DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

BART Application Analysis

AP-6047

May 28, 2009

NAME OF FIRM: Basin Electric Power Cooperative

NAME OF FACILITY: Laramie River Station

FACILITY LOCATION: 347 Grayrocks Road

Platte County (Wheatland), Wyoming

UTM Zone 13, NAD 27:

509,900 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 Dakota 58503

TELEPHONE NUMBER: (701) 355-5654

REVIEWERS: Cole Anderson, Air Quality Engineer

Josh Nall, Air Quality Modeler

PURPOSE OF APPLICATION:

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

Class I areas. On July 1, 1999, EPA first published the Regional Haze Rule, which provided specific 

details regarding the overall program requirements to improve visibility. The goal of the regional haze 

program is to achieve natural conditions by 2064.

Section 308 of the Regional Haze Rule (40 CFR 51) includes discussion on control strategies for 

improving visibility impairment. One of these strategies is the requirement under 40 CFR 51.308(e) for 

certain stationary sources to install Best Available Retrofit Technology (BART) to reduce emissions of 

three (3) visibility impairing pollutants, nitrogen oxides (NOx), particulate matter (PM), and sulfur 

dioxide (SO2). EPA published Appendix Y to part 51 - Guidelines for BART Determinations Under the 

Regional Haze Rule in the July 6, 2005 Federal Register to provide guidance to regulatory authorities for 

making BART determinations. Chapter 6, Section 9, Best Available Retrofit Technology was adopted 

into the Wyoming Air Quality Standards and Regulations (WAQSR) and became effective on December 

5, 2006. The Wyoming Department of Environmental Quality, Air Quality Division (Division) will 

determine BART for NOx and PM10 for each source subject to BART and include each determination in 

the §308 Wyoming Regional Haze State Implementation Plan (SIP).
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AP-6047 BART Application Analysis

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Section 309 of the Regional Haze Rule (40 CFR part 51), Requirements related to the Grand Canyon 

Visibility Transport Commission, provides states that are included within the Transport Region addressed 

by the Grand Canyon Visibility Transport Commission (i.e., Arizona, California, Colorado, Idaho, 

Nevada, New Mexico, Oregon, Utah, and Wyoming) an alternative to the requirements established in 40 

CFR 51.308. This alternative control strategy for improving visibility contains special provisions for 

addressing SO2 emissions, which include a market trading program and a provision for a 2018 SO2

milestone. Wyoming submitted a §309 Regional Haze SIP to EPA on December 29, 2003. As of the date 

of this analysis, EPA has not taken action on the SIP. National litigation issues related to the Regional 

Haze Rule, including BART, required states to submit revisions. On November 21, 2008, the State of 

Wyoming submitted revisions to the 2003 §309 Regional Haze SIP submittal. Sources that are subject to 

BART are required to address SO2 emissions as part of the BART analysis even though the control 

strategy has been identified in the Wyoming §309 Regional Haze SIP.

On March 5, 2007, in accordance with the requirements of WAQSR Chapter 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 correct errors in the 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 three BART-eligible units separately. 

On February 25, 2009, Basin Electric submitted additional information on the NOx emission rates that 

would be achievable by the BART-eligible units.

On March 16, 2009, Basin Electric submitted a letter with proposed NOx emission limits for the BARTeligible 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 prescribed in 40 CFR part 51, 

Appendix Y: Guidelines for BART Determinations Under the Regional Haze Rule to identify sources and 

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

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

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

visibility impairing pollutant when emissions are aggregated from all eligible emission units at a 

stationary source. Fifty-one (51) sources at fourteen (14) facilities were identified that could be subject to 

BART in Wyoming.

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

which may reasonably be anticipated to cause or contribute to any impairment of visibility. Three 

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

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

aerodynamic diameter of 10 microns or less (PM10) was used as an indicator of PM. 
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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 SO2 or NOx or 15 tons of PM10 were included in 

the screening analysis. Using three years of meteorological data, the screening analysis calculated 

visibility impacts from sources at nearby Class I areas. Sources with modeled 98th percentile, 24-hour 

impact (i.e., 8

th highest modeled impact) equal to or greater than 0.5 delta deciviews (Δdv) 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 River Station is comprised of three 550 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 1980. Unit 2 commenced service in 1981, and Unit 3 entered service in 1982. All 

three units were manufactured by Babcock & Wilcox (B&W). Each unit is equipped with early 

generation low NOx burners (LNBs) to control emission of nitrogen oxides (NOx). They are also 

equipped with cold-side electrostatic precipitators (ESPs) to control particulate matter (PM) emissions. 

To control sulfur dioxide (SO2) emissions, Units 1 and 2 are equipped with wet flue gas desulfurization 

(WFGD). Unit 3 is equipped with a dry scrubber (DFGD) for SO2 removal. All three units burn subbituminous 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

NOx

(lb/MMBtu) (a)

SO2

(lb/MMBtu) (a)

PM 

(lb/MMBtu) (a)

Unit 1 LNB, ESP, 

WFGD 0.5 (3-hourb

)

0.2 

(2-hour fixed block)

0.085 (3-hour)

Unit 2 LNB, ESP, 

WFGD 0.5 (3-hourb

)

0.2 

(2-hour fixed block)

0.085 (3-hour)

Unit 3 LNB, ESP, 

DFGD

0.5 (3-hourb)

0.2 

(2-hour fixed block)

0.083 (3-hour)

(a) Emissions taken from current Operating Permit 3-1-102-1.

(b) Arithmetic average of three contiguous one-hour periods

CHAPTER 6, SECTION 9 – BEST AVAILABLE RETROFIT TECHNOLOGY (BART):

A BART determination is an emission limit based on the application of a continuous emission reduction 

technology for each visibility impairing pollutant emitted by a source. It is “...established, on a case-bycase basis, taking into consideration: (1) the costs of compliance, (2) the energy and non-air quality 

environmental impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) 

the remaining useful life of the source, and (5) the degree of improvement in visibility which may
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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 for each pollutant subject to BART review based 

on the evaluation.

Visibility control options presented in the application for each of the emission units were reviewed using 

the methodology prescribed in 40 CFR 51 subpart Y, as required in WAQSR Chapter 6 Section 9(c)(i). 

This methodology is comprised of five basic steps:

Step 1: Identify all2available retrofit control technologies

Step 2: Eliminate technically infeasible options

Step 3: Evaluate control effectiveness of remaining control technologies

Step 4: Evaluate impacts and document the results

Step 5: Evaluate visibility impacts

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 sources under the Prevention of Significant 

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

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

five steps listed above were applied to NOx, PM, and SO2 emitted from the Laramie River Station‟s coalfired boilers to determine BART control measures.

PRESUMPTIVE LIMITS FOR SO2 AND NOX FROM UTILITY BOILERS

EPA conducted detailed analyses of retrofit technology available to control NOx and SO2 emissions from 

coal-fired power plants. These analyses considered unit size, fuel type, cost effectiveness, and existing 

controls to determine reasonable control levels based on the application of an emissions reduction 

technology.

EPA‟s presumptive BART SO2 limits analysis considered coal-fired units with existing SO2 controls and 

units without existing control. Four key elements of the analysis were: “...(1) identification of all 

potentially BART-eligible EGUs [electric generating units], and (2) technical analyses and industry 

research to determine applicable and appropriate SO2 control options, (3) economic analysis to determine 

cost effectiveness for each potentially BART-eligible EGU, and (4) evaluation of historical emissions and 

forecast emission reduction for each potentially BART-eligible EGU.”3 491 BART-eligible coal-fired 

units were identified and included in the presumptive BART analysis for SO2. Based on removal 

efficiencies of 90% for spray dry lime dry flue gas desulfurization systems and 95% for limestone forced 

oxidation wet flue gas desulfurization systems, EPA calculated projected SO2 emission reductions and 

cost effectiveness for each unit. Based on the results of this analysis, EPA concluded that the majority of 

identified BART-eligible units greater than 200 MW without existing SO2 control can meet the 

presumptive limits at a cost of $400 to $2,000 per ton of SO2 removed.

A presumptive BART NOx limits analysis was performed using the same 491 BART-eligible coal-fired 

 

1

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

2

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

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

3

40 CFR Part 51 Appendix Y Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 39133).
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units identified in the SO2 presumptive BART analysis. EPA considered the same four key elements and 

established presumptive NOx limits for EGUs based on coal type and boiler configuration. For all boiler 

types, except cyclone, presumptive limits were based on combustion control technology (e.g., low NOx

burners and overfire air). Presumptive NOx limits for cyclone boilers are based on the installation of 

SCR, a post combustion add-on control. EPA acknowledged that approximately 25% of the reviewed 

units could not meet the proposed limits based on current combustion control technology, but that nearly 

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

Rotating Opposed Fire Air. National average cost-effectiveness values for presumptive NOx limits 

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

Based on the results of the analyses for presumptive NOx and SO2 limits, EPA established presumptive 

limits for EGUs greater than 200 MW operating without NOx post combustion controls or existing SO2

controls located at facilities with a generating capacity greater than 750 MW. 40 CFR part 51 Appendix 

Y states that the presumptive SO2 level for an uncontrolled unit is either 95% control or 0.15 lb/MMBtu. 

Presumptive NOx levels for uncontrolled units are listed in Table 1 of Appendix Y and are classified by 

the boiler burner configuration (unit type) and coal type. NOx emission values range from 0.62 

lb/MMBtu down to 0.15 lb/MMBtu. While Appendix Y establishes presumptive SO2 limits and says that 

states should require presumptive NOx, it also clearly gives states discretion to “...determine that an 

alternative [BART] control level is justified based on a careful consideration of the statutory factors.”4 

The Division‟s following BART analyses for NOx, SO2, and PM/PM10 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 NOx post-combustion controls. The presumptive NOx emission limit for dry-bottom, 

wall-fired boilers burning sub-bituminous coal (i.e., each of the three units) is 0.23 lb/MMBtu. 

NOx: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Basin Electric identified six control technology configurations for control of NOx emissions from Units 1 

through 3: 

Overfire Air (OFA) 

New Low NOx Burners (LNB)

Selective Catalytic Reduction (SCR)

Selective Non-Catalytic Reduction (SNCR)

SNCR/SCR Hybrid

Natural Gas Reburn 

1. Overfire Air – OFA is a combustion control technology that reduces NOx 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 N2 instead of NOx, additional air (or 

OFA) is introduced downstream of the main burner zone to burn out any residual material. By 

injecting the OFA into the lower temperature combustion zone, NOx is less likely to form, while

burning the residual solid fuel (char). 

 

4

Ibid. (70 Federal Register 39171)
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2. New Low NOx Burners - LNB technologies rely on a combination of fuel staging and combustion 

air control to suppress the formation of thermal NOx. Fuel staging occurs in the very beginning 

of combustion, where the pulverized coal is injected through the burner into the furnace. Careful 

control of the fuel-air mixture leaving the burner can limit the amount of oxygen available to the 

fuel during combustion creating a fuel rich zone that converts nitrogen to molecular nitrogen (N2) 

rather than using oxygen in the combustion air to oxidize the nitrogen to NOx. This allows 

complete combustion of the fuel while reducing both thermal and chemical NOx formation.

3. Selective Catalytic Reduction – SCR is a post combustion control technique in which vaporized 

ammonia is injected into the flue gas upstream of a catalyst. NOx entrained in the flue gas is 

reduced to N2 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 

can 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 NOx emissions reductions 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 NOx 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 NOx 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 NOx 

emissions. It involves the introduction of a supplemental fuel into the main section of the steam 

generator to produce reducing conditions that convert NOx to N2. Natural gas reburn requires 

three separate combustion zones and sufficient residence time (adequate furnace height).

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

NOx reduction. Basin Electric evaluated the combined application of OFA/LNB and the combined 

application of OFA/LNB with SNCR.

NOx: 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. 
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NOx: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

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

permit limit that would be established for that technology if it were chosen as BART. The permit 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, such as LNB with OFA, generally 

have inherent variability that must be considered when establishing the permit limit. Otherwise, the 

source 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 evaluation of an SNCR system for Laramie River Station 

indicated that the controlled NOx 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 Electric, 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 described 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 as the lowest theoretical NOx level that could be achieved 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 Electric‟s contractor (Black & Veatch) as 

representing 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 indicated 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 

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

Table 2 presents a summary of the effectiveness of the technically feasible control technologies for NOx.
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Table 2: NOx 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) annual averages for 2001-2003.

NOx: EVALUATE IMPACTS AND DOCUMENT RESULTS

Basin Electric quantified the costs of applying the remaining NOx control technologies by considering the 

following types of impact:

Cost of compliance

Energy impacts

Non-air quality 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 flue gas flow, 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 estimates 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 Control Cost Manual (Sixth Edition)

Budgetary quotes from equipment vendors

Cost estimates from previous design/build projects or in-house engineering estimates
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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 

control 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 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 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 equipment. When performing the presumptive BART levels analyses 

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

visibility improvement. EPA did not use the dollars per deciview metric to compare control options. 

Visibility improvements from the application of the control measures used to establish presumptive levels 

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

presented later in this analysis, 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 NOx emission control. 

Tables 3 through 5 present the economic and environmental costs associated with the remaining NOx 

control technologies for Units 1 through 3.
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Table 3: Unit 1 Economic and Environmental Costs for NOx Control

Parameter OFA New LNB

New LNB 

with OFA

SNCR/SCR 

Hybrid

New 

LNB/OFA 

and SNCR SCR

Capital Costs

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

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

NOx Emissions 

(lb/MMBtu) 0.23 0.23 0.23 0.20 0.12 0.07

Annual NOx Emission 

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

Annual NOx

Reduction (tpy) 936 936 936 1,639 3,511 4,681

Cost per ton of 

Reduction $668 $1,453 $2,077 $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 Hybrid not calculated (considered 

an inferior technology and not considered further in this analysis).

Table 4: Unit 2 Economic and Environmental Costs for NOx Control

Parameter OFA New LNB

New LNB 

with OFA

SNCR/SCR 

Hybrid

New 

LNB/OFA 

and SNCR SCR

Capital Costs

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

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

NOx Emissions 

(lb/MMBtu) 0.23 0.23 0.23 0.20 0.12 0.07

Annual NOx Emission 

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

Annual NOx

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

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 Hybrid not calculated (considered 

an inferior technology and not considered further in this analysis).
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Table 5: Unit 3 Economic and Environmental Costs for NOx Control

Parameter OFA New LNB

New LNB 

with OFA

SNCR/SCR 

Hybrid

New 

LNB/OFA 

and SNCR SCR

Capital Costs

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

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

NOx Emissions 

(lb/MMBtu) 0.23 0.23 0.23 0.20 0.12 0.07

Annual NOx Emission 

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

Annual NOx

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

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 Hybrid not calculated (considered 

an inferior technology and not considered further in this analysis).

The cost effectiveness and incremental cost effectiveness of the proposed BART technologies for NOx 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 was not individually evaluated in Step 5: Evaluate 

visibility impact, the anticipated degree of visibility improvement from applying this control option lies 

within the range of visibility impacts that were modeled.

The final step in the BART NOx 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 pollutants and associate control options. The visibility analysis follows Steps 1-4 for PM10

emissions in this application analysis.

SO2: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Basin Electric identified three control technology configurations for reduction of SO2 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 Injection 
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1. Elimination of Stack Reheat System – Basin Electric routes a portion of the flue gas on Units 1 

and 2 to a reheat system that decreases the moisture in the flues and avoids 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 SO2 emissions, 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 SO2 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 SO2 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 SO2 removal is to upgrade the capacity of the 

recycle pumps, thus increasing the slurry flow rate. This would increase the L/G ratio. As a 

fourth option, an additional absorber 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 SO2 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 SO2 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 configurations for reduction of SO2 emissions from Unit 

3, which currently uses a DFGD system: 

Fabric Filter Retrofit into Unit 3 ESP Casing

Replacement of Dry Scrubber Reactor with New Generation SDA Modules 

New WFGD System

Sorbent Injection 

1. Fabric Filter Retrofit into Unit 3 ESP Casing – Enhanced SO2 removal can be achieved by 

retrofitting a fabric filter system into the existing Unit 3 ESP. Removal of SO2 would occur from 

contact of the remaining SO2 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 SO2 removal can be 10 to 20 percent. 
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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

scrubber equipment on Unit 3 was designed by B&W, and achieves an SO2 removal rate of 

approximately 85 percent. Replacement of the existing four dry scrubber reactors with two SDA 

modules could achieve a small increase in SO2 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 for Unit 3. 

4. Sorbent Injection – The sorbent injection system described earlier for Units 1 and 2 is also a 

possibility for Unit3.

SO2: 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. 

SO2: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

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

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

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

practices. 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 has 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.

Tables 6 and 7 present the effectiveness of the remaining technically feasible control technologies for 

SO2.
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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Table 6: Units 1 and 2 SO2 Emission Rates Per Boiler

Control 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 SO2 Emission Rates 

Control Technology

Control 

Effectiveness

(lb/MMBtu)

Baseline 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.

SO2: EVALUATE IMPACTS AND DOCUMENT RESULTS

Basin Electric quantified the costs of applying the remaining SO2 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 section 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 

control 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 
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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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 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 equipment. When performing the presumptive BART levels analyses 

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

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

Visibility improvements from the application of the 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 each proposed emission control. Tables 8 through 10 

present the economic and environmental costs associated with the remaining SO2 control technologies for 

Units 1 through 3.

Table 8: Unit 1 Economic and Environmental Costs for SO2 Control

Parameter

Sorbent 

Injection

FGD 

Chemical 

Additives

Eliminate Stack 

Reheat System

Capital Costs

$7,453,000 $2,363,000 $63,845,000

Annualized Costs $906,000 $366,000 $6,664,000

SO2 Emissions (lb/MMBtu) 0.15 0.15 0.13

Annual SO2 Emission (tpy) 3,511 3,511 3,043

Annual SO2 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 Additives
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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Table 9: Unit 2 Economic and Environmental Costs for SO2 Control

Parameter

Sorbent 

Injection

FGD 

Chemical 

Additives

Eliminate Stack 

Reheat System

Capital Costs

$7,453,000 $2,363,000 $63,845,000

Annualized Costs $906,000 $366,000 $6,664,000

SO2 Emissions (lb/MMBtu) 0.15 0.15 0.13

Annual SO2 Emission (tpy) 3,492 3,492 3,026

Annual SO2 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 SO2 Control

Parameter

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) New WFGD

Capital Costs

$194,809,000 $134,934,000 $240,777,000

Annualized Costs $19,585,000 $14,376,000 $31,243,000

SO2 Emissions (lb/MMBtu) 0.13 0.13 0.06

Annual SO2 Emission (tpy) 3,105 3,105 1,433

Annual SO2 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 Costs $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 Retrofit
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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Several of the technically feasible control options for SO2 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 98th percentile result for all three units combined, would be (at most) 

0.02 delta deciview. Therefore, none of the proposed control options for SO2 were carried forward for 

further analysis. 

PM/PM10: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Basin Electric identified four control technology configurations for control of PM emissions from Units 1 

through 3: 

Flue Gas Treatment 

Existing ESP Performance Enhancements

PJFF Retrofit into ESP (Unit 3 only)

GE Max-9 Hybrid 

1. Flue Gas Treatment – One option for flue gas treatment is flue gas “conditioning”, for which 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 particles. 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 H2SO4. 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. Existing ESP Performance Enhancements – The ESP imparts an electrical charge to particles in 

the flue gas, 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 – Retrofit 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 cleaning 
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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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. The PJFF retrofit is a viable option only for 

Unit 3. Units 1 and 2 utilize wet flue gas desulfurization (WFGD), and a PJFF is not feasible for 

use downstream of a WFGD system.

4. GE Max-9 Hybrid – The GE Max-9 Electrostatic Fabric Filter (ESFF) is an electrostatic 

precipitator/pulse-jet baghouse hybrid, using high-voltage discharge electrodes to charge flue gas 

particles, but with fabric filters instead of collecting plates in the casing. The system can provide 

high collection efficiency while operating at a lower 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/PM10: 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 existing 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 Hybrid 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/PM10: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

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

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

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

practices. 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 has 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

Control Technology

Control 

Effectiveness

(lb/MMBtu)

Baseline 0.030

Retrofit Fabric Filter into Unit 3 ESP 0.015
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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PM/PM10: 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 environmental 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 

control 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 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 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 equipment. When performing the presumptive BART levels analyses 

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

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

Visibility improvements from the application of the control measures used to establish presumptive levels 

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

presented later in this analysis, 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

AP-6047 BART Application Analysis

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

Parameter

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 Costs

$194,809,000 $134,934,000

Annualized Costs $19,585,000 $14,376,000

PM Emissions (lb/MMBtu) 0.015 0.015

Annual PM Emission (tpy) 358 358

Annual PM Reduction (tpy) 358 358

Cost per ton of Reduction $54,707 $40,156

Energy Costs $242,000 $243,000

The remaining technically feasible PM10 control option for Unit 3 is not cost effective, and was not carried 

forward for further analysis. 

VISIBILITY IMPROVEMENT DETERMINATION:

The fifth of five factors 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 visibility 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 

system (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) emissions from the facility. The screening 

modeling, as well as more 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 Figure 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 located to the northeast of the 

station, at distances of approximately 190 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. It can be reasonably assumed that areas at greater 

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

predicted for the two modeled areas. 
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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Figure 1

Laramie River Station and Class I Areas

#

Albany

Converse

Platte

Laramie

Niobrara

Goshen

Johnson Campbell Weston

Natrona

Carbon

Rawah Wilderness

Rocky Mountain NP

Badlands/Sage Creek Wilderness 1

Wind Cave National Park

Wyoming

Colorado

Nebraska

South Dakota

Lusk

Laramie

Douglas

Cheyenne

Wheatland

Newcastle

Torrington

Laramie River

103°0'0"W

103°0'0"W

104°0'0"W

104°0'0"W

105°0'0"W

105°0'0"W

106°0'0"W

106°0'0"W

44°0'0"N 44°0'0"N

43°0'0"N 43°0'0"N

42°0'0"N 42°0'0"N

41°0'0"N 41°0'0"N

40°0'0"N

Distances from Laramie River Station (km)

Rawah WA = 165

Rocky Mtn NP = 185 Wind Cave NP = 190

Badlands NP = 270
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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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 meteorological 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. Sources input to the modeling included the potential 

emissions (current operation) from the three coal-fired boilers at the facility. 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 Colorado Class I areas due to the predominant wind direction.

Results of the modeling showed that the 98th percentile value for the change in visibility (delta deciview 

[Δdv]) was above 0.5 Δdv at Wind Cave NP and Badlands NP for all three years of meteorology. As 

defined in EPA‟s final BART rule, a 98th percentile 0.5 Δdv 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 Table 13 below.

Table 13: Results of the Class I Area Screening Modeling

Year and Class I Area

Maximum 

Modeled 

Value (Δdv)

98th

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

2003

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 BART analysis that included CALPUFF visibility modeling for the facility. 

The modeling approach followed the requirements described in the Division‟s BART modeling protocol, 

BART Air Modeling Protocol - Individual Source Visibility Assessments for BART Control Analyses 

(WDEQ-AQD, September 2006).

CALPUFF System

Predicted visibility impacts from the 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, the CALPUFF system was appropriate for use.
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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

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

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

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

removal. 

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

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

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

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

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

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

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

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

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

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

CALPUFF model in a refined mode.

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

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

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

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

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

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

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

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

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

Table 14: Key Programs in CALPUFF 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-dimensional 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 limited 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 applicants all of the raw meteorological inputs for the CALMET model Default settings were 
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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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, 3400 

RMIN2 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 and to model an 

additional control scenario at Wind Cave NP and Badlands NP. Surface, upper-air, and precipitation data 

for the domains were incorporated into the CALMET windfields. Figures 2 and 3 below show the 

locations of surface, upper-air, and precipitation stations used for the two windfields.
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AP-6047 BART Application Analysis

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Figure 2: Observations Input to CALMET (BEPC Windfield)

-300 -200 -100 0 100 200 300

LCC East (km)

-300

-200

-100

0

100

200

LCC North (km)

Scottsbluff

Casper

Cheyenne

Rapid_City

Sheridan

Laramie_River

DNR

LBF

UNR

Wind Cave NP

Badlands NP

Precipitation Station

Surface Station

Upper-Air Station
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AP-6047 BART Application Analysis

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Figure 3: Observations Input to CALMET (Expanded Windfield)

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

LCC E (km)

-300

-200

-100

0

100

200

300

400

LCC N (km)

KWX

AIA

AKO

APA

ASE

BFF

BIL

BPI

BTM

BYG

BYI

BZN

CAG

CPR CDR

CUT

CYS

D07

DEN

DGW

DLN

EEO

EVW

GCC

GEY

GJT

IDA

IEN

ITR

LAR

LGU

LIC

LND

LVM

LXV

OGD

P60

PHP

PIH

PUC

RAP

RIL

RIW

RKS

RWL

RXE

SHR

SLC

SNY

TOR

VEL

WRL

RAP

DEN

SLC

RIW

Laramie_River

Precipitation Station = green

Surface Station = white 3-letter

Upper-Air (+ surface) = red 3-letter

RMNP

Rawah 

WA

Badlands

NP

Wind 

Cave

NP
Laramie River Station

AP-6047 BART Application Analysis

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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 National Monument, Idaho

Highland, Utah

Thunder Basin, Wyoming

Yellowstone NP, Wyoming

Centennial, Wyoming

Pinedale, Wyoming

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

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

ppb was used. 

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

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

Lambert Conformal Conic coordinates. Figures 4-7 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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Figure 4

Receptors for Rawah WA
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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Figure 5

Receptors for Rocky Mountain NP
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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Figure 6

Receptors for Wind Cave NP

Figure 7

Receptors for Badlands NP
Basin Electric Laramie River Station

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CALPUFF Inputs – Baseline and Control Options

The first step in the refined modeling analysis was to perform visibility modeling for current 

(baseline) operations at the facility. Emissions of NOx and SO2 for the baseline runs were 

established based on CEM annual emissions averages for years 2001 to 2003. All particulate 

emissions (PM) were based on an emission rate of 0.03 lb/MMBtu and were treated as PM2.5 (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. 

Baseline source release parameters and emissions are shown in the table below, followed by 

tables with data for the various control options. No 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

AP-6047 BART Application Analysis

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Table 16: Baseline Source Parameters

Parameter

Baseline

Coal-Fired 

Unit 1 (P1)

Coal-Fired 

Unit 2 (P2)

Coal-Fired 

Unit 3 (P3)

LNB, 

WFGD, ESP

LNB, 

WFGD, ESP

LNB, 

DFGD, 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

Stack 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

SO2 Emissions (lb/MMBtu) 0.16 0.16 0.17

SO2 Emissions (tpy) 3745 3725 4060

HS2O4 Emissions (tpy) 3.06 2.80 0.22

NOx Emissions (lb/MMBtu) 0.27 0.27 0.27

NOx 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 heat input and lb/MMBtu emissions for NOx and SO2 based on continuous emissions 

monitoring (CEM) annual averages for 2001-2003.

DFGD = dry flue gas desulfurization

ESP = electrostatic precipitator

H2SO4 = sulfuric acid

K = Kelvin

lb/MMBtu = pounds per million British thermal units

LNB = low-NOx burners

m = meters

m/s = meters per second

MMBtu/yr = million British thermal units per year

NOx = nitrogen oxides

PM = particulate matter

SO2 = sulfur dioxide

tpy = tons per year

WFGD = wet flue gas desulfurization 
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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Table 17: Source Parameters and Emissions for BART Control Options

Parameter

Control Option 1 Control Option 2

NOx Control: Overfire Air (OFA) 

or New LNB NOx Control: New LNB with OFA

CoalFired 

Unit 1 

(P1)

CoalFired 

Unit 2 

(P2)

CoalFired 

Unit 3 

(P3)

CoalFired 

Unit 1 

(P1)

CoalFired 

Unit 2 

(P2)

CoalFired 

Unit 3 

(P3)

Base Elevation (m) 1348 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

SO2 Emissions (lb/MMBtu) 0.16 0.16 0.17 0.16 0.16 0.17

SO2 Emissions (tpy) 3745 3725 4060 3745 3725 4060

H2SO4 Emissions (tpy) 3.18 3.25 0.22 3.18 3.25 0.22

NOx Emissions (lb/MMBtu) 0.23 0.23 0.23 0.23 0.23 0.23

NOx Emissions (tpy) 5384 5354 5493 5384 5354 5493

PM Fine Emissions (lb/MMBtu) 0.030 0.030 0.030 0.030 0.030 0.030

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

H2SO4 = sulfuric acid 

K = Kelvin

lb/MMBtu = pounds per million British thermal units

LNB = low NOx burners

m = meters

m/s = meters per second

NOx = nitrogen oxides

OFA = overfire air

PM = particulate matter

SCR = selective catalytic reduction

SO2 = sulfur dioxide

tpy = tons per year
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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

Parameter

Control Option 4

NOx Control: SCR

CoalFired 

Unit 1 

(P1)

CoalFired 

Unit 2 

(P2)

CoalFired 

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 Velocity (m/s) 21.33 21.03 22.25

SO2 Emissions (lb/MMBtu) 0.16 0.16 0.17

SO2 Emissions (tpy) 3745 3725 4060

H2SO4 Emissions (tpy) 3.18 3.25 0.22

NOx Emissions (lb/MMBtu) 0.07 0.07 0.07

NOx Emissions (tpy) 1639 1630 1672

PM Fine Emissions 

(lb/MMBtu) 0.030 0.030 0.030

PM Fine Emissions (tpy) 702 698 716

H2SO4 = sulfuric acid 

K = Kelvin

lb/MMBtu = pounds per million British thermal units

LNB = low NOx burners

m = meters

m/s = meters per second

NOx = nitrogen oxides

OFA = overfire air

PM = particulate matter

SCR = selective catalytic reduction

SO2 = sulfur dioxide

tpy = tons per year 
Basin Electric Laramie River Station

AP-6047 BART Application Analysis

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Visibility 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

Month

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

October 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, natural background conditions as a reference for determination of the 

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

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

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

to CALPOST. 

 

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

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

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

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

annual concentrations, the 20 percent best days deciview values 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 Badlands 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

AP-6047 BART Application Analysis

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dv = 10 ln (bext/10) or bext = 10 exp (dv/10)

where: bext = light extinction expressed in inverse megameters (Mm-1).

Using this relationship with the known deciview value of 2.18, one obtains an 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:

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

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

where:

bracketed quantities represent background concentrations in μg/m3

values in parenthesis represent scattering efficiencies

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

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

Substituting the annual average natural background concentrations, the average f(RH) for 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 the 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/m3)

Calculated Scaling 

Factor

20% Best Days for 

Badlands NP 

(μg/m3)

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 Badlands 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

AP-6047 BART Application Analysis

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Table 20: Natural Background Aerosol Concentrations (μg/m3)

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 0.189 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 tables 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 98th percentile 

Δdv results are reported along with the total number of days for which the predicted impacts exceeded 0.5 

dv. Following the tables are figures that present the results graphically for Wind Cave NP and Badlands 

NP. 
Laramie River Station

AP-6047 BART Application Analysis

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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. of 

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 0.700 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 0.322 4 0.402 4 0.303 5 0.342 4

Wind Cave NP 0.378 3 0.320 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 0.530 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 NP 0.573 12 0.762 16 0.530 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 0.320 4 0.399 4 0.302 5 0.340 4

Wind Cave NP 0.384 3 0.319 1 0.310 3 0.338 2
Laramie River Station

AP-6047 BART Application Analysis

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Table 23: CALPUFF Visibility Modeling Results 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 0.630 8 0.718 13

Wind Cave NP 0.680 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 0.447 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 6
Laramie River Station 

AP-6047 BART Application Analysis Page 40

Figure 8 – Modeled BART Impacts: Number of Days > 0.5 delta-dv 

0.02.04.06.08.0

10.012.014.016.0

LR Unit1 LR Unit2 LR Unit3 LR Unit1 LR Unit2 LR 

Baseline (LControl OpControl OpControl Op

Badlands NP Wind Cave NP

(Modeling results represent the three‐year average of results using 2001‐2003 meteorology)

BEPC Laramie River Station

Unit 1 (550 MW, net)

Unit 2 (550 MW, net)

Unit 3 (550 MW, net)

(# Days)
Laramie River Station 

AP-6047 BART Application Analysis Page 41

Figure 9 – Modeled BART Impacts: 98th Percentile (delta-dv) 

0.0000.1000.2000.3000.4000.5000.6000.7000.800

LR Unit1 LR Unit2 LR Unit3 LR Unit1 LR Unit2 LR 

BaseContContCont

Badlands NP Wind Cave NP

BEPC Laramie River StationUnit 1 (550 MW, net)

Unit 2 (550 MW, net)

Unit 3 (550 MW, net)

(Modeling results represent the three‐year average of results using 2001‐2003 meteorology)

(del‐dv)
Laramie River Station

AP-6047 BART Application Analysis

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BART CONCLUSIONS:

After considering: (1) the costs of compliance, (2) the energy and non-air quality environmental impacts 

of compliance, (3) any pollution equipment in use or in existence at the source, (4) the remaining useful 

life of the source, and (5) the degree of improvement in visibility (all five statutory factors) from each 

proposed control technology, the Division determined BART for the three units at the Laramie River 

Station.

NOx

New LNB with OFA is determined to be BART for NOx control for Units 1-3 based, in part, on the 

following conclusions:

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

and $2,036-$2,088 per ton of NOx 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 environmental 

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

impact.

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

existing pollution control equipment, a NOx control level of 0.23 lb/MMBtu on a 30-day rolling 

average, equal to EPA‟s established presumptive limit for dry-bottom, wall-fired boilers burning 

sub-bituminous coal, is justified.

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

impairing pollutants and the associated 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/MMBtu (based on the 98th percentile modeled results)

was 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 NOx 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 NOx control for Units 1-3 based, in part, on 

the following conclusions:

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

LNB with OFA. Additional capital costs for SCR on Units 1-3 are $101,005,000 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

AP-6047 BART Application Analysis

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

from each unit.

4. The cumulative visibility improvement for SCR, as compared to LNB/OFA, across Wind Cave 

NP and Badlands NP (based on the 98th 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 NOx controls, new LNB 

with OFA, to meet the statutory requirements of BART.

Unit-by-unit NOx BART determinations:

Laramie River Unit 1: New LNB with OFA and meeting NOx emission limits of 0.23

lb/MMBtu (30-day rolling average), 1,348 lb/hr (30-day rolling average),

and 5,343 tpy (12-month rolling) as BART for NOx. 

Laramie River Unit 2: New LNB with OFA and meeting NOx emission limits of 0.23

lb/MMBtu (30-day rolling average), 1,348 lb/hr (30-day rolling average),

and 5,343 tpy (12-month rolling) as BART for NOx. 

Laramie River Unit 3: New LNB with OFA and meeting NOx emission limits of 0.23

lb/MMBtu (30-day rolling average), 1,386 lb/hr (30-day rolling average),

and 5,493 tpy (12-month rolling) as BART for NOx. 

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 operational variability that is typical for a boiler. The 30-day limits that are expressed in terms of 

mass emissions (lb/hr) are based on 0.21 lb/MMBtu. Because reduced steam loads on a boiler can result 

in periods of increased 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 limit 

(expressed in tpy) based on 0.19 lb/MMBtu.

PM/PM10

Existing ESP is determined to be BART for Units 1-3 for PM/PM10 based, in part, on the following 

conclusions:

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 

installing the retrofit fabric filter is $40,156 per ton of PM/PM10 removed. No additional control 

technologies were deemed to be technically feasible for Units 1 and 2. 
Laramie River Station

AP-6047 BART Application Analysis

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2. Visibility impacts from the installation of controls on PM/PM10 emissions, in general, 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 Cave NP or Badlands NP was at most 0.07 Δdv.

The Division considers the operation of the BART-determined PM/PM10 controls, existing ESP, to meet 

the statutory requirements of BART.

Unit-by-unit PM/PM10 BART determinations:

Laramie River Unit 1: Continuing to use the existing ESP to meet the established PM/PM10

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

PM/PM10.

Laramie River Unit 2: Continuing to use the existing ESP to meet the established PM/PM10

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

PM/PM10.

Laramie River Unit 3: Continuing to use the existing ESP to meet the established PM/PM10

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

PM/PM10.

SO2: REGIONAL SO2 MILESTONE AND BACKSTOP TRADING PROGRAM

Basin Electric evaluated SO2 control technologies that can achieve a SO2 emission rate of 0.15 lb/MMBtu 

or lower from the coal-fired boilers. Basin Electric proposed BART controls include using chemical 

additives in the Unit 1 and 2 WFGD systems. 

Wyoming is a §309 state participating in the Regional SO2 Milestone and Backstop Trading Program. 

§308(e)(2) provides States with the option to implement or require participation in an emissions trading 

program or other alternative measure rather than to require sources subject to BART to install, operate, 

and maintain additional control technology to meet an established emission limit on a continuous basis. 

However, the alternate program must achieve greater reasonable progress than would be accomplished by 

installing BART. A demonstration that the alternate program can achieve greater reasonable progress is 

prescribed by §308(e)(2)(i). Since the pollutant of concern is SO2, this demonstration has been performed 

under §309 as part of the state implementation plan. §309(d)(4)(i) requires that the SO2 milestones 

established under the plan “...must be shown to provide for greater reasonable progress than would be 

achieved by application of BART pursuant to §51.308(e)(2).”

Wyoming participated in creating a detailed report entitled Demonstration that the SO2 Milestones 

Provide Greater Reasonable Progress than BART covering SO2 emissions from all states participating 

in the Regional SO2 Milestone and Backstop Trading Program. The document was submitted to EPA in 

support of the §309 Wyoming Regional Haze SIP in November of 2008.

As part of the §309 program, participating states, including Wyoming, must submit an annual Regional 

Sulfur Dioxide Emissions and Milestone Report that compares actual emissions to pre-established 

milestones. Participating states have been filing these reports since 2003. Each year, states have been 
Laramie River Station

AP-6047 BART Application Analysis

Page 45

able to demonstrate that actual SO2 emissions are well below the milestones. The actual emissions and 

their respective milestones are shown below:

Table 25: Regional Sulfur Dioxide Emissions and Milestone Report Summary

Year Reported SO2 Emissions

(tons)

3-year Milestone 

Average

(tons)

2003 330,679 447,383

2004 337,970 448,259

2005 304,591 446,903

2006 279,134 420,194

2007 273,663 420,637

In addition to demonstrating successful SO2 emission reductions, §309 states have also relied on visibility 

modeling conducted by the WRAP to demonstrate improvement at Class I areas. The complete modeling 

demonstration showing deciview values was included as part of the visibility improvement section of the 

§309 SIP, but the SO2 portion of the demonstration has been included as Table 26 to underscore the 

improvements associated with SO2 reductions.

Table 26: Visibility - Sulfate Extinction Only

Class I Area Monitor

(Class I Areas Represented)

20% Worst Visibility Days 

(Monthly Average, Mm-1)

20% Best Visibility Days

(Monthly Average, Mm-1)

2018 1

Base Case

(Base 18b)

2018 2

Preliminary

Reasonable

Progress Case

(PRP18a)

2018 1

Base Case

(Base 18b)

2018 2

Preliminary

Reasonable

Progress Case

(PRP18a)

Bridger, WY

(Bridger WA and Fitzpatrick WA) 5.2 4.3 1.6 1.3

North Absaroka, WY

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

Yellowstone, WY

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

Badlands, SD 17.8 16.0 3.5 3.1

Wind Cave, SD 13.0 12.1 2.7 2.5

Mount Zirkel, CO

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

Rocky Mountain, CO 6.8 6.2 1.3 1.1

Gates of the Mountains, MT 5.3 5.1 1.0 1.0

UL Bend, MT 9.7 9.6 1.8 1.7

Craters of the Moon, ID 5.8 5.5 1.5 1.5

Sawtooth, ID 3.0 2.8 1.2 1.1

Canyonlands, UT

(Canyonlands NP and Arches NP) 5.4 4.8 2.1 1.9

Capitol Reef, UT 5.7 5.4 1.9 1.8

1 Represents 2018 Base Case growth plus all established controls as of Dec 2004. No BART or S02 Milestone assumptions were 

included.

2 Represents 2018 Preliminary Reasonable Progress growth estimates and established S02

limits.
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AP-6047 BART Application Analysis

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

to SO2 on the worst days and no degradation on the best days. More discussion on the visibility 

improvement of the §309 program can be found in the Wyoming §309 Regional Haze SIP submitted in 

November 2008.

Therefore, in accordance with §308(e)(2), Wyoming‟s §309 Regional Haze 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 SO2 Milestone and Backstop Trading Program authorized under Chapter 14 of the WAQSR.

LONG-TERM STRATEGY FOR REGIONAL HAZE:

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

environmental impacts of compliance, any pollution control equipment in use at the source, the remaining

useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated 

to result from the use of such technology were taken into consideration when determining BART. When 

evaluating the costs of compliance, the Division recognized a time limitation to install BART-determined 

controls imposed by the Regional Haze Rule. When addressing the required elements, including 

documentation for all required analyses to be submitted in the State Implementation Plan, 40 CFR 

51.308(e)(1)(iv) states: “A requirement that each source subject to BART be required to install and 

operate BART as expeditiously as practicable, but in no event later than 5 years after approval of the 

implementation plan revision.” As a practical measure, the Division anticipates the requirement to install 

the BART-determined controls to possibly occur as early as 2015.

Based 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 within the regulatory timeframe allotted for BART installations by 

the Regional Haze Rule, the Division is requiring the installation of additional controls under the LongTerm Strategy of the Wyoming Regional Haze State Implementation Plan. The Division is requiring 

Basin Electric submit a permit application to install additional add-on NOx 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 visibility impairment (i.e., the four statutory factors taken into consideration when

establishing reasonable progress goals5) and the associated visibility impacts from the application of each 

proposed NOx control. Each proposed add-on NOx control shall achieve an emission rate, on an 

individual unit basis, at or below 0.07 lb/MMBtu on a 30-day rolling average. Additional add-on controls 

shall be installed and operational on one of the Laramie River Station units by December 31, 2018 and on 

a second Laramie 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 Regulations 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 to meet BART. 

 

5

40 CFR 51.308(d)(1)(i)(A).
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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.

CHAPTER 5, SECTION 3 – NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS (NESHAPs) AND CHAPTER 6, SECTION 6 – HAZARDOUS AIR POLLUTANT 

(HAP) EMISSIONS AND MAXIMUM AVAILABLE CONTROL TECHNOLOGY (MACT):

The installation of 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 Regulations. Operating Permit 3-1-102-2 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 include 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 BART 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 

NOx control that achieves an emission rate, on an individual unit basis, at or below 0.07 lb/MMBtu on a 

30-day rolling average by December 31, 2018 and December 31, 2023, respectively, under the LongTerm Strategy of the Wyoming §308 Regional Haze State Implementation Plan.
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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 permission to enter and inspect 

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

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

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

or orders.

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

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

enforceable as conditions of this permit.

3. That 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 associated with this permit shall be submitted to the 

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

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

Division, at the same address.

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/PM10 lb/hr and tpy limits shall apply during all operating 

periods. PM/PM10 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 generators are put online.

Pollutant lb/MMBtu lb/hr tpy

PM/PM10

(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/PM10 performance tests shall 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 is achieved.
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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 NOx limits shall apply during all operating periods. 

Pollutant lb/MMBtu lb/hr tpy

NOx 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 initial NOx performance tests be conducted, in accordance with Chapter 6, Section 2(j) of 

the WAQSR, within 30 days of achieving a maximum design rate but not later than 90 days 

following initial start-up, and a written report of the results be submitted. If a maximum design 

rate is not achieved within 90 days of start-up, the Administrator may require testing be done at 

the rate achieved and again when a maximum rate is achieved.

9. Performance tests shall consist of the following:

Coal-fired Boilers (Laramie River Station Units 1 through 3):

NOx Emissions – Compliance with the NOx 30-day rolling average shall be 

determined using a continuous emissions monitoring system (CEMS) certified in 

accordance with 40 CFR part 60.

PM/PM10 Emissions – Testing shall follow 40 CFR 60.46 and EPA Reference 

Test Methods 1-4 and 5. 

Testing required by the 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 

within 45 days of completing the tests.

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

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

12. 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 

follows:

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

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

limits calculated in accordance with the compliance provisions and monitoring 
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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 existing CEM equipment which 

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

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

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

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

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

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

CFR part 60, subpart Da.

iii. Any 12-month rolling emission rate which exceeds the tpy NOx limit as 

calculated using the following formula:

2,000

h 1

C h

E

Where:

C = 1-hour average emission rate (lb/hr) for hour “h” calculated using data 

from the CEM equipment required 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 

period 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 excess 

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

WAQSR, Chapter 5, Section 2(g).

13. Compliance with the PM/PM10 limits set forth in this permit for the coal-fired boilers (Laramie 

River Units 1-3) shall be determined with data from testing for PM conducted annually, or more 

frequently as specified by the Administrator, following 40 CFR 60.46 and EPA Reference Test 

Methods 1-4 and 5. Testing required by the WAQSR Chapter 6, Section 3 operating permit may 

be submitted to satisfy the testing required by this condition.

14. 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.
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15. Basin Electric shall install new low NOx burners 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, 2012 for Unit 1; December 31, 2013 for Unit 

2; and December 31, 2014 for Unit 3.

16. Basin Electric shall submit permit applications for the installation of additional add-on NOx

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 Strategy of the Wyoming §308 Regional Haze State 

Implementation Plan. It shall include an analysis of the four statutory factors and the associated 

visibility impacts from the application of each proposed NOx control and resulting emission 

levels. This application shall address each add-on NOx control as a system of continuous 

emissions reduction achieving the lowest viable NOx emission, not to exceed a maximum of 0.07 

lb/MMBtu on a 30-day rolling average as measured by a certified CEM. Additional add-on NOx

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