**PRELIMINARY COMMENTS:**

**Background** Nebraska Public Power District (NPPD) operates the Gerald Gentleman Station ( GGS ), which includes two Electric Generating Unit s (EGU s ), near Sutherland , NE
. The plant is located within 4 00 km of three Class Iareas (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% a sh in 20 01 )
. 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 (PM 10 )
. Ita ppears that Low -NO x Burners (LNB) and Over
- Fire Air (OFA) were installed 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 ye ar (tpy) to about 0.2 lb/mmBtu and about 6,000 tpy
. There are no controls for sulfur dioxide (SO 2 ) , which ty

pically i s emitted at 0.5

– 0.6 pounds per million Btu (lb/mmBtu) and 14,000

– 16,000 tons per year (tp y)
. Unit #2 is a dry

-bottom, wall

- fired boiler rated at 70 0 MW (net). Unit #2 is equipped with a fabric filter to control particulate matter (PM 10 )
. There are no controls for SO 2 , which ty picall y is emitted at 0.5

– 0.6 lb/mmBtu and 14,000

– 16,000 tpy . There are no controls for NO x , which typicall y is emitted at 0. 30

– 0. 35 lb/mmBtu and 8 ,000

– 1 0 ,000 tpy
. Modeling anal ys es have shown that GGS causes visibility impairment in the Badlands National Park (NP ) , Wind cave NP, Rocky M ountain 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 anal ys es 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 anal ys es. NPPD appears to have used cost escal ation 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 cost s. The BART anal ys is is based upon2

judgments as to the reasonableness of costs and benefits of reducing emissions from a specific source relative to costs born by s imilar 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 consis tency, cost estimates should be based on the OAQPS Contro l Cost Manual, where possible. NPPD should follow this guidance. Our contention that the Cost Manual should be the primary s ource for developing cost anal ys es 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 SO 2 and PM cost analyses were com pleted using the CUECost mo del. 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 anal ys es 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 p ollution control equipment that involve s 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 necessaril y 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. Its imply 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

s ignificantly

impaired. I f 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 explaine d 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

**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
- Catal ytic Reduction (SNCR) from consideration without sufficient justification on the basis that it is not technically f easible because of high temperatures measured in a similar boiler. However, it appears from the CAM data plotted in Figure 1.c. that NO x emissions from the two “similar” boilers at GGS are significantl y different. We therefore question not only NPP D’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 c an be evaluated in combination, not individually
. (This same concern applies to the rest of NPPD’s analyses of NO x controls.) Thu s NPPD should show , with data specific to the GG S boilers , that this is the case at the GG S facility also. NPPD rejected Selective Cataly tic 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 b y 1. 15 dv at Badlands NP
. NPPD did not evaluate the cumulative benefit s of improving visibility

at the other Class I areas. **Table 1. Nebraska Public Power** **-- Gerald Gentleman** 

**— NPPD estim** **ates LNB+SCR burning PRB sub**  **- bituminous**  Unit #1 Source #2 Rating (MW Net) each 665 company report 700 Rating (mmBtu/hr) 7,538 company rep ort 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 20 01
- 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 %) NO x control efficiency

a ssumed 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 NO x control s ystems: 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 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 C lean Air M arkets (CAM) database of boilers similar to those at GGS that have been retrofitted with SCR and are achieving annual 3 emission rates well below NPPD’s “target” for SCR. We were able to find 2006 hourl y emissions in EPA’s CAM database for 14 of those EGUs, and charts showing those emissions are included in Appendix A. Ita ppears that the majority

o f those retrofit SCR systems are able to achieve 0.05 lb/mmBtu when in use during the eastern ozone season. 4 It is likel y 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 Secti on 4, Chapter 2 of the Cost Manual to the GGS boilers. 6 Because modern SCR systems are ty pically 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 $1 2 million, and produced cost- effectiveness estimates of less than $ 1 ,000/ton. (Please s ee T able 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 wo uld exceed the NPPD target. 4 For example, we recently received a proposal from a major SCR vendor to install its system on a wall

fired 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 2,35 8 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 b y 1.2 1 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. NO x BART Conclusions : Use of EPA guidance and data results in cost- effectiveness value s 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 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 additional controls for BART for SO 2 . NPPD estimates that wet and dry s crubbers 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 b e 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 coul d be added at GGS would be completely n ew, and should therefore be capable of performing 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 uncontrol led emissions increase, 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 efficiency o n a gas stream with a lower inlet SO 2 concentration, but easier to achieve a lower outlet concentration. S o, 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 SO 2 control that is feasible fo r 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/mmBtu 10 (or lower) on a 30
- day rolling average. **Table 4.a. Wet Scrubber SO 2**  **Rankings (30 -**  **da y 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 UT
0065 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 80 3 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

c onsistency, it is assumed that the SO 2 emissio n factor is dependent upon the coal ty pe, but independent of the boiler ty pe. 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 wo uld emit 95% of their sulfur content as SO 2 , while sub

-bituminous coals wo uld emit 87.5%, and li gnites 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 F GD system s are being proposed/permitted at 0.06

– 0. 09 lb/mmBtu on coals with much higher uncontrolled emissions than currentl y used at GGS. Based upon this data and a consideration of GGS’ even cleaner coal quality, we believe that a new semi

- dry F GD at GGS should be able to achieve 0.0 6 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 Power
White 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 NV
0036 0.45 8400 0.938 200 0.065 93.1% LS Power
White Pine draft permit NV 0.3 8200 0.640 3x53 0 0.065 89.8% LS Pwr
-- High Plains 1 application CO 0.46 8200 0.982 600 0.065 93.4% Sierra Pacific

Ely application NV 0.8 8100 1.728 2x750 0.060 96.5% W e have presented information showing that several EGUs are operating at, or have been proposed or p ermitted 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 would cost over $2,700/ton to control SO 2 using a dry

s crubber at GGS. While much of this cost is due to extensive baghouse modifications to accommodate the additional particulate generated in the dry s crubber, the over- $700 capital cost per kilowatt hour (kWh) appears unusually high, esp eciall y 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 Gentle**  **ma n**  **— NPPD estim** **ates 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 Unco ntrolled 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 $3 74
- $3 93 /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 .8 8 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 contro l 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, especiall y when compared to the $335

- $4 96/kWh that Basin Electric Power proposes to spend to add wet scrubbers to its Leland Olds Unit s #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 Gentle**  **ma n**  **— NPPD estim** **ates Wet FGD addition burning PRB sub**  **- bitumi**  **nous** 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 Emi ssions (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 -**  **ben efit 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 op erating 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 Co st** **- 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 SO 2 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. SO 2 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 s crubbing anal ys e s 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 0.0 4

– 0. 0 6 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.