PRELIMINARY COMMENTS:

Background

Nebraska Public Power District (NPPD) operates the Gerald Gentleman Station (GGS), 

which includes two Electric Generating Units (EGUs), near Sutherland, NE. The plant is 

located within 400 km of three Class I areas (Badlands, Wind Cave, and Rocky Mountain 

National Parks) which are administered by the National Park Service. GGS includes two 

BART-eligible boilers which burn pulverized Powder River Basin (PRB) sub-bituminous 

coal (8,576 Btu/lb; 0.30 % sulfur; 4.69% ash in 2001). Historic emissions, based upon 

data from EPA’s Clean Air Markets (CAM) database, are illustrated in the attached charts 

(figures 1.a. – 1.d.). 

Unit #1 is a dry-bottom, wall-fired boiler rated at 665 MW (net). Unit #1 is equipped with 

a fabric filter to control particulate matter (PM10). It appears that Low-NOx Burners 

(LNB) and Over-Fire Air (OFA) were installed 2005 – 2006 to reduce nitrogen oxides 

(NOx) from about 0.45 pounds per million Btu (lb/mmBtu) and 12,000 – 14,000 tons per 

year (tpy) to about 0.2 lb/mmBtu and about 6,000 tpy. There are no controls for sulfur 

dioxide (SO2), which typically is emitted at 0.5 – 0.6 pounds per million Btu (lb/mmBtu) 

and 14,000 – 16,000 tons per year (tpy). 

Unit #2 is a dry-bottom, wall-fired boiler rated at 700 MW (net). Unit #2 is equipped with 

a fabric filter to control particulate matter (PM10). There are no controls for SO2, which 

typically is emitted at 0.5 – 0.6 lb/mmBtu and 14,000 – 16,000 tpy. There are no controls 

for NOx, which typically is emitted at 0.30 – 0.35 lb/mmBtu and 8,000 – 10,000 tpy. 

Modeling analyses have shown that GGS causes visibility impairment in the Badlands 

National Park (NP), Wind cave NP, Rocky Mountain NP, and Wichita Mountains 

Wilderness Class I areas. GGS also contributes to visibility impairment at the Hercules 

Glades and Mingo Class I Wilderness areas. 

On 6/19/08 we were notified that NPPD’s BART analyses were available on the 

Nebraska Air Division’s website. The following are our comments and questions 

regarding those documents. 

Cost-Effectiveness Metrics

NPPD has presented extensive information to support its contention that costs of 

pollution controls are increasing, and that this should be taken into account in these cost 

analyses. NPPD appears to have used cost escalation as its rationale to present a mix of 

costing techniques that borrow from the OAQPS Control Cost Manual (Cost Manual), 

and NPPD’s consultant’s proprietary methods. We agree with NPPD that inflation should 

be a factor in these cost analyses. In fact, we included just such a factor our own analyses 

that we discuss later in this document. However, we do not agree that NPPD, or any 

source, should be able to pick and choose bits and pieces from among the various 

methods for estimating pollution control costs. The BART analysis is based upon 
2

judgments as to the reasonableness of costs and benefits of reducing emissions from a 

specific source relative to costs born by similar sources and the benefits of reducing 

emissions at those sources. EPA guidance states: 

The basis for equipment cost estimates also should be documented, either with data 

supplied by an equipment vendor (i.e., budget estimates or bids) or by a referenced 

source (such as the OAQPS Control Cost Manual). In order to maintain and improve 

consistency, cost estimates should be based on the OAQPS Control Cost Manual, where 

possible. 

NPPD should follow this guidance. 

Our contention that the Cost Manual should be the primary source for developing cost 

analyses that are consistent across the nation and provide a common means for assessing 

costs is further supported by this November 7, 2007, statement from EPA Region 8 to the 

North Dakota Department of Health: 

The SO2 and PM cost analyses were completed using the CUECost model. According to 

the BART Guidelines, in order to maintain and improve consistency, cost estimates 

should be based on the OAQPS Control Cost Manual. Therefore, these analyses should 

be revised to adhere to the Cost Manual methodology. 

We believe that this guidance from EPA reaffirms our comments and that NPPD should 

revise its cost analyses to reflect a more consistent use of the Cost Manual. 

Much of NPPD’s argument against installing pollution controls at GGS centers on the 

increasing worldwide costs of pollution controls in general. If this argument is carried to 

its logical conclusion, then no EGU should be required to install any pollution control 

equipment that involves a large capital expenditure. Instead, we believe that pollution 

control is an inherent cost of doing business, and that NPPD must show why the GGS 

plant would experience uniquely higher costs for pollution controls than would normally 

be considered reasonable. 

Finally, BART is not necessarily the most cost-effective solution. Instead, it represents a 

broad consideration of technical, economic, energy, and environmental (including 

visibility improvement) factors. 

Visibility Improvement Metrics

We continue to believe that it is appropriate to consider both the degree of visibility 

improvement in a given Class I area as well as the cumulative effects of improving 

visibility across all of the Class I areas affected. It simply does not make sense to use the 

same metric to evaluate the effects of reducing emissions from a BART source that 

impacts only one Class I area as for a BART source that impacts multiple Class I areas. 

And, it does not make sense to evaluate impacts at one Class I area, while ignoring others 

that are similarly significantly impaired. If emissions from GGS are reduced, the benefits 

will be spread well beyond only the most-impacted Class I area, and this must be 

accounted for. While NPPD presented data describing improvements to visibility at 

Badlands NP that would result from the various control scenarios it investigated, NPPD 

still has not explained how it incorporated this information on impacts upon all Class I 

areas into its BART decision. NPPD has effectively ignored the other Class I areas where 

GGS is also causing or contributing to visibility impairment. 
3

NOx BART1

NPPD has proposed only LNB and OFA as NOx controls (They have already been 

installed on Unit #1.) to meet the presumptive BART limit. 

NPPD has eliminated Selective Non-Catalytic Reduction (SNCR) from consideration 

without sufficient justification on the basis that it is not technically feasible because of 

high temperatures measured in a similar boiler. However, it appears from the CAM data 

plotted in Figure 1.c. that NOx emissions from the two “similar” boilers at GGS are 

significantly different. We therefore question not only NPPD’s assumption that it can 

eliminate SNCR on the basis of temperature characteristics at a distant boiler, but also 

whether it can assume that the two boilers at GGS are so similar that they can be 

evaluated in combination, not individually. (This same concern applies to the rest of 

NPPD’s analyses of NOx controls.) Thus NPPD should show, with data specific to the 

GGS boilers, that this is the case at the GGS facility also. 

NPPD rejected Selective Catalytic Reduction (SCR) as too expensive on a cost-per-tonof-pollutant-removed ($/ton) and cost-per-deciview-improvement ($/dv) basis. The table 

below uses company data and estimates that it would cost about $2,300/ton to improve 

visibility by 1.15 dv at Badlands NP. NPPD did not evaluate the cumulative benefits of 

improving visibility at the other Class I areas. 

Table 1. Nebraska Public Power--

Gerald Gentleman—NPPD estimates LNB+SCR burning PRB sub-bituminous 

Unit #1 Source #2 

Rating (MW Net) each 665 company report 700 

Rating (mmBtu/hr) 7,538 company report 7,538 

 

Current Emissions (tpy) 13,408 2001 - 2003CAM data 8,894 

Current Emissions (lb/mmBtu) 0.46 2001 - 2003CAM data 0.32 

Current Uncontrolled Emissions (tpy) 13,408 2001 - 2003CAM data 8,894 

Current Control Efficiency 47% calculated 0%

 

Company Cost-benefit Analysis 

Future Uncontrolled Emissions (tpy) 15,122 company report 15,122 

Controlled Emissions (lb/mmBtu) 0.08 company report 0.08 

Overall Control Efficiency (FGD) 83% calculated 75%

Controlled emissions (tpy) 2,659 calculated 2,659 

Emission Reductions (tpy) 12,463 company report 12,463 

Capital Cost $ 257,540,500 company report $ 257,540,500 

Capital Cost ($/kW) $ 387 calculated $ 368 

O&M Cost 

Annualized Cost $ 28,625,500 company report $ 28,625,500 

Cost-Effectiveness ($/ton) $ 2,297 company report $ 2,297 

 

1

 Presumptive BART for these wall-fired boilers burning sub-bituminous coal is 0.23 lb/mmBtu. 
4

A significant reason for the poor cost-effectiveness of this option is the low (75% - 83%) 

NOx control efficiency assumed for a technology that should be able to achieve 90% 

control.2 And, NPPD's almost $400/kW capital cost is much higher than the $40 - 

$50/kW range estimated for SCR at this facility by EPA's Cost Tool database. 

NPPD has underestimated the ability of modern NOx control systems:

NPPD estimates that addition of SCR can reduce NOx by 75% - 83% to 0.08 lb/mmBtu. 

SCR has been retrofitted to many wall-fired eastern PC boilers that are now achieving 

0.05 lb/mmBtu on a 30-day rolling average basis. We have found at least 16 examples 

(Please see enclosed Table 2.) in EPA’s Clean Air Markets (CAM) database of boilers 

similar to those at GGS that have been retrofitted with SCR and are achieving annual3

emission rates well below NPPD’s “target” for SCR. We were able to find 2006 hourly 

emissions in EPA’s CAM database for 14 of those EGUs, and charts showing those 

emissions are included in Appendix A. It appears that the majority of those retrofit SCR 

systems are able to achieve 0.05 lb/mmBtu when in use during the eastern ozone season.4

It is likely that many of these EGUs are burning eastern bituminous coals with higher 

fuel-bound nitrogen than that burned at GGS. Because “fuel nitrogen can account for up 

to 80 percent of total NOx from coal combustion,”5

 it should be easier for GGS to achieve 

lower NOx emissions than an EGU burning coal with higher fuel-bound nitrogen. If SCR 

is capable of reducing emissions below NPPD’s target, then the amount of the reductions 

and consequent visibility improvements will increase. 

NPPD’s NOx & SCR costs are overestimated

We applied the procedures described in Section 4, Chapter 2 of the Cost Manual to the 

GGS boilers.6

 Because modern SCR systems are typically designed to achieve 90+% 

NOx reductions, we used 0.05 lb/mmBtu as our target. Using most of the NPPD 

information and estimates, we estimated a Total Annual Cost of $12 million, and 

produced cost-effectiveness estimates of less than $1,000/ton. (Please see Table 3. 

below.) 

 

2

 NPPD has combined these two boilers for its analysis, even though NOx emissions from these boilers 

differ substantially. Separate analyses are preferable. 3

 While it is likely that 30-day rolling average emission rates would be somewhat higher, it is unlikely that 

they would exceed the NPPD target. 

4

 For example, we recently received a proposal from a major SCR vendor to install its system on a wallfired boiler burning PRB coal and reduce NOx emissions to 0.05 lb/mmBtu. 5

 EPA “Compilation of Air Pollutant Emission Factors” (AP-42), section 1.1.3.3. 

6

 Our calculations are contained in the attached Excel workbook and in Appendix B. 
5

Table 3. NPS estimates for SCR at 

NPPD--Gerald Gentleman LNB+SCR burning PRB sub-bituminous 

Unit #1 #2 

Rating (MW Gross) each 665 company report 700 

Rating (mmBtu/hr) 7,538 company report 7,538 

 

Current Emissions (tpy) 13,408 2001 - 2003CAM data 8,894 

Current Emissions (lb/mmBtu) 0.46 2001 - 2003CAM data 0.32 

Current Uncontrolled Emissions (tpy) 13,408 2001 - 2003CAM data 8,894 

Current Control Efficiency 47% calculated 0%

 

NPS Cost-benefit Analysis 

Future Uncontrolled Emissions (tpy) 15,122 company report 15,122 

Controlled Emissions (lb/mmBtu) 0.05 NPS estimate 0.05 

Overall Control Efficiency (FGD) 89% calculated 84%

Controlled emissions (tpy) 1,633 calculated 2,358 

Emission Reductions (tpy) 13,489 calculated 12,764 

Capital Cost $ 44,424,446 NPS estimate $ 44,424,446 

Capital Cost ($/kW) $ 67 calculated $ 63 

O&M Cost $ 2,942,821 NPS estimate $ 2,794,842 

Annualized Cost $ 12,072,668 NPS estimate $ 11,924,689 

Cost-Effectiveness ($/ton) $ 895 NPS estimate $ 934 

We estimate that SCR would improve visibility by 1.21 dv at Badlands NP, but we did 

not have sufficient data to evaluate the cumulative benefits of improving visibility at the 

other Class I areas. 

NOx BART Conclusions:

Use of EPA guidance and data results in cost-effectiveness values for combustion 

modifications plus SCR of less than $1,000/ton. This cost-effectiveness appears 

reasonable, given the magnitude and extent of GGS’ impacts upon visibility. NPPD 

should re-do its SCR analysis in the format presented by the OAQPS Control Cost 

Manual7

 and model the effects on all Class I areas of reducing NOx to 0.05 lb/mmBtu to 

provide the information to develop the “fifth factor” in the BART process. 

SO2 BART8

NPPD has proposed no additional controls for BART for SO2. NPPD estimates that wet 

and dry scrubbers can only achieve 0.15 lb/mmBtu on a 30-day rolling average, and has 

rejected them as too expensive. 

NPPD has underestimated the ability of modern SO2 control systems.

 

7

 It would be very helpful if NPPD would provide vendor quotes and supporting documentation for major 

cost items. 

8

 EPA’s presumptive SO2 BART limit for similar boilers is 95% control or 0.15 lb/mmBtu. 
6

Unlike the retrofittng of NOx controls that is highly dependent upon the existing boiler 

configuration, the SO2 controls that could be added at GGS would be completely new, 

and should therefore be capable of performing as well as at a greenfield facility. 

It is easier to achieve a higher SO2 control efficiency on coals with higher inherent, 

uncontrolled emissions. And, as uncontrolled emissions increase, controlled emissions 

will also tend to increase despite the increasing SO2 control efficiency. It follows that it is 

harder to achieve a higher control efficiency on a gas stream with a lower inlet SO2

concentration, but easier to achieve a lower outlet concentration. So, if one can achieve 

lower emission rate on a “dirtier” gas stream, it would indicate a higher degree of 

scrubbing success. All of this must be considered when determining the level of SO2

control that is feasible for a given coal.9

 

Inspection of Table 4.a. (below) reveals that wet FGD systems are achieving (e.g., 

Navajo Generating Station, Intermountain Power) or being proposed/permitted at 0.04 – 

0.09 lb/mmBtu on coals with much higher uncontrolled emissions than currently seen at 

GGS. Based upon this data and a consideration of GGS’ cleaner coal quality, we believe 

that a new wet FGD at GGS should be able to achieve 0.04 lb/mmBtu10 (or lower) on a 

30-day rolling average. 

Table 4.a. Wet Scrubber SO2 Rankings (30-day rolling averaging period) 

SO2 Coal Quality Capacity 

Emissions 

or 

Limits 

Control 

Facility Name Unit Status Permit 

# %S (Btu/lb) (lb/mmBtu) MW (lb/mmBtu) (%) 

NPPD-GGS 1&2 operating NE 0.30 8576 0.555 1365 0.040 92.8% 

Colstrip 4 operating MT 0.75 8487 1.546 778 0.093 94.4% 

Colstrip 4 operating MT 0.75 8487 1.546 778 0.091 94.5% 

Intermountain 

Pwr 3 issued UT0065 0.75 11193 1.273 950 0.090 92.9% 

Navajo 1 operating AZ 0.53 10919 0.922 803 0.072 92.9% 

Navajo 3 operating AZ 0.53 10919 0.922 803 0.064 93.2% 

Sithe-Desert 

Rock pending EPA 0.82 8910 1.611 1500 0.060 96.3% 

Sithe-Toquop application NV 1.4 8215 2.982 750 0.060 98.0% 

Mustang application NM 1.56 8647 3.157 300 0.060 98.1% 

Intermountain 

Pwr 2 operating UT 0.48 11817 0.772 820 0.059 92.4% 

Navajo 2 operating AZ 0.53 10919 0.922 803 0.044 95.5% 

FPL-Glades application FL 1.98 12324 3.053 2x980 0.040 98.7% 

Taylor application FL 3.46 7475 8.100 800 0.040 99.5% 

 

9

 For the sake of consistency, it is assumed that the SO2 emission factor is dependent upon the coal type, 

but independent of the boiler type. The natural process of retention of sulfur in the ash is just as 

fundamental a characteristic of the coal burned as its sulfur content and its heating value. So, bituminous 

coals would emit 95% of their sulfur content as SO2, while sub-bituminous coals would emit 87.5%, and 

lignites 75%. 

10 For example, EPA has proposed to permit the Desert Rock power plant at 0.06 lb/mmBtu (24-hour 

average) despite coal with almost three times the uncontrolled emissions as at Boardman. 
7

Inspection of Table 4.b. (below) reveals that semi-dry FGD systems are being 

proposed/permitted at 0.06 – 0.09 lb/mmBtu on coals with much higher uncontrolled 

emissions than currently used at GGS. Based upon this data and a consideration of GGS’ 

even cleaner coal quality, we believe that a new semi-dry FGD at GGS should be able to 

achieve 0.06 lb/mmBtu (or lower) on a 30-day rolling average. 

Table 4.b. Dry Scrubber SO2 Rankings (30-day rolling averaging period) 

SO2 Coal Quality Capacity 

Emissions 

or 

Limits 

Control 

Facility Name Unit Status Permit 

# %S (Btu/lb) (lb/mmBtu) MW (lb/mmBtu) (%) 

NPPD-Gerald 

Gentleman 1&2 operating NE 0.30 8576 0.555 1365 0.060 89.2% 

LS Pwr--High 

Plains 1 application CO 0.66 8200 1.409 600 0.090 93.6% 

Black Hills 

Pwr-WYGEN 3 issued WY 1.20 7950 2.642 100 0.090 96.6% 

LS PowerWhite Pine draft permit NV 0.66 8200 1.409 3x530 0.089 93.7% 

Basin Electric--

Dry Fork permit WY 0.47 7800 1.054 385 0.075 92.9% 

Newmont 

Nevada issued NV0036 0.45 8400 0.938 200 0.065 93.1% 

LS PowerWhite Pine draft permit NV 0.3 8200 0.640 3x530 0.065 89.8% 

LS Pwr--High 

Plains 1 application CO 0.46 8200 0.982 600 0.065 93.4% 

Sierra PacificEly application NV 0.8 8100 1.728 2x750 0.060 96.5% 

We have presented information showing that several EGUs are operating at, or have been 

proposed or permitted with much lower SO2 limits than evaluated by NPPD. NPPD 

should evaluate a SO2 limit that reflects the capabilities of modern scrubbers. 

NPPD’s FGD costs are overestimated

Dry Scrubber: NPPD has estimated that it would cost over $2,700/ton to control SO2

using a dry scrubber at GGS. While much of this cost is due to extensive baghouse 

modifications to accommodate the additional particulate generated in the dry scrubber, 

the over-$700 capital cost per kilowatt hour (kWh) appears unusually high, especially 

when compared to the $423/kWh that Great River Energy proposes to spend to add a dry 

scrubber to its Stanton Unit #1 in North Dakota. 
8

Table 5.a. Gerald Gentleman —

NPPD estimates Dry FGD addition burning PRB sub-bituminous 

Unit #1 Source #2 

Rating (MW Gross) each 665 company report 700 

Rating (mmBtu/hr) 7,538 company report 7,538 

 

Current Emissions (tpy) 16,329 2001 - 2003CAM data 15,183 

Current Emissions (lb/mmBtu) 0.57 2001 - 2003CAM data 0.56 

Current Uncontrolled Emissions (tpy) 16,329 2001 - 2003CAM data 15,183 

Current Control Efficiency 0% company report 0%

 

Company Cost-benefit Analysis 

Future Uncontrolled Emissions (tpy) 24,893 company report 24,893 

Controlled Emissions (lb/mmBtu) 0.15 company report 0.15 

Overall Control Efficiency (FGD) 74% calculated 73%

Controlled emissions (tpy) 4,985 calculated 4,985 

Emission Reductions (tpy) 19,908 company report 19,908 

Capital Cost $ 490,796,000 company report $ 490,796,000 

Capital Cost ($/kW) $ 738 calculated $ 701 

O&M Cost 

Annualized Cost $ 54,258,500 company report $ 54,258,500 

Cost-Effectiveness ($/ton) $ 2,726 company report $ 2,726 

Although we were unable to estimate operating costs, and thus total annual costs and 

cost-per-ton, due to a lack of information from NPPD, we were able to estimate capital 

costs based upon Section 5 of the Cost Manual.11

Table 5.b. Gerald Gentleman —

NPS estimates Dry FGD addition burning PRB sub-bituminous 

Unit #1 Source #2 

Rating (MW Gross) each 665 company report 700 

Rating (mmBtu/hr) 7,538 company report 7,538 

 

Current Emissions (tpy) 16,329 2001 - 2003CAM data 15,183 

Current Emissions (lb/mmBtu) 0.57 2001 - 2003CAM data 0.56 

Current Uncontrolled Emissions (tpy) 16,329 2001 - 2003CAM data 15,183 

Current Control Efficiency 0% company report 0%

 

NPS Cost-benefit Analysis 

Future Uncontrolled Emissions (tpy) 24,893 2001 - 2003CAM data 24,893 

Controlled Emissions (lb/mmBtu) 0.06 calculated 0.06 

Overall Control Efficiency (FGD) 90% NPS estimate 90%

Controlled emissions (tpy) 2,489 calculated 2,489 

Emission Reductions (tpy) 22,403 calculated 22,403 

Capital Cost $ 261,514,440 calculated $ 261,514,440 

Capital Cost ($/kW) $ 393 calculated $ 374 

 

11 Our calculations are contained in the attached Excel workbook and in Appendix C. 
9

Even when we include NPPD’s high costs for ductwork, stack, and baghouse 

modifications, our estimates of $374 - $393/kWh appear much more reasonable than 

those of NPPD. 

We estimate that a 90% reduction in SO2 at GGS would improve visibility by 0.88 dv at 

Badlands NP, but we did not have sufficient data to evaluate the cumulative benefits of 

improving visibility at the other Class I areas. 

Wet Scrubber: As shown in Table 6.a. (below), NPPD has estimated that it would cost 

over $2,700/ton to control SO2 using a wet scrubber at GGS. Once again, NPPD 

estimates a capital cost/kWh of over $700. And, again, this appears unusually high, 

especially when compared to the $335 - $496/kWh that Basin Electric Power proposes to 

spend to add wet scrubbers to its Leland Olds Units #1 & #2 in North Dakota. Also in 

North Dakota, Minnkota Power is proposing to add a wet scrubber to its M.R. Young 

Unit #1 at a capital cost of $435/kWh. 

Table 6.a. Gerald Gentleman —

NPPD estimates Wet FGD addition burning PRB sub-bituminous 

Unit #1 Source #2 

Rating (MW Gross) each 665 company report 700 

Rating (mmBtu/hr) 7,538 company report 7,538 

 

Current Emissions (tpy) 16,329 2001 - 2003CAM data 15,183 

Current Emissions (lb/mmBtu) 0.57 2001 - 2003CAM data 0.56 

Current Uncontrolled Emissions (tpy) 16,329 2001 - 2003CAM data 15,183 

Current Control Efficiency 0% company report 0%

 

Company Cost-benefit Analysis 

Future Uncontrolled Emissions (tpy) 24,893 company report 24,893 

Controlled Emissions (lb/mmBtu) 0.15 company report 0.15 

Overall Control Efficiency (FGD) 74% calculated 73%

Controlled emissions (tpy) 4,985 calculated 4,985 

Emission Reductions (tpy) 19,908 company report 19,908 

Capital Cost $ 514,909,500 company report $ 514,909,500 

Capital Cost ($/kW) $ 774 calculated $ 736 

O&M Cost 

Annualized Cost $ 54,225,000 company report $ 54,225,000 

Cost-Effectiveness ($/ton) $ 2,724 company report $ 2,724 

Although we were again unable to estimate operating costs, and thus total annual costs 

and cost-per-ton, due to a lack of information from NPPD, we were able to estimate 

capital costs based upon Section 5 of the Cost Manual.12

 

12 Our calculations are contained in the attached Excel workbook and in Appendix C. 
10

Table 6.b. Gerald Gentleman —

NPS estimates Wet FGD addition burning PRB sub-bituminous 

Unit #1 Source #2 

Rating (MW Gross) each 665 company report 700 

Rating (mmBtu/hr) 7,538 company report 7,538 

 

Current Emissions (tpy) 16,329 2001 - 2003CAM data 15,183 

Current Emissions (lb/mmBtu) 0.57 2001 - 2003CAM data 0.56 

Current Uncontrolled Emissions (tpy) 16,329 2001 - 2003CAM data 15,183 

Current Control Efficiency 0% company report 0%

 

NPS Cost-benefit Analysis 

Future Uncontrolled Emissions (tpy) 24,893 2001 - 2003CAM data 24,893 

Controlled Emissions (lb/mmBtu) 0.04 NPS estimate 0.04 

Overall Control Efficiency (FGD) 93.6% NPS estimate 93.6%

Controlled emissions (tpy) 1,591 NPS estimate 1,591 

Emission Reductions (tpy) 23,302 NPS estimate 23,302 

Capital Cost $ 257,765,112 NPS estimate $ 257,765,112 

Capital Cost ($/kW) $ 388 NPS estimate $ 368 

Our capital cost estimates of $368 - $388/kWh appear much more reasonable than those 

of NPPD. 

We estimate that a 93.6% reduction in SO2 at GGS would improve visibility by 0.91 dv at 

Badlands NP, but we did not have sufficient data to evaluate the cumulative benefits of 

improving visibility at the other Class I areas. 

SO2 BART Conclusions:

Use of EPA guidance and data results in capital cost estimates that are significantly lower 

than those presented by NPPD. NPPD should re-do its scrubbing analyses in the format 

presented by the OAQPS Control Cost Manual13 and model the effects on all Class I 

areas of reducing SO2 to 0.04 – 0.06 lb/mmBtu to provide the information to develop the 

“fifth factor” in the BART process. 

 

13 It would be very helpful if NPPD would provide vendor quotes and supporting documentation for major 

cost items.