### PRELIMINARY COMMENTS:

Background

Nebraska Public Power District (NPPD) opera tes 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 ar eas (Badlands, Wind Cave, and Rocky Mountain National Parks) which are administered by th e 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 % sulf ur; 4.69% ash in 2001). Histor ic 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 rate d at 665 MW (net). Unit #1 is equipped with a fabric filter to cont rol particulate matter (PM 10 

### ). It appears that Low-NO x 

### Burners (LNB) and Over-Fire Air (OFA) were inst alled 2005 – 2006 to reduce nitrogen oxides (NO x 

### ) 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 (SO 2 

### ), 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 rate d at 700 MW (net). Unit #2 is equipped with a fabric filter to control particulate matter (PM 10 

### ). There are no controls for SO 2 

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

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

Modeling analyses have shown that GGS cause s visibility impairment in the Badlands National Park (NP), Wind cave NP, Roc ky 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 fo llowing 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 in creasing, and that this should be taken into ac count in these cost analyses. NPPD appears to have used cost es calation as its rationale to present a mix of costing techniques that borrow from the O AQPS 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. Ho wever, we do not agree that NPPD, or any source, should be able to pick and choos e bits and pieces from among the various methods for estimating pollu tion control costs. The BA RT 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 sim ilar 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 s ource for developing cost analyses that are consistent across the na tion and provide a common means for assessing costs is further supported by this November 7, 2007, statemen t from EPA Region 8 to the North Dakota Department of Health:
The SO 2 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 r eaffirms our comments and that NPPD should revise its cost analyses to reflect a mo re consistent use of the Cost Manual.

Much of NPPD’s argument against installi ng pollution controls at GGS centers on the increasing worldwide costs of po llution 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 busine ss, and that NPPD mu st show why the GGS plant would experience uniquely higher costs for pollution c ontrols than would normally be considered reasonable.

Finally, BART is not necessarily the most co st-effective solution. Inst ead, it represents a broad consideration of technical, econom ic, 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 we ll as the cumulative effects of improving visibility across all of the Cla ss 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 impact s 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 vari ous 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 contributi ng to visibility impairment.

### 3

NO x 

### BART 1



### NPPD has proposed only LNB and OFA as NO x 

### controls (They have already been installed on Unit #1.) to meet the presumptive BART limit.

NPPD has eliminated Selective Non-Cataly tic Reduction (SNCR) from consideration without sufficient justification on the basis that it is not te chnically feasible because of high temperatures measured in a similar boile r. However, it appears from the CAM data plotted in Figure 1.c. that NO x 

### emissions from the two “similar” boilers at GGS are significantly different. We therefore questi on not only NPPD’s assumption that it can eliminate SNCR on the basis of temperature char acteristics at a dist ant 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. (T his same concern applies to the rest of NPPD’s analyses of NO x 

### controls.) Thus NPPD should sh ow, 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 ($/ton) and cost-per-dec iview-improvement ($/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 di d not evaluate the cumulative benefits of improving visibility at th e 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 Efficien cy (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 op tion is the low (75% - 83%) NO x 

### control efficiency assumed for a technolo gy that should be able to achieve 90% control. 2 

### And, NPPD's almost $400/kW capital co st 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 NO x 

### control systems: NPPD estimates that addition of SCR can reduce NO x 

### by 75% - 83% to 0.08 lb/mmBtu. SCR has been retrofitted to many wall-fired eastern PC boile rs that are now achieving 0.05 lb/mmBtu on a 30-day rolling average ba sis. 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 re trofitted with SCR and are achieving annual 3 

### emission rates well below NPPD’s “target” fo r 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 appear s that the majority of those retrofit SCR systems are able to achieve 0.05 lb/mmBtu wh en 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 NO x 

### from coal combustion,” 5 

### it should be easier for GGS to achieve lower NO x 

### 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 NO x 

### & SCR costs are overestimated We applied the procedures described in Sect ion 4, Chapter 2 of the Cost Manual to the GGS boilers. 6 

### Because modern SCR systems are typically designed to achieve 90+% NO x 

### 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 NO
x 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 NO
x 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 visibil ity by 1.21 dv at Badlands NP, but we did not have sufficient data to evaluate the cumu lative benefits of impr oving visibility at the other Class I areas.

NO x 

### BART Conclusions: Use of EPA guidance and data results in cost-effectiveness values for combustion modifications plus SCR of less than $1,00 0/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 Manual 7 

### and model the effects on all Class I areas of reducing NO x 

### to 0.05 lb/mmBtu to provide the information to develop the “fifth factor” in the BART process.

SO 2 

### BART 8



### NPPD has proposed no additiona l controls for BART for SO 2 

### . 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 SO 2 

### 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 SO 2 BART limit for similar boilers is 95% control or 0.15 lb/mmBtu.

### 6

Unlike the retrofittng of NO x 

### controls that is highly dependent upon the existing boiler configuration, the SO 2 

### controls that could be added at GGS would be completely new, and should therefore be capable of performi ng as well as at a greenfield facility.

It is easier to achieve a higher SO 2 

### control efficiency on coals with higher inherent, uncontrolled emissions. And, as uncontrolled emissions increas e, controlled emissions will also tend to increase despite the increasing SO 2 

### control efficiency. It follows that it is harder to achieve a higher control efficien cy on a gas stream with a lower inlet SO 2 

### concentration, but easier to achieve a lower ou tlet concentration. S o, if one can achieve lower emission rate on a “dirtier” gas st ream, it would indicate a higher degree of scrubbing success. All of this must be cons idered when determining the level of SO 2 

### control that is feasib le for a given coal. 9



### Inspection of Table 4.a. (b elow) reveals that wet FGD systems are achieving (e.g., Navajo Generating Station, Intermountain Po wer) or being proposed/permitted at 0.04 – 0.09 lb/mmBtu on coals with much higher uncontro lled 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/mmBtu 10 

### (or lower) on a 30-day rolling average.

Table 4.a. Wet Scrubber SO 2 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 SO 2 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 SO 2 , while sub-bituminous coals would emit 87.5%, and lignites 75%.

10 For example, EPA has proposed to permit the Dese rt Rock power plant at 0.06 lb/mmBtu (24-hour average) despite coal with al most three times the uncontrolle d 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 Ranking s (30-day rolling ave raging 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 se veral EGUs are operating at, or have been proposed or permitted with much lower SO 2 

### limits than evaluated by NPPD. NPPD should evaluate a SO 2 

### limit that reflects the capabilities of modern scrubbers.

NPPD’s FGD costs are overestimated

Dry Scrubber: NPPD has estimated that it w ould cost over $2,700/ton to control SO 2 

### 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 Ri ver 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 fr om 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 co sts 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 SO 2 

### at GGS would improve visibility by 0.88 dv at Badlands NP, but we did not have sufficient da ta to evaluate the cumulative benefits of improving visibility at th e other Class I areas.

Wet Scrubber: As shown in Table 6.a. (below), N PPD has estimated that it would cost over $2,700/ton to control SO 2 

### 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 Ol ds Units #1 & #2 in North Dakota. Also in North Dakota, Minnkota Power is proposing to add a wet sc rubber 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 oper ating costs, and thus total annual costs and cost-per-ton, due to a lack of informa tion from NPPD, we were able to estimate capital costs based upon Sec tion 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 (F GD) 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 SO 2 

### at GGS would improve visibility by 0.91 dv at Badlands NP, but we did not have sufficient da ta to evaluate the cumulative benefits of improving visibility at th e other Class I areas.

SO 2 

### BART Conclusions: Use of EPA guidance and data re sults 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 Manual 13 

### and model the effects on all Class I areas of reducing SO 2 

### 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.