave Johnston Plant

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

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days > 0.5

Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– ESP

Badlands NP 1.635 59 1.176 37 1.652 47 1.488 48

Wind Cave NP 1.596 57 1.806 43 2.406 49 1.936 50

Post

- Control Scenario 1

– LNB w/ advanced OFA, Dry FGD, ESP

Badlands NP 0.477 7 0.351 4 0.478 7 0.435 6

Wind Cave NP 0.567 10 0.488 7 0.748 11 0.601 9

Post

- Control Scenario 2

– LNB w/ advanc ed OFA, Dry FGD, Fabric Filter

Badlands NP 0.378 6 0.305 0 0.401 3 0.361 3

Wind Cave NP 0.481 5 0.404 5 0.624 10 0.503 7

Post

- Control Scenario 3

– LNB w/ advanced OFA and SCR, Dry FGD, Fabric Filter

Badlands NP 0.208 1 0.143 0 0.188 0 0.180 0

Wind Cav e NP 0.213 1 0.211 0 0.305 1 0.243 1

Post

- Control Scenario 4

– LNB w/ advanced OFA and SCR, Wet FGD, ESP, New Stack

Badlands NP 0.253 3 0.155 0 0.233 0 0.214 1

Wind Cave NP 0.269 1 0.205 0 0.312 1 0.262 1

Post

- Control Scenario A

– Committed Controls: L NB w/ advanced OFA, Dry FGD, Fabric Filter

Badlands NP 0.448 7 0.36 0 4 0.469 6 0.426 6

Wind Cave NP 0.57 0 10 0.48 0 5 0.735 11 0.595 9

Post

- Control Scenario B

– Committed Controls + SCR

Badlands NP 0.23 0 3 0.168 0 0.218 0 0.205 1

Wind Cave NP 0.249 1 0 .241 0 0.345 2 0.278 1PacifiCorp Dave Johnston Plant

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Table 29 : CALPUFF Visibility Modeling Results for Dave Johnston Unit 4 (South Dakota Class I Areas)

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days > 0.5

Δdv 98th

Percentile

Value (Δdv) No. o f

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– Venturi Scrubber

Badlands NP 1.347 50 1.1 00 29 1.449 45 1.299 41

Wind Cave NP 1.527 47 1.344 37 2.078 40 1.650 41

Post

- Co ntrol Scenario 1

– LNB w/ advanced OFA, Dry FGD, Fabric Filter

Badlands NP 0.456 6 0.34 0 3 0.48 0 7 0.425 5

Wind Cave NP 0.467 7 0.465 7 0.751 10 0.561 8

Post

- Control Scenario 2

– LNB w/ advanced OFA, Wet FGD, Fabric Filter

Badlands NP 0.454 7 0.336 2 0 .437 5 0.409 5

Wind Cave NP 0.551 9 0.46 0 5 0.663 10 0.558 8

Post

- Control Scenario 3

– LNB w/ advanced OFA and SCR, Dry FGD, Fabric Filter

Badlands NP 0.326 4 0.23 0 1 0.329 1 0.295 2

Wind Cave NP 0.353 3 0.347 3 0.492 7 0.397 4

Post

- Control Scenario 4

– LNB w/ advanced OFA and SCR, Wet FGD, Fabric Filter

Badlands NP 0.409 4 0.262 0 0.327 1 0.333 2

Wind Cave NP 0.443 4 0.339 3 0.518 8 0.433 5

Post

- Control Scenario A

– Committed Controls: LNB w/ advanced OFA, Dry FGD, Fabric Filter

Badlands NP 0.456 6 0.34 0 3 0.48 0 7 0.425 5

Wind Cave NP 0.469 7 0.465 7 0.751 10 0.562 8

Post

- Control Scenario B

– Committed Controls + SCR

Badlands NP 0.326 4 0.23 0 1 0.327 1 0.294 2

Wind Cave NP 0.354 3 0.347 3 0.492 7 0.398 4PacifiCorp Dave Johnston Plant

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

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days > 0.5

Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– ESP

Rawah WA 0.718 11 1.075 14 0.918 14 0.904 13

Mt Zirkel WA 0.515 8 0.707 14 0.802 16 0.675 13

Post

- Control Scenario A

– Committed Controls: LNB w/ advanced OFA, Dry FGD, Fabric Filter

Rawah WA 0.163 2 0.283 5 0.265 2 0.237 3

Mt Zirkel WA 0.125 0 0.191 1 0.245 0 0.187 0

Post

- Control Scenario B

– Committed Controls + SCR

Rawah WA 0.087 0 0.142 0 0.119 0 0.116 0

Mt Zirkel WA 0.066 0 0.100 0 0.109 0 0.092 0PacifiCorp Dave Johnston Plant

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

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days > 0.5

Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– Venturi Scrubber

Rawah WA 0.514 8 0.841 14 0.827 13 0.727 12

Mt Zirkel WA 0.387 6 0.659 11 0.654 11 0.567 9

Post

- Control Scenario A

– Committed Controls: LNB w/ advanced OFA, Dry FGD, Fabric Filter

Rawah WA 0.178 1 0.284 3 0.240 2 0.234 2

Mt Zirkel WA 0.127 0 0.190 0 0.238 0 0.185 0

Post

- Co ntrol Scenario B

– Committed Controls + SCR

Rawah WA 0.133 0 0.214 1 0.172 1 0.173 1

Mt Zirkel WA 0.103 0 0.142 0 0.164 0 0.136 0PacifiCorp Dave Johnston PlantAP-6041 BART Application AnalysisPage 43Figure 7Modeled BART Impacts at South Dakota Class I Areas: 98thPercentile (delta-dv)0.00.20.40.60.81.01.21.41.61.82.0DJU3 DJU4 DJU3 DJU4BaselinePostControlScenarioAPostControlScenarioB‐‐‐‐‐‐BadlandsNP‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐WindCaveNP‐‐‐‐‐‐‐‐‐DJU3=DaveJohnstonUnit3(230MW)DJU4=DaveJohnstonUnit4(330MW)(Modelingresultsrepresentthethree‐yearaverageofresultsusing2001‐2003 meteorology)

(Delta

‐ dv)PacifiCorp Dave Johnston PlantAP-6041 BART Application AnalysisPage 44Figure 8Modeled BART Impacts at South Dakota Class I Areas: Number of Days > 0.5 delta-dv05101520253035404550DJU3 DJU4 DJU3 DJU4BaselinePostControlScenarioAPostControlScenarioB‐‐‐‐‐‐‐‐‐‐BadlandsNP‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐WindCaveNP‐‐‐‐‐‐‐‐‐‐DJU3=DaveJohnstonUnit3(230MW)DJU4=DaveJohnstonUnit4(330MW)(Modelingresultsrepresentthethree‐yearaverageofresultsusing2001‐2003 meteorology)

(# Days)PacifiCorp Dave Johnston PlantAP-6041 BART Application AnalysisPage 45Figure 9Modeled BART Impacts at Colorado Class I Areas: 98thPercentile (delta-dv)0.00.20.40.60.81.01.21.41.61.82.0DJU3 DJU4 DJU3 DJU4BaselinePostControlScenarioAPostControlScenarioB‐‐‐‐‐‐RawahWilderness‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐MtZirkelWA‐‐‐‐‐‐‐‐‐DJU3=DaveJohnstonUnit3(230MW)DJU4=DaveJohnstonUnit4(330MW)(Modelingresultsrepresentthethree‐yearaverageofresultsusing2001‐2003 meteorology)

(Delta

‐ dv)PacifiCorp Dave Johnston PlantAP-6041 BART Application AnalysisPage 46Figure 10Modeled BART Impacts at Colorado ClassI Areas: Number of Days > 0.5 delta-dv05101520253035404550DJU3 DJU4 DJU3 DJU4BaselinePostControlScenarioAPostControlScenarioB‐‐‐‐‐‐‐‐‐‐RawahWA‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐MtZirkelWA‐‐‐‐‐‐‐‐‐‐DJU3=DaveJohnstonUnit3(230MW)DJU4=DaveJohnstonUnit4(330MW)(Modelingresultsrepresentthethree‐yearaverageofresultsusing2001‐2003 meteorology)

(# Days)PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 47

BART CONCLUSIONS:

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

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

emitted from the two units subject to BART at the Dave Johnston Power Plant.

NO

x

LNB with advanced OFA is determined to be BART for Units 3 and 4 for NO

x based, in part, on the following conclusions:

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

, 5 00,000 and $ 7

, 9 00,000 per unit, respectively. The average cost effectiveness, over a twenty year operational life, is $6 48 per ton of NO

x removed for Unit 3 and $ 137 per ton for Unit 4

.

2. Combustion cont rol using LNB with advanced OFA does not require non

- air quality environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is a minimal energy impact.

3. After careful consideration of the five statutory factors, especially the costs of compliance and the existing pollution control equipment, a NO

x control level of 0. 28 lb/MMBtu on a 30

- day rolling

average, below EPA‟s applicable presumptive limit of 0. 45 lb/MMBtu for cell

- fired boilers burning su b

- bituminous coal, is justifi ed for Unit 3.

4. After careful consideration of the five statutory factors, especially the costs of compliance and the existing pollution control equipment, a NO

x control level of 0. 15 lb/MMBtu on a 30

- day rolling

average, equal to EPA‟s applicable presumpt ive limit for tangential

- fired boilers burning su b

bituminous coal, is justified for Unit 4.

5. Visibility impacts were addressed in a comprehensive visibility analysis covering all three visibility impairing pollutants and associated control options. The c umulative 3

- year averaged

98 th percentile visibility improvement from the baseline summed across all four Class I areas achieved with LNB with advanced OFA, dry FGD, and a new full

- scale fabric filter, Post

- Control

Scenario A for each unit

, was 3.558 Δdv from Unit 3 and 1.963 Δdv from Unit 4

.

6. Annual NO

x emission reductions from baseline achieved by applying LNB with advanced OFA

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

LNB with advanced OFA and SCR was not determined to be BART for Units 3 and 4 for NO

x based, in part, on the following conclusions:

1. The cost of compliance for installing SCR on each unit is significantly higher than LNB with advanced OFA. Capital cost for SCR on Unit 3 is $ 129

, 7 00,000 and $ 151 ,900,000 for Unit 4

. Annual SCR O&M costs for Unit 3 are $4

, 009

, 159 and $ 1

, 9 80

, 281 for Unit 4

.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 48

2. Additional non

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

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

from Unit 3 and 2.1 MW from Unit 4.

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

Control Scenario B is directly comparable to Post

- Control Scenario A as the only difference is directly attributabl e to the installation of SCR. Subtracting the modeled 98 th percentile values from each other yield the incremental 98 th percentile visibility improvement from SCR. The

cumulative 3

- year averaged 98 th percentile visibility improvement from Post

- Control Sc enario A

summed across all four Class I areas achieved with Post

- Control Scenario B was 0. 754 Δdv from

Unit 3 and 0. 405 Δdv from Unit 4

.

The Division considers the installation and operation of the BART

- determined NO

x controls, new LNB

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

, to meet the statutory requirements of BART.

Unit

- by

- unit NO

x BART determinations:

Dave Johnston Unit 3 : I nstalling new LNB with advanced OFA and meeting NO

x emission

limits of 0 .2 8 lb/MMBtu (30

- day rolling average), 784 lb/hr (30

- day rolling average), and 3

, 434 tpy as BART for NO

x .

Dave Johnston Unit 4 : I nstalling new LNB with advanced OFA and meeting NO

x emission

limits of 0. 15 lb/MMBtu (30

- day rolling average), 6 15 /hr (30

- day rolling average), and 2, 694 tpy as BART for NO

x .

PM/PM 10

A new full

- scale fabric filter is determined to be BART for Unit s 3 and 4 for PM/PM 10 based, in part, on the following conclusions:

1. While the Division considers the cost s of compliance for ful l

- scale fabric filter s on Unit s 3 and 4 not reasonable, PacifiCorp is committed to installing this control device and has permitted the

installation of a full

- scale fabric filter Unit 3 and Unit 4 in Air Quality Permit MD

- 5098 . A full

scale fabric filter is the most stringent PM/PM 10 control technology and therefore the Division will accept it as BART.

The Division considers the installation and operation of the BART

- determined PM/PM 10 controls, new

full

- scale fabric filter on Unit s 3 and 4 to meet corres ponding emission limits on a continuous basis

, to meet the statutory requirements of BART.

Unit

- by

- unit PM/PM 10 BART determinations:

Dave Johnston Unit 3 : I nstalling a new full

- scale fabric filter and meeting PM/PM 10 emission

limits of 0.0 15 lb/MMBtu, 4 2 .1 lb/hr, and 184 tpy as BART for

PM/PM 10

.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 49

Dave Johnston Unit 4 : I nstalling a new full

- scale fabric filter and meeting PM/PM 10 emission

limits of 0.0 15 lb/MMBtu

, 6 1.5 lb/hr, and 269 tpy as BART for

PM/PM 10

.

SO 2 : WESTERN BACKSTOP SULFUR DIOXIDE TRADING P ROGRAM

PacifiCorp evaluated control SO 2 control technologies that can achieve a SO 2 emission rate of 0.15

lb/MMBtu or lower from the coal

- fired boilers. PacifiCorp proposed d ry FGD, and a full

- scale f abric f ilter as SO 2 BART controls on both Unit s 3 and 4

.

Wyoming is a §309 state participating in the Regional SO 2 Milestone and Backstop Trading Program. §308(e)(2) provides States with the option to implement or require participation in an emissions trading program or other alternative measure rather than to require sources subject to BART to install, operate, and maintain additional control technology to meet an established emission limit on a continuous basis. However, the alternate program must achieve greater reasonable progress than would be accompli shed by installing BART. A demonstration that the alternate program can achieve greater reasonable progress is prescribed by §308(e)(2)(i). Since the pollutant of concern is SO 2 , this demonstration has been performed under §309 as part of the state imple mentation plan. §309(d)(4)(i) requires that the SO 2 milestones established under the plan “...must be shown to provide for greater reasonable progress than would be achieved by application of BART pursuant to §51.308(e)(2).”

Wyoming participated in creatin g 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 filing 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 ar e shown in Table 3 2

.

Table 3 2 : Regional Sulfur Dioxide Emissions and Milestone 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 reductions, §309 states have also relied on visibility modeling conducted by the WRAP to demonstrate improvement at Class I areas. The complete modeling demonstration showing deciview values was included as part of the visibility improvement section of the §309 SIP, but the SO 2 portion of the demonstration has been included as Table 3 3 to underscore the improvements associated with SO 2 reductions.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 50

Table 3 3 : Visibility

- Sulfate Extinct ion Only

Class I Area Monitor
(Class I Areas Represented) 20% Worst Visibility Days (Monthly Average, Mm - 1 ) 20% Best Visibility Days (Monthly Average, Mm - 1 )

2018 1

Base Case (Base 18b) 2018 2

Preliminary

Reasonable Progress Case (PRP18a) 2018 1

Base Cas e (Base 18b) 2018 2

Preliminary

Reasonable Progress Case (PRP18a) Bridger, WY
(Bridger WA and Fitzpatrick WA) 5.2 4.3 1.6 1.3

North Absaroka, WY

(North Absaroka WA and Washakie WA) 4.8 4.5 1.1 1.1

Yellowstone, WY

(Yellowstone NP, Grand Teton NP and Teto n WA) 4.3 3.9 1.6 1.4

Badlands, SD 17.8 16.0 3.5 3.1
Wind Cave, SD 13.0 12.1 2.7 2.5
Mount Zirkel, CO

(Mt. Zirkel WA and Rawah WA) 4.6 4.1 1.4 1.3

Rocky Mountain, CO 6.8 6.2 1.3 1.1
Gates of the Mountains, MT 5.3 5.1 1.0 1.0
UL Bend, MT 9.7 9.6 1.8 1 .7
Craters of the Moon, ID 5.8 5.5 1.5 1.5
Sawtooth, ID 3.0 2.8 1.2 1.1 Canyonlands, UT
(Canyonlands NP and Arches NP) 5.4 4.8 2.1 1.9

Capitol Reef, UT 5.7 5.4 1.9 1.8

1 Represents 2018 Base Case growth plus all established controls as of Dec. 2004. No BART or SO 2 Milestone assumptions were included.

2 Represents 2018 Preliminary Reasonable Progress growth estimates and established SO 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, Section 9, PacifiCorp will not be required to install the company

- proposed BART technology and meet the corresponding achievable emission limit. Instead, PacifiCorp is required to participa te in the Regional

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

LONG

- TERM STRATEGY FOR REGIONAL HAZE:

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

- air quality

environ mental 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 take n into consideration when determining BART. When evaluating the costs of compliance the Division recognized a time limitation to install BART

- determined controls imposed by the Regional Haze Rule. In addressing the required elements, including

documentat ion for all required analyses, to be submitted in the state implementation plan, 40 CFRPacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 51

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

the BART

- determined controls to occur as early as 2015.

PacifiCorp used the EPA Air Pollution Control Cost Manua l , 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) desc ribes the concepts and methodology of cost estimation used in the manual. Beginning on page 2

- 28 of Chapter 2.5.4.2, the manual discusses retrofit cost consideration including the practice of developing a retrofit factor to account for unanticipated addit ional costs of installation not directly related to the capital cost of the controls themselves. However, PacifiCorp did not present a retrofit factor in their cost analyses. PacifiCorp estimated that the installation of SCR requires a minimum of 6 years of advanced planning and engineering before the control can be successfully installed and operated. This planning horizon would necessarily be considered in the scheduled maintenance turnarounds for existing units to minimize the installation costs of th e pollution control

systems.

PacifiCorp‟s BART

- eligible or subject

- to

- BART power plant fleet is shown in Table 3 4 . While the majority of affected units are in Wyoming, there are four units in Utah and one in Arizona. Since the 5

- year control installat ion requirement is stated in the federal rule it applies to all of PacifiCorp‟s units requiring additional BART

- determined controls. Although BART is determined on a unit

- by

- unit basis taking into consideration the statutory factors, consideration for add itional installation costs related to the logistics of managing more than one control installation, which are indirect retrofit costs, was afforded under the statutory factor: costs of compliance.

Table 3 4 : 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

Ji m Bridger Unit 3 Wyoming Jim Bridger Unit 4 Wyoming Naughton Unit 1 Wyoming Naughton Unit 2 Wyoming Naughton Unit 3 Wyoming Wyodak Wyoming

(a) Units identified in Utah‟s §308 Regional Haze SIP.

(b) Unit identified on the Western Regional Air Partners hip‟s BART Clearinghouse.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 52

Based on the cost of compliance and visibility improvement presented by PacifiCorp in the BART applications for Dave Johnston Units 3 and 4, and taking into consideration the logistical challenge of managing multiple pollution c ontrol installations within the regulatory time allotted for installation of BART by the Regional Haze Rule, the Division is not requiring additional controls under the Long

- Term Strategy of the Wyoming Regional Haze State Implementation Plan in this permi tting action. Additional controls may be required in future actions related to the Long

- Term Strategy of the Wyoming Regional Haze State Implementation Plan.

CHAPTER 6, SECTION 4

– PREVENTION OF SIGNIFICANT DETERIORATION (PSD):

PacifiCorp‟s Dave Johnsto n Power Plant is a “major emitting facility” under Chapter 6, Section 4, of the Wyoming Air Quality Standards and Regulations because emissions of a criteria pollutant are greater than 100 tpy for a listed categorical source. PacifiCorp should comply with the permitting requirements of Chapter 6, Section 4 as they apply to the installation of controls determined to meet BART.

CHAPTER 5, SECTION 2

– NEW SOURCE PERFORMANCE STANDARDS (NSPS):

The installation of controls determined to meet BART will not chan ge New Source Performance Standard applicability for Dave Johnston Units 3 and 4

.

CHAPTER 5, SECTION 3

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

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

The installation of controls determined to meet BART will not change Nation Emission Standards For Hazardous Air Pollutants applicability for Dave Johnston Units 3 and 4

.

CHAPTER 6, SECTION 3

– OPERATING PERMIT:

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

- 2

- 148

, was issued for the facility on September 2 , 200 8 . In accordance with Chapter 6, Section 3 of the Wyoming Air Quality Standards and Regulations (WAQSR), PacifiCorp will need to modify their operating permit to include the changes authorized in this permitting action.

CONCLUSION:

The Division is satisfied that PacifiCorp‟s Dave Johnston Power P lant will comply with all applicable Wyoming Air Quality Standards and Regulations. The Division proposes to issue a BART Air Quality

Permit for modification to install new LNB with advanced OFA and a new full

- scale fabric filter on Unit s 3 and 4.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 53

P ROPOSED PERMIT CONDITIONS:

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

Johnston Power Plant with the following conditions:

1. Authorized representatives of the Division of Air Quality be given permi ssion to enter and inspect any property, premise or place on or at which an air pollution source is located or is being constructed or installed for the purpose of investigating actual or potential sources of air pollution, and for determining compliance o r 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 referenc e and are enforceable as conditions of this permit.

3. That PacifiCorp shall modify their Operating Permit in accordance with Chapter 6, Section 9(e)(iv) and Chapter 6, Section 3 of the WAQSR.

4. All notifications, reports and correspondence associated w ith this permit shall be submitted to the Stationary Source Compliance Program Manager, Air Quality Division, 122 West 25th Street, Cheyenne, WY 82002 and a copy shall be submitted to the District Engineer, Air Quality Division, 152 N orth Durbin Street, Su ite 100

, Casper , WY 82601

.

5. Effective upon completion of the initial performance tests to verify the emission levels below, as required by Condition 6 of this permit, emissions from Dave Johnston Units 3 and 4 shall not

exceed the levels below. The 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 oil in to the boiler and ends no later than the point in time when coal is introduced as fuel.

Unit Pollutant lb/MMBtu lb/hr tpy

3 NO

x 0.2 8 (30

- day rolling) 784 (30

- day rolling) 3,434

4 NO

x 0. 15 (30

- day rolling) 615 (30

- day rolling) 2,694

3 PM/PM 10 (a) 0.015 42 .1 184

4 PM/PM 10 (a) 0.015 61 .5 269

(a) Filterable portion only

6. That initial performance tests be conducted, in accordance with Chapter 6, Section 2(j) of the WAQSR, within 30 days of achieving a maximum design rate but not later than 90 days

follow ing initial start

- up, and a written report of the results be submitted. If a maximum design rate is not achieved within 90 days of start

- up, the Administrator may require testing be done at the rate achieved and again when a maximum rate is achieved.PacifiCorp Dave Johnston Plant

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7. Performance tests shall consist of the following:

Coal

- fired Boilers ( Dave Johnston Units 3 and 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

a ccordance 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 Permit may be submitted to satisfy the testing required by this condit ion.

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

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

10. C ompliance with the NO

x limits set forth in this permit for the coal

- fired boilers (Dave Johnston Units 3 and 4) shall be determined with data from the continuous monitoring systems required by

40 CFR Part 75 as follows:

a. Exceedances of the NO

x limits shall be defined as follows:

i. Any 30

- day rolling a verage of NO

x emissions which exceeds the lb/MMBtu limits calculated in accordance with the compliance provisions and monitoring requirements of §60.48Da and §60.49Da. The definition of “boiler operating day” shall be consistent with the definition as spe cified in 40 CFR part 60, subpart Da.

ii. Any 30

- day rolling average calculated using valid data (output concentration and average hourly volumetric flowrate) from the existing CEM equipment which

exceeds the lb/hr 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 requirements of §60.48Da and §60.49Da. The 30

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

emissio ns with valid data during the previous 30

- day period. The definition of “boiler operating day” shall be consistent with the definition as specified in 40 CFR part 60, subpart Da.PacifiCorp Dave Johnston Plant

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- 6041 BART Application Analysis Page 55

b. PacifiCorp shall comply with all reporting and record keeping requir ements as specified

in WAQSR, Chapter 5, Section 2(g) and 40 CFR part 60, subpart D. All excess emissions shall be reported using the procedures and reporting format specified in WAQSR, Chapter 5, Section 2(g).

1 1

. PacifiCorp shall use EPA‟s Clean Air Ma rkets reporting program to convert the monitoring system data to annual emissions. PacifiCorp shall provide substituted data according to the missing data procedures of 40 CFR, Part 75 during any period of time that there is not monitoring

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

1 2

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

- fired boilers ( Dave

Johnston Units 3 and 4 ) shall be determined with data from testing for PM conducted annually, or more frequently as specified by the Administrator, following 40 CFR 60.46 and EPA Reference

Test Methods 1

- 4 and 5. Testing required by the Chapter 6, Section 3, Operating Permit may be submitted to satisfy the testing required by this condit ion.

1 3

. 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 4

. PacifiCorp shall install new low NO

x burners with advanced overfire air on Unit s 3 and 4 , i n accordance with the Division‟s BART determination, and conduct the initial performance tests required in Condition 6 no later than December 31, 20 10 and December 31, 2009, respectively

.

1 5

. PacifiCorp shall install new full

- scale fabric filters on Unit s 3 and 4 , in accordance with the Division‟s BART determination, and conduct the initial performance tests required in Condition 6 no later than December 31, 2010 and December 31, 2012, respectively.

# Appendix A Facility Location