Comments on Proposed BART Permits for Nebraska Public Power District (NPPD)

Gerald Gentleman Station (GGS) Units #1 and #2

January 14, 2011

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

which includes two Electric Generating Units (EGUs), near Sutherland, NE. 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). EPA’s Clean Air 

Markets (CAM) database shows that, in 2009, GGS ranked #48 (of 1,230 facilities) in 

SO2 emissions at 31,931 tons, and ranked #20 in NOX emissions at 14,987 tons. The 

useful remaining life of GGS Units 1 and 2 is greater than 20 years under the current 

NPPD energy resource plan. Therefore the remaining useful life has no impact on the 

annualized estimated control technology cost at this time.

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.

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

National Park (NP) @ 2.9 deciviews (dV) three-year average 98th percentile impact, 

Wind Cave NP (2.5 dV), Rocky Mountain NP (1.1 dV), and Wichita Mountains 

Wilderness (1.2 dV). GGS also contributes to visibility impairment at the Hercules 

Glades (0.7 dV) and Mingo (0.5 dV) Class I Wilderness areas. The cumulative impact of 

GGS on visibility is 9.3 dV. 

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 0.22 lb/mmBtu and about 5,000 - 6,000 tpy.1 There are no controls for 

sulfur dioxide (SO2), which typically is emitted at 0.5 – 0.6 lb/mmBtu and 14,000 –

17,000 tpy. CAM data show that, in 2009, GGS Unit 1 ranked #82 (of 3,563 units) in SO2

emissions at 15,805 tons, and ranked #57 in NOX emissions at 5,446 tons.

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 – 17,000 tpy. There are no controls 

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

CAM data show that, in 2009, GGS Unit 2 ranked #80 (of 3,563 units) in SO2 emissions

at 16,125 tons, and ranked #11 in NOX emissions at 9,540 tons.

 

1 According to NDEQ, ―On January 4, 2006, the Department received a PSD Construction Permit 

application for the replacement of Unit 1’s burner equipment system including an overfire air port system. 

NPPD installed new Low NOx Burners (LNB) on Unit 1 because the existing burners were near the end of 

their useful life and to be pro-active in installing expected Best Available Retrofit Technology (BART) 

controls. A PSD construction permit was issued to GGS for the installation of the LNB on Unit 1 on 

August 18, 2006. A PSD permit was required for the modification due to the expected increase in carbon 

monoxide emissions as a result of the LNB installation.‖
2

In August of 2008 we filed comments regarding NPPD’s BART analyses. We are 

updating our comments to reflect new information obtained since 2008.

BART Analyses

As noted by NPPD, the five basic steps of a case-by-case BART analysis are:

1. Identify All Available Retrofit Control Technologies. Control technologies should 

include pollution prevention, use of add-on controls and combinations of the two.

2. Eliminate Technically Infeasible Options. Technologies demonstrated to be infeasible 

based on chemical, physical, and engineering principles are excluded from further 

consideration.

3. Evaluate Control Effectiveness of Remaining Control Technologies. Technically 

feasible control technologies are ranked in the order of highest expected emission 

reduction to lowest expected emission reduction and are evaluated following a ―topdown‖ approach similar to BACT analyses.

4. Evaluate Impacts and Document Results. Impacts that should be considered for each 

control technology include: cost of compliance, energy impacts, non-air quality 

environmental impacts, and the remaining useful life of the unit to be controlled.

5. Evaluate Visibility Impacts. Modeling should be performed on the pre- and postcontrol emissions to determine the actual impact on visibility and assess the visibility 

improvement achieved and at what cost. This step does not need to be performed if the 

most stringent control technology is chosen.

However, before we begin a step-by-step discussion of the BART proposed for GGS for each 

pollutant, we provide some general comments.

Cost-Effectiveness Metrics

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. For example, Oregon DEQ has established a cost/ton threshold of 

$7,300 based upon the premise that improving visibility in multiple Class I areas warrants 

a higher cost/ton than where only one Class I area is affected. In their BART proposal for 

the San Juan Generating Station, New Mexico used a range from $5,946/ton to 

$7,398/ton. Colorado uses $5,000/ton, New York uses $5,500/ton, and Wisconsin is 

using $7,000 - $10,000/ton as its BART threshold.2

One of the options suggested by the BART Guidelines to evaluate cost-effectiveness is 

cost/deciview. We believe that visibility improvement must be a critical factor in any 

program designed to improve visibility. Compared to the typical control cost analysis in 

which estimates fall into the range of $2,000 - $10,000 per ton of pollutant removed, 

 

2

―The Department used cost-per-ton reduced as the primary metric for determining the BART level of 

control. The upper limit for this metric was $7,000 to $10,000 per ton, which reflects historical low-end 

costs for controls required under BACT.‖ BEST AVAILABLE RETROFIT TECHNOLOGY AT NONEGU FACILITIES April 19, 2010, WISCONSIN DEPARTMENT OF NATURAL RESOURCES
3

spending millions of dollars per deciview (dv) to improve visibility may appear 

extraordinarily expensive. However, our compilation3of BART analyses across the U.S. 

reveals that the average cost per dv proposed by either a state or a BART source is 

$14 - $18 million,

4 with a maximum of $51 million per dv proposed by South Dakota at 

the Big Stone power plant. (For example, we note that OR DEQ has explicitly chosen 

$10 million/dv as a cost criterion, which is somewhat below the national average.)

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. 

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

then-increasing worldwide costs of pollution controls in general; that is no longer true. 

According to a report prepared for the Utility Air Regulatory Group:5

The recent moderation in the world economy has removed many of the supply barriers and eased 

cost escalation. The cost to retrofit FGD and SCR equipment is expected to moderate from peak 

levels observed in the last 24 months, but may not significantly decline. A key reason is the everincreasing complexity of the host sites. As host units are older and of smaller generating capacity, 

there is less available space for control equipment. Frequently, convoluted and complex ductwork 

is required, increasing retrofit difficulty.

While the concern about complex retrofits may be true for eastern EGUs where the capand-trade programs allowed utilities to control the easiest and most cost-effective retrofits 

first, and leave the more complex retrofits for later (or never), no such ―natural selection‖ 

process exists in Nebraska. There is no reason to believe that Gerald Gentleman would 

be an especially difficult retrofit.

Furthermore, if the NPPD cost argument were 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 GGS 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.

 

3

http://www.wrapair.org/forums/ssjf/bart.html

4

For example, PacifiCorp has stated in its BART analysis for its Bridger Unit #2 that ―The incremental 

cost effectiveness for Scenario 1 compared with the baseline for the Bridger WA, for example, is 

reasonable at $580,000 per day and $18.5 million per deciview.‖

5

J.E. Chichanowicz Report ―Current Capital Cost and Cost Effectiveness‖ - January 2010
4

Cost Estimation Methods

The cost estimates submitted by NPPD are severely lacking in the types of specific 

information needed to give them credibility. Although there are several methods for 

estimating costs, our experience leads us to believe that no one method is perfect and that 

the costing methods need to be tempered by real-world data. And, while NDEQ states 

that ―NPPD used vendor quotes for the majority of the analysis,‖ we found no documented actual 

vendor quotes in the materials made available for our review.6In that case, the BART 

Guidelines recommend use of the OAQPS Control Cost Manual: 

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, Fifth Edition, February 1996, 453/B-96-001). In order to maintain and 

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

possible. The Control Cost Manual addresses most control technologies in sufficient detail for a 

BART analysis. The cost analysis should also take into account any site-specific design or other 

conditions identified above that affect the cost of a particular BART technology option.

Cost Escalation

NPPD included an escalation component in its cost estimates. Larry Sorrels, an 

economist at EPA’s Office of Air Quality Planning and Standards (OAQPS) commented7

upon use escalation factors to calculate the levelized cost of each technology.

Estimating real annual costs means no use of escalation factors...

It is not appropriate to escalate costs into the future and compare them against current 

cost thresholds.

Inflation and the Allowance for Funds During Construction:

Mr. Sorrels also provided8insight on matters pertaining to inflation and the Allowance 

for Funds During Construction (AFUDC):

On cost indexes, I prefer the CEPCI (Chemical Engineering Plant Cost Index) for 

escalating/deescalating costs for chemical plant and utility processes since this index specifically 

covers cost items that's pertinent to pollution control equipment (materials, construction labor, 

structural support, engineering & supervision, etc.). The Marshall & Swift cost index is useful for 

industry-level cost estimation, but is not as accurate at a disaggregated level when compared to the 

CEPCI. Thus, I recommend use of the CEPCI as a cost index where possible.

I agree with including AFUDC in a capital cost estimate if this is already included in the base case 

as per a utility commission decision. Otherwise, I do not agree with its inclusion.

The CEPCI has declined since the NPPD analysis (see chart below)

 

6 The NPPD BART analysis contained such general statements as ―Equipment costs were developed based 

on vendor budgetary quotes‖ and ―Major equipment costs were based on vendor budgetary quotes.‖ NDEQ 

refers to the ―2008 S&L NPPD Study‖ but we were not provided a copy.

7 E-mail dated September 7, 2010 to Don Shepherd of NPS.

8

7/21/10 e-mail to Don Shepherd
5

and, as we will show later, NPPD included AFUDC costs that amount to scores of 

millions of dollars.

Annual Costs

The Direct Annual Cost (DAC) component of the process is also important because it 

represents a significant portion of the Total Annual Cost. The methods presented by the 

Cost Manual for estimating DAC appear to be straight-forward and should accurately 

represent annual costs with no need for adjustment. However, we note in our review of 

the BART analyses presented by NPPD that there appears to be a consistent 

significant overestimation of DAC.

Visibility Improvement Metrics

NDEQ considered visibility improvements at Badlands NP, but effectively ignored 

potential improvements to visibility in the other Class I areas where GGS is also causing 

or contributing to visibility impairment. 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. It follows 
6

that, if emission from the BART source are reduced, the benefits will be spread well 

beyond only the most impacted Class I area, and this must be accounted for.9 While 

NDEQ presented data describing improvements to visibility at Badlands NP that would 

result from the various control scenarios it investigated, NDEQ still has not explained 

how it incorporated this information on impacts upon all Class I areas into its BART 

decision. 

The BART Guidelines represent an attempt to create a workable approach to estimating 

visibility impairment. As such, they require several assumptions, simplifications, and 

shortcuts about when visibility is impaired in a Class I area, and how much impairment is 

occurring. The Guidelines do not attempt to address the geographic extent of the 

impairment, but assume that all Class I areas are created equal, and that there is no 

difference between widespread impacts in a large Class I area and isolated impacts in a 

small Class I area. To address the problem of geographic extent, we have been looking at 

the cumulative impacts of a source on all Class I areas affected, as well as the cumulative 

benefits from reducing emissions. While there are certainly more sophisticated 

approaches to this problem, we believe that this is the most practical, especially when 

considering the modeling techniques and information available. For example, we 

understand that the Oregon Department of Environmental Quality used a similar 

approach in its analyses when it evaluated the benefits of various control strategies on all 

14 of the Class I areas within 300 km of the Boardman power plant. 

Average versus Incremental Cost-Effectiveness

Contrary to EPA guidance to consider both average and incremental cost-effectiveness, 

NDEQ appears to have relied excessively upon incremental costs and benefits when 

moving from a lower level of emission control to a higher level. Although NDEQ 

calculated the average costs of scrubbing SO2 and concluded they were ―reasonable,‖ it 

reported only the incremental costs and benefits in the body of its SIP analysis. NDEQ’s 

treatment of Selective catalytic reduction (SCR) is more troubling. While NDEQ 

correctly asserts that:

Although SCR is a feasible control technology, it would be most practical to install SCR in 

combination with combustion controls...Therefore, the cost associated with installing LNB/OFA 

is linked to this control technology throughout the analysis.

NDEQ goes on to reject addition of SCR to LNB/OFA on the basis of excessive 

incremental costs and without estimating average cost-effectiveness of ―SCR in 

combination with combustion controls‖:

The NDEQ determined that the incremental cost for the addition of SCR is excessive and that 

LNB/OFA would be required for BART.

We believe that NDEQ must evaluate the cost-effectiveness of ―SCR in combination with 

combustion controls‖ as it had recommended.

 

9

For example, the cumulative benefits have been a factor in the BART determinations by NM, OR, and 

WY, as well as EPA in its proposals for the Navajo Generating Station and the Four Corners Power Plant.
7

BART for Sulfur Dioxide (SO2)

Step 1: Identify All Available Retrofit Control Technologies and Step 2: Eliminate Technically 

Infeasible Options.

NPPD presented the following options and feasibility determinations:

Coal Desulfurization Infeasible - not demonstrated for low-sulfur PRB coal

Pahlman Process Infeasible - not demonstrated on large coal-fired boilers

Other Regenerative Processes Infeasible – none have been demonstrated on large coal-fired 

boilers

Wet Scrubbing Feasible based on demonstrated performance on many similar 

units

Dry Scrubbing Feasible based on demonstrated performance on many similar 

units

NPPD and NDEQ erred by not considering Dry Sorbent Injection (DSI), which uses no 

water. ―Dry sorbent duct injection is a means for utility and large boiler operators to 

reduce emissions of sulfur oxides. The effectiveness of dry sorbent injection is dependent 

on the type of sorbent, injection location, and system operating parameters...For higher 

removal requirements (greater than 50%), either trona or sodium bicarbonate is 

recommended. For systems equipped with baghouses (like GGS), trona is the more costeffective sorbent since the residence time provided by the baghouse allows for this lower 

cost sorbent to be used.‖10

EPA states11 that DSI can achieve up to 80% control efficiency. (While EPA also notes 

that DSI is an emerging technology for medium-to-small industrial boilers, that is 

because larger boilers typically are required to install the more-efficient wet or dry 

scrubbing systems.) For example, Nalco-Mobotec advertises that its DSI systems can 

achieve 50% - 80% SO2 control.

Oregon Department of Environmental Quality (ODEQ) is requiring DSI as BART for the 

Boardman Power Plant. According to ODEQ, “Dry sorbent injection is considered to meet 

the BART requirements because it is cost effective and will provide significant visibility 

improvement (>0.5 dV) in at least the Mt. Hood wilderness 12area. Based on installations on 

smaller boilers, DSI can achieve emission reductions of 30 to 70%. Considering the size of 

the Boardman unit (duct geometry and exhaust gas flow), a DSI system may perform in the 

lower range of the control effectiveness, but the effectiveness could be improved with 

additional operating experience. Therefore, DEQ proposes a limit of 0.40 lb/MMBtu (35% 

emission reduction) in 2014 to satisfy the BART requirements. The limit is lowered to 0.30 

lb/MMBtu (51% emission reduction) in 2018. The limit in 2018 could be met by further 

refinements to the DSI system or in combination with ultra-low sulfur coal or supplemental 

fuels, such as biomass.‖ (Please note that the Boardman EGU uses an electrostatic 

 

10 Jon Norman, P.E., James R. Paye, Keith Day, O’BRIEN & GERE ENGINEERS, INC. ―DECISION 

MATRIX FOR DRY SORBENT DUCT INJECTION FOR CONTROL OF SULFUR OXIDE 

EMISSIONS FROM COMBUSTION PROCESSES‖ Paper # 6

11 Air Pollution Control Technology Fact Sheet EPA-452/F-03-034

12 Addendum to the DEQ BART Report for the Boardman Power Plant (November 30, 2010)
8

precipitator to control particulate (PM) emissions, which decreases the effectiveness of DSI 

versus a baghouse like GGS.)

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies

NDEQ has underestimated the ability of modern SO2 control systems. NDEQ effectively 

assumed that wet and dry scrubbing could achieve only 80% - 87% SO2 control down to 

0.1 - 0.15 lb/mmBtu. It appears that NDEQ evaluated scrubbing at both 0.15 lb/mmBtu 

and 0.1 lb/mmBtu, but provides no information on how those analyses were conducted.

Unlike the retrofitting 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.13

Inspection of Table 1.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/mmBtu14 (or lower) on a 

30-day rolling average.

Table 1.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

(Proposed) 1&2 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%

 

13 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%.

14 For example, EPA 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 GGS.
9

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%

Inspection of Table 1.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 1.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

(Proposed)

1&2 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 call attention to the permit issued by Nevada to Newmont Nevada requiring its dry 

scrubber to meet the following limits on very low-sulfur coal:

Section V. Specific Operating Conditions (continued)

A. Emission Unit #S2.001 - Pulverized Coal Fired Boiler (continued)

2. NAC 445B.3405

a. Emission Limits (continued)

(7) Article 8.2.1.2 Federally Enforceable SIP - The discharge of sulfur to the atmosphere 

will not exceed 1,218.0 pounds per hour.

(8) NAC 445B.305 BACT Emission Limit – The discharge of SO2 to the atmosphere will 

not exceed:

(i) While combusting coal with a Sulfur content equal to or greater than 0.45 percent (30-

day rolling period), based on daily ASTM sampling:
10

(a) 0.09 pound per million Btu, based on a 24-hour rolling average period.

(b) 95% minimum SO2 removal efficiency will be maintained across the system, based on 

a 30-day rolling period.

(ii) While combusting coal with a Sulfur content less than 0.45 percent (30-day rolling 

period), based on daily ASTM sampling:

(a) 0.065 pound per million Btu, based on a 24-hour rolling average period.

(b) 91% minimum SO2 removal efficiency will be maintained across the system, based on 

a 30-day rolling period.

The Newmont Nevada permit indicates that a modern dry scrubber can achieve greater 

than the 80% maximum assumed by NPPD and NDEQ, even on low-sulfur coals.

In its ―response to Comments,‖ NDEQ appears to contend that, because some EGUs are 

not achieving the low SO2 limits we suggest here, that GGS should not be expected to do 

so, either. We remind NDEQ that BART requires ―Best Available Retrofit Technology,‖ 

not ―Average or Worst Available Retrofit Technology.‖

Step 4: Evaluate Impacts and Document Results.

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 (Table 2.a). 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.

Table 2.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 

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%

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 

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 industry data15 which lead to an estimated Capital Cost of $280 -

 

15 J.E. Cichanowicz ―Overview of Information on Project Control Technology Costs‖ October 2010
11

$420/kW. (For a 700 MW EGU like GGS 1 & 2, Capital Cost should be $200 - $300 

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

modifications, our previous estimates of $374 - $393/kW appear much more reasonable 

than those of NPPD. It is likely that the $700+/kW capital cost estimates from NPPD 

were the highly influenced by the improper inclusion of over $120 million in 

―Escalation‖ costs and over $83 million in AFUDC costs. We also question a 

―Contingency‖ cost of over $149 million (15%) of a $987 million total; this is five times 

higher than the 3% contingency expense estimated by the Cost Manual. 

Because the NPPD capital costs estimates were higher than we expected, we applied the 

Cost Manual methods to the NPPD cost analyses and our ―adjusted‖ results are presented 

Table 2.b. below:

Table 2.b. Spray-Dry FGD at 0.15 lb/mmBtu

Dry FGD Cost Components NPPD* NPS**

Direct Capital Cost $ 575,827,000 $ 575,827,000 

Indirect $ 47,452,000 $ 16,608,200 

Escalation $ 120,449,000 $ - 

Sales/Use Tax $ 11,077,000 $ 11,077,000 

Contingency $ 148,745,000 $ 17,274,810 

AFUDC $ 83,302,000 $ - 

Total Capital Cost $ 986,852,000 $ 620,787,010 

Total Capital Cost/kW $ 723 $ 455 

Capital Recovery Factor 0.0944

Levelized Capital Cost (w/ fan sized for FGD only) $ 80,013,000 $ 58,597,902 

Levelized O&M Cost $ 27,806,000 $ 27,806,000 

Levelized Outage Cost $ 698,000 $ 698,000 

Total Levelized Capital, Outage and O&M Cost $ 108,517,000 $ 87,101,902 

Tons SOx removed 40,426 40,426

Dry FGD cost-effectiveness ($/ton) $ 2,684 $ 2,155 

*DRY FGD AND ID FAN & AUXILIARY POWER CONCEPTUAL DESIGN COSTS

**Based upon OAQPS Control Cost Manual

If the Escalation and AFUDC costs were eliminated, and the Contingency cost were 

adjusted to the recommended 3%, the resulting $366 million reduction in dry scrubber 

costs would bring the Total Capital Cost down to a more realistic $455/kW. Using the 

NPPD O&M costs and SO2 removal estimates in conjunction with our lower annual 

capital cost results in a cost-effectiveness of less than $2,200/ton.

Wet Scrubber: As shown in Table 3.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.
12

Table 3.a. GGS —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 

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%

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 

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

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

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 industry data16 which lead to an estimated Capital Cost of $370 -

$460/kW. (For a 700 MW EGU like GGS 1 & 2, Capital Cost should be $250 - $330 

million.) Our previous capital cost estimates of $368 - $388/kWh appear much more 

reasonable than those of NPPD.

It is likely that the $700+/kW capital cost estimates from NPPD were the highly 

influenced by the improper inclusion of over $120 million in ―Escalation‖ costs and over 

$83 million in AFUDC costs. We also question a ―Contingency‖ cost of over $149 

million (15%) of a $987 million total; this is five times higher than the 3% contingency 

expense estimated by the Cost Manual. 

Because the NPPD capital costs estimates were higher than we expected, we applied the 

Cost Manual methods to the NPPD cost analyses and our ―adjusted‖ results are presented 

Table 3.b. below:

Table 3.b. Wet FGD at 0.15 lb/mmBtu

Wet FGD Cost Components NPPD* NPS**

Direct Capital Cost $ 597,727,000 $ 597,727,000 

Indirect $ 51,963,000 $ 18,187,050 

Escalation $ 126,848,000 $ - 

Sales/Use Tax $ 14,634,000 $ 14,634,000 

Contingency $ 155,308,000 $ 17,931,810 

AFUDC $ 88,599,000 $ - 

Total Capital Cost $ 1,035,079,000 $ 648,479,860 

Total Capital Cost/kW $ 758 $ 475 

Capital Recovery Factor 0.0944

Levelized Capital Cost (w/ fan sized for FGD only) $ 83,965,000 $ 61,211,911 

Levelized O&M Cost $ 24,485,000 $ 24,485,000 

Levelized Outage Cost $ - $ - 

Total Levelized Capital, Outage and O&M Cost $ 108,450,000 $ 85,696,911 

 

16 J.E. Cichanowicz ―Overview of Information on Project Control Technology Costs‖ October 2010
13

Tons SOx removed 41,338 41,338

Wet FGD cost-effectiveness ($/ton) $ 2,623 $ 2,073 

*WET FGD AND ID FAN & AUXILIARY POWER CONCEPTUAL DESIGN COSTS

**Based upon OAQPS Control Cost Manual

If the Escalation and AFUDC costs were eliminated, and the Contingency cost were 

adjusted to the recommended 3%, the resulting $387 million reduction in wet scrubber 

costs would bring the Total Capital Cost down to a more realistic $475/kW. Using the 

NPPD O&M costs and SO2 removal estimates in conjunction with our lower annual 

capital cost results in a cost-effectiveness of less than $2,100/ton.

Step 5: Evaluate Visibility Impacts.

NDEQ estimates that reducing SO2 emissions to 0.15 lb/mmBtu would improve visibility 

at Badlands NP (the only Class I area for which improvements was provided) by 0.785 

dV, and by 0.845 dV at 0.10 lb/mmBtu, but we did not have sufficient data to evaluate 

the cumulative benefits of improving visibility at the other Class I areas. If the scrubbers 

achieved the lower emission rates that we believe are reasonable, then the visibility 

benefits would increase.

BART Determination for SO2

NDEQ: Scrubber technology is a technically feasible SO2 retrofit technology that could 

be implemented on GGS Units 1 and 2. Not taking the other environmental effects, 

except energy, into account, the average cost effectiveness of using scrubbing control 

technology is approximately $2,500 – $2,700 per ton SO2 removed. The cost per ton 

removed seems reasonable. When evaluating the cost effectiveness in terms of the 

visibility benefit derived from scrubbing, the NDEQ assessed the average incremental 

visibility impairment improvement. The NDEQ also calculated the incremental cost per 

day of visibility improvement.

Over the three years of meteorology modeled, at 0.10 lb SO2/MMBtu, the average 

incremental visibility impairment improvement cost is $132,816,547 per year per change 

in deciview impact. The average number of days the Badlands would expect to 

experience a contribution from GGS of greater than 0.5 dV would be 22 per year. This is 

a 39% reduction in the 56 days per year that the units contribute more than 0.5 dV. The 

average incremental cost per day of visibility improvement calculates to be $4,870,860 

per day ($2,435,430 per unit).

Again, these values do not account for the added costs that would be incurred from other 

environmental impacts, except energy. These values are of the same magnitude as the 

OPPD Nebraska City Unit 1 BART evaluation. There, NDEQ determined that additional 

SO2 controls were not reasonable, in part due to the excessive cost per benefit in terms of 

visibility improvement (i.e., $/yr/dV).

Here in the case of NPPD GGS Units 1 and 2, NDEQ has serious concerns over the 

current availability of water to supply the scrubber and the potential effects of the 
14

depletion of water on threatened and endangered species in the Platte River Valley area. 

Since the incremental visibility impairment improvement cost is so large compared to 

similar improvements in visibility using LNB/OFA technology and most importantly,17

the potential for other serious environmental impacts, the NDEQ has determined that it is 

inappropriate to require the installation of SO2 scrubbing technology as BART at this 

time. NPPD shall instead continue to utilize low sulfur coal. However, additional SO2

controls may be required in the future for purposes of ―reasonable further progress.‖ At 

that time, available control technologies would be evaluated, as well as water availability, 

whether water availability can reasonably be resolved, and the ability to mitigate 

potential threats to endangered species in the Platte River Valley area.

The costs to transport water increased the total annualized cost associated with the 

installation of Wet FGD at GGS to $2,108,450,000. The average cost effectiveness of this 

control technology is $52,956 per ton SO2 removed ($2,108,450,000 / 39,815 tons SO2 

removed) based on an emissions rate of 0.15 lb/MMBtu. The average cost effectiveness 

of this control technology at an emissions rate of 0.1 lb/MMBtu is approximately $48,877 

per ton SO2 removed ($2,108,450,000/43,138 tons SO2 removed).

The NDEQ determined that the costs to transport water made scrubbing costs prohibitive 

for NPPD as a BART SO2 measure.

NPS SO2 BART Conclusions:

NPPD and NDEQ erred by not considering Dry Sorbent Injection (DSI), which uses no 

water.

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 NDEQ. NDEQ

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

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 Manual18 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.

NOx BART19

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

these boilers differ substantially.20 We continue to believe that separate analyses are 

 

17 How is LNB/OFA relevant to SO2 scrubbers and water?

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

cost items.

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

20 In response to our previous comment on this issue, NDEQ replied that ―The temperature issue was 

discussed with NPPD. The two units are different and could not be evaluated in combination.‖
15

necessary. NDEQ has proposed only LNB and OFA as NOx controls (They have already 

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

Step 1: Identify All Available Retrofit Control Technologies and Step 2: Eliminate Technically 

Infeasible Options.

NDEQ 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 

that NOx emissions from the two boilers at GGS are significantly different. Therefore, 

we question not only NDEQ’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 each of the GGS boilers, that this is the case at the 

GGS facility also. However, in response to our previous comment on this issue, NDEQ 

replied that ―The temperature issue was discussed with NPPD. The two units are different 

and could not be evaluated in combination.‖ This indicates that NDEQ’s rejection of 

SNCR on the basis of similarity to another boiler is not valid.

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies

NDEQ has underestimated the ability of modern NOx control systems: A significant 

reason for the higher cost-effectiveness of this option estimated by NDEQ is the low NOx

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

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

SCR is different from many other control technologies in that its efficiency is not highly 

dependent upon the concentration of the pollutant to be controlled.21 Instead, SCR 

efficiency is primarily influenced by the design of the catalyst reactor, that is, the volume 

of the catalyst, its cross-sectional area, number of layers, and measures to prevent 

blinding and deactivation, as well as replacement schedule. If it is necessary to achieve a 

high degree of removal efficiency on an inlet stream with a low concentration, more 

catalyst can be included in the design. It is generally understood that NOX reductions of 

approximately 90% or more may be achieved with SCR systems.22 And, according to the 

June 13, 2009 ―Power‖ magazine article ―Air Quality Compliance: Latest Costs for SO2

 

21 However, as noted below in an excerpt from the EPA Control Cost manual, at very low inlet 

concentrations, removal efficiency may be lower:

In general, higher uncontrolled NOx inlet concentrations result in higher NOx removal efficiencies 

due to reaction kinetics. However, NOx levels higher than approximately 150 parts per million 

(ppm), generally do not result in increased performance. Low NOx inlet levels result in decreased 

NOx removal efficiencies because the reaction rates are slower, particularly in the last layer of 

catalyst.

22 According to the Institute of Clean Air Companies white paper titled ―Selective Catalytic Reduction 

(SCR) Control of NOx Emissions from Fossil Fuel-Fired Electric Power Plants‖ (published in May 2009), 

―By proper catalyst selection and system design, NOX removal efficiencies exceeding 90 percent may be 

achieved.‖
16

and NOX Removal (effective coal clean-up has a higher–but known–price tag)‖ by Robert 

Peltier, ―An excellent example of the significant investment many utilities have made 

over the past decade is American Electric Power (AEP), one of the largest public utilities 

in the U.S. with 39,000 MW of installed capacity with 69% of that capacity coal-fired. 

AEP is under a New Source Review (NSR) consent decree signed in 2007 that requires 

the utility install air quality control systems to reduce NOX by 90%...‖

We are aware of vendor guarantees of 0.05 lb/mmBtu,23 and understand that major 

vendors are designing SCR systems to achieve 0.02 lb/mmBtu24 on coal-fired boilers.

Operational evidence from SCR retrofits on eastern EGUs (see Appendix A for “EGUs 

less than 0.06 lb/mmBtu in 2009”) clearly indicates that SCR can achieve 0.05 

lb/mmBtu or lower on an annual basis. For example, we found eight dry-bottom, wallfired boilers operating at or below 0.05 lb/mmBtu in 2009. We also looked at monthly 

data for 28 EGUs with SCR’s operating at or below 0.05 lb/mmBtu on an annual average 

(see Appendix A for “2009 monthly emissions”) and found that, of the 228 months of 

data, 214 were at or below 0.06 lb/mmBtu. For dry-bottom, wall-fired EGUs, we found 

that 73 of 77 months were at or below 0.06 lb/mmBtu. We conclude that SCR can 

achieve 0.05 lb/mmBtu on an annual basis and 0.06 lb/mmBtu on a 30-day rolling 

average basis.

It is generally assumed that SCR can achieve at least 90% NOX reduction,25 and we have 

presented evidence demonstrating that SCR can achieve 0.05 lb/mmBtu (or lower) on 

similar wall-fired boilers. For example, Tri-State Generation has submitted analyses26 of 

application of SCR at its Craig Colorado station which is based upon an assumption that 

SCR can achieve 0.05 lb/mmBtu. We also note that Salt River Project (SRP) assumed 

that addition of SCR to the Navajo Generating Station27 could achieve 0.05 lb/mmBtu on 

an annual basis. The combination of the real-world examples we have previously 

presented plus the assumptions by Tri-State and SRP should provide sufficient weight-ofevidence for NDEQ to conclude that SCR can reasonably be expected to achieve 0.05 

lb/mmBtu (or better) on an annual basis.

Step 4: Evaluate Impacts and Document Results.

NPPD’s SCR costs are overestimated. Table 4.a (below) uses company data and 

estimates that the combination of LNB/OFA+SCR would cost about $2,300/ton to reduce 

NOX emissions to 0.08 lb/mmBtu on an annual average basis.

 

23 Minnesota Power Taconite Harbor BART analysis.

24 Babcock & Wilcox presentation to Minnesota Pollution Control Agency.

25 Tri-State’s Exhibit #20 also assumed 90% NOX removal.

26 Exhibit 16 - Craig Stations 1, 2, and 3 November 2010 Black & Veatch Report, Tables 2-1, 2-1, 4-6,4-8, 

7-7, 7-8, ―Selective Catalytic Reduction System‖

27 Slide 36 of ―Navajo Generating Station Preliminary Capital Cost Estimate” prepared by Sargent & 

Lundy and presented by Salt River Project to the Environmental Protection Agency – July 20, 2010.
17

Table 4.a. 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

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%

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 

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

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

SCR Cost Estimation Methods

The SCR cost estimates submitted by NPPD are severely lacking in the types of specific 

information needed to give them credibility. Although there are several methods for 

estimating SCR costs, our experience leads us to believe that no one method is perfect 

and that the costing methods need to be tempered by real-world data. An excellent 

example of a SCR retrofit cost analysis was prepared for the Navajo Generating Station 

(NGS) and is being provided separately (in Appendix B. “SCR Costs‖). The NGS 

analysis contains the type of vendor estimates and detailed engineering analyses 

recommended by the BART Guidelines and necessary to arrive at a reasonable and 

informed estimate of site-specific costs. In the absence of such a comprehensive analysis, 

the BART Guidelines recommend use of the EPA Control Cost Manual.

“Real-World” SCR Capital Costs

Real-world, utility industry-generated evidence that NPPD has overestimated its SCR 

costs can be found in a June 2009 article in ―Power‖ magazine:28

―One more current data set is the historic capital costs reported by AEP averaged over 

several years and dozens of completed projects. For example, AEP reports that their 

historic average capital costs for SCR systems are $162/kW for 85% to 93% NOX

removal...‖

―...historical data finds the installed cost of an SCR system of the 700MW-class as 

approximately $125/kW over 22 units with a maximum reported cost of $221/kW in 

2004 dollars. This data was reported prior to the dramatic increase in commodity prices 

of 14% per year average experienced from 2004 to 2006 (from the FGD survey results). 

Applying those annual increases to the 2004 estimates for three years (from the date of 

 

28 June 13, 2009 ―Power‖ magazine article ―Air Quality Compliance: Latest Costs for SO2 and NOx 

Removal (effective coal clean-up has a higher–but known–price tag)‖ by Robert Peltier. 

http://www.masterresource.org/2009/06/air-quality-compliance-latest-costs-for-so2-and-nox-removaleffective-coal-clean-up-has-a-higher-but-known-price-tag/
18

the survey to the end of 2007) produces an average SCR system installed cost of 

$185/kW...‖

―Overall, costs were reported to be in the $100 to $200/kW range for the majority of the 

systems, with only three reported installations exceeding $200/kW.‖

Five industry studies conducted between 2002 and 2007 have reported the installed unit 

capital cost of SCRs, or the costs actually incurred by owners, expressed in dollars per 

kilowatt. These actual costs are generally lower than estimated by NPPD. 

The first study evaluated the installed costs of more than 20 SCR retrofits from 1999 to 

2001. The installed capital cost ranged from $106 to $213/kW, converted to 2007 

dollars.29 Costs are escalated through using the CEPCI. 

The second survey of 40 installations at 24 stations reported a cost range of $76 to 

$242/kW, converted to 2007 dollars.30

The third study, by the Electric Utility Cost Group, surveyed 72 units totaling 41 GW, or 

39% of installed SCR systems in the U.S. This study reported a cost range of $118/kW to 

$261/kW, converted to 2007 dollars.31

A fourth study, presented in a course at PowerGen 2005, reported an upper bound range 

of $180/kW to $202/kW, converted to 2007 dollars.32

A fifth summary study, focused on recent applications that become operational in 2006 or 

were scheduled to start up in 2007 or 2008, reported costs in excess of $200/kW on a 

routine basis, with the highest application slated for startup in 2009 at $300/kW.33

 

29 Bill Hoskins, Uniqueness of SCR Retrofits Translates into Broad Cost Variations, Power Engineering, 

May 2003. Ex. 2. The reported range of $80 to $160/kW $123 - $246/kW was converted to 2008 dollars 

($116 - $233/kW) using the ratio of CEPCI in 2008 to 2002: 575.4/395.6. 

30

 J. Edward Cichanowicz, Why are SCR Costs Still Rising?, Power, April 2004, Ex. 3; Jerry Burkett, 

Readers Talk Back, Power, August 2004, Ex. 4. The reported range of $56/kW - $185/kW was converted to 

2008 dollars ($83 - $265/kw) using the ratio of CEPCI for 2008 to 1999 (575.4/.390.6) for lower end of the 

range and 2008 to 2003 (575.4/401.7) for upper end of range, based on Figure 3. 

31 M. Marano, Estimating SCR Installation Costs, Power, January/February 2006. Ex. 5. The reported 

range of $100 - $221/kW was converted to 2008 dollars ($130 - $286/kW) using the ratio of CEPCI for 

2008 to 2004: 575.4/444, 2.

http://findarticles.com/p/articles/mi_qa5392/is_200602/ai_n21409717/print?tag=artBody;col1 

32 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, Competitive Power 

College, by Babcock Power, Inc. and LG&E Energy, December 2005, Ex. 6. The reported range of $160 -

$180/kW) was converted to 2008 dollars ($197 - $221/kW) using the ratio of CEPCI for 2008 to 2005 

(575.4/468.2). 

33 J. Edward Cichanowicz, Current Capital Cost and Cost-Effectiveness of Power Plant Emissions Control 

Technologies, June 2007, pp. 28-29, Figure 7-1 (Ex. 1). 
19

EPA’s Region 8 Office has compiled a graphic presentation of SCR capital costs adjusted 

to 2009 dollars—please see Appendix B for “SCR References”. The EPA data confirm 

that SCR capital costs typically range from $73 – $243/kW.

A graphic illustration of a ―real-world‖ retrofit was presented by Burns & McDonnell at 

the 2010 Power Plant MegaSymposium and is provided in Appendix B in the “Boswell 

retrofit” files. Despite the limited space and other obstacles, the SCR installation cost 

$205/kW.34 It should also be noted that the Boswell Unit 3 retrofit was designed to meet 

0.05 lb/mmBtu. Burns & McDonnell reported that performance tests showed that, 

―Average NOx emissions at the outlet of the SCR reactor were 0.029 lb/mmBtu, which is 

below the design emission rate for the SCR system (0.05 lb/mmBtu).‖

Thus, the overall range for these industry studies is $50/kW to $300/kW. The upper end 

of this range is for highly complex retrofits with severe space constraints, such as Belews 

Creek, reported to cost $265/kW,

35 or Cinergy's Gibson Units 2-4. Gibson, a highly 

complex, space-constrained retrofit in which the SCR was built 230 feet above the power 

station using the largest crane in the world,36 only cost $251/kW in 2007 dollars.37

We reviewed NPPD’s Appendix C38 to determine the costs it had specifically assigned to 

SCR and derived Table 4b. below:

Table 4.b SCR at 0.08 lb/mmBtu

SCR Cost Components NPPD* NPS**

Direct Capital Cost $ 268,199,000 $ 268,199,000 

Indirect $ 35,212,000 $ 53,639,800 

Escalation $ 60,482,000 

Sales/Use Tax $ 5,589,000 $ 5,589,000 

Contingency $ 72,779,000 $ 61,685,770 

AFUDC $ 41,150,000 

Total Capital Cost (w/ fan sized for SCR only) $ 478,151,000 $ 389,113,570 

Total Capital Cost/kW $ 350 $ 285 

Capital Recovery Factor 0.0944

Levelized Capital Cost (w/ fan sized for SCR only) $ 38,755,000 $ 36,729,568 

Levelized O&M Cost $ 14,515,000 $ 14,515,000 

Levelized Outage Cost $ 1,021,000 $ 1,021,000 

Total Levelized Capital, Outage and O&M Cost $ 54,291,000 $ 52,265,568

 

34 Minnesota Power’s Environmental Improvement Plan submitted to the MN PUC 10/27/06, Docket 

#E015/M-06-1501. LNB+OFA+SCR TCI = $77 million in 2006 $ on 375 (gross) MW Unit #3.

35 Steve Blankinship, SCR = Supremely Complex Retrofit, Power Engineering, November 2002, Ex. 7. The 

unit cost: ($325,000,000/1,120,000 kW) (608.8/395.6) = $290/kW.

http://pepei.pennnet.com/display_article/162367/6/ARTCL/none/none/1/SCR-=-Supremely-ComplexRetrofit/ 

36

 Standing on the Shoulder of Giants, Modern Power Systems, July 2002, Ex. 8. 

37 McIlvaine, NOX Market Update, August 2004, Ex. 9. SCR was retrofit on Gibson Units 2-4 in 2002 and 

2003 at $179/kW. Assuming 2002 dollars, this escalates to ($179/kW) (608.8/395.6) = $275.5/kW. 

http://www.mcilvainecompany.com/sampleupdates/NoxMarketUpdateSample.htm 

38 SCR AND ID FAN & AUXILIARY POWER CONCEPTUAL DESIGN COSTS
20

Tons NOx removed 9,970 9,970

SCR cost-effectiveness ($/ton) $ 5,445 $ 5,242 

*SCR AND ID FAN & AUXILIARY POWER CONCEPTUAL DESIGN COSTS

**Based upon OAQPS Control Cost Manual

NPPD's $350/kW capital cost is much higher than the $250 - $300/kW range estimated 

for SCR at this facility by applying recent industry cost data.39 It is likely that the capital 

cost estimates from NPPD were the highly influenced by the improper inclusion of over 

$60 million in ―Escalation‖ costs and over $41 million in AFUDC costs. We also 

question a ―Contingency‖ cost of over $72 million (27%) of a $268 million total; this is 

higher than the 23% contingency expense estimated by the Cost Manual. If the $89 

million in these excess costs is eliminated from the NPPD estimate, the resulting 

$285/kW becomes more consistent with industry data. Finally, by choosing the most 

costly alternative for supplying ammonia to the SCR, the use of urea with a conversion 

plant, NPPD has further increased costs above the typical industry SCR installation.

Because the NPPD capital costs estimates were higher than we expected, we applied the 

Cost Manual methods to the NPPD cost analyses.

EPA Control Cost Manual

We have been working with an Excel workbook we derived from the SCR cost 

estimation method presented by EPA’s Office of Air Quality Planning and Standards 

Control Cost Manual (Cost Manual). Based upon the industry data cited above, we now 

believe that the Cost Manual method tends to underestimate the Direct Capital Cost 

(DCC) component of the SCR cost estimate. Because the Total Capital Investment (TCI) 

component is directly proportional to the DCC in the Cost Manual method, a 

straightforward application of the Cost Manual method usually results in TCI costs lower 

than what we would expect from the real-world industry data presented above. Therefore, 

we have been developing a way to modify the Cost Manual method to provide TCI 

estimates more consistent with industry data. First, we adjust the DCC from the Cost 

Manual’s 1998 baseline to current (2009) cost using the Chemical Engineering Plant Cost 

Index (CEPCI ratio = 1.34) to adjust costs for inflation. Next we use the DCC presented by 

the source ($135 million for each EGU) and apply the Cost Manual ratios for Indirect 

Installation (20%) and Contingency (5% + 18%) costs to the DCC to estimate TCI. If the 

resulting TCI $189 million each EGU) expressed in $/kW ($284/kW) is within the 

expected range, we carry that estimate through the remainder of the cost estimation 

process. (If this TCI estimate is outside the expected range, we can override the TCI 

calculation by inserting our best estimate (in $/kW) based upon the size of the EGU and 

the degree of retrofit difficulty.) Please see the individual source analyses for specific 

details of how we apply this method.

Annual SCR Costs

The Direct Annual Cost (DAC) component of the process is also important because it 

 

39 J.E. Chichanowicz Report ―Current Capital Cost and Cost Effectiveness,‖ January 2010
21

represents a significant portion of the Total Annual Cost. The methods presented by the 

Cost Manual for estimating DAC appear to be straight-forward and should accurately 

represent annual costs with no need for adjustment. However, the BART analyses 

presented by NPPD show a consistent significant overestimation of DAC.

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

GGS boilers (Tables 5.a and 5.b).

40 Because modern SCR systems are typically designed 

to achieve 90+% NOx reductions, we used 0.05 lb/mmBtu as our target. Except for the 

Annual Maintenance Costs, all other O&M cost estimates produced by NPPD were 

significantly higher than estimated by a direct application of the Cost Manual, even 

though we estimated a greater amount of NOX removal which should have led to higher 

operating costs. Due to a lack of supporting information, we were unable to determine the 

reasons for NPPD’s higher cost estimates. We estimated a Total Annual Cost of $24.5

million for GGS Unit 1, and produced cost-effectiveness estimates of $2,000/ton. 

Table 5.a Annual Costs for SCR at 

0.05 lb/mmBtu

Gerald Gentleman Station Unit 1

NPS NPPD NPPD/NPS

Annual Maintenance Cost = $ 2,835,007 $ 733,000.00 26%

Annual Reagent Cost = $ 824,401 $ 1,751,000 212%

Annual Electricity Cost = $ 762,722 $ 2,412,000 316%

Annual Catalyst Cost = $ 732,419 $ 2,329,000 318%

DAC = $ 5,154,549 $ 7,225,000 140%

Indirect Annual Cost = $ 17,840,306 $ 19,128,000 107%

SCR Total Annual Cost = $ 22,994,855 $ 27,145,500 118%

CC+SCR Total Annual Cost = $ 24,474,855 $ 28,625,500 117%

NOx Removed by SCR = 5,303 4,626 87%

Total NOx Removed = 12,160 12,463 102%

SCR Cost effectiveness = $ 4,336 $ 5,445 126%

Total Cost effectiveness = $ 2,013 $ 2,297 114%

Table 5.b. Annual Costs for SCR at 

0.05 lb/mmBtu

Gerald Gentleman Station Unit 2

NPS NPPD NPPD/NPS

Annual Maintenance Cost = $ 2,835,000 $ 733,000.00 26%

Annual Reagent Cost = $ 800,657 $ 1,776,000 222%

Annual Electricity Cost = $ 740,755 $ 2,412,000 326%

Annual Catalyst Cost = $ 732,419 $ 2,367,000 323%

DAC = $ 5,108,831 $ 7,288,000 143%

Indirect Annual Cost = $ 17,840,263 $ 19,627,000 110%

SCR Total Annual Cost = $ 22,949,094 $ 27,145,500 118%

CC+SCR Total Annual Cost = $ 24,429,094 $ 28,625,500 117%

NOx Removed by SCR = 5,150 4,692 91%

Total NOx Removed = 8,318 12,463 150%

SCR Cost effectiveness = $ 4,456 $ 5,445 122%

Total Cost effectiveness = $ 2,937 $ 2,297 78%

 

40 Our calculations are contained in the attached Excel workbook and in Appendix B.
22

We estimated a Total Annual Cost of $24.4 million for GGS Unit 2, and produced costeffectiveness estimates of $2,900/ton.41

Step 5: Evaluate Visibility Impacts.

NDEQ estimates that reducing NOX emissions to 0.08 lb/mmBtu would improve 

visibility at Badlands NP (the only Class I area for which improvements was provided) 

by 1.152 dV, but we did not have sufficient data to evaluate the cumulative benefits of 

improving visibility at the other Class I areas. If the SCR achieved the lower emission 

rate that we believe is reasonable, then the visibility benefits would increase.

BART Determination for NOX

Quoting NDEQ: LNB/OFA technology is a feasible NOx retrofit technology that could be 

implemented on GGS Units 1 and 2.

The average cost effectiveness of this control technology is $198 per ton NOx removed. Over the 

three years of meteorology modeled, the average incremental visibility impairment improvement 

cost is $4,475,825 per year per change in deciview impact.

Utilizing SCR technology is also feasible only if LNB/OFA is utilized. The incremental cost 

effectiveness (incremental cost SCR) is $5,445 per ton NOx removed, over 25 times the amount of 

LNB/OFA alone. Over the three years of meteorology modeled, the incremental visibility 

impairment improvement cost of adding SCR is $111,993,640 per year per change in deciview 

impact. The average incremental improvement in visibility for the addition of SCR is less than 

0.5 dV and improvement would be seen on an average of 7.3 days per year.

The NDEQ determined that the incremental cost for the addition of SCR is excessive and that 

LNB/OFA would be required for BART.

Therefore BART for GGS Units 1 and 2 shall be the installation of LNB/OFA with an emission 

limitation of 0.23 lb NOx/MMBtu.

NPS NOx BART Conclusions:

We have presented information showing that several EGUs are operating at much lower 

NOX rates than evaluated by NDEQ. NDEQ should evaluate NOX rates that reflect the 

capabilities of SCR systems. 

Use of EPA guidance and industry data results in capital and O&M cost estimates that are 

significantly lower than those presented by NPPD. NDEQ improperly rejected Selective 

Catalytic Reduction (SCR) as too expensive on an incremental cost-per-deciviewimprovement ($/dv) basis. NDEQ began its cost-effectiveness analysis by estimating the 

average costs of combustion controls:

 

41 The higher Total Cost Effectiveness for LNB/OFA+SCR on GGS #2 is primarily due to its inherently 

lower uncontrolled NOX emissions and the higher cost/ton of the LNB/OFA to reduce NOX emissions to 

the presumptive BART level.
23

The total annualized cost associated with the installation of LNB/OFA is $2,960,000. The cost 

effectiveness of LNB/OFA is $198 per ton NOx removed ($2,960,000 / 14,956 tons NOx 

removed).

and then the combination of combustion control plus SCR:

The total annualized cost associated with the installation of LNB/OFA and SCR is $57,251,000. 

The cost effectiveness of LNB/OFA and SCR is $2,297 per ton NOx removed ($57,251,000 / 

24,926 tons NOx removed).

in accordance with its proper understanding of the cost-effectiveness of such a 

combination:

Although SCR is a feasible control technology, it would be most practical to install SCR in 

combination with combustion controls. This is because if NOx formation was not reduced 

upstream of the SCR system, the amount of catalyst required would be higher, subjecting more 

catalyst to degradation. The amount of ammonia required would also be higher, increasing the 

capital and O&M costs of SCR significantly. Also, reagent costs would be significantly higher if 

LNB/OFA were not used to minimize NOx emissions before treatment with the SCR system. 

Therefore, the cost associated with installing LNB/OFA is linked to this control technology 

throughout the analysis.

NDEQ should have stopped at that point. However, NDEQ then contradicted its proper 

assessment of the combination of combustion controls plus SCR and created an 

incremental cost for a ―straw man‖ strategy that it had already deemed ―impractical‖:

The incremental cost effectiveness calculation compares the costs and performance level of a 

control option to those of the next most stringent option. The incremental cost analysis of 

installing LNB/OFA and SCR as opposed to LNB/OFA alone is $5,445 ([$57,251,000 -

$2,960,000] / [24,926 – 14,956]).

NDEQ should have relied upon its good judgment that ―it would be most practical to 

install SCR in combination with combustion controls‖ and based its decision upon the 

outcome of that analysis.42

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

modifications plus SCR of $2,000 - $3,000/ton. This cost-effectiveness appears 

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

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

Manual43 and model the effects on all Class I areas of reducing NOx to not greater than 

0.07 lb/mmBtu and provide the information to develop the ―fifth factor‖ in the BART 

process.

 

42 It should be noted that the combustion controls currently present on GGS #1 did not exist at the time the 

BART Guidelines were finalized, and thus cannot be separated from the LNB/OFA+SCR combination 

endorsed by NDEQ.

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

cost items.