DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION

BART Application Analysis

AP

- 604 3

May 28 , 200 9

NAME OF FIRM: PacifiCorp

NAME OF FACILITY: Wyodak Plant

FACILITY LOCATION: Section 27, T50N, R7 1W

UTM Zone: 1 3

, NAD 27 Easting: 4 69

, 410 m
, Northing: 4, 903

, 708 m C ampbell County, Wyoming

TYPE OF OPERATION: Coal

- Fired Electric Generating Plant

RESPONSIBLE OFFICIAL: Gary L. Harris

MAILING ADDRESS: 48 Wyodak Road

- Garner Lake Route

Gillette , WY 82718

TELEPHONE NUMBER: (307) 687

- 4230

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

PURPOSE OF APPLICATION:

Sections 169A and 169B of the 1990 Clean Air Act Amendments require states to improve visibility at Class I areas. On July 1, 1999, EPA first publ ished 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 emissio ns 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 Federal Re gister to provide guidance to regulatory authorities for making BART determinations. Chapter 6, Section 9, Best Available Retrofit Technology was adopted into the Wyoming Air Quality Standards and Regulations (WAQSR) and became effective on December 5, 20 06. 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 (SIP).PacifiCorp Wyodak Plant

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Section 309 of the Regional Haze Rule (40 CFR part 51), Requirements related to the Grand Canyon Visibility Transport Commission , provides states that are included within the Transport Region addressed by the Grand Canyon Visibility Transport Commission (i .e., Arizona, California, Colorado, Idaho, Nevada, New Mexico, Oregon, Utah, and Wyoming) an alternative to the requirements established in 40 CFR 51.308. This alternative control strategy for improving visibility contains special provisions for

addressin g 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. Nationa l litigation issues related to the Regional Haze Rule, including BART, required states to submit revisions. On November 21, 2008, the State of Wyoming submitted revisions to the 2003 §309 Regional Haze SIP submittal. Sources that are subject to BART are required to address 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 February 5 , 2007 , in accordance with the requirements of WAQSR Chapter 6 Section 9(e)(i), the

Div ision received a BART application for the existing coal

- fired boiler at the PacifiCorp Wyodak Power

Plant . A map showing Wyodak‟s location is attached as Appendix A.

On June 5, 2007, PacifiCorp submitted additional copies of the February application for the existing unit at Wyodak subj ect to BART

.

On October 1 6

, 2007, PacifiCorp submitted an updated application for the single unit subject to BART at Wyodak . Additional modeling performed after the February 5 , 2007 submittal and revised visibility

control effectiveness calculations were included.

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

processing of the visibility model runs for Wyodak U nit 1

.

On March 31, 2008, PacifiCorp submitted an addendum to the BART application for Wyodak Unit 1

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

x control scenarios were included

i n the addendum.

BART ELIGIBILITY DETERMINATION:

In August of 2005 the Wyoming Air Quality Division began an internal review of sources that could be subject to BART. This initial effort followed the methods prescribed in 40 CFR part 51, Appendix Y: Guidelines for BART Determinations Under the Regional Haze Rule to identify sources and facilities. The rule requ ires 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 m ore than 250 tons per year (tpy) of any visibility impairing pollutant when emissions are aggregated from all eligible emission units at a stationary source. Fifty

- one (51) sources at fourteen (14) facilities were identified that could be subject to BART in Wyoming.PacifiCorp Wyodak 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 oxides (NO

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

emitted over 40 tons of SO 2 or NO

x or 15 tons of PM 10 were included in the screening analysis. Using three years of meteorologica l 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 b ackground conditions (Δdv) were determined to be subject to BART. For additional information on the Division‟s screening analysis see the Visibility Improvement Determination: Screening Modeling section of this analysis. The single existing coal

- fired bo iler at PacifiCorp‟s Wyodak Power Plant, Unit 1 , w as 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 Wyodak Power Plant is comprised of one ( 1 ) coal

- fired boiler burning pulverized sub

bituminous Powder River Basin coal for a total net generating capacity of a nominal 33 5 megawatts ( MW )

. Wyodak‟s pulverized coal

- fired boiler commenced service in 1978. It was manufactured by

Babcock & Wilcox and equipped with wall

- fired burners. NO

x emissions from the boiler are currently controlled with first generation low NO

x burners. Particulate matter (PM) emissions from the unit are controlled using a Babcock & Wilcox Rothemuhle weighted wire el ectrostatic precipitator (ESP)

. SO 2 emissions from Wyodak Unit 1 are controlled using a Joy Niro, three

- tower lime

- based spray dryer

installed in 1986

.

Table 1: Wyodak Unit 1 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)

Unit 1 4

, 100 (b) LNB, ESP, & dry FGD 0.7 0 (3

- hour fixed )

0. 3 1 (annual) (c) 0.5 ( 3

- hour fixed ) 0. 1 0

(a) Emissions taken from Operating Permit 3

- 1

- 1 01

- 1

. ( b ) Boiler heat input reported based on historic al monthly coal data

. (c ) Annual emission limit established under 40 CFR part 76

.

On April 24, 2007

, WAQSR Chapter 6, Section 3 Operating Permit 3

- 1

- 101

- 1

, was issued to PacifiCorp for Wyodak Unit 1. NO

x and PM emission limits did not change fro m the pre vious Operating Permit 30

- 101

- 1. SO 2 emission limit established under the Acid Rain Program ( 40 CFR 76.11) for the baseline period were 0.31 lb/ MMBtu , annual average.

The reported maximum firing rate of the boiler stated in Operating Permit 3

- 1

- 101

- 1 is based on monthly

coal data. The maximum firing rate of the boiler, as measured by the existing continuous emission monitoring system (CEM), is 4,700 MMBtu/hr. PacifiCorp based emissions calculations for the BART analysis on the highest firing rate of 4,7 00 MMBtu/hr.PacifiCorp Wyodak Plant

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PacifiCorp recently received an Air Quality permit to modify Wyodak Unit 1. The first generation LNB

on Unit 1 will be replaced with Alstom TFS 2000 TM LNB with overfire air. T he existing ESP will be replaced with a new full

- scale fabric filter baghouse

. Table 2 lists the new emission limits for Unit 1. They become effective after the corresponding controls are installed and the applicable initial performance tests are completed.

Table 2 : New Emission Limits for Wyodak Unit 1 (a)

Sourc e Permitted Controls NO

x SO 2 PM/PM 10 ( b )

Unit 1 New LNB with

advanced OFA, Dry FGD, Fabric

Filter Baghouse 0.2 3 lb/MMBtu

( 30

- day rolling) 1,081 .0 lb/hr

( 30

- day rolling) 0.1 6 lb/MMBtu

( 30

- day rolling) 0.5 lb/MMBtu

(3

- hr block) 2,115 .0 lb/hr

( 3

- hr block ) 0.015 lb/MMBtu

7 1 .0 lb/hr

308.8 tpy

(a) Emissions limits taken from recent New Source Review construction permit for Wyodak Unit 1

. ( b ) Averaging period is determined by the appropriate test method

.

PacifiCorp provided a construction schedule for the in stallation of the new LNB with advanced OFA and

a new full

- scale fabric filter baghouse in the permit application. C onstruction activities for the pollution control upgrades on Unit 1 are anticipated to begin March 5, 2011 during the scheduled outage and end approximately April 16, 2011.

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 em itted 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 sourc e, (4) the remaining useful life of the source, and (5) the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.” 1 A BART analysis is a comprehensive evaluation of potential retrofit technologi es with respect to the five criteria above. At the conclusion of the BART analysis, a technology and corresponding emission limit is chosen for each pollutant for each unit subject to BART.

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

Step 1: Identify all 2 available retrofit control technologies Step 2: Eli minate technically infeasible options Step 3: Evaluate control effectiveness of remaining control technologies Step 4: Evaluate impacts and document the results Step 5: Evaluate visibility impacts

1 40 CF R Part 51 Appendix Y: Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 39163).

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

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The Division acknowledges that BART is intended to ide ntify retrofit technology for existing sources and is not the same as a top down analysis required for new sources under the Prevention of Significant Deterioration (PSD) rules known as Best Available Control Technology (BACT). Although BART is not

the sa me as BACT, it is possible that BART may be equivalent to BACT on a case

- by

- case basis. The Division applied all five steps to each visibility impairing pollutant emitted from Wyodak Unit 1 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 effect iveness, 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 existi ng control. Four key elements of the analysis were: “...(1) identification of all potentially BART

- eligible EGUs [electric generating units], and (2) technical analyses and industry research to determine applicable and appropriate SO 2 control options, (3) e conomic 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 identifie d and included in the presumptive BART analysis for SO 2 . Based on removal efficiencies of 90% for spray dry lime dry flue gas desulfurization systems and 95% for limestone forced oxidation wet flue gas desulfurization systems, EPA calculated projected SO 2 emission reductions and cost effectiveness for each unit. Based on the results of this analysis, EPA concluded that the majority of

identified BART

- eligible units greater than 200 MW without existing SO 2 control can meet the presumptive limits at a cost of $400 to $2,000 per ton of SO 2 removed.

A presumptive BART NO

x limits analysis was performed using the same 491 BART

- eligible coal

- fired

units identified in the SO 2 presumptive BART analysis. EPA considered the same four key elements and established pr esumptive 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 boil ers are based on the installation of SCR, a post combustion add

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

all the units coul d meet the presumptive limits using advanced combustion control technology, such as rotating opposed fire air. National average cost effectiveness values for presumptive NO

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

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

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Based on the results of the analyses for presumptive NO

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

x post combustion controls or existing SO 2 controls located at facilities with a generating capacity greater 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 confi guration (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.

PacifiCor p‟s Wyodak Power Plant generates nominal 335 MW from the single unit

. A three

- tower lime

based spray dryer currently controls SO 2 emissions. The unit does not have NO

x post

- combustion

controls. Presumptive SO 2 limit of 95% reduction or 0.15 lb/MMBtu and presumptive NO

x limit of 0. 23 lb/MMBtu, based on unit type and coal type, do not apply to Unit 1 since the cumulative generating capacity of the facility is less than 750 MW

. B efore making a BART determination for Unit 1, t he

Division analyzed potential retrofit controls for NO

x , SO 2 , and PM/PM 10 , taking into consideration all five statutory factors. The analysis is presented below.

NO

x : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

PacifiCorp identified four control technologies to control NO

x emis sions: (1) low NO

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

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

x emissions by controlling the combustion process within the boiler. These two technologies have been demonstrated to effectively control NO

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

- rich environment and by enhancing control of air

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

add

- on controls that provide a chemical conversion mechanism for NO

x to form molecular nitrogen (N 2 ) in the flue gas after com

bustion 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 contro l to suppress the formation of thermal NO

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

burner into the furnace. Careful control of the fuel

- air mixture leaving the burner can limit the

amoun t 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 provide s additional NO

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

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

x formation.

4 Ibid. (70 Federal Register 39171).PacifiCorp Wyodak Plant

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2. Rotating Opposed Fire Air

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

- mixing and air

- flow characteristics within

the boiler. By inducing rotation of the combustion air within the boiler, ROFA can reduce the number of high temperature combustion zones in the boiler and increase the effective heat absorption. Both of which effectively reduce the formation of 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 reducing agent such as ammonia or urea into the flue gas stream. The reduction chemistry, however, takes place without the aid of a catalyst. SNCR systems rely on appropriate injection temperatures, proper mixing of the reagent and flue gas, and prolonged retention time in place of the catalyst. SNCR operates at higher temperatures than SCR. The effective temperature r ange 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 s ystem.

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 ammo nia is injected into the process, unreacted ammonia can be released to the atmosphere through the stack. This release is commonly referred to as ammonia slip . A well controlled SCR system typically emits less ammonia than a comparable SNCR control system

.

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

NO

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

both SNCR and SCR add

- on controls.

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 eff ectiveness of a proposed control technology to be equivalent to the

BART

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

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

x control technologies for the Wyodak unit and to collect data from boiler vendors. Based on results from the study, PacifiCorp indicates that new LNB with advanced OFA on Wyoda k Unit 1 would result in a NO

x emission rate of 0.2 3 lb/MMBtu. On page 3

- 4 of the December 2007 submittal PacifiCorp states: “PacifiCorp has indicated that this rate [0.2 3 lb/MMBtu] corresponds to a vendor guarantee plus an added operating margin, not a v endor prediction, and they believe that this emission rate can be sustained as an average between overhauls.”

PacifiCorp worked with Mobotec to conduct an analysis of retrofitting the existing boiler at the Wyodak
Power Plant with Mobotec‟s ROFA. Mobotec analyzed the operation of existing burners and OFA ports. Typically the existing burner system does not require modification and the existing OFA ports are not used by a new ROFA system. Instead, computational fluid modeling is performed to determine th e location of the new ROFA ports. Mobotec concluded that a NO

x emission rate of 0.1 8 lb/MMBtu was

achievable on Unit 1 using ROFA technology. PacifiCorp added an additional operating margin of 0.0 2

lb/MMBtu to Unit 1 to account for site specific issues, such as feed coal variance , for total proposed

emission rate of 0. 20 lb/MMBtu

.

S&L evaluated emission reductions associated with installing SNCR in addition to retrofitting the boilers with LNB with advanced OFA. Based on installing LNB with advanced OFA capable of achieving a NO

x emission rate of 0.2 3 lb/MMBtu on Unit 1, S&L concluded that SNCR can reduce emissions by 20% resulting in projected NO

x emission rate of 0.1 8 lb/MMBtu. PacifiCorp noted in the analysis that the

economics of SNCR are greatly im pacted 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 1 on accou nt of the expected marginal emission rate improvement, the burden of significant ongoing parasitic costs, the operating difficulties, and the potential ammonia slip.

S&L prepared the design conditions and cost estimates for installing SCR on Wyodak Unit 1 . A high

dust SCR configuration, where the catalyst is located downstream from the boiler economizer before the air heater and any particulate control equipment, was used in the analysis. The flue gas ducts would be routed to a separate reactor containin g 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 Unit 1 can achieve a NO

x emission rate of 0.07 lb/MMBtu.PacifiCorp Wyodak Plant

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Table 3 : Wyodak Unit 1 Boiler NO

x Emission Rates

Control Technology Resulting NO

x Emission Rate (lb/MMBtu)

Existing LNB 0. 31 (a)

New LNB wi th advanced OFA 0. 23

Existing burners with R OFA 0.20

New LNB with advanced OFA and SNCR 0. 18

New LNB with advanced OFA and SCR 0. 07

( a) Operating Permit 3

- 1

- 101

- 1 a nnual averaged NO

x emissions established through 40 CFR part 7 6

.

NO

x : EVALUATE IMPACTS AND DOCUMENT RESULTS

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

. Replacing the existin g LNB with new LNB with advanced OFA will not significantly impact the boiler efficiency o r forced dra ft fan power usage, two common boiler features for adverse energy impact often affected by changes in boiler combustion.

Installing the Mobotec ROFA system has a significant energy impact on Wyodak . One 7,000 horsepower (hp) ROFA fan on Unit 1 is require d to induct a sufficient volume of air into the boiler to cause rotation of the combustion air throughout the boiler. The annual energy impact from operating the proposed

ROFA fan is 4 1, 2 00 Mega Watt

- hour (MW

- hr)

.

PacifiCorp determined the SNCR system wo uld require 340 kilo Watt (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 w ill require additional power from the existing flue gas fan systems to overcome the pressure drop across the catalyst. Based on the S&L study, PacifiCorp estimated the additional power requirement for SCR

installation on Unit 1 would be approximately 2.4 MW.

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). M obotec has predicted CO emissions and LOI would be the same or lower than prior levels for the ROFA system. The installation of SNCR and SCR could impact the saleability and disposal of fly ash due to higher ammonia levels, and could potentially create a visible stack plume sometimes referred to as a blue plume, if the ammonia injection rate is not well controlled. Other environmental impacts involve the storage of ammonia, especially if anhydrous ammonia is used, and transportation of the ammonia to the power plant site.PacifiCorp Wyodak Plant

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PacifiCorp anticipates operating Wyodak Unit 1 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 t o 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, associa ted with the operation of pollution controls

were included.

Several different metrics can be considered when evaluating the cost

- benefit relationships of different emission control technologies. In 40 CFR part 51 Appendix Y two metrics are specifically m entioned: 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. Incr emental cost effectiveness is also used extensively by the Division when comparing emission controls under the BACT process. While the BART and the BACT processes are not necessarily equivalent, control determinations from either process are based on cost effectiveness

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

cost information in terms of cost of applying emission controls and the level of visibility improvement achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and visibility improvement differences between control options, it is not commonly used to asse ss 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 t he 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 comprehens ive 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 cons idered 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 Wyodak Unit 1 are summarized in the following

tables.

Table 4 : Wyodak Unit 1 Economic Costs

Cost Existing

LNB New LNB with

advanced OFA Existing

Burners with

ROFA New LNB with

advanced OFA

and SNCR New LNB with

advanced OFA

and SCR Control Equipment Capital Cost $0 $ 1 3

, 1 00 ,0 00 $ 15

, 252

, 149 $ 19

, 495

, 6 54 $1 71

, 9 00,000

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

Annual Capital Recovery Costs $0 $1, 246

, 203 $1, 450

, 937 $ 1 ,8 54

, 622 $1 6 ,3 52

, 847

Annual O&M Costs $0 $ 6 0

, 000 $ 2

, 147

, 685 $ 452 ,1 06 $ 2

, 557

, 934

Annual Cost of Control $0 $ 1, 306

, 203 $ 3

, 598 ,6 22 $2, 306

, 728 $1 8

, 910

, 781PacifiCorp Wyodak Plant

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Table 5 : Wyodak Unit 1 Environmental Costs

Existing

LNB 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. 31 0. 2 3 0. 20 0. 1 8 0.07

Annual NO

x Emission (tpy) (a) 5,744 4,261 3,706 3,335 1,297

Annual NO

x Reduction (tpy) N/A 1,483 2,038 2,409 4,447

Annual Cost of Control $0 $ 1,306,203 $3,598,622 $2, 306

, 728 $18,910,781

Cost per ton of Reduction N/A $881 $1,766 $958 $4,252

Incremental Cost per

ton of Reduction N/A $881 $4,130

- $3,482 (b) $8,147

(a) Annual emissi ons based on unit heat input rate of 4

, 7 00 MMBtu/hr and 7

, 884 hours of operation per year

. (b ) Incremental cost is negative because the annual cost o f 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

incremental cost effectiveness is reasonable for all N O

x control technologies. PacifiCorp modeled the range of anticipated visibility improvement from the company

- proposed BART controls for Unit 1 by modeling LNB with advanced OFA and LNB with advanced OFA and SCR. While the installation of

SNCR and ROFA we re not individually evaluated in Step 5: Evaluate visibility impact, the anticipated degree of visibility improvement from applying either control lies within the modeled range of visibility impacts.

The final step in the NO

x BART determination process fo r Wyodak Unit 1 , Step 5: Evaluate visibility impacts, is addressed in a comprehensive visibility analysis covering all three visibility impairing pollutants. The visibility analysis follows Steps 1

- 4 for SO 2 emissions in this application analysis. Table

15 on page 28 list s the modeled control scenarios and associated emission r ate s.

PM 10 : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Wyodak Unit 1 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 / PM 10 from the flue gas stream by creating a strong electro

- magnetic field in which fly ash particles gain electric charge

. While

the current PM 10 emission limit for Unit 1 is 0.10 lb/MMBtu, PacifiC orp states that the existing ESP is achieving controlled PM /PM 10 emission s of 0. 030 lb/MMBtu. PacifiCorp analyzed three technologies for

additional PM control : fabric filters or baghouses, ESPs, and flue gas conditioning.

1. Fabric filters (FF)

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

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2. Electrostatic precipitators

– ESPs use electrical forces (charge) to move parti culate matter out the gas stream onto collection plates. The particles are given an electrical charge by directing the gas stream through a corona, or region of gaseous ion flow. The charged particles are acted upon by

an induced electrical field from hi gh voltage electrodes in the gas flow that forces them to the walls or collection plates. Once the particles couple with the collection plates, they must be

removed without re

- entraining them into the gas stream. In dry ESP applications, this is usually accomplished by physically knocking them loose from the plates and into a hopper for disposal. Wet ESPs use water to wash the particles from the collector plates into a sump. The efficiency of an ESP is primarily determined by the resistivity of the part icle, which is dependent on chemical composition, and also by the ability to clean the collector plates without reintroducing the particles back into the flue gas stream.

3. Flue Gas Conditioning (FGC)

– Injecting a conditioning medium, typically SO 3 , into t he flue gas can lower the resistivity of the fly ash, improving the particles‟ ability to gain an electric charge. If the material is injected upstream of an ESP the flue gas particles more readily accept charge

from the corona and are drawn to the collec tion plates. Adding FGC can account for large improvements in PM collection efficiency for existing ESPs that are constrained by space and flue gas residence time.

PM 10 : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

PacifiCorp did not eliminate the use of th e existing ESP with a polishing fabric filter or installing a new full

- scale fabric filter to control PM / PM 10 emissions as technically infeasible. However, PacifiCorp did not further analyze the use of FGC or installing a new full

- scale fabric filter . Ac cording to PacifiCorp, the existing ESP on Unit 1 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 signific antly improve PM/PM 10 removal efficiency. Installing a new full

- scale fabric filter is

cost

- prohibitive in comparison to installing a polishing fabric filter on the existing ESP , which can

achieve the same PM/PM 10 emission rate.

PM 10 : EVALUATE EFFECTIVEN ESS 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 m aintained 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 equipm ent will have some emissions variability. Complex emission control equipment, such as electrostatic precipitators, generally have inherent variability that must be considered when establishing the limit. Otherwise, the source will be out of compliance ev en though the equipment is operated and maintained as well as possible.

Unit 1 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 unit is already capable of controlling PM 10 emissions from Unit 1 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 addition to maintaining the existing ESP, a polishing fabric filter can be installed downstream of the existing ESPs. PacifiCorp proposed the use of Compact Hybrid Particulate Collector (COHPAC) licensed by Electric Power Research Inst itute (EPRI).PacifiCorp Wyodak Plant

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The COHPAC unit is smaller than a full

- scale fabric filter and has a higher air

- to

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

- size pulse jet fabric filter (3.5 to 4:1). COHPAC is effective at controlling particulates not captured by the pri mary 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 the existing ESP on Unit 1 can reduce emissions an additional 50% resulting in a PM 10 emission rate of 0.015 lb/MMBtu. PacifiCorp did not further evaluate the

installation on a n ew full

- scale fabric filter on Unit 1 since there is a substantial capital cost associated with the control and no anticipated benefit when compared to COHPAC.

Table 6 : Wyodak Unit 1 Boiler PM 10 Emission Rates

Source Existing ESP

PM 10 Emission (lb/MMBtu) Existing ESP

With Polishing Fabric Filter

PM 10 Emission (lb/MMBtu)

Unit 1 0.030 0.015

PM 10 : EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impact of installing CO HPAC on Unit 1 . The pressure drop created by

the fabric filter a nd associated ductwork requires additional energy from the existing draft fan, which will have to be upgraded. PacifiCorp calculated the additional energy costs based on a 90 percent annual plant capacity factor . The installation of a COHPAC fabric filte r w ould require approximately 2.1 MW of

power, equating to an annual power usage of approximately 1 6

, 2 00 MW

- hr

.

PacifiCorp evaluated the environmental impacts from the proposed installation of COHPAC on Unit 1

and did not antici p ate negative environmental impacts from the addition of this PM control technolog y.

PacifiCorp anticipates operating Wyodak Unit 1 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, includi ng a cost escalation factor, associated with the operation of pollution controls

were included.

Several different metrics can be considered when evaluating the cost

- benefit relationships of different emission control technologies. In 40 CFR part 51 Appen dix 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

d ifferent 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 f rom either process are based on cost effectiveness

and incremental cost effectiveness and are indicative of the economic costs to control emissions. In addition to providing cost effectiveness and incremental cost effectiveness results, PacifiCorp provide d cost information in terms of cost of applying emission controls and the level of visibility improvement achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and visibility improvement differences between control opti ons, it is not commonly used to assess the overallPacifiCorp Wyodak Plant

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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

visibi lity 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 analy sis. 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 co ntrol technology. The Division considered capital cost, annual cost, cost effectiveness, and

incremental cost effectiveness in the evaluation of the proposed PM/PM 10 emission control. Economic

and environmental costs for additional PM/PM 10 control on Wyo dak Unit 1 are summarized in the following tables.

Table 7 : Wyodak Unit 1 Economic Costs

Cost Existing ESP Existing ESP w ith

New Polishing Fabric Filter

Control Equipment Capital Cost $0 $ 32,630,832

Capital Recovery Factor N/A 0.09513

Annual Capital Recovery Costs $0 $ 3

, 104

, 1 71

Annual O&M Costs $0 $ 1,120,709

Annual Cost of Control $0 $ 4

, 224

, 880

Table 8 : Wyodak Unit 1 Environmental Costs

Existing ESP Exiting ESP w ith

New Polishing Fabric Filter

PM 10 Emission Rate (lb/MMBtu) 0.030 0.0 15

Annual P M 10 Emission (tpy) (a) 556 278

Annual PM 10 Reduction (tpy) N/A 278

Annual Cost of Control $0 $ 4,224

, 880

Cost per ton of Reduction N/A $15

, 197

Incremental Cost per ton of Reduction N/A $ 15,197

(a) Annual emissi ons based on unit heat input rate of 4,700 MMBtu/hr and 7

, 884 hours of operation per year

.

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

1 are not reasonable. However, the control was included in the final step in the PM/PM 10 BART

de termination process for Wyodak Unit 1 , Step 5: Evaluate visibility impacts, which is addressed in a comprehensive visibility analysis covering all three visibility impairing pollutants. The visibility analysis follows Steps 1

- 4 for SO 2 emissions in this a pplication analysis. Table 15 on page 28 lists the modeled

control scenarios and associated emission r ate s.PacifiCorp Wyodak Plant

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SO 2 : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

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

c learinghouse, in an effort to identify applicable SO 2 emission control technologies for Wyodak Unit 1

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

1. Wet FGD

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

SO 2 diffuses from the gas into the scrubber water when the liquid contains less than the equilibrium concentration of the gaseous SO 2 . The rate of SO 2 mass transfer between the two phases is largely dependent on the surface area exposed and the time of contact. A properl y 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 dissolve d 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 injection systems in that both systems introduce media directly into the flue gas stream, however the addition of the dry scrubber vessel provides greater contact area for adsorption and enhances chemical reactivity. A spray dryer dry scrubber sprays an atomized alkaline slurry into the flue gas upstream of particulate control system, often a

fabric f ilter. 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 stor age bin. The dry by

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

- product. Spray dryer dry scrubbers typically require lower capital cost than a wet scrubber. They also require less flue gas

after

- treatment. When e xhaust 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 do es not enhance stack corrosion like a wet scrubber because it will not saturate the exhaust gas or significantly lower the gas temperature. Removal efficiencies for spray dryer dry scrubbers can range from 70% to 95%.

SO 2 : ELIMINATE TECHNICALLY INFEASIBL E OPTIONS

PacifiCorp did not eliminate either control technology listed above as technically infeasible. Both dry FGD and wet FGD are proven SO 2 control technologies. PacifiCorp analyzed the impact of both SO 2 emission reduction technologies on Wyodak U nit 1

.

SO 2 : 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 limitPacifiCorp Wyodak Plant

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it is important to consider that even wel l maintained and operated equipment will have some emissions variability. Complex emission control equipment, such as dry FGD, generally have inherent variability that must be considered when establishing the limit. Otherwise, the source will be out of c ompliance even though the equipment is operated and maintained as well as possible.

PacifiCorp determined that Wyodak Unit 1 has an uncontrolled SO 2 emission rate of 1.61 lb / MMBtu

, based on an average coal sulfur content of 0.65% by weight. The existing three column dry scrubber currently reduces SO 2 emissions by approximately 69% to achieve the SO 2 emission limit of 0.50

lb / MMBtu

. Upgrading the existing dry FGD system by eliminat ing bypass flue gas flow , placing new

static mixers to redistribute the flu e gas flow prior to the ESP

, increas ing the reagent feed ratio , and

increas ing the recycle ratio is projected to reduce SO 2 emissions by 80% from uncontrolled levels, based on an average sulfur content in the feed coal of 0.65% by weight. The resulting SO 2 emission rate would

be 0.32 lb /

MMBtu.

If the existing ESP is replaced with a new full

- scale fabric filter downstream of the lime spray dryer, the dry FGD system is projected to achieve 90% SO 2 removal after the aforementioned upgrades are applied

to the dry scrubber. Based on an average sulfur content of 0.65% by weight, the resulting SO 2 emission

rate is 0.16 lb /MMBtu.

P acifiCorp evaluated the application of wet FGD on Wyodak Unit 1 . A new wet FGD would likely use

lime/limestone forced oxidation scru bbing, which is available in several variations from vendors. Wet lime/limestone scrubbing is projected to achieve a SO 2 removal rate of 95% resulting in an outlet SO 2 emission rate of 0.08 lb/MMBtu, based on a sulfur content of 0. 65 % by weight in the fee d coal. PacifiCorp‟s proposed emission rates for each SO 2 emission reduction technology applied to Wyodak

Unit 1 are shown in Table 9.

Table 9 : Wyodak Unit 1 SO 2 Emission Rates

Control Technology SO 2 Emission Rate (lb/MMBtu)

Existing Dry FGD 0.5 0

Upg raded Dry FGD with existing ESP 0. 3 2

Upgraded Dry FGD with full

- scale Fabric Filter 0.1 6

Wet Lime FGD with existing ESP 0.0 8

SO 2 : EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impacts of upgrading the existing dry FGD syste m wi th the existing ESP on Wyodak Unit 1 . D ry FGD requires less electric power than a wet FGD system. Upgrading the current dry FGD system with the exis t ing ESP at Wyodak would require approximately 0.1 MW of additional

power

. Upgrading the existing dry FGD and installing a new polishing fabric filter would require 0.2

MW

, while a new wet FGD would require approximately 1.8 MW. Using a 90% annual plant capacity factor, upgrading the existing dry FGD and installing a full

- scale fabric filter equates to an an nual power savings of approximately 12

, 6 00 MW

- hr as opposed to installing an d operating a new wet FGD system.PacifiCorp Wyodak Plant

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PacifiCorp compared the environmental impacts of dry FGD versus wet FGD technology. PacifiCorp concluded that dry FGD has five significant envir onmental advantages over wet FGD. These advantages are taken directly from Pa cifiCorp‟s environmental analysi s for SO 2 controls on Wyodak Unit 1 and listed

below.

Sulfuric Acid Mist Sulfur trioxide (SO 3 ) in the flue gas, which condenses to liquid sulfur ic acid at temperatures below the acid dew point, is removed efficiently with a lime spray dryer system. Wet scrubbers capture less than 40 to 60 percent of SO 3 and may require the addition of a wet electrostatic precipitator (ESP) or hydrated lime inject ion 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 threshold value, may result in a visible plume after the vapor plume dissipates.

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

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

Liquid Waste Disposal There is no liquid waste from a dry FGD system. However, wet FGD systems produce a wastewater blowdown stream that must be treated to limit chloride buildup in the absorber scrubbing loop. In some cases, a wastewater treatment plant must be installed to

treat the liquid waste prior to disposal. The wastewater treatment plant would produce a small volume of solid waste, which may be contaminated with toxic metals (including mercury), requiring proper disposal.

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

Makeup Water Requirements Dry FGD has advantages over a wet scrubber, producing a dry waste material and requiring less makeup water in the absorber. Given that water is a valuable commodity in Wyomin g, the reduced water consumption required for dry FGD is major advantage for this technology.

PacifiCorp anticipates operating Wyodak Unit 1 indefinitely and did not include life extension costs in the economic analysis. A standard control life of 20 yea rs was used to calculate the capital recovery factor. The annual cost to control was determined using a capital recovery factor based on a 7.1% interest rate. PacifiCorp labor and service costs were used to calculate the annual operating and maintenance costs. Annual power costs, including a cost escalation factor, associated with the operation of pollution controls

were included.

Several different metrics can be considered when evaluating the cost

- benefit relationships of different

emission control te chnologies. 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 DivisionPacifiCorp Wyodak Plant

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when comparing emission controls under the BACT process. While the BART and the BACT processes are not necessarily equivalent, control determinations from either process are based on cost effectiveness

and incremental cost effectiveness and are indicative of the economic costs to control emissions. In addition to providing cost effectiveness and incremental cost effec tiveness results, PacifiCorp provided cost information in terms of cost of applying emission controls and the level of visibility improvement achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and visibility improvem ent 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 cos t 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 addr essed 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 a pplication of additional emission control technology. The Division considered capital cost, annual cost, cost effectiveness, and incremental cost effectiveness in the evaluation of each proposed SO 2 emission control. Economic and

environmental costs for additional SO 2 controls on Wyodak Unit 1 are summarized in the following

tables.

Table 10 : Wyodak Unit 1 Economic Costs

Cost Existing Dry FGD with existing ESP Upgraded

Dry FGD with existing ESP Upgraded

Dry FGD with

new full

- scale

Fabric Filter New

W et FGD

Control Equipment Capital Cost $0 $ 26,759,011 $ 66,777,531 $ 95,136,483

Capital Recovery Factor N/A 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $ 2

, 545

, 585 $ 6, 352,547 $ 9

, 050 ,33 4

Annual O&M Costs $0 $ 1,346,423 $ 1,471,432 $ 2,798,979

Annual Cost of Control $0 $ 3, 892

, 00 8 $ 7

, 823

, 979 $ 11

, 849

, 313PacifiCorp Wyodak Plant

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Table 1 1 : Wyodak Unit 1 Environmental Costs

Existing Dry FGD with existing ESP Upgraded

Dry FGD with existing ESP Upgraded

Dry FGD with

new full

- scale

Fabric Filter New

Wet FGD

SO 2 Emission Rate (lb/MMBtu) 0.5 0. 32 0.16 0.0 8

Annual SO 2 Emission (tpy) (a) 9,264 5

, 929 2,964 1,482

Annual SO 2 Reduction (tpy) N/A 3,335 6,300 7,782

Annual Cost of Control $0 $ 3, 892

, 00 8 $ 7

, 823

, 979 $ 11

, 849

, 313

Cost per ton of Reduction N/A $1, 167 $1, 242 $1,5 23

Incremental Cost per ton of Reduction N/A $1, 167 $ 1,326 $ 2 ,7 16

(a) Annual emissi ons based on unit heat input rate of 4,700 MMBtu/hr and 7

, 884 hours of operation per year

.

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

for Unit 1 are reasonable. The final step in the SO 2 BART determination process for Wyodak Unit 1

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

next sec tion of this BART application analysis. The Division evaluated the amount 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. Tabl e 15 on page 28 list s the modeled

control scenarios 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 degr ee of Class I area visibility improvement that would result from installation

of the various options for control technology. This factor was evaluated for the PacifiCorp Wyodak 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 that was conducted using current (baseline) emissions from the facility. The screening mo deling, as well as m ore refined modeling conducted by the applicant

, is

described in detail below.

Wind Cave and Badlands National Parks (NP) in South Dakota are the closest Class I areas to the Wyodak plant , as shown in F igure 1 below. Wind Cave NP is located approximately 168 kilometers (km)

east

- south east of the plant and Badlands NP i s located approximately 2 4 0 km east

- south east of the plant

.

Only those Class I areas most likely to be impacted by the Wyodak sources were modeled, as determined

b y source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. I t can be reasonably assumed that areas at greater distance s and in directions of less frequent plume transport will experience lower impacts than those predicted for the two
modeled areas

.PacifiCorp Wyodak Plant

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SCREENING MODELING

To determine if the Wyodak plant would be subject to BART, the Division conducted CALPUFF visibility modeling using three years of meteorological data. These data, from 2001

- 2003 , consisted of surface and upper

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

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

- km for all three of the modeled years.

Potential emissions for cu rrent operation from the coal

- fired boiler at the Wyodak 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 Δdv for Badlands NP and Wind Cave NP. A s defined in EPA‟s final BART rule, a predicted 98 th percentile impact equal to or greater than 0.5 Δdv fr om a given source indicates that the source contributes to visibility impa irment, and therefore is subject to BART. The results of the screening modeling are shown in T able 12

.PacifiCorp Wyodak Plant

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Figure 1 Wyodak Power Plant and Class I AreasPacifiCorp Wyodak Plant

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Table 12 : Results of the Class I Area Screening Modeling

Class I Ar ea Maximum

Modeled Value (Δdv) 98 th

Percentile Value (Δdv)

2001

Badlands NP 1.155 0.842

Wind Cave NP 1.671 1.007

2002

Badlands NP 2.160 1.246

Wind Cave NP 2.490 1.213

200 3

Badlands NP 2.484 1.097

Wind Cave NP 3.685 1.657

Δdv = delta deciview

N P = national park

REFINED MODELING

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

Protocol

- Individual Source Visibility Assessments for BART Control Analyses (WDEQ

- AQD, September 2006).

CALPUFF System

Predicted visibility impacts from the Wyodak plant w ere determined with the EPA CALPUFF modeling system, which is the EPA

- preferred modeling system for long

- range transport. As described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR p art 51), long

- range transport is defined as modeling w ith 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), a n air dispersion model (CALPUFF), and post

- processor programs (POSTUTIL, CALSUM, CALPOST). The CALPUFF model was developed as a non

- steady

- state air quality modeling system for assessing the

effects of time

- and space

- varying meteorological conditions on pollutant transport, transformation, and

removal.

CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a three

dimensional, gridded modeling domain. Meteorological inputs to CALMET can include surface and

upper

- air obser vations 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 tw o

- dimensional fields such as mixing height, land use, and surface roughness are included in the input to CALMET. The CALMET model allows the user to “weight” various terrain influence parameters in the vertical and horizontal directions by defining the ra dius of influence for surface and upper

- air stations.PacifiCorp Wyodak Plant

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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 steady

- state dispersion models. All far

- field modeling assessments described here were completed using the

CALPUFF model in a refined mode.

CALSUM is a post

- processi ng program that can operate on multiple CALPUFF output files to combine the results for further post

- processing. POSTUTIL is a post

- processing program that processes

CALPUFF concentrations and wet/dry flux files . The POSTUTIL model operates on one or mor e output data files from CALPUFF to sum, scale, and/or compute species derived from those that are modeled , and outputs selected species to a file for further post

- processing . 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 modeling was conducted with the version of the CALPUFF system that was recognized as the EPA

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

Table 13 : Key Programs in CALPUFF System
Program Version Level

CALMET 5.53a 040716

CALPUFF 5.711a 040716

CALPOST 5.51 030709

Meteorological Data Processing (CALME T)

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 obt ained MM5 data at 12

- km resolution that spanned the years 2001

- 2003.

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

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

- defined CALMET settings that were

selected.PacifiCorp Wyodak Plant

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Table 14 : Key User

- Defined CALMET Settings

Variable Description Value

PMAP Map projection LCC

DGRID KM Grid spacing (km) 4

NZ Number of layers 10

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

RMIN2 Minimum distance for extrapolation

- 1

IPROG Use gridded prognostic model output 14

RMAX 1 Maximum radius o f 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 Wyodak Plant

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Figure 2 Observations Input to CALMETPacifiCorp Wyodak 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 . F or ozone, hourly data collected from the following stations were used:

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

For any ho ur that was missing ozone data from all stations, a default value of 44 parts per billion (ppb) was used by the model as a substitute. For ammonia, a domain

- wide background value of 2 ppb was

used.

Latitude and longitude coordinates for Class I area d i screte 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 through 4 show the receptor configuration s that w ere used for Badlands NP and

Wind Cave NP

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

- west direction and approximately 0.9 km in the north

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

- west direction and approxima tely 1.8 km in the north

- south direction.PacifiCorp Wyodak Plant

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Figure 3 Receptors for Wind Cave NP

Figure 4 Receptors for Badlands NPPacifiCorp Wyodak Plant

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CALPUFF Inputs

– Baseline and Control Options

S ource release parameters and emissions for baseline and control options for the Wyodak p lant are shown

in the table below

.

Table 15 : CALPUFF Inputs for Wyodak Unit 1PacifiCorp Wyodak Plant

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V isibility Post

- Processing (CALPOST)

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

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

that were used for Badlands NP and Wind Cave NP are shown in the table below.

Table 16 : Relative Humidity Factors for CALPOST

Mont h Badlands

NP &

Wind Cave

NP
January 2.65

February 2.65

March 2.65

April 2.55

May 2.70

June 2.60

July 2.30

August 2.30

September 2.20

October 2.25

November 2.75

December 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 Wyodak 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 17 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 17 : 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 two Class I areas in question are listed in the table below.PacifiCorp Wyodak Plant

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Table 18 : Natural Background Aerosol Concentrations (μg/m 3 )

Aerosol Component Wind Cave

NP &

Badlands NP

Ammonium Sulfate 0.047

Ammonium Nitrate 0.040

Organic Carbon 0.186

Elemental Carbon 0.008

Soil 0.198

Coarse Mass 1.191

Visibility Post

- Processing Results

The results of the visibility modeling for the Wyodak facility for the baseline and control scenarios are shown in the table s below. For each scenario, the 98 th percentile Δdv results are reported along with the total number of days for which the predicted impacts exce eded 0.5 dv. Following the tables are figures that present the results graphically for baseline, the BART configuration proposed by PacifiCorp, and for the proposed BART configuration with the addition of SCR.PacifiCorp Wyodak Plant

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Table 19 : CALPUFF Visibility Modeling Results for Wyodak Unit 1

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days > 0.5

Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– Dry FGD, ESP

Badlands NP 0.841 27 1.140 34 1.070 31 1.017 3 1

Wind Cave NP 1.153 41 1.323 38 1.530 37 1.335 3 9

Post

- Control Scenario 1

– LNB w/ advanced OFA, Dry FGD, ESP

Badlands NP 0.595 12 0.829 18 0.739 20 0.721 1 7

Wind Cave NP 0.817 19 0.940 26 1.114 28 0.957 24

Post

- Control Scenario 2

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

Badlands NP 0.472 6 0.624 14 0.583 13 0.560 11

Wind Cave NP 0.671 11 0.788 17 0.929 17 0.796 15

Post

- Control Scenario 3

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

Badlands NP 0.254 1 0.331 2 0.31 4 2 0.300 2

Wind Cave NP 0.333 2 0.383 5 0.457 6 0.391 4

Post

- Control Scenario 4

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

Badlands NP 0.294 1 0.405 3 0.340 3 0.346 2

Wind Cave NP 0.396 2 0.519 9 0.684 10 0.533 7

Post

- Control Scenario A

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

Badlands NP 0.473 6 0.624 14 0.583 13 0.560 11

Wind Cave NP 0.671 11 0.788 17 0.929 17 0.796 15

Post

- Control Scenario B

– Committed Controls + SCR

Badlands NP 0.254 1 0.331 2 0.314 2 0.300 2

Wind C ave NP 0.333 2 0.383 5 0.457 6 0.391 4PacifiCorp Wyodak Plant

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Figure 5 Modeled BART Impacts: 98 th Percentile (delta

- dv)PacifiCorp Wyodak Plant

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Fi gure 6

Modeled BART Impac t s: Number of Days > 0.5 delta

- dvPacifiCorp Wyodak Plant

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BART CONCLUSIONS:

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

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

emitted from the single unit subject to BART at the Wyodak Power Plant.

NO

x

LNB with advanced OFA is determined to be BART for Unit 1 f or NO

x based, in part , on the following

conclusions:

1. LNB with advanced OFA on Unit 1 was cost effective with a capital cost of $ 13

, 1 00,000. The average cost effectiveness, over a twenty year operational life, is $ 881 per ton of NO

x removed.

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

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

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

x control level of 0.2 3 lb/MMBtu on a 30

- day rolling

average, equal to EPA‟s presumptive limit of 0. 23 lb/MMBtu for wal l

- fired boilers burning sub

bituminous coal, though it is not applicable, is just ified for Unit 1

.

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

- year averaged

98 th percentile visibility improvement from the b aseline summed across both Class I areas achieved with LNB with advanced OFA, upgrading the existing dry FGD, and a new full

- scale fabric filter, Post

- Control Scenario A for Unit 1 , was 0

. 996 Δdv

.

5. Annual NO

x emission reduction from baseline achieved by applying LNB with advanced OFA on

Unit 1 is 1

, 4 83 tons.

LNB with advanced OFA and SCR was not determined to be BART for Unit 1 for NO

x based, in part, on the following conclusions:

1. The cost o f compliance for installing SCR on the unit is significantly higher than LNB with

advanced OFA. Capital cost for SCR on Unit 1 is $1 71

, 9 00,000. Annual SCR O&M costs for

Unit 1 are $ 2

, 557

, 934

.

2. Additional non

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

3. Operation of LNB with advanced OFA and SCR is parasitic and requires an estimated 2.4 MW

from Unit 1

.PacifiCorp Wyodak Plant

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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 attributable 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 Scenario A

summed across both Class I areas achieved with Post

- Control Scenario B was 0. 665 Δdv.

The Division considers the installation and operation of the BART

- determined NO

x control, new LNB

with advanced OFA on Unit 1 to meet corresponding emission limits on a continuous basis, to meet the statutory requirements of BART.

Unit

- by

- unit NO

x BART determinations:

Wyodak Unit 1 : Installing new LNB with advanced OFA and meeting NO

x emission

limits of 0. 23 lb/MMBtu (30

- day rolling average), 1,081 .0 lb/hr (30

- day rolling average), and 4,735 tpy as BART for NO

x .

PM/PM 10

A new full

- scale fabric filter is determined to be BART for Unit 1 for PM/PM 10 based, in part, on the following conclusions:

1. While the Division considers the cost of compliance for a full

- scale fabric filter on Unit 1 not reasonable, PacifiCorp is committed to installing this co ntrol device and has permitted the

installation of a full

- scale fabric filter on Unit 1 in a recently issued New Source Review construction permit. 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 control, new

full

- scale fabric filter on Unit 1 to meet corresponding emission limits on a continuous basis, to meet the statutory requirements of BAR T.

Unit

- by

- unit PM/PM 10 BART determinations:

Wyodak Unit 1 : Installing a new full

- scale fabric filter and meeting PM/PM 10 emission

limits of 0.015 lb/MMBtu, 71.0 lb/hr, and 309 tpy as BART for

PM/PM 10

.

SO 2 : WESTERN BACKSTOP SULFUR DIOXIDE TRADING PROGR AM

PacifiCorp evaluated control SO 2 control technologies that can achieve a SO 2 emission rate of 0.1 6

lb/MMBtu or lower from the coal

- fired boilers. PacifiCorp proposed upgrading the existing dry FGD and installing a full

- scale fabric filter as SO 2 BART controls on Wyodak Unit 1

.PacifiCorp Wyodak Plant

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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 alte rnative 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 prog ress than would be accomplished by installing BART. A demonstration that the alternate program can achieve greater reasonable progress is prescribed by §308(e)(2)(i). Since the pollutant of concern is SO 2 , this demonstration has been performed under §309 as part of the state implementation plan. §309(d)(4)(i) requires that the SO 2 milestones 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).”

Wyom ing participated in creating a detailed report entitled Demonstration that the SO 2 Milestones Provide Greater Reasonable Progress than BART covering SO 2 emissions from all states participating in the Regional SO 2 Milestone and Backstop Trading Program. Th e 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 c ompares 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

the ir respective milestones are shown in Table 2 0

.

Table 2 0 : 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

demo nstration 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 21 to underscore the improvements associated with SO 2 reductions.PacifiCorp Wyodak Plant

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T able 21 : Visibility

- Sulfate Extinction Only

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

2018 1

Base Case (Base 18b) 2018 2

Preliminary

Reasonable

P rogress Case (PRP18a) 2018 1

Base Case (Base 18b) 2018 2

Preliminary

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

North Absaroka, WY

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

Yellowstone, WY

(Ye llowstone NP, Grand Teton NP and Teton WA) 4.3 3.9 1.6 1.4

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

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

Rocky Mountain, CO 6.8 6.2 1.3 1.1
Gates of the Mountains, MT 5.3 5 .1 1.0 1.0
UL Bend, MT 9.7 9.6 1.8 1.7
Craters of the Moon, ID 5.8 5.5 1.5 1.5
Sawtooth, ID 3.0 2.8 1.2 1.1 Canyonlands, UT
(Canyonlands NP and Arches NP) 5.4 4.8 2.1 1.9

Capitol Reef, UT 5.7 5.4 1.9 1.8

1 Represents 2018 Base Case growth plus all es tablished 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 visibili ty 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 2 008.

Therefore, in accordance with §308(e)(2), Wyoming‟s §309 Regional Haze SIP, and WAQSR Chapter 6, Section 9, PacifiCorp will not be required to install the company

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

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, t he energy and non

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

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

- determined controls imposed by the Regional Haze Rule. In addressing the re quired elements, including documentation for all required analyses, to be submitted in the state implementation plan, 40 CFRPacifiCorp Wyodak Plant

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

the BART

- determined controls to occur as early as 2015.

PacifiCorp used the EPA Air Pollution Control Cost Manual , which is identified in 40 CFR part 51 Appendix Y(IV)(D)(4)(a)(5) as a reference source, to estimate capital costs and calculate cost effectiveness. Section 1 Chapter 2 of the EPA Air Pollution Control Cost Manual

- Sixth Edition (EPA 452/B

- 02

- 001) describes the concepts and methodology of cost estimation used in the manual. Beginning on page 2

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

systems.

PacifiCorp‟s BART

- eligible or subject

- to

- BART power plant fleet is shown in Table 22 . While the majority of affected units are in Wyoming, there are four units in Utah and one in Arizona

. Since the 5

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

- determined controls. Although BART is determined on a unit

- by

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

Table 22 : 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 Wy oming Jim Bridger Unit 2 Wyoming Jim Bridger Unit 3 Wyoming Jim Bridger Unit 4 Wyoming Naughton Unit 1 Wyoming Naughton Unit 2 Wyoming Naughton Unit 3 Wyoming Wyodak Wyoming

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

(b) Unit identified on the Western Regional Air Partnership‟s BART Clearinghouse.PacifiCorp Wyodak Plant

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Based on the cost of compliance and visibility improvement presented by PacifiCorp in the BART application for Wyodak Unit 1 , and taking into consideration the logistical challenge of managin g multiple pollution control installations within the regulatory time allotted for installation of BART by the Regional Haze Rule, the Division is not requiring additional controls under the Long

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

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

CHAPTER 6, SECTION 4

– PREVENTION OF SIGNIFICANT DETERIORATION (PSD):

Pac ifiCorp‟s Wyodak 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 sho uld 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 BAR T will not change New Source Performance Standard applicability for Wyodak Unit 1

.

CHAPTER 5, SECTION 3

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

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

The installation of controls determined to meet BART will not change Nation Emission Standards For Hazardous Air Pollutants applicability for Wyodak Unit 1

.

CHAPTER 6, SECTION 3

– OPERATING PERMIT:

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

- 2

- 1 01 , was issued for the facility on February 18, 2009 . In accordance with Chapter 6, Section 3 of the Wyoming Air Q uality Standards and Regulations, 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 Wyodak Power Plant will comply with all applicabl e 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 1

.PacifiCorp Wyodak Plant

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PROPOSED PERMIT CONDITIONS:

The Division proposes to issue an Air Quality Permit to PacifiCorp for the modification of the Wyodak Power Plant with the following conditions:

1. Authorized representatives of the Division of Air Quality be given permission to enter and inspect any property, premise or place on or at which an air pollution source is located or is being constructed or installed for the purpose of investigating actual or potential sources of air pollution, and for determining compliance or non

- compliance with any rules, standards, perm its

or orders.

2. All substantive commitments and descriptions set forth in the application for this permit, unless superseded by a specific condition of this permit, are incorporated herein by this reference and are enforceable as conditions of this perm it.

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

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

Statio nary 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, 1866 South Sheridan Avenue

, Sheridan , WY 82801

.

5. Effective upon completi on of the initial performance tests to verify the emission levels below, as required by Condition 6 of this permit, emissions from Wyodak Unit 1 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 into the boiler and ends no later than the point in time when the flue gas desulfurization system on Unit 1 reaches a temperature of 275 F and three (3) coal pulverizers have been placed in service.

Pollutant lb/MMBtu lb/hr tpy

NO

x 0.23 (30

- day rolling) 1,081.0 (30

- day rolling) 4,735

PM/PM 10 (a) 0.015 71.0 309

(a) Filter able portion only

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

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

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

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7. Performance tests shall consist of the follow ing:

Coal

- fired Boiler ( Wyodak Unit 1 ):

NO

x Emissions

– Compliance with the NO

x 30

- day rolling average shall be determined using a continuous emissions monitoring system (CEMS) certified in accordance with 40 CFR part 60.

PM/PM 10 Emissions

– Testing sha ll follow 40 CFR 60.46 and EPA Reference

Test Methods 1

- 4 and 5.

Testing required by the Chapter 6, Section 3, Operating Permit may be submitted to satisfy the testing required by this condition.

8. Prior to any testing required by this permit, a test pr otocol 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

com pleting 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 boiler (Wyodak Unit 1) shall be determined with data from the continuous monitoring system 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 average of NO

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

s ubpart 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 emissions with valid data during the previous 30

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

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b. PacifiCorp shall comply wit h all reporting and record keeping requirements as specified

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

11

. PacifiCorp shall use EPA‟s Clean Air Markets reporting program to convert the monitoring system data to annual emissions. PacifiCorp shall provide substituted data according to the missing data procedures of 40 CFR, Part 75 during any period of time tha t there is not monitoring data. All monitoring data must meet the requirements of WAQSR, Chapter 5, Section 2(j).

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

- fired boiler ( Wyodak

Unit 1 ) 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 testi ng required by this condition.

13. Records required by this permit shall be maintained for a period of at least five (5) years and shall be made available to the Division upon request.

14. PacifiCorp shall install new low NO

x burners with advanced overfi re air and a new full

- scale

fabric filter on Unit 1 , in accordance with the Division‟s BART determination, and conduct the initial performance tests required in Condition 6 no later than December 31, 201 1.

# Appendix A Facility Location