DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION

BART Application Analysis

AP

- 604 7

May 2 8

, 200 9

NAME OF FIRM: Basin Electric Power Cooperative

NAME OF FACILITY: Laramie River Station

FACILITY LOCATION: 347 Grayrocks Road

Platte C ounty (Wheatland) , Wyoming
UTM Zone 13, NAD 27:

509

, 9 00 m E ; 4

, 661

, 675 m N

TYPE OF OPERATION: Electric Power Generating Station

RESPONSIBLE OFFICIAL: Mr. Robert Eriksen

MAILING ADDRESS: 1717 East Interstate Avenue Bismarck, North Dako ta 58503

TELEPHONE NUMBER: ( 701 ) 355

- 565 4

REVIEW ER S : Cole Anderson , Air Quality Engineer Josh Nall, Air Quality Modeler

PURPOSE OF APPLICATION:

Sections 169A and 169B of the 1990 Clean Air Act Amendments require states to improve visibility at

Cla ss I areas. On July 1, 1999, EPA first published the Regional Haze Rule, which provided specific details regarding the overall program requirements to improve visibility. The goal of the regional haze program is to achieve natural conditions by 2064.

Se ction 308 of the Regional Haze Rule (40 CFR 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 Retro fit Technology (BART) to reduce emissions of three (3) visibility impairing pollutants, nitrogen oxides (NO

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

- Guidelines for BART Determinations Under the Regional H

aze Rule in the July 6, 2005 Federal Register to provide guidance to regulatory authorities for making BART determinations. Chapter 6, Section 9, Best Available Retrofit Technology was adopted into the Wyoming Air Quality Standards and Regulations (WAQSR) and became effective on December 5, 2006. The Wyoming Department of Environmental Quality, Air Quality Division (Division) will

determine BART for NO

x and PM 10 for each source subject to BART and include each determination in the §308 Wyoming Regional Ha ze State Implementation Plan (SIP).Basin Electric Laramie River Station

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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 Cany on 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 cont ains special provisions for addressing SO 2 emissions, which include a m arket t rading program and a provision for a 2018 SO 2

m ilestone. Wyoming submitted a § 309 Regional Haze SIP to EPA on December 29, 2003. As of the date of this analysis, EPA has not ta ken action on the SIP. National litigation issues related to the Regional Haze Rule, including BART, required states to submit revisions. On November 2 1 , 2008, the State of Wyoming submitted revisions to the 2003 § 309 Regional Haze SIP submittal. Source s 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 March 5, 2007

, in accordance with the requirements of WAQSR Ch a pte r 6 Section 9(e)(i)

, Basin

Electric submitted a BART application for the Laramie River Station

.

On February 15, 2008

, Basin Electric submitted replacement pages for the BART application based on revised CALPUFF modeling conducted to c orrect errors in th e CALMET windfield discovered by the Division during review of the initial modeling submittal.

On July 28, 2008

, Basin Electric submitted an additional report with the results of additional CALPUFF modeling conducted to provide results for each of the t hree BART

- eligible units separately.

On February 25, 2009, Basin Electric submitted additional information on the NO

x emission rates that would be achievable by the BART

- eligible units.

On March 16, 2009, Basin Electric submitted a letter with proposed NO

x emission limits for the BART

eligible units.

BART ELIGIBILITY DETERMINATION:

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

- eligible sources, which are sources that fall

within the 26 so urce categories, have emission units which were in existence on August 7, 1977 but not in operation before August 7, 1962 and have the potential to emit more than 250 tons per year (tpy) of any visibility impairing pollutant when emissions are aggregated f rom all eligible emission units at a stationary source. Fifty

- one ( 5 1) sources at fourteen (14) facilities were identified that could be subject to BART in Wyoming.

The next step for the Division was to identify BART

- eligible sources that may emit any ai r pollutant which may reasonably be anticipated to cause or contribute to any impairment of 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.Basin Electric Laramie River Station

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In order to determine visibility impairment of each source, a screening analysis was performed using the

CALPUFF model . Sources that emitted over 40 tons of SO 2 or NO

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

, 24

- hour impact (i.e.

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

. The three existing coal

- fired boilers at Basin Electric ‟s Laramie River Station were determined to be subject to BART. Basin Electric was notified in a letter dated June 14, 2006 of the Division‟s finding.

DESCRIPTION OF BART ELIGIBLE SOURCES:

Basin Electric ‟s Laramie Riv er Station is comprised of three 5 5 0 MW (net) dry

- bottom, wall

- fired boilers burning pulverized coal for a total net generating capacity of 1

, 650 MW. Laramie River Unit 1 was placed in service in 19 80 . Unit 2 commenced service in 19 81, and Unit 3 entered service in 19 82

. All three units were manufactured by Babcock & Wilcox (B&W). Each unit is equipped with early generation low NO

x burners (LNB s ) to control emission of nitrogen oxides ( NO

x )

. The y are also equipped with cold

- side e lectrostatic precipita tor s (ESP s ) to control particulate matter (PM) emissions

. T o control sulfur dioxide ( SO 2 ) emissions, Units 1 and 2 are equipped with wet flue gas desulfurization ( W FGD) . Unit 3 is equipped with a dry scrubber (DFGD) for SO 2 removal

. All three units burn sub

bituminous coal. Table 1 presents the permitted emission limits for the Laramie River Station prior to 2005, which is considered the baseline year for BART analyses.

Table 1: Laramie River Station Units 1 through 3 ( Pre

- 2005 ) Emission Limits

Source Existing

Controls NO

x

(lb/MMBtu) (a) SO 2

(lb/MMBtu) (a) PM

(lb/MMBtu) (a)

Unit 1 LNB , ESP,

WFGD 0. 5 ( 3

- hour b ) 0.2
(2

- hour fixed block ) 0. 085 ( 3

- hour)

Unit 2 LNB , ESP,

WFGD 0. 5 ( 3

- hour b ) 0.2
(2

- hour fixed block ) 0. 085 ( 3

- hour)

Unit 3 LNB , ESP,

DFG D 0. 5 ( 3

- hour b ) 0.2
(2

- hour fixed block ) 0. 083 ( 3

- hour)

(a) Emissions taken from current Operating Permit 3

- 1

- 1 0 2

- 1

. (b) Arithmetic average of three contiguous one

- hour periods

CHAPTER 6, SECTION 9

– BEST AVAILABLE RETROFIT TECHNOLOGY (BART) :

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

, on a case

- by

case basis

, taking into consideration : (1) the costs of compliance , (2) the energy and non

- air quality environmental impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) the remaining useful life of the source, and (5) the degree of improvement in visibility which mayBasin Electric Laramie River Station

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reasonably be anticipated to result from the use of such technology.” 1 A BART analysis is a comprehensive evaluation of potential retrofit technologies with respect to the five criteria above. One technology and corresponding emission limit is chosen fo r each pollutant subject to BART review based

on the evaluation

.

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

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

The Division acknowledges that BART is intended to identify retrofit technology for existing sources and

is not the same as the top

- down analysis required for new sour ces under the Prevention of Significant Deterioration (PSD) rules known as Best Available Control Technology (BACT). Although BART is not the same as BACT, it is possible that BART may be equivalent to BACT on a case

- by

- case basis. The

fi v e steps listed above were applied to NO

x , PM, and SO 2 emitted from the Laramie River Station‟s coal

fired boilers to determine BART control measure s

.

PRESUMPTIVE LIMITS FOR SO 2 AND NO X FROM UTILITY BOILERS

EPA conducted detailed analyses of retrofit technology availabl e to control NO

x and SO 2 emissions from

coal

- fired power plants. These analyses considered unit size, fuel type, cost effectiveness, and existing controls to determine reasonable control levels based on the application of an emissions reduction technology

.

EPA‟s presumptive BART SO 2 limits analysis considered coal

- fired units with existing SO 2 controls and units without existing control. Four key elements of the analysis were: “...(1) identification of all potentially BART

- eligible EGUs [electric generatin g units], and (2) technical analyses and industry research to determine applicable and appropriate SO 2 control options, (3) economic analysis to determine cost effectiveness for each potentially BART

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

- eligible EGU.” 3 491 BART

- eligible coal

- fired units were identified and included in the presumptive BART analysis for SO 2 . Based on removal efficiencies of 90% for spray dry lime dry flue gas desu lfurization 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 co al

- fired

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

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

o ption and a reasonable set of options for analysis that reflects a comprehensive list of available technologies.”

3 40 CFR Part 51 Appendix Y Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 39133).Basin Electric Laramie River Station

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

x limits for EGUs based on coal type and boiler configuration. For all boiler types, except cyclone, presumptive limit s were based on combustion control technology (e.g.

, low NO

x burners and overfire air). Presumptive NO

x limits for cyclone boilers are based on the installation of SCR, a post combustion add

- on control. EPA acknowledged that approximately 25% of the revi ewed units could not meet the proposed limits based on current combustion control technology, but that nearly all the units could meet the presumptive limits using advanced combustion control technology, such as Rotating Opposed Fire Air. National average cost

- effectiveness values for presumptive NO

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

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.

Pre sumptive NO

x levels for uncontrolled units are listed in Table 1 of Appendix Y and are classified by the boiler burner configuration (unit type) and coal type. NO

x emission values range from 0.62 lb/MMBtu down to 0.15 lb/MMBtu. While Appendix Y establish es 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 Di vision‟s following BART analyses for NO

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

Basin Electric‟s Laramie River Station generates a net 550 MW from each of three coal

- fired units. None

of the units has NO

x post

- combustion controls. The p resumptive NO

x emission limit for dry

- bottom,

wall

- fired boilers burning sub

- bituminous coal (i.e.

, each of the three units) is 0.23 lb/MMBtu.

NO

x : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Basin Electric identified s ix control t echnolog y configurations for control of NO

x emissions from Units 1 through 3 :

Overfire Air (OFA)

New Low NO

x Burners (LNB) Selective Catalytic Reduction (S CR )

Selective Non

- Catalytic Reduction (S N CR) SNCR/SCR Hybrid

Natural Gas Reburn

1. Overfire Air

– OFA is a combustion control technology that reduces NO

x emissions by controlling the combustion process within the boiler. Within an initial fuel

- rich environment that

is used to favor the conversion of fuel

- bound nitrogen to N 2 instead of NO

x , additional air (or OFA) is introduced down stream of the main burner zone to burn out any residual material. By injecting the OFA into the lower temperature combustion zone, NO

x is less likely to form

, while burning the residual solid fuel (char).

4 Ibid. (70 Federal Register 39171)Basin Electric Laramie River Station

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2. New Low NO

x Burn ers

- L NB technologies rely on a combination of fuel staging and combustion air control to suppress the formation of thermal NO

x . Fuel staging occurs in the very beginning of combustion, where the pulverized coal is injected through the burner into the fu rnace. Careful

control of the fuel

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

x . This allows complete combustion of the fuel while reducing both thermal and chemical NO

x formation.

3. Selective C atalytic Reduction

– SCR is a post combustion control technique in which vaporized ammonia is injected int o the flue gas upstream of a catalyst. NO

x entrained in the flue gas is

reduced to N 2 and water

. When catalyst temperatures are not in the optimal range for the

reduction reaction or when too much ammonia is injected into the process, unreacted ammonia

c an be released to the atmosphere through the stack. This release is commonly referred to as

ammonia slip

.

4. Selective Non

- Catalytic Reduction

- SNCR involves the injection of a reducing agent such as ammonia or urea into the flue gas stream. Rather than rely on a catalyst, SNCR systems rely on appropriate injection temperatures, proper mixing of the reagent and flue gas, and prolonged

retention time

. The effective temperature range for SNCR is higher than for SCR, and SNCR

systems typically have lower NO

x emissions reduction s than SCR. Also, SNCR systems are more prone to ammonia slip than SCR.

5. SNCR/SCR Hybrid

– A hybrid SNCR/SCR system combines the lower costs and higher ammonia slip of SNCR with the higher NO

x reduction potential and lower ammonia slip of SCR. During operation, the SNCR system is allowed to inject higher amounts of reagent into the flue gas. The increased reagent flow brings about increased NO

x reduction, but also causes increased ammonia slip which is then consumed by the SCR system

. The use of the ammonia slip by the SCR system can reduce the size of the required SCR catalyst.

6. Natural Gas Reburn

– Fuel reburning is a method of fuel staging designed to reduce NO

x emissions. It involves the introduction of a supplemental fuel into the main section of the steam generator to produce reducing conditions that convert NO

x to N 2 . Natural gas reburn requires three separate combustion zones and sufficient residence time (adequate furnace height).

I n addition to applying these control s technologies separately, they can be combined to increase overall

NO

x reduction. Basin Electric evaluated the combined application of OFA / LNB and the combined application of OFA/ LNB with SNCR

.

NO

x : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

Natural Gas Reburn

- Basin Electric determined that natural gas reburn is technically infeasible because the effectiveness of such a system would be negatively impacted by the amount of space available in the

Laramie River Station furnaces.Basin Electric Laramie River Station

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NO

x : EVALUATE EFFECTI VENESS OF REMAINING CONTROL TECHNOLOGIES

The Division considers the control effectiveness of a proposed control technology to be equivalent to the permit limit that would be established for that technology if it were chosen as BART . The permit limit is

b ased on continuous compliance when the control equipment is well maintained and operated in a manner consistent with good air pollution control practices. In order to demonstrate continuous compliance with the permit limit

, it is important to consider tha t even well maintained and operated equipment will have some emissions variability. Complex emission control equipment, such as LNB with OFA , generally have inherent variability that must be considered when establishing the permit limit. Otherwise, the

s ource may be out of compliance even though the equipment is operated and maintained as well as possible

.

Basin Electric determined that SNCR as the sole control technology would not meet the presumptive emission rate of 0.23 lb/MMBtu. A preliminary evalu ation of an SNCR system for Laramie River Station

indicated that the controlled NO

x emission would be 0.24 lb/MMBtu. Therefore, SNCR was not further evaluated as the sole control technology.

In the initial BART permit application submitted by Basin Ele ctric, the installation of OFA or new LNB individually were both listed with a control effectiveness of 0.23 lb/MMBtu. A combination of OFA with

new LNB was listed with a control effectiveness of 0.15 lb/MMBtu. Subsequent submittals from Basin

Electric d escribed that the 0.15 lb/MMBtu control effectiveness was based entirely on computational fluid dynamics (CFD) modeling that was conducted in 2004

. The value produced by the CFD modeling was

described a s the lowest theoretical NO

x level that could be achi eved when operating conditions match the optimum conditions simulated in the modeling. Additionally, the 2004 CFD modeling included an error

in the use of sea

- level conditions and was described by Basin Ele ct ric‟s contractor (Black & Veatch) as representi ng optimum, steady

- state conditions that could not be maintained during normal operation of

the Laramie River Station boilers.

More current CFD modeling performed by Reaction Engineering at the request of Basin Electric for the Unit 1 OFA project indicat ed that the installation of OFA with new LNB would result in a control

effectiveness of 0.18 lb/MMBtu ( ± 0.02 lb/MMBtu). As described by Burns & McDonnell on behalf of

Basin Electric, the results of the more recent CFD modeling indicate that an appropriate emissions limit

for OFA + new LNB that takes into account the normal operation variability would be 0.23 lb/MMBtu for

a 30

- day rolling average.

Basin Electric contracted with Black & Veatch to analyze the control effectiveness of other control

te chnologies, including a SNCR/SCR Hybrid (Cascade) system, OFA + new LNB with SNCR, and SCR.

T able 2 presents a summary of the effectiveness of the technically feasible control technologies for NO

x .Basin Electric Laramie River Station

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Table 2 : NO

x Emission Rates Per Boiler

Control Technology Control

Effectiveness (lb/MMBtu)

Baseline 0.27

Overfire Air 0.23

New LNB 0.23

New LNB with OFA 0.23

SNCR/SCR Hybrid 0.20

New LNB with OFA and SNCR 0.12

SCR 0.07

Note: Baseline emissions based on continuous emissions monitoring (CEM) an nual averages for 2001

- 2003.

NO

x : EVALUATE IMPACTS AND DOCUMENT RESULTS

Basin Electric quantified the costs of applying the remaining NO

x control technologies by c onsidering the following types of impact :

Cost of compliance
Energy i mpacts

Non

- air qualit y environmental impacts Remaining useful life Visibility (described in a later section of the document)

Energy impacts, such as added auxiliary power consumption or the power associated with additional draft systems to overcome resistance to flu e gas flo w, were calculated for each control technology. Non

- air quality environmental impacts were also considered, and for this analysis were limited to the costs associated with disposal of byproducts or waste generated by control technologies. Basin Electric anticipates operating the Laramie River Station Units 1

- 3 indefinitely and did not include life extension costs in the economic analysis. A standard control life of 20 years was used to calculate the capital recovery factor.

Basin Electric developed es timates for the cost of compliance, including Total Capital Investment (TCI) and annual operation and maintenance (O&M) costs, using the following sources of information:

Coal Utility Environmental Cost (CUECost) workbook (Version 1.0)

EPA Air Pollution C ontrol Cost Manual (Sixth Edition) Budgetary quotes from equipment vendors Cost estimates from previous design/build projects or in

- house engineering estimatesBasin Electric Laramie River Station

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Several different metrics can be considered when evaluating the cost

- benefit relationships of d ifferent emission control technologies. In 40 CFR part 51 Appendix Y

, two metrics are specifically mentioned: cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has extensive experience using cost effecti veness (i.e.

, dollars per ton of pollutant removed) to evaluate

c ontrol technologies. Incremental cost effectiveness is also used extensively by the Division when comparing emission controls under the BACT process. While the BART process and the BACT pro cess are not equivalent, control determinations from either process that are based on cost effectiveness and

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

In addition to providing cost effectiveness and increm ental cost effectiveness results, Basin Electric provided cost information in terms of cost of applying emission controls and the level of visibility improvement achieved (i.e.

, dollars per deciviews). While this metric can illustrate the control cost and visibility improvement differences between control options, it is not commonly used to assess the overall effectiveness of pollution control equipment. When performing the presumptive BART levels analyses

for NO

x and SO 2 , EPA addressed cost effectiveness and incremental cost effectiveness separate from visibility improvement. EPA did not use the dollars per deciview metric to compare control options. Visibility improvements from the application of the control measures used to establish presumptive level s were addressed in a separate visibility analysis. As discussed in the comprehensive visibility analysis presented later in this analysis, the Division evaluated the amount of anticipated visibility improvement gained by the application of each proposed emission control technology. The Division considered cost effectiveness and incremental cost effectiveness in the evaluation of each proposed NO

x emission control.

Tables 3 through 5 present the economic and environmental costs associated with the rema ining NO

x control technologies for Units 1 through 3.Basin Electric Laramie River Station

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Table 3 : Unit 1 Economic and Environmental Costs for NO

x Control

Parameter OFA New LNB New LNB

with OFA SNCR/SCR

Hybrid New

LNB/OFA

and SNCR SCR

Capital Cost s $5,326,000 $1 5,631,000 $22,096,000 $44,969,000 $43,441,000 $123,101,000

Annual ized Costs $625,000 $1,360,000 $1,944,000 $7,429,000 $7,365,000 $15,787,000

NO

x Emissions (lb/MMBtu) 0.23 0.23 0.23 0.20 0.12 0.07

Annual NO

x Emission (tpy) 5,384 5,384 5,384 4,681 2,809 1,639

Annual NO

x Reduction (tpy) 936 936 936 1,639 3,511 4,681 Cost per ton of

Reduction $668 $1,453 $2,07 7 $4,534 $2,098 $3,372 Incremental Cost per

ton of Reduction (1)

-- -- -- -- $2,105 $ 7,198

Energy Costs $140,000

-- -- $77,000 $77,000 $414,000

Non

- Air Quality Costs

-- -- -- -- -- $1,000

(1) Incremental costs for new LNB + OFA + SNCR calculated relative to new LNB + OFA. Incremental costs for SCR calculated relative to new LNB + OFA + SNCR. Incremental costs for SNCR/SCR Hyb r id not calculated (consi dered an inferior technology and not considered further in this analysis)

.

T able 4 : Unit 2 Economic and Environmental Costs for NO

x Control

Parameter OFA New LNB New LNB

with OFA SNCR/SCR

Hybrid New

LNB/OFA

and SNCR SCR

Capital Cost s $5,326,000 $15 ,631,000 $22,096,000 $44,969,000 $43,441,000 $123,101,000

Annual ized Costs $625,000 $1,360,000 $1,944,000 $7,429,000 $7,365,000 $15,787,000

NO

x Emissions (lb/MMBtu) 0.23 0.23 0. 23 0.20 0.12 0.07

Annual NO

x Emission (tpy) 5,354 5,354 5,354 4,656 2,793 1 ,630

Annual NO

x Reduction (tpy) 931 931 931 1,630 3,492 4,656 Cost per ton of

Reduction $671 $1,461 $ 2,088 $4,559 $2,109 $3,391 Incremental Cost per

ton of Reduction (1)

-- -- -- -- $2,117 $7,242

Energy Costs $140,000

-- -- $77,000 $77,000 $414,000

N on

- Air Quality Costs

-- -- -- -- -- $1,000

(1) Incremental costs for new LNB + OFA + SNCR calculated relative to new LNB + OFA. Incremental costs for SCR calculated relative to new LNB + OFA + SNCR. Incremental costs for SNCR/SCR Hybrid not calculated (consid ered an inferior technology and not considered further in this analysis)

.Basin Electric Laramie River Station

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Table 5 : Unit 3 Economic and Environmental Costs for NO

x Control

Parameter OFA New LNB New LNB

with OFA SNCR/SCR

Hybrid New

LNB/OFA

and SNCR SCR

Capital Cost s $5,326,000 $15, 631,000 $22,096,000 $44,969,000 $43,441,000 $123,101,000

Annual ized Costs $625,000 $1,360,000 $1,944,000 $7,429,000 $7,365,000 $15,787,000

NO

x Emissions (lb/MMBtu) 0.23 0.23 0.23 0.20 0.12 0.07

Annual NO

x Emission (tpy) 5,493 5,493 5,493 4,777 2,866 1, 672

Annual NO

x Reduction (tpy) 955 955 955 1,672 3,582 4,777 Cost per ton of

Reduction $654 $1,424 $2,036 $4,444 $2,056 $3,305 Incremental Cost per

ton of Reduction (1)

-- -- -- -- $2,064 $ 7,054

Energy Costs $140,000

-- -- $77,000 $77,000 $414,000

No n

- Air Quality Costs

-- -- -- -- -- $1,000

(1) Incremental costs for new LNB + OFA + SNCR calculated relative to new LNB + OFA. Incremental costs for SCR calculated relative to new LNB + OFA + SNCR. Incremental costs for SNCR/SCR Hybrid not calculated (conside red an inferior technology and not considered further in this analysis)

.

The cost effectiveness and incremental cost effectiveness of the proposed BART technologies for NO

x are all reasonable. The SNCR/SCR Hybrid was eliminated from further consideration as an inferior technology as compared to New LNB/OFA / SNCR because of the higher costs/higher emissions associated with the Hybrid option . Basin Electric modeled the range of anticipated visibility improvement from the company

- proposed BART controls (OFA) by modeling OFA/New LNB and

OFA/New LNB/SCR. While OFA/New LNB / SNCR w as not individually evaluated in Step 5: Evaluate visibility impact , t he anticipated degree of visibility improvement from applying this control option lies

within the range of visibili ty impacts that were modeled.

The final step in the BART NO

x determination process for Laramie River Station Units 1

- 3 , Step 5: Evaluate visibility impacts, is addressed in a comprehensive visibility analysis covering all three visibility impairing pollut ants and associate control options. The visibility analysis follows Steps 1

- 4 for PM 10 emissions in this application analysis.

SO 2 : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Basin Electric identified three control technology configurations for re duc tion of S O 2 emissions from Units 1 and 2, which are currently equipped with back

- end WFGD systems:

Elimination of Stack Reheat System Improvements to Existing WFGD Sorbent InjectionBasin Electric Laramie River Station

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1. Elimination of Stack Reheat System

– Basin Electric routes a port ion of the flue gas on Units 1 and 2 to a reheat system that decreases the moisture in the flue s and avoid s damage to the flues,

which are brick

- lined. The elimination of the reheat system would route more of the flue gas through the WFGD and reduce S O 2 e missions , but would place added strain on the scrubber and require a new stack with a liquid collection system.

2. Improvements to Existing WFGD

– Units 1 and 2 are equipped with dual

- loop, counter

- flow

absorber towers. Each unit has five absorber towers . Current operation of the system meets the permitted emission limit of 0.20 lb/MMBtu. One possible measure to improve the performance of the system would be the installation of an additional level of perforated tray below the existing perforated tray

. This tray would serve to increase the contact time between the flue gas and the reagent liquid (L/G ratio) and increase overall S O 2 removal. This technique , however, would increase the pressure drop in the scrubber vessel, and would require an upgrade to draft system. Another option for enhanced S O 2 removal is to increase the slurry flow rate into the absorber section of the WFGD by adding an additional spray header. The disadvantage of this option is increased erosion on the vaning system in the tower, and the need to enhance the reagent preparation system. A third option for higher S O 2 removal is to upgrade the capacity of the recycle pumps, thus increasing the slurry flow rate. This would increase the L/G rati o. As a fourth option, an additional abs orber tower could be installed to allow for the treatment of more flue gas and to increase the L/G ratio by allowing a rebalancing of the flue gas flow rates to a
lower flow through each tower. A fifth option is the introduction of chemical additives that

enhance the S O 2 capture rate. Three additives that are typically used are dolomitic lime, dibasic (DBA) or adipic acid, and formic acid. Basin Electric chose this option for further evaluation because it had the least plant impacts, outage time, and FGD operation procedure impacts.

3. Sorbent Injection

– Components of a reagent injection system typically include an air compressor, sorbent storage tank, heat tracing, controls, injection system, injection platform, and slurry pump. Furnace and duct injection systems require a wet or dry reagent, and are capable of removing 10 to 20 percent of the S O 2 in the flue gas. A dry reagent such as powdered lime is preferred for furnace injection systems. For duct injection systems, a wet reagent such as lime slurry is preferred. Use of a wet reagent upstream of an existing ESP can help reduce the gas temperature, improve ESP performance, and eliminate the need for additional ID fans for draft control.

Basin Electric identified four control technology configuratio ns for reduction of S O 2 emissions from Unit

3 , which currently uses a DFGD system :

Fabric Filter Retrofit into Unit 3 ESP Casing

Re placement of Dry Scrubber Reactor with New Generation SDA Modules

New WFGD System Sorbent Injection

1. Fabric Filter Retr ofit into Unit 3 ESP Casing

– Enhanced S O 2 removal c an be achieved by retrofitting a fabric filter system into the existing Unit 3 ESP. Removal of S O 2 would occur from contact of the remaining S O 2 molecules in the flue gas with unreacted lime particles in the fly ash cake on the fabric filter bags. With a typical Spray Dryer Absorber (SDA) and pulse jet fabric filter (PJFF) system, additional S O 2 removal can be 10 to 20 percent.Basin Electric Laramie River Station

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2. Replacement of Dry Scrubber Reactor with New Generation SDA Modules

– Exist ing dry scrubber equipment on Unit 3 was designed by B&W, and achieves an S O 2 removal rate of approximately 85 percent. Replacement of the existing four dry scrubber reactors with two SDA

modules could achieve a small increase in S O 2 removal.

3. New WFGD System

– A new wet FGD system similar to those used on Units 1 and 2 could be installed on Unit 3 to replace the existing dry scrubber. Unit 3‟s dry scrubber would be left in place with its internal equipment removed to reduce pressure drop. The Unit 3 ESP would remain in operation to remove fly ash, and the location of the new WFGD would be to the east of the existing chimney. A new stack with a liner capable of wet flue gas operation would be required. Outage time for the unit would only be required for tie

- in with the new system. New booster fans would be needed to adjust for additional pressure drop from the scrubber, and the limestone reagent preparation system for Units 1 and 2 might have to be upgraded to

accommodate additional material needed f or Unit 3.

4. Sorbent Injection

– The sorbent injection system described earlier for Units 1 and 2 is also a possibility for Unit3.

SO 2 : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

All of the control technologies identified for Units 1 and 2 are technically feasible. For Unit 3, two of the listed technologies were deemed by Basin Electric as technically infeasible:

New Generation SDA Modules : Unit 3 is already equipped with a system that is essentially an SDA, and therefore it is not feasible to replace the existing system with a similar system.

Sorbent Injection

– Sorbent injection is not technically feasible for Unit 3 because the expected controlled emission level would not meet the presumptive level.

SO 2 : EVALUATE EFFECTIVENESS OF REMAINING CONTROL T ECHNOLOGIES

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

BART

- determined permit limit. The limit is based on continuous compliance when the control equipment is well maintained and operated in a manner consistent with good air pollution control practices. 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 generally ha s 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.

Table s 6 and 7 pr esent the effectiveness of the remaining technically feasible control technologies for

S O 2

.Basin Electric Laramie River Station

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Table 6 : Units 1 and 2 SO 2 Emission Rates Per Boiler

Co ntrol Technology Control

Effectiveness (lb/MMBtu)

Baseline 0. 16

Sorbent Injection 0.15

FGD Chemical Additives 0.15

Elimination of Stack Reheat System 0. 13

Note: Baseline emissions based on continuous emissions monitoring (CEM) annual averages for 2001

- 2003.

Table 7 : Unit 3 SO 2 Emission Rates

Co ntrol Technology Control

Effectiveness (lb/MMBtu)

Base line 0.17

Fabric Filter Retrofit into Unit 3 ESP 0.13

New WFGD 0.06

Note: Baseline emissions based on continuous emissions monitoring (CEM) annual averages for 2001

- 2003.

SO 2 : EVALUATE IMPACTS AND DOCUMENT RESULTS

Basin Electric quantified the costs of applying the remaining SO 2 control technologies at the Laramie River Station by considering the following types of impact:

Cost of compliance
Energy Impacts

Non

- air quality environmental impacts Remaining useful life Visibility (described in later se ction of the document)

Basin Electric anticipates operating the Laramie River Station Units 1

- 3 indefinitely and did not include life extension costs in the economic analysis. A standard control life of 20 years was used to calculate the capital recovery factor.

Several different metrics can be considered when evaluating the cost

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

cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has extensive experience using cost effectiveness (i.e.

, dollars per ton of pollutant removed) to evaluate

c ontrol technologies . Incremental cost effectiveness is also used extensively by the Division when comparing emission controls under the BACT process. While the BART process and the BACT processBasin Electric Laramie River Station

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

incremental cost effectiveness are indica tive of the economic costs to control emissions.

In addition to providing cost effectiveness and incremental cost effectiveness results, Basin Electric provided cost information in terms of cost of applying emission controls and the level of visibility improvement achieved (i.e.

, dollars per deciviews). While this metric can illustrate the control cost and visibility improvement differences between control options, it is not commonly used to assess the overall effectiveness of pollution control equipmen t. When performing the presumptive BART levels analyses

for NO

x and SO 2 , EPA addressed cost effectiveness and incremental cost effectiveness separate from visibility improvement. The dollars per deciview metric was not used to compare control options.

V isibility improvements from the application of the control measures used to establish presumptive levels were addressed in a separate visibility analysis. The Division considered cost effectiveness and

incremental cost effectiveness in the evaluation of e ach proposed emission control. Tables 8 through 10 present the economic and environmental costs associated with the remaining SO 2 co ntrol technologies for Units 1 through 3.

Table 8 : Unit 1 Economic and Environmental Costs for S O 2 Control

Parameter Sor bent Injection FGD

Chemical

Additives Eliminate Stack

Reheat System

Capital Cost s $7,453,000 $2,363,000 $ 63

, 845 ,000

Annual ized Costs $ 906 ,000 $36 6 ,000 $ 6

, 664 ,000

S O 2 Emissions (lb/MMBtu) 0. 15 0. 15 0. 13

Annual S O 2 Emission (tpy) 3,511 3,511 3,043

Ann ual S O 2 Reduction (tpy) 234 234 702

Cost per ton of Reduction $ 3,871 $1, 564 $ 9,490

Incremental Cost per ton of Reduction (1)

-- -- $13,453

Energy Costs $ 62 ,000 $6,000 $ 459 ,000

Non

- Air Quality Costs

-- -- -- (1) Incremental costs for Eliminate Stack Reheat System relative to FGD Chemical AdditivesBasin Electric Laramie River Station

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Table 9 : Unit 2 Economic and Environmental Costs for SO 2 Control

Parameter Sorbent Injection FGD

Chemical

Additives Eliminate Stack

Reheat System

Capital Cost s $7,453,000 $2,363,000 $63,845,000

Annua l ized Costs $906,000 $366,000 $6,664,000

S O 2 Emissions (lb/MMBtu) 0.15 0.15 0.13

Annual S O 2 Emission (tpy) 3,492 3,492 3,026

Annual S O 2 Reduction (tpy) 233 233 698

Cost per ton of Reduction $3,892 $1,572 $9,542

Incremental Cost per ton of Reduction (1 )

-- -- $13,527

Energy Costs $62,000 $6,000 $459,000

Non

- Air Quality Costs

-- -- -- (1) Incremental costs for Eliminate Stack Reheat System relative to FGD Chemical Additives

Table 10 : Unit 3 Economic and Environmental Costs for SO 2 Control

Parameter Fabr ic Filter

Retrofit into

Unit 3 ESP ( peak rate for lost gen.

costs ) Fabric Filter

Retrofit into

Unit 3 ESP ( non

- peak

rate for lost

gen. costs ) New WFGD

Capital Cost s $194,809,000 $134,934,000 $240,777,000

Annual ized Costs $19,585,000 $14,376,000 $3 1,243,000

S O 2 Emissions (lb/MMBtu) 0.13 0.13 0.06

Annual S O 2 Emission (tpy) 3,105 3,105 1,433

Annual S O 2 Reduction (tpy) 955 955 2,627

Cost per ton of Reduction $20,501 $15,049 $11,893

Incremental Cost per ton of Reduction (1)

-- -- $10,089

Energy Co sts $242,000 $243,000 $3,858,000

Non

- Air Quality Costs

-- -- $715,000

(1) Incremental costs for new WFGD for Unit 3 relative to Fabric Filter RetrofitBasin Electric Laramie River Station

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Several of the technically feasible control options for SO 2 are not cost effective, including all proposed options for Unit 3, and the elimination of the stack reheat system for Units 1 and 2. The remaining options for Units 1 and 2, Sorbent Injection and FGD Chemical Additives, were modeled by the applicant

to determine Class I area visibility improvement

. Results of the modeling showed that visibility improvement would be insignificant. For example, the predicted visibility improvement at Badlands National Park, based on the modeled 98 th percentile result for all three units combined

, would be (at most)

0. 02 delta deciview . Therefore, none of the proposed control options for SO 2 were carried forward for further analysis.

PM/ PM 10 : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Basin Electric identified four control technology configurations fo r control of PM emissions from Units 1 through 3:

Flue Gas Treatment Existing ESP Performance Enhancements

PJFF Retrofit into ESP (Unit 3 only)

GE M ax

- 9 Hybrid

1. F lue Gas Treatment

– One option for flue gas treatment is flue gas “conditioning”, for whi ch flue gas is conditioned by adding ionic compounds such as sulfur trioxide and ammonia to improve the PM capture rate in the ESP. Moisture in the flue gas combines with the ionic compounds and the mixture is deposited on the surface of the fly ash parti cles. In this way, the conductivity of the fly ash is increased and the capture rate of the ESP is improved. Another option is in

- duct humidification, for which moisture is added to the flue gas upstream of the ESP. This serves to reduce the temperature (and volume) of the flue gas, and a denser flue gas allows for an increase in the Specific Collection Area (SCA) of the ESP without a physical modification to the ESP. The humidification would have to be limited to avoid an outlet temperature that would promote
the formation of H 2 SO 4

. Particle agglomeration is another option for flue gas treatment. For this process, the flue gas is pretreated with electrostatic charges upstream of the ESP to promote agglomeration of the particles. By agglomerating the particles into larger sizes and reducing the number of particles to be collected by the ESP, the overall removal efficiency of the ESP is improved.

2. E xisting ESP Performance Enhancements

– The ESP imparts an electrical charge to particles in the flue g as, and the particles adhere to metal plates inside the precipitator. Rapping on the plates removes the particles from the plates for disposal. One technology for improving rapping efficiency and preventing re

- entrainment of the fly ash into the flue gas is the use of a computerized rapping system. This has already been implemented at the Laramie River Station. Another option for improving the ESP performance is to upgrade the electrical and control system. This type of upgrade can not only enhance the particle collection efficiency, but will also allow the ESP to operate more efficiently and therefore lower the auxiliary power use. This also has already been implemented at the Laramie River Station.

3. Pulse Jet Fabric Filter Retrofit into ESP

– Re trofit of a PJFF into the existing Unit 3 ESP casing would require several physical modifications to the system, including the construction of a tubesheet to hold the fabric filter bags and the installation of a compressed air system for cleaningBasin Electric Laramie River Station

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the bags. A new booster fan system would be required to offset the added pressure drop from the

filter bags. The additional auxiliary power consumption from the new booster fan would be offset by power savings from not operating the ESP. Th e PJFF retrofit is a v iable option only for

Unit 3. Units 1 and 2 utilize wet flue gas desulfurization ( W FGD)

, and a PJFF is not feasible for use downstream of a WFGD system

.

4. GE M ax

- 9 Hybrid

– The GE Max

- 9 Electrostatic Fabric Filter ( ESFF ) is an electrostatic precipitator/pu lse

-

jet baghouse hybrid, using high

- voltage discharge electrodes to charge flue gas particle s , but with fabric filters instead of collecting plates in the casing. The system can provide high collection efficiency while operating at a lo wer system pressure drop . Pressure drop is lower because particles are charged positively and repel each other on the surface of the filter, making the dust cake very porous. Compressed air pulses are used to clean the filters.

PM/ PM 10 : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

Basin Electric identified three of the four potential control technologies for PM as technically infeasible:

Flue Gas Treatment : This option would not increase the level of emissions control to a higher level than is currently achieved with the e xisting ESP, and is therefore considered to be technically infeasible.

Existing ESP Performance Enhancement

– The ESP performance enhancements , as described earlier, are already in use at the Laramie River Station.

GE Max

- 9 Hybrid

– The GE Max

- 9 Hybr id has been recently installed in a smaller utility boiler, but not

with a boiler of the size used at the Laramie River Station. Therefore, the GE Max

- 9 is not considered as a technically feasible technology.

PM/ PM 10 : EVALUATE EFFECTIVENESS OF REMAININ G 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 o perated in a manner consistent with good air pollution control practices. 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 variabilit y. Complex emission control equipment generally ha s 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. Table 11 presents the control effectiveness associated with the remaining technically feasible PM controls.

Table 11 : PM Emission Rates Per Boiler

Co ntrol Technology Control

Effectiveness (lb/MMBtu)

Baseline 0.030

Retrofit Fabric Filter into Unit 3 ESP 0.0 15Basin Electric Laramie River Station

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PM/ PM 10 : EVALUATE IMPACTS AND DOCUMENT RESULTS

Basin Electric quantified the costs of applying the remaining technologies at the Laramie River Station by considering the following types of impact:

Cost of compliance
Energy Impacts

Non

- air quality env ironmental impacts Remaining useful life Visibility (described in later section of the document)

Basin Electric anticipates operating each of the Laramie River Station units 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.

Several different metrics can be considered when evaluating the cost

- benefit relationships of different emission control technologies. In 40 CFR part 51 Appendix Y two metrics are specifically mentioned: cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has extensive experience using cost effectiveness (i.e.

, dollars per ton of pollutant removed) to evaluate

c ontrol technologies. Incremental cost effectiveness is also used extensively by the Division when comparing emission controls under the BACT process. While the BART process and the BACT process are not equivalent, control determinations from either process tha t are based on cost effectiveness and

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

In addition to providing cost effectiveness and incremental cost effectiveness results, Basin Electric provided cost informat ion in terms of cost of applying emission controls and the level of visibility improvement achieved (i.e.

, dollars per deciviews). While this metric can illustrate the control cost and visibility improvement differences between control options, it is not commonly used to assess the overall effectiveness of pollution control equipment. When performing the presumptive BART levels analyses

for NO

x and SO 2 , EPA addressed cost effectiveness and incremental cost effectiveness separate from visibility improvemen t. The dollars per deciview metric was not used to compare control options. Visibility improvements from the application of the c ontrol measures used to establish presumptive levels were addressed in a separate visibility analysis. As discussed in the c omprehensive visibility analysis presented later in this analysis, the Division evaluated the amount of visibility improvement gained in relation to each proposed emission control technology. The Division considered cost effectiveness and

incremental cost effectiveness in the evaluation of each proposed PM emission control. Table 12 present

the economic and environmental costs associated with the remaining PM technologies.Basin Electric Laramie River Station

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Table 12 : Unit 3 Economic and Environmental Costs for PM Control

Paramete r Fabric Filter

Retrofit into Unit 3

ESP ( peak rate for lost gen. costs ) Fabric Filter

Retrofit into Unit 3

ESP ( non

- peak rate for lost gen. costs )

Capital Cost s $194,809,000 $134,934,000

Annual ized Costs $19,585,000 $14,376,000

PM Emissions (lb/MMB tu) 0. 0 15 0. 015

Annual PM Emission (tpy) 358 358

Annual PM Reduction (tpy) 358 358

Cost per ton of Reduction $ 54, 707 $ 40,1 56

Energy Costs $242,000 $243,000

The remaining technically feasible PM 10 control option for Unit 3 is not cost effective, and was not carried forward for further analysis.

VISIBILITY IMPROVEMENT DETERMINATION :

The fifth of five factor s that must be considered for a BART determination analysis, as required by 40 CFR part 51

- Appendix Y, is the degree of Class I area v isibility improvement that would result from the

installation of the various options for control technology

. This factor was evaluated for the Basin Electric Power Cooperative (BEPC) Laramie River Station by using an EPA

- approved dispersion modeling

syste m (CALPUFF) to predict the change in Class I area visibility. The Division had previously

determined that the Laramie River Station was subject to BART based on the results of initial screening modeling that was conducted using current (baseline) emission s from the facility. The screening modeling, as well as m ore refined modeling conducted by the applicant

, is described in detail below.

Rocky Mountain National Park (NP) and Rawah Wilderness Area in Colorado are the closest Class I

areas to the Laramie River Station, as shown in F igure 1 below. Rawah WA is located approximately 165 kilometers (km) to the southwest of the station and Rocky Mountain NP is located approximately 185 km

to the southwest of the station. Wind Cave NP and Badlands NP are loca ted to the northeast of the station, at distances of approximately 1 90 km and 270 km , respectively

.

Only those Class I areas most likely to be impacted by the Laramie River sources were modeled, as determined by source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. I t can be reasonably assumed that areas at greater

distance s and in directions of less frequent plume transport will experience lower impacts than those predic ted for the two modeled areas

.Basin Electric Laramie River Station

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Figure 1

Laramie River Station and Class I AreasBasin Electric Laramie River Station

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SCREENING MODELING

To determine if the Laramie River Station would be subject to BART, the Division conducted CALPUFF modeling using three years of meteorologica l data. These data, from 2001

- 2003 , consisted of surface and

upper

- air observations and gridded output from the Mesoscale Model ( MM5 ) . Resolution of the MM5

data was 36

- km for all three of the modeled years. S ources input to the modeling included the po tential emissions (current operation) from the three coal

- fired boilers at the f acility

. The Division chose to model the impacts at Wind Cave NP and Badlands NP for the screening, using the assumption that these areas would yield larger impacts than the C olorado Class I areas due to the predominant wind direction.

Results of the modeling showed that the 98 th percentile value for the change in visibility (delta deciview [Δdv]) was above 0.5 Δ dv at Wind Cave NP and Badlands NP for all three years of meteo rolog y

. As defined in EPA‟s final BART rule, a 98 th percentile 0.5 Δ dv impact or more from a given source indicates that the source contributes to visibility impairment, and therefore is subject to BART. The results of the screening modeling are shown in T able 13 below.

Table 13 : Results of the Class I Area Screening Modeling

Year and Class I Area Maximum

Modeled Value (Δdv) 98 th

Percentile Value (Δdv)

2001

Wind Cave NP 6.27 3.30

Badlands NP 5.50 3.68

2002

Wind Cave NP 7.71 3.14

Badlands NP 5.88 2.78

200 3

Wind Cave NP 8.52 3.21

Badlands NP 5.44 2.67

Δdv = delta deciview

NP = National Park

REFINED MODELING

Because of the results of the Division‟s screening modeling for the Laramie River Station

, BEPC was required to conduct a refined BA RT analysis that included CALPUFF visibility modeling for the facility. The modeling approach followed the requirements described in the Division‟s BART modeling protocol, BART Air Modeling Protocol

- Individual Source Visibility Assessments for BART Cont rol Analyses (WDEQ

- AQD, September 2006)

.

CALPUFF System

Predicted visibility impacts from the Laramie River Station were determined with the EPA CALPUFF modeling system, which is the EPA

- preferred modeling system for long

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

- range transport is defined as modeling with source

- receptor distances greater than 50 km . Because all modeled areas are located more than 50 km from the sources in question, t he CALPUFF system was appropriate for use.Basin Electric Laramie River Station

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The CALPUFF modeling system consists of a meteorological data pre

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

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

- steady

- state air quality modeling system for assessing the

effects of time

- and space

- varying meteorological conditions on pollutant transport, transformation, and

removal.

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

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

upper

- air observations from multiple meteorological monitoring stations. Additionally, the CALMET model can utilize gridded analysis fields from various mesoscale models such as MM5 to better represent regional wind flows and complex terrain circulations. Associated two

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

- air stations.

CALPUFF is a multi

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

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

- air station in a format consistent with the meteorological file s used to drive steady

- state dispersion mod els. All far

- field modeling assessments described here were completed using the

CALPUFF model in a refined mode.

CALSUM is a post

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

- processing. PO STUTIL is a post

- processing program that processes

CALPUFF concentrations and wet/dry flux files . The POSTUTIL model operates on one or more output data files from CALPUFF to sum, scale, and/or compute species derived from those that are modeled , and

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

Table 14 : Key Programs in C ALPUFF System
Program Version Level

CALMET 5.53a 040716

CALPUFF 5.711a 040716

CALPOST 5.51 030709

Meteorological Data Processing (CALMET)

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

three

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

- air data were also input

to CALMET to adjust the initial windfield, but because of the relative scarcity of observations in the modeling domain, the influence of the observations was limite d within CALMET . Because the MM5 data were afforded a high degree of influence on the CALMET windfields, the Division obtained MM5 data

with 12

- km resolution that spanned the years 2001

- 2003 for use in the analysis

. The Division provided the BART applican ts all of the raw meteorological inputs for the CALMET model D efault settings wereBasin Electric Laramie River Station

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used in the CALMET input files for most of the technical options.

The following table lists the key user

- defined CALMET settings that were selected.

Table 15 : Key User

- Defined CALMET Settings

Variable Description Value

PMAP Map projection LCC (Lambert Conformal Conic)

DGRIDKM Grid spacing (km) 4

NZ Number of layers 10

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

RM IN2 Minimum distance for extrapolation

- 1

IPROG Use gridded prognostic model output 14 (MM5 data)

RMAX 1 Maximum radius of influence (surface

layer, km) 30

RMAX 2 Maximum radius of influence (layers

aloft, km) 50

TERRAD Radius of influence for terrain (km) 15

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

R2 Relative weighting aloft (km) 25

Two CALMET windfields were used for the Laramie River station BART modeling. The initial windfield was developed by BEPC to model the impacts at Wind Cave NP and Badlands NP, as directed by the Division and as specified in the Division‟s modeling protocol. A second, larger windfield was developed by the Division to model the impacts at Rawah WA and Rocky Mountain NP a nd to model an

additional control scenario at Wind Cave NP and Badlands NP. Surface, upper

- air, and precipitation data

for the domain s w ere incorporated into the CALMET windfield s

. Figure s 2 and 3 below show the locations of surface, upper

- air, and preci pitation stations used for the two windfields

.Basin Electric Laramie River Station

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Figure 2 : Observations Input to CALMET (BEPC Windfield)Basin Electric Laramie River Station

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Figure 3 : Observations Input to CALMET (Expanded Windfield)Laramie River Station

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

Rocky Mountain National Park, Colorado (NP)

Craters of the Moon Nat ional Monument, Idaho Highland, Utah Thunder Basin, Wyoming Yellowstone NP, Wyoming Centennial, Wyoming Pinedale, Wyoming

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

- wide background value of 2 ppb was used.

Latitude and longitude coordinates for Class I area d iscrete receptors were taken from the National Park Service (NPS) Class I Receptors database and converted to the appropriat e Lambert Conformal Conic coordinates. Figures 4

- 7 show the receptor configurations that were

used for Rawah WA, Rocky Mountain NP, 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 Rawah WA, Rocky Mountain NP, and Badlands NP, the receptor spacing is approximately 1. 4 km in the east

- west direction and approximately 1.8 km in

the north

- south direction.Basin Electric Laramie River Station

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Figu re 4 Receptors for Rawah WABasin Electric Laramie River Station

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Figure 5 Receptors for Rocky Mountain NPBasin Electric Laramie River Station

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Figure 6 Receptors for Wind Cave NP

Figure 7 Receptors for Badlands NPBasin Electric Laramie River Station

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CALPUFF Inputs

– Baseline and Control Options

T he first step in the ref

ined modeling analysis was to perform visibility modeling for current (baseline) operations at the facility

. Emissions of NO

x and SO 2 for the baseline runs were established based on CEM annual emissions averages for years 2001 to 2003. All particulate

em issions (PM) were based on an emission rate of 0.03 lb/MMBtu and were treated as PM 2.5 (fine PM) within CALPUFF and CALPOST. Direct emissions of sulfate were based on the values calculated for the Toxic Release Inventory (TRI) for the years modeled.

Ba seline source release parameters and emissions are shown in the table below, followed by tables with data for the various control options. N o attempt was made by the applicant to estimate the increase in sulfate emissions that would result from operation of SCR and SNCR/SCR hybrid controls, and as a result the visibility improvement for those scenarios may be overestimated by some undetermined amount.Basin Electric Laramie River Station

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Table 16 : Baseline Source Parameters

Parameter Baseline

Coal

- Fired

Un it 1 (P1) Coal

- Fired

Unit 2 (P2) Coal

- Fired

Unit 3 (P3)

LNB, WFGD, ESP LNB,

WFGD, ESP LNB,

D FGD, ESP

Heat Input (MMBtu/yr) 46,814,433 46,557,738 47,765,529

Base Elevation (m) 1348 1348 1348

Stack Height (m) 184.4 184.4 184.40

St ack Diameter (m) 8.69 8.69 8.69

Stack Temperature (K) 338.7 338.7 352.0

Exit Velocity (m/s) 21.33 21.03 22.25

SO 2 Emissions (lb/MMBtu) 0.16 0.16 0.17

SO 2 Emissions (tpy) 3745 3725 4060

HS 2 O 4 Emissions (tpy) 3.06 2.8 0 0.22

NO

x Emissions (lb/MMBtu) 0.2 7 0.27 0.27

NO

x Emissions (tpy) 6320 6285 6448

PM Fine Emissions (lb/MMBtu) 0.03 0.03 0.03

PM Fine Emissions (tpy) 702 698 716

Note : Boiler h eat input and lb/MMBtu emissions for NO

x and SO 2 based on continuous emissions monitoring (CEM) annual average s for 2001

- 2003

.

DFGD = dry flue gas desulfurization ESP = electrostatic precipitator

H 2 SO 4 = sulfuric acid

K = Kelvin lb/MMBtu = pounds per million British thermal units

LNB = low

- NO

x burners

m = meters m/s = meters per second

MMBtu/ yr = million B ritish thermal units per year NO

x = nitrogen oxides PM = particulate matter

SO 2 = sulfur dioxide

tpy = tons per year WFGD = wet flue gas desulfurizationBasin Electric Laramie River Station

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Table 17 : Source Parameters and Emissions for BART Control Options

Parameter Control Option 1 Control Option 2

NO

x Control: Overfire Air (OFA)

or New LNB NO

x Control: New LNB with OFA

Coal

Fired

Unit 1 (P1) Coal

Fired

Unit 2 (P2) Coal

Fired

Unit 3 (P3) Coal

Fired

Unit 1 (P1) Coal

Fired

Unit 2 (P2) Coal

Fired

Unit 3 (P3)

Base Elevation (m) 13 48 1348 1348 1348 1348 1348

Stack Height (m) 184.4 184.4 184.4 184.4 184.4 184.4

Stack Diameter (m) 8.69 8.69 8.69 8.69 8.69 8.69

Stack Temperature (K) 338.7 338.7 352.0 338.7 338.7 352.0

Exit Velocity (m/s) 21.33 21.03 22.25 21.33 21.03 22.25

SO 2 Emi ssions (lb/MMBtu) 0.16 0.16 0.17 0.16 0.16 0.17

SO 2 Emissions (tpy) 3745 3725 4060 3745 3725 4060

H 2 SO 4 Emissions (tpy) 3.18 3.25 0.22 3.18 3.25 0.22

NO

x Emissions (lb/MMBtu) 0.23 0.23 0.23 0.23 0. 23 0. 23

NO

x Emissions (tpy) 5384 5354 5493 5384 5354 54 93

PM Fine Emissions (lb/MMBtu) 0.03 0 0.03 0 0.03 0 0.03 0 0.03 0 0.03 0

PM Fine Emissions (tpy) 702 698 716 702 698 716

H 2 SO 4 = sulfuric acid

K = Kelvin lb/MMBtu = pounds per million British thermal units

LNB = low NO

x burners

m = meters
m/s = meters per second

NO

x = nitrogen oxides

OFA = overfire air PM = particulate matter SCR = selective catalytic reduction

SO 2 = sulfur dioxide

tpy = tons per yearBasin Electric Laramie River Station

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Table 17 : Source Parameters and Emissions for BART Control Options (cont.)

Parameter Control Option 4

NO

x Control: SCR

Coal

Fired

Unit 1 (P1) Coal

Fired

Unit 2 (P2) Coal

Fired

Unit 3 (P3)

Base Elevation (m) 1348 1348 1348

Stack Height (m) 184.4 184.4 184.4

Stack Diameter (m) 8.69 8.69 8.69

Stack Temperature (K) 338.7 338.7 352.0

Exit Vel ocity (m/s) 21.33 21.03 22.25

SO 2 Emissions (lb/MMBtu) 0.16 0.16 0.17

SO 2 Emissions (tpy) 3745 3725 4060

H 2 SO 4 Emissions (tpy) 3.18 3.25 0.22

NO

x Emissions (lb/MMBtu) 0.07 0.07 0.07

NO

x Emissions (tpy) 1639 1630 1672

PM Fine Emissions (lb/MMBtu) 0.03 0 0.03 0 0.03 0

PM Fine Emissions (tpy) 702 698 716

H 2 SO 4 = sulfuric acid

K = Kelvin lb/MMBtu = pounds per million British thermal units

LNB = low NO

x burners

m = meters m/s = meters per second

NO

x = nitrogen oxides

OFA = overfire air PM = particulate matter SCR = selective catalytic reduction

SO 2 = sulfur dioxide

tpy = tons per yearBasin Electric Laramie River Station

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V isibility Post

- Processing (CALPOST) Setup

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

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

. Monthly f(RH) factors that were used for this analysis are shown in the table below.

Table 18 : Relative Humidity Factors for CALPOST

Mo nth Rocky

Mountain

NP Rawah

WA Wind

Cave NP

and

Badlands

NP January 1.7 2.1 2.65

February 1.9 2.1 2.65

March 1.9 2.0 2.65

April 2.1 2.1 2.55

May 2.3 2.3 2.70

June 2.0 2.0 2.60

July 1.8 1.8 2.30

August 2.0 2.0 2.30

September 1.9 2.0 2.20

Oct ober 1.8 1.9 2.25

November 1.8 2.1 2.75

December 1.7 2.0 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:Basin Electric Laramie River Station

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- 60 47 BART Application Analysis Page 36

dv = 10 ln (b ext

/10) or b ext = 10 exp (dv/10)

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 19 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 19 : 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 Badl ands NP and Wind Cave NP because of their geographical proximity and similar annual background visibility. The 20 percent best days aerosol

concentrations for the Class I areas in question are listed in the table below.Basin Electric Laramie River Station

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Table 20 : Natural Background Aer osol Co ncentrations (μg/m 3 )

Aerosol Component Rawah WA Rocky

Mountain

NP Wind Cave

NP &

Badlands NP

Ammonium Sulfate 0.045 0.045 0.047

Ammonium Nitrate 0.038 0.038 0.040

Organic Carbon 0.178 0.177 0.186

Elemental Carbon 0.008 0.008 0.008

Soil 0.1 89 0.189 0.198

Coarse Mass 1.135 1.132 1.191

The results of the visibility modeling for each of the three units for the baseline and control scenarios are shown in the table s below. Results for the Colorado Class I areas are presented for the baseline scenario only because the results for this scenario were well below 0.5 Δdv

. For each scenario, the 98 th percentile

Δdv results are reported along with the total number of days for which the predicted impacts exceeded 0.5 dv. Following the tables are figures that present the results graphically for Wind Cave NP and Badlands

NP

.Laramie River Station

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Table 21 : CALPUFF Visibility Modeling Results for Laramie River 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. o f

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– LNB, Wet FGD, ESP

Badlands NP 0.643 14 0.841 17 0.599 9 0.694 13

Wind Cave NP 0.732 17 0.7 00 16 0.542 9 0.658 14

Post

- Control Scenario 1

– OFA

Badlands NP 0.574 12 0.761 16 0.532 9 0.622 12

Wind Cave NP 0.662 15 0.619 11 0.496 7 0.592 11

Post

- Control Scenario 2

– OFA + New LNB

Badlands NP 0.574 12 0.761 16 0.532 9 0.622 12

Wind Cave NP 0.662 15 0.619 11 0.496 7 0.592 11

Post

- Control Scenario 4

– SCR

Badlands NP 0.32 2 4 0.402 4 0.303 5 0.342 4

Wind Cave NP 0.378 3 0.32 0 1 0.307 3 0.335 2

Table 22 : CALPUFF Visibility Modeling Results for Laramie River Unit 2

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days > 0.5

Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– LNB, Wet FGD, ESP

Badlands NP 0.642 14 0 .842 17 0.594 10 0.693 14

Wind Cave NP 0.725 17 0.699 16 0.546 9 0.657 14

Post

- Control Scenario 1

– OFA

Badlands NP 0.573 12 0.762 16 0.53 0 9 0.622 12

Wind Cave NP 0.658 15 0.615 11 0.498 7 0.590 11

Post

- Control Scenario 2

– OFA + New LNB

Badlands N P 0.573 12 0.762 16 0.53 0 9 0.622 12

Wind Cave NP 0.658 15 0.615 11 0.498 7 0.590 11

Post

- Control Scenario 4

– SCR

Badlands NP 0.32 0 4 0.399 4 0.302 5 0.340 4

Wind Cave NP 0.384 3 0.319 1 0.31 0 3 0.338 2Laramie River Station

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Table 23 : CALPUFF Visibility Modeling R esults for Laramie River Unit 3

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days > 0.5

Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– LNB, Wet FGD, ESP

Badlands NP 0.639 14 0.886 18 0.63 0 8 0.718 13

Wind Cave NP 0.68 0 17 0.717 16 0.553 10 0.650 14

Post

- Control Scenario 1

– OFA

Badlands NP 0.572 11 0.803 17 0.561 8 0.645 12

Wind Cave NP 0.609 14 0 .643 13 0.502 8 0.585 12

Post

- Control Scenario 2

– OFA + New LNB

Badlands NP 0.572 11 0.803 17 0.561 8 0.645 12

Wind Cave NP 0.609 14 0.643 13 0.502 8 0.585 12

Post

- Control Scenario 4

– SCR

Badlands NP 0.336 4 0.446 4 0.323 4 0.368 4

Wind Cave NP 0. 381 4 0.348 2 0.297 3 0.342 3

Table 24 : CALPUFF Visibility Modeling Results for Laramie River Station: Rocky Mountain National Park & Rawah WA (Baseline Scenario)

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

Unit 1

Rawah WA 0.308 3 0.425 7 0.287 2 0.340 4
Rocky Mtn. NP 0.414 6 0.4 47 7 0.441 5 0.434 6

Unit 2

Rawah WA 0.309 3 0.422 7 0.279 2 0.337 4
Rocky Mtn. NP 0.415 6 0.455 7 0.437 5 0.436 6

Unit 3

Rawah WA 0.295 3 0.440 6 0.301 2 0.345 4
Rocky Mtn. NP 0.433 7 0.481 7 0.448 4 0.454 6Laramie River StationAP-6047 BART Application AnalysisPage 40Figure 8 – Modeled BART Impacts: Number of Days > 0.5 delta-dv0.02.04.06.08.010.012.014.016.0LRUnit1 LRUnit2 LRUnit3 LRUnit1 LRUnit2 LRUnit3Baseline(LNB)ControlOption1ControlOption2ControlOption4BadlandsNPWindCaveNP(Modelingresultsrepresentthethree‐yearaverageofresultsusing2001‐2003 meteorology)BEPCLaramieRiverStationUnit1(550MW,net)Unit2(550MW,net)Unit 3(550MW,net)(#Days)Laramie River StationAP-6047 BART Application AnalysisPage 41Figure 9 – Modeled BART Impacts: 98thPercentile (delta-dv)0.0000.1000.2000.3000.4000.5000.6000.7000.800LRUnit1 LRUnit2 LRUnit3 LRUnit1 LRUnit2 LRUnit3Baseline(LNB)ControlOption1ControlOption2ControlOption4BadlandsNP WindCaveNPBEPCLaramieRiverStationUnit1(550MW,net)Unit2(550MW,net)Unit3(550MW,net)(Modelingresultsrepresentthethree‐yearaverageofresultsusing2001‐2003 meteorology)(del‐dv)Laramie River Station

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BART CONCLUSIONS:

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

- air quality environmen tal 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, th e Division determined BART fo r the three unit s a t the Laramie River

Station

.

NO

x

New LNB with OFA is determined to be BART for NO

x control fo r Units 1

- 3 based, in part, on the following conclusions:

1. Installation of new LNB with OFA was cost effective, w ith a capital cost of $22,096,000 per unit and $2,036

- $2,088 per ton of NO

x removed based on the average cost effectiveness for each unit over a twenty year operational life

.

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

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

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

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

- day rolling

average, equal to EPA‟s established presumptive limit fo r dry

- bottom, wall

- fired boilers burning

sub

- bituminous coal, is justified.

4. V isibility impacts were addressed in a comprehensive visibility ana lysis covering three visibility impairing pollutants and the associate d control options. The cumulative visibility improvement as compared to the baseline across Wind Cave NP and Badlands NP achieved with new LNB

with OFA at the 30

- day limit of 0.23 lb/MM Btu ( based on the 98 th percentile modeled results )

w as 0.14 Δdv from each of the three units

. The expected visibility improvement over the course of a full annual period would be even greater due to the annual BART limit that is based on 0.19

lb/MMBtu.

5. Annual NO

x emission reductions from new LNB with OFA on Units 1, 2, and 3 are 1,862

- 1,910 tons per unit for a total annual reduction of 5,645 tons.

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

x control for Units 1

- 3 based, in part, on

t he following conclusions:

1. The cost of compliance for installing SCR on each unit is significantly higher than the cost for

LNB with OFA. Additional c apital costs for SCR on Units 1

- 3 are $1 01

, 005 ,000 per unit. Annual operating costs for SCR on Units 1

- 3 are $ 4

, 608

, 000 per unit.

2. Additional non

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

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- 6047 BART Application Analysis Page 43

3. Operation of LNB with OFA and SCR is parasitic and requires an estimated 4.8 MW o f power

from each unit.

4. The cumulative visibili ty improvement for SCR

, as compared to LNB/OFA

, across Wind Cave NP and Badlands NP (based on the 98 th percentile modeled results) was 0.52

- 0.54 Δdv for each of

the three units.

The Division considers the installation and operation of the BART

- determined NO

x controls , new LNB with OFA, to meet the statutory requirements of BART.

Unit

- by

- unit NO

x BART determinations:

Laramie River Unit 1 : N ew LNB with OFA and meeting NO

x emission limits of 0.2 3

lb/MMBtu (30

- day rolling average)

, 1, 348 lb/hr (30

- day rolling average)

, and 5,343 tpy (12

- month rolling) as BART for NO

x .

Laramie River Unit 2 : N ew LNB with OFA and meeting NO

x emission limits of 0 .2 3

lb/MMBtu (30

- day rolling average)

, 1, 348 lb/hr (30

- day rolling average)

, and 5,343 tpy (12

- month rolling) as BART for NO

x .

Laramie River Unit 3 : N ew LNB with OFA and meeting NO

x emission limits of 0.2 3

lb/MMBtu (30

- day rolling average)

, 1, 386 lb/hr (30

- day rolling average)

, and 5,493 tpy (12

- month rolling) as BART for NO

x .

The performance/efficiency

- based

, 30

- day rolling average emission rate of 0.23 lb/MMBtu is set to allow for continuous compliance with proper operation of the control equipment

, while taking into account the normal operation al variability that is typical for a boiler. T he 30

- day limit s that are expressed in terms of mass emissions (lb/hr) are based on 0.21 lb/MMBtu

. Because r educed steam load s on a boiler can result in periods of in creased emissions in terms of lb/MMBtu but lower emissions in terms of lb/hr, the

Division has chosen to set the dual 30

- day limits, one set at 0.23 lb/MMBtu and one expressed in lb/hr

based on 0.21 lb/MMBtu. For the 12

- month rolling emission limits , the Division considered the ability of

the source to maintain a lower emission rate over a longer time period and set the long

- term l imit (expressed in tpy) based on 0.19 lb/MMBtu

.

PM/PM 10

Existing ESP is determined to be BART for Units 1

- 3 for PM/PM 1 0 based, in part, on the following

conclusion s :

1. The cost of compliance for the sole technically feasible control option, a retrofit fabric filter on the Unit 3 ESP, is not reasonable over a twenty year operational life. The cost effectiveness for

install ing the retrofit fabric filter is $40,156 per ton of PM/PM 10 removed

. No additional control technologies were deemed to be technically feasible for Units 1 and 2.Laramie River Station

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- 6047 BART Application Analysis Page 44

2. V isibility impacts from the installation of controls on PM/PM 10 emissions , in gene ral, are not expected to produce significant visibility improvements. In particular for the Laramie River Station, Basin Electric modeled the fabric filter retrofit on Unit 3, and the predicted improvement in visibility as compared to baseline at Wind Cav e NP or Badlands NP was at most 0.07 Δdv

.

The Division considers the operation of the BART

- determined PM/PM 10 controls

, existing ESP

, to meet the statutory requirements of BART.

Unit

- by

- unit PM/PM 10 BART determinations:

Laramie River Unit 1 : Continuing to use the existing ESP to meet the established PM/PM 10

emission limit s of 0.030 lb/MMBtu , 193 lb/hr, and 844 tpy as BART for

PM/ PM 10

.

Laramie River Unit 2 : Continuing to use the existing ESP to meet the established PM/PM 10

emission limit s of 0.030 lb/MMBtu , 193 lb/hr, and 844 tpy as BART for

PM/ PM 10

.

Laramie River Unit 3 : Continuing to use the existing ESP to meet the established PM/PM 10

emission limit s of 0.030 lb/MMBtu , 198 lb/hr, and 867 tpy as BART for

PM/ PM 10

.

SO 2 : REGIONAL SO 2 MILESTONE AND BACKSTOP TRADING PROGRAM

Basin Electri c evaluated SO 2 control technologies that can achieve a SO 2 emission rate of 0.1 5 lb/MMBtu

or lower from the coal

- fired boilers. Basin Electric proposed BART control s include using chemical additives in the Unit 1 and 2 WFGD systems.

Wyoming is a §309 s tate participat ing in the Regional SO 2 Milestone and Backstop Trading Program

. §308(e)(2) provides States with the option to implement or require participation in an emissions trading program or other alternative measure rather than to require sources sub ject to BART to install, operate, and maintain additional control technology to meet an established emission limit on a continuous basis. However, the alternate program must achieve greater reasonable progress than would be accomplished by installing BART . A demonstration that the alternate program can achieve greater reasonable progress is prescribed by §308(e)(2)(i). Since the pollutant of concern is 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).”

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

in the Regional SO 2 Milestone and Backstop Trading Program. The document was submitted to EPA in support of the §309 Wyoming Regional Haze SIP in November of 2008

.

As part of the §309 program, participating states, including Wyoming, must submit an annual Regional Sulfur Dioxide Emissions and Milestone Report that compares actual emissions to pre

- established

milest ones. Participating states have been filing these reports since 2003. Each year, states have beenLaramie River Station

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- 6047 BART Application Analysis Page 45

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

Table 2 5 : 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 additio n to demonstrating successful SO 2 emission reductions, § 309 states have also relied on visibility modeling conducted by the WRAP to demonstrate improvement at Class I areas. The complete modeling demonstration showing deciview values was included as part of the visib i lity improvement section of the § 309 SIP, but the SO 2 portion of the demonstration has been included as Table 26 to underscore the improvements associated with SO 2 reductions.

Table 2 6 : Visibility

- Sulfate Extinction Only

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

2018 1

Base Case (Base 18b) 2018 2

Preliminary

Reasonable Progress Case (PRP18 a ) 2018 1

Base Case (Base 18b) 2018 2

Preliminary

Reasonable Progress Case (PRP18 a ) Bridger, WY
(Bridger WA and Fitzpatrick WA) 5.2 4.3 1.6 1.3

North Absaroka, WY

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

Yellowstone, WY

(Yellowstone NP, Grand Teton NP and Teton WA) 4.3 3.9 1.6 1 .4

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

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

Rocky Mountain, CO 6.8 6.2 1.3 1.1
Gates of the Mountains, MT 5.3 5.1 1.0 1.0
UL Bend, MT 9.7 9.6 1.8 1.7

Craters of the Moon, ID 5.8 5.5 1.5 1.5
Sawtooth, ID 3.0 2.8 1.2 1.1 Canyonlands, UT
(Canyonlands NP and Arches NP) 5.4 4.8 2.1 1.9

Capitol Reef, UT 5.7 5.4 1.9 1.8

1 Represents 2018 Base Case growth plus all established controls as of Dec 2004 . N o BART or S0 2 M iles tone assumptions were included.

2 Represents 2018 Preliminary Reasonable Progress growth estimates and established S0 2 limits

.Laramie River Station

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

to SO 2 on the worst d ays 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 submitted in

November 2008.

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

- proposed BART technology and meet the corresponding achievable emission limit. Instead, Basin Electric is required to participate in the Regional SO 2 Milest one and Backstop Trading Program authorized under Chapter 14 of the WAQSR.

LONG

- TERM STRATEGY FOR REGIONAL HAZE :

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

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

to result from the use of such technology were taken into consideration when det ermining BART. When evaluating the costs of compliance

, the Division recognized a time limitation to install BART

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

documentation for all required analy ses to be submitted in the State I mplementation P lan, 40 CFR 51.308(e)(1)(iv) states: “A requirement that each source subject to BART be required to install and operate BART as expeditiously as practicable, but in no event later than 5 years after approval of the implementation plan revision. ” As a practical measure, the Division anticipates the requirement to install

the BART

- determined controls to possib ly occur as early as 2015.

B ased on the costs and visibility improvement presented by Basin Electric in the BART applications for

Laramie River Station Units 1

- 3

, and taking into consideration the logistical challenge of managing multiple pollution control installations with in the regulatory time frame allotted for BART installations by the Regional Haze R ule, the Division is requiring the installation of additional controls under the Long

Term Strategy of the Wyoming Regional Haze State Implementation Plan. The Division is requiring

Basin Electric submit a permit application to install additional add

- on N O

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

- air quality environmental impacts of compliance; and (4) the remaining useful life of existing sources that

contribute to vi sibility impairment (i.e., the four statutory factors taken into consideration when establishing reasonable progress goals 5 ) and the associated visibility impacts from the application of each proposed NO

x control. Each proposed add

- on NO

x control shall ac hieve an emission rate, on an individual unit basis, at or below 0.07 lb/MMBtu on a 30

- day rolling average. A dditional add

- on controls shall be installed and operational o n one of the Laramie River Station units by December 31, 201 8 and on

a second Larami e River Station unit by December 31, 2023.

CHAPTER 6, SECTION 4

– PREVENTION OF SIGNIFICANT DETERIORATION (PSD):

Basin Electric‟s Laramie River Station is a “major emitting facility” under Chapter 6, Section 4, of the Wyoming Air Quality Standards and R egulations because emissions of a criteria pollutant are greater than

100 tpy for a listed categorical source

. Basin Electric should comply with the permitting requirements of Chapter 6, Section 4 as they apply to the installation of controls determined t o meet BART.

5 40 CFR 51.308(d)(1)(i)(A).Laramie River Station

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CHAPTER 5, SECTION 2

– NEW SOURCE PERFORMANCE STANDARDS (NSPS):

The installation of the controls determined to meet BART will not change New Source Performance Standard applicability for the coal

- fired boilers at Laramie River Station

.

CHA PTER 5, SECTION 3

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

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

The installation of the controls determined to meet BART will not change NESHAP/MACT applicability

for the coal

- fired boilers at Laramie River Station.

CHAPTER 6, SECTION 3

– OPERATING PERMIT:

The Laramie River Station is a major source under Chapter 6, Section 3 of the Wyoming Air Quality

Standards and R egulations. Operating Permit 3

- 1

- 1 0 2

- 2 was issued for the facility on November 15,

2005. In accordance with Chapter 6, Section 3 of the Wyoming Air Quality Standards and Regulations (WAQSR), Basin Electric will need to modify their operating permit to in clude the changes authorized in this permitting action.

CONCLUSION:

The Division is satisfied that Basin Electric ‟s Laramie River Station will comply with all applicable Wyoming Air Quality Standards and Regulations. The Division proposes to issue a BAR T Air Quality

Permit for the Laramie River Station modification to install OFA and new LNB on Laramie River Station

Units 1

- 3 to meet the statutory requirements of BART. Two (2) of the three (3) units must install add

- on NO

x control that achieve s an emiss ion rate, on an individual unit basis, at or below 0.07 lb/MMBtu on a

30

- day rolling average b y December 31, 2018 and December 31, 2023, respectively, under the Long

Term Strategy of the Wyoming §308 Regional Haze State Implementation Plan.Laramie River Station

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PROPOSED PERMIT CONDITIONS:

The Division proposes to issue an Air Quality Permit to Basin Electric for the modification of the

Laramie River Station with the following conditions:

1. Authorized representatives of the Division of Air Quality be given p ermission 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 complian ce or non

- compliance with any rules, standards, permits

or orders.

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

3. That Basin Electric 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 asso ciated with this permit shall be submitted to the Stationary Source Compliance Program Manager, Air Quality Division, 122 West 25th Street,

C heyenne, WY 82002 and a copy shall be submitted to the District Engineer, Air Quality Division, at the same addres s

.

5. Effective upon completion of the performance tests to verify the emission levels below, as required by Condition 6 of this permit

, emissions from Laramie River Station Units 1 through 3

shall not exceed the levels below. PM/PM 10 lb/hr and tpy limit s 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 electricity ge nerators are put online.

Pollutant lb/MMBtu lb/hr tpy

PM/PM 10 (a) 0.030 Unit 1: 193

Unit 2: 193

Unit 3: 198 Unit 1: 844

Unit 2: 844

Unit 3: 867

(a) Filterable portion only

6. That no later than 90 days after permit issuance PM/PM 10 performance tests s hall be conducted

on Units 1

- 3 and a written report of the results be submitted. If a maximum design rate is not achieved within 90 days of permit issuance , the Administrator may require testing be done at the rate achieved and again when a maximum rate i s achieved.Laramie River Station

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7

. Effective upon completion of the initial performance tests to verify the emission levels below, as required by Condition 8 of this permit

, emissions from Laramie River Station Units 1 through 3

shall not exceed the levels below. The N O

x limits shall apply during all operating periods.

Pollutant lb/MMBtu lb/hr tpy

NO

x 0. 23 (30

- day rolling) Unit 1: 1,348 Unit 2: 1,348 Unit 3: 1,386
(all 30

- day rolling) Unit 1: 5,343

Unit 2: 5,343 Unit 3: 5,493
(all 12

- month rolling)

8. That init ial NO

x 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 r e sults 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.

9

. P erformance tests shall consist of the following:

Coal

- fired Boilers ( Laram ie River Station Units 1 through 3 ):

NO

x Emissions

– Compliance with the NO

x 30

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

PM/PM 10 Emissions

– Testing shall f ollow 40 CFR 60.46 and EPA Reference

Test Methods 1

- 4 and 5

.

Testing required by the WAQSR Chapter 6, Section 3 operating permit may be submitted to satisfy the testing required by this condition.

10

. Prior to any performance testing required by this permit, a test protocol shall be submitted to the Division for approval, at least 30 days prior to testing. Notification should be provided to the

Division at least 15 days prior to any testing. Results of the tests shall be submitted to this office

with in 45 days of completing the tests.

11

. Basin Electric 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.

1 2

. After the installation or upgrade of control equipment , compliance with the limits set forth in this permit for the coal

- fired boilers ( Laramie River Station Units 1 through 3 ) shall be determined with data from the existing continuous monitoring systems required by 40 CFR Part 75 as follo ws:

a. Exceedances of the NO

x limits shall be defined as follows:

i. Any 30

- day rolling average of NO

x emissions which exceeds the lb/MMBtu

limits calculated in accordance with the compliance provisions and monitoringLaramie River Station

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requirements of §60.48Da and §60.49Da

. The definition of “boiler operating

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

ii. Any 30

- day rolling average calculated using valid data (output concentration and average hourly volumetric flowrate) from the exi sting 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

- d ay 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.

iii. Any 12

- month rolling emission rate which exceeds the tpy NO

x limit as calculated using the following formula:

Where:

C = 1

- hour average emission rate (lb/hr) for hour “h” calculated using data from the CEM equip ment r equired by 40 CFR Part 75. For monitoring data not meeting the requirements of WAQSR, Chapter 5, Section 2(j)

, Basin Electric shall provide substituted data for an emissions unit according to the missing data procedures of 40 CFR, Part 75 during any perio d of time that there is not monitoring data.

E = 12

- month rolling emission rate (tpy).

b. Basin Electric shall comply with all reporting and record keeping requirements as specified in WAQSR, Chapter 5, Section 2(g) and 40 CFR part 60, subpart D. All e xcess emissions shall be reported using the procedures and reporting format specified in WAQSR, Chapter 5, Section 2(g).

1 3

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

- fired boilers ( Laramie

River Units 1

- 3 ) shall be determin ed with data from t 

### esting for PM conducted annually , or more frequently as specified by the Administra t or, following 40 CFR 60.46 and EPA Reference Test

Methods 1

- 4 and 5. Testing required by the WAQSR Chapter 6, Section 3 operating permit may

be submitte d to satisfy the testing required by this condition.

1 4

. 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.Laramie River Station

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1 5

. Basin Electric shall install new low NO

x b urners with overfire air on Units 1 through 3, in accordance with the Division‟s BART determination, and conduct the initial performance tests required in Condition 8 no later than December 31, 201 2 for Unit 1; December 31, 2013 for Unit 2; and December 31 , 2014 for Unit 3

.

1 6

. Basin Electric shall submit permit application s for the installation of additional add

- on NO

x control on two units at the Laramie River Station to the Division no later than six (6) years prior

to installation

, under the Long

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

x control and resulting emission

levels. This ap plication shall address each add

- on NO

x control as a system of continuous emissions reduction achieving the lowest viable NO

x emission, not to exceed a maximum of 0.07

lb/MMBtu on a 30

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

- on NO

x control shall be installed and operational on one (1) unit by December 31, 2018 and on a second

unit by December 31, 2023

.

# Appendix A Facility Location