Appendix 10.13 

Reference 17: 

Appendix A of NPPD’s letter dated March 15, 2011 to the NDEQ. 

HDR Engineering, Inc. 701 Xenia Avenue South

Minneapolis, MN 55416-3636 

Phone (763) 591-5400

Fax (763) 591-5413 

www.hdrinc.com 

ONE COMPANY I Many Solutions SM

Nebraska Public Power District, Gerald Gentleman Station, Units 1 & 2, Sutherland, NE 

Supplemental BART Assessment – Dry Sorbent Injection (DSI) 

INTRODUCTION

In February 2011 the Nebraska Department of Environmental Quality (NDEQ) requested that Nebraska 

Public Power District (NPPD) supplement the 2008 BART Analysis for Gerald Gentleman Station (GGS) 

Units 1 & 2. The 2008 BART Analysis considered various technologies for the control of nitrogen oxides 

(NOx) and sulfur dioxide (SO2) emissions. The BART determination of NDEQ contained in the 

December 2010 draft Nebraska Regional Haze SIP is that BART for these emission units is the 

application of low-NOx burners and overfire air (LNB/OFA) to meet an average (of both units) NOx

emission limit of 0.23 pounds per million British thermal units (lb/MMBtu) of heat input, and continued 

use of low sulfur coal with respect to SO2 emissions, without installation of post-combustion controls. 

NDEQ has requested that NPPD perform an analysis of DSI in a “side-by-side” comparison against dry 

and wet flue gas desulfurization (FGD) systems, which were evaluated in the 2008 BART Analysis. 

Because the possible implementation timing of SO2 emission control retrofits for any of these 

technologies would be farther in the future than originally assessed, NPPD requested Sargent & Lundy to 

perform the cost analysis for a hypothetical implementation of DSI in the year of 2016 (see attached 

Appendix A, Dry Sorbent Injection Cost Analysis for Gerald Gentleman Station, prepared by Sargent & 

Lundy, March 11, 2011). Sargent & Lundy has escalated the earlier costs for dry and wet FGD to the 

year 2016, and also used 2016 for DSI cost estimation, to provide the most reasonable side-by-side 

comparison of the various control technologies. HDR has used the Sargent & Lundy cost estimates, 

together with CALPUFF dispersion modeling results for visibility improvement with DSI, to calculate the 

costs per amount of visibility improvement to allow a comparison of DSI with both dry and wet FGD 

technologies assessed in the 2008 BART Analysis. 

BART ANALYSIS – DRY SORBENT INJECTION

As with the 2008 BART Analysis, and as directed by BART implementation guidelines for control of 

Regional Haze (Appendix Y to 40 CFR 51), this analysis of DSI proceeds in a five-step process, as 

follows: 

STEP 1—Identify All Available Retrofit Control Technologies, 

STEP 2—Eliminate Technically Infeasible Options, 

STEP 3—Evaluate Control Effectiveness of Remaining Control Technologies, 

STEP 4—Evaluate Impacts and Document the Results, and 

STEP 5—Evaluate Visibility Impacts. 
Page 2 

STEP 1—Identify All Available Retrofit Control Technologies 

This step is fairly obvious for the current analysis, as NPPD has been asked to assess just one additional 

control technology for SO2 emissions control, that being DSI. However, the BART guidelines state that: 

“In identifying “all” options, you must identify the most stringent option and a reasonable set of 

options for analysis that reflects a comprehensive list of available technologies. It is not 

necessary to list all permutations of available control levels that exist for a given technology—the 

list is complete if it includes the maximum level of control each technology is capable of 

achieving.” 

This is a challenging aspect of the current DSI evaluation, because the technology has not been applied on 

similar units such that we can have confidence in knowing what “maximum level of control” to assume 

for the technology. On the one large boiler proposed for DSI application, a unit rated at 584 MW at the 

Boardman Power Plant in Oregon, the applicant proposed DSI implementation to bring emissions down 

from 0.6 lb/MMBtu to 0.4 lb/MMBtu (33% reduction), and requested flexibility to revise the final SO2

emission rate depending on the success of pilot testing. Also, as discussed in the more detailed technical 

assessment provided by Sargent & Lundy (see Appendix A), the temperatures in the ductwork where 

sorbent could be injected on GGS Units 1 & 2 are not optimum, which would make it more difficult to 

achieve high SO2 removal rates. 

Given the great uncertainty in applying DSI for the first time at a large coal-fired boiler, this analysis has 

identified a theoretical controlled emission rate of 0.36 lb/MMBtu, which would equate to nearly 80% 

control for the design basis coal used for the FGD analysis in the 2008 BART Analysis. The 0.36 

lb/MMBtu emission rate being assessed here is slightly more aggressive than in the Boardman Power 

Plant DSI BART Analysis, and for the reasons stated above and in Appendix A, may be quite optimistic 

given the lack of demonstration of DSI on boilers of this size and type. 

By using the emission rate of 0.36 lb/MMBtu for this DSI analysis, NPPD is not committing to this 

number as a potential permit limit. This is only being used as a potential control level to produce an 

estimate of the costs and resultant impacts for DSI implementation. Given the uncertainties, it would take 

a significant amount of GGS-specific facility modeling and testing studies accompanied by enforceable 

contractual vendor performance guarantees to be confident about meeting any particular emission rate. 

STEP 2—Eliminate Technically Infeasible Options 

Based on lack of DSI implementation on similar sized PRB-fired coal boilers, NPPD’s engineering 

consultant, Sargent & Lundy considers DSI not “technically feasible” as defined under the BART 

guidelines. In its discussion of technical feasibility under the BART guidelines, EPA states: 

Vendor guarantees may provide an indication of commercial availability and the technical 

feasibility of a control technique and could contribute to a determination of technical feasibility 

or technical infeasibility, depending on circumstances. However, we do not consider a vendor 

guarantee alone to be sufficient justification that a control option will work. Conversely, lack of a 

vendor guarantee by itself does not present sufficient justification that a control option or an 
Page 3 

emissions limit is technically infeasible. Generally, you should make decisions about technical 

feasibility based on chemical, and engineering analyses (as discussed above), in conjunction with 

information about vendor guarantees. 

NPPD does not have a contractual emissions performance guarantee from any vendors of DSI technology. 

Obviously, such a vendor has much to gain in sorbent sales if their technology is implemented 

successfully, but also has much to lose if a guarantee cannot be met, and will be reluctant to make such a 

guarantee without substantial pilot studies on units of similar size and characteristics to the units being 

considered for controls. Given the fact that DSI for control at any given outlet emission rate has not been 

demonstrated on a unit similar to GGS Unit 1 & 2, Sargent & Lundy considers DSI to be an 

undemonstrated technology for these units at this time. However, because of the NDEQ request that 

NPPD evaluate DSI as if it were a technically feasible control option for GGS, NPPD is carrying the DSI 

technology evaluation (assuming 0.36 lb/MMBtu outlet SO2 emissions) through the final three steps of 

the BART analysis as described below. 

STEP 3—Evaluate Control Effectiveness of Remaining Control Technologies 

In this case, the only additional technology being evaluated is DSI. Step 3 involves evaluating the 

potential control effectiveness of the technology or technologies being considered. EPA expresses in the 

BART guidelines that the control level should be specified in a metric that relates to the process rate or 

product produced, which in the case of boilers is typically specified in units of lb/MMBtu. In this case, 

we have limited information to provide a basis for establishing a control level as discussed earlier. Thus, 

to present the comparison requested by NDEQ, and based on both a similar control level used in the 

Boardman Power Plant DSI BART analysis, and a very aggressive removal rate for GGS, an SO2 control 

level of 0.36 lb/MMBtu has been selected for this analysis. 

STEP 4—Evaluate Impacts and Document the Results 

The fourth step in the BART analysis evaluates A) costs of compliance, B) energy impacts, C) non-air 

quality environmental impacts, and D) remaining useful life. 

With respect to “remaining useful life,” this factor is considered only if the source unit(s) being evaluated 

have a relatively short life until expected permanent shutdown, such that a typical amortization period for 

control equipment (e.g., 10-20 years) means that BART controls would not be useful for at least a normal 

amortization period. In this case, both GGS units are expected to have a long enough operating future

such that remaining useful life does not affect the BART cost analysis. 

In the case of potential DSI application to GGS Units 1 & 2, factors A), B) and C) above have all been

assessed by Sargent & Lundy (see Appendix A) in terms of their effects on potential costs to NPPD. The 

costs of compliance are calculated for both capital expenditures to install the DSI technology and 

supporting infrastructure (rail spur, sorbent tanks, larger ash/waste handling tanks, landfill, etc.) and for 

operation and maintenance (O&M) costs. In the case of DSI, the major O&M cost is the sorbent itself, 

which is estimated to cost $145/ton delivered to the site. A side-by-side summary of the year 2016 

annualized capital cost, annualized O&M, and total annualized costs for dry FGD, wet FGD, and DSI are 

provided in Table 1. 
Page 4 

Table 1 also summarizes estimated costs in terms of dollars per ton of pollutant removed. The amounts of 

pollutants removed are theoretical values based on a 100% capacity factor for both of the units and 

assuming that the baseline emissions are equal to the maximum 24-hour SO2 emission rate of both units 

combined in the 2001-2003 period specified by NDEQ for the purpose of ensuring consistent BART 

analysis across all sources (see 2008 BART Analysis on-file with NDEQ). 

Table 1. Comparison of Annualized Costs for SO2 Emission Controls in 2016 (Combined GGS 

Units 1 and 2) 

 Cost Element Dry FGD Wet FGD DSI 

Total Capital Cost $1,057,068,000 $1,109,003,000 $208,330,000

Annualized Capital Cost $86,166,000 $90,422,000 $17,500,000

Annualized O&M Cost $30,697,000* $26,368,000 $138,270,000

Total Annualized Cost $116,863,000 $116,790,000 $155,770,000

Annual Tons SO2 Removed 39,815 39,815 25,857

Cost Per Ton Removed $2,935 $2,933 $6,024

*Includes annual outage cost of $752,000 

The energy consumption required by the DSI system is not a large percentage of plant output, so it is not 

expected to require substantial replacement generation. However, the energy aspect of this analysis tallies 

only the in-plant energy use, and does not attempt to add up the energy used in mining the sorbent 

(Trona), transporting it to the facility by rail, land-filling the additional waste product, or obtaining 

replacement material for the coal ash product currently being consumed for beneficial reuse. The energy 

costs for off-site Trona production and delivery activities are inherent in the delivered cost of the sorbent 

at the site. 

The non-air environmental impacts are primary due to construction and operation of an additional landfill 

that would be needed to hold the new waste product. In addition to the Trona-related mass of waste, the 

ash that is currently sold from GGS would represent not only lost revenue to NPPD, but additional cost

for landfill space. 

STEP 5—Evaluate Visibility Impacts. 

The visibility impacts analysis is based on the same CALMET/CALPUFF modeling system and software 

version numbers, and the same modeling protocol approved for the 2008 BART Analysis for GGS and 

other BART-related modeling in Nebraska. HDR executed the CALPUFF model and post-processors for 

the DSI scenario, assuming baseline emissions of NOx and PM components, and using an SO2 emission 

rate based on an emission factor of 0.36 lb/MMBtu and at maximum permitted heat input rate. 
Page 5 

The DSI technology would not be expected to significantly alter stack exhaust parameters, so these were 

kept the same as for the baseline scenario for input to CALPUFF. An updated table of emission rates and 

stack parameters with the DSI scenario added is included as Appendix B of this document. 

To provide the visibility impact modeling results in a format that is most convenient for NDEQ 

use, we have copied the tabular summary of SO2 BART control options and modeling results 

from Table 10.14 of the draft December 2010 NDEQ State Implementation Plan for Regional 

Haze and Best Available Retrofit Technology (BART) at the end of this section. We have edited 

that table to insert the DSI control option and the CALPUFF modeling results. We have also 

calculated the cost benefit metric in units of dollars/year/change in deciviews ($/yr/dV). All 

the edits to Table 10.14 for addition of the DSI option and for clarifying the data are shown in 

gray highlights in the edited table and its footnotes provided at the end of this section. 

Both NPPD and HDR are not clear on how the NDEQ has calculated the “Cost per Day of 

Improvement” metric in Table 10.14 of the draft SIP, so we have left this blank.

The average (across three years of modeled meteorology) cost/benefit metric, or cost 

effectiveness measured as $/yr/dv, is presented in Table 2 for dry sorbent injection (DSI) of 

Trona with SO2 controlled to 0.36 lb/MMBtu, and for the two controlled emission levels (0.15 

lb/MMBtu and 0.10 lb/MMBtu) with wet flue gas desulfurization (FGD), updated to year 2016 

annualized costs. Note that the estimated annualized costs for dry FGD are virtually the same as 

for wet FGD at the same control levels, so just the wet FGD values are presented here. 

Table 2. Average Cost Effectiveness Comparison for SO2 Controls 

Control 

Technology 

Controlled Emissions 

Level (lb/MMBtu) 

Average Incremental Impairment 

Improvement Cost ($/yr/dV) 

DSI 0.36 $ 287,764,058 

FGD (wet) 0.15 $ 154,504,368 

FGD (wet) 0.10 $ 142,860,500 
Page 6 

Table 10.14: Incremental Visibility Effectiveness (SO2 Controls)

 2001 2002 2003 

Control 

Option 

Class I Area with Greatest Impact 

from GGS Badlands Badlands Badlands 

Baseline 

(no SO2

Control) 

SO2 Modeled Emission Rate 

(lb/MMBtu) 0.749 0.749 0.749 

Modeled 98th Percentile Value (dV) 2.845 2.828 3.121 

Number of Days Exceeding 0.5 dV 54 55 60 

DSI Control Added 

(0.36 lb/MMBtu) 

Modeled 98th Percentile Value (dV) 2.158 2.409 2.540 

Incremental Visibility Impairment 

Improvement (∆dV) [1] 0.696 0.419 0.581 

Number of Days Exceeding 0.5 dV 43 44 44 

Incremental Impairment Improvement 

Cost ($/yr/∆dV)[1],[3] $223,807,472 $371,766,110 $268,106,713

Cost per Day of Improvement 

FGD Control Added 

(0.15 lb/MMBtu) 

Modeled 98th Percentile Value (dV) 1.836 2.125 2.478 

Incremental Visibility Impairment 

Improvement (∆dV) [1], [4] 1.009 0.703 0.643 

Number of Days Exceeding 0.5 dV 36 35 39 

Incremental Impairment Improvement 

Cost ($/yr/∆dV)[1] $115,748,266 $166,130,868 $181,633,971

Cost per Day of Improvement $3,442,603 $3,543,963 $3,177,787 

FGD Control Added 

(0.10 lb/MMBtu) 

Modeled 98th Percentile Value (dV) 1.790 2.026 2.443 

Incremental Visibility Impairment 

Improvement (∆dV) [1], [4] 1.055 0.802 0.678 

Number of Days Exceeding 0.5 dV 33 33 36 

Incremental Impairment Improvement 

Cost ($/yr/∆dV)[1],[2] $110,701,422 $145,623,441 $172,256,637

Cost per Day of Improvement $3,755,566 $3,755,566 $3,442,603 

[1]Total annualized cost & incremental visibility impairment improvement compared to baseline. 

[2] The control can be achieved without additional costs, so total annualized cost/the overall incremental impairment 

improvement is calculated. 

[3]Total annualized cost (capital + O&M) of DSI estimated at $155,770,000. 
Page 7 

[4]Total annualized costs (capital + O&M) of FGD (“wet” shown here) control options were updated to year 2016 

annualized values to calculate the “Incremental Impairment Improvement Cost” for each year of modeling. This cost is 

estimated at $116,790,000/yr for both wet FGD at 0.15 lb/MMBtu and wet FGD at 0.10 lb/MMBtu (difference is 

insignificant). Therefore, the annualized cost for the 0.15 lb/MMBtu wet FGD option is conservatively used in the 

calculations for both the 0.15 and 0.10 lb/MMBtu FGD options. 

CONCLUSIONS

Based on the side-by-side comparison of SO2 emission control with DSI technology to both dry and wet 

FGD, which were analyzed in the 2008 BART Analysis for GGS Units 1 & 2, it is clear that DSI has 

substantially higher costs per amount of visibility improvement. Added to this is the great uncertainty in 

the ability of DSI to remove SO2 emissions at any specified control level, and it is concluded that DSI can 

not be considered as BART for GGS Units 1 & 2.

 
APPENDIX A 

 

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Dry Sorbent Injection Cost Analysis for Gerald Gentleman Station

1.0 Introduction 

Gerald Gentleman Station (GGS) is a source subject to the Regional Haze rule. A Best Available Retrofit 

Technology (BART) Analysis was submitted to the Nebraska Department of Environmental Quality (NDEQ) 

in February 2008 (hereafter referred to as 2008 BART Analysis) which included an evaluation of retrofitting 

emissions control technologies to lessen the impact of Gerald Gentleman Station (GGS) on visibility at the 

Badlands National Park in South Dakota. The technologies considered in the 2008 BART Analysis were dry

and wet Flue Gas Desulfurization (FGD) systems for SO2 control and Low NOx burners (LNB) and Selective 

Catalytic Reduction (SCR) for NOx control. Sargent & Lundy (S&L) provided input to the 2008 BART 

Analysis by providing capital, O&M, and annualized cost estimates for the FGD and SCR technologies. 

The 2008 BART Analysis did not include an evaluation of Dry Sorbent Injection (DSI) technology because it 

was not considered to be technically feasible for use at GGS. During the final comment period for the 

associated Nebraska State Implementation Plan (SIP) in 2010, the NDEQ received comments from the 

National Park Service suggesting that dry sorbent injection should be considered for application at GGS. At 

Nebraska Public Power District’s (NPPD’s) request, Sargent & Lundy prepared a letter dated January 6, 

2011 that responded to the National Park Service comments. In that letter, Sargent & Lundy delineated the 

considerations that were used to eliminate DSI from being addressed in the 2008 BART Analysis and 

concluded that “DSI is currently not technically feasible for application for the source under consideration, 

Gentleman Station Units 1 and 2”, and that “while ... an argument could be made that DSI is available for 

certain source type applications, it is not applicable to Gentleman Station”.

The NDEQ disagreed with S&L’s conclusion. In February 2011, the NDEQ asked that a side-by-side 

comparison be performed of dry sorbent injection technology and the FGD technologies, including both a 

cost comparison and a visibility impact comparison. Although S&L still believes that DSI is not technically 

feasible as previously stated in our January 6, 2011 letter, as requested by NPPD, we proceeded to prepare 

the cost comparison, for what should be considered a hypothetical evaluation based on S&L’s opinion of the 

“technical feasibility” of the DSI technology. 

As detailed herein, this analysis identifies the hypothetical capital, O&M, and annualized costs of applying 

dry sorbent injection technology at GGS. The analysis is based on both publicly available data and S&L 

expertise related to DSI. The visibility improvement and effectiveness will be modeled by HDR. HDR 

performed the same modeling used in the 2008 BART Analysis. 

2.0 Evaluation Methodology 

The evaluation of DSI technology for the purpose of developing cost estimates for SO2 reduction at GGS was 

based on the following: 

Selection of a “target” stack SO2 emission rate 

Selection of a sorbent type for reduction of SO2

Selection of a sorbent stoichiometric ratio based on the SO2 removal efficiency needed 

Once the appropriate performance parameters were established, design of the system could be approximated 

and the sorbent consumption and waste production rate could be calculated. The capital and O&M costs 

could then be determined. The final step was to convert the capital and O&M costs into an annualized cost 

estimate such that the technologies could be compared on an equal basis. This approach is further explained 

in the following sections. 
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2.1 Selection of “Target” Stack SO2 Emission Rate 

DSI technology has demonstrated the capability of removing moderate amounts of SO2. However, DSI has 

not demonstrated that it can remove as much SO2 as conventional wet or dry utility grade FGD technologies. 

In the 2008 BART Analysis, the candidate FGD technologies (conventional wet limestone and lime spray 

dryer) were evaluated as being able to reduce SO2 emissions to less than 0.15 lb/MMBtu for coals having as 

much as 2.27 lb SO2 /MMBtu. This sulfur content is representative of the high end of the sulfur content range 

for Powder River Basin (PRB) coals which are used exclusively at GGS. The evaluated reduction represents 

a removal efficiency of about 93%. S&L’s expectation for a cost effective application of the DSI technology 

would be at a considerably lower efficiency and a much higher resultant SO2 emission rate. 

From publicly available information, we are aware that a recent BART analysis prepared for Boardman 

Power Plant contained an evaluation of the use of DSI to lower emissions to 0.4 lb SO2 /MMBtu subject to 

the results of pilot testing that would prove or disprove this capability. Also, it should be noted that the 

Boardman BART analysis for the use of DSI technology represented only 4-6 years of operation prior to 

closure of the Boardman Plant in the 2018-2020 time frame. This type of analysis criterion will tend to favor 

low capital and high operating cost technologies such as DSI. 

Selection of a target SO2 emission rate is based in part on the proposed DSI implementation for the 

Boardman Plant, which burns PRB coal and has a boiler/generating unit of similar size (584 MW) compared 

to the somewhat larger GGS generating units. The selection of the target SO2 emission rate is also based in 

part on published theoretical projections by Solvay, a supplier of Trona and sodium bicarbonate sorbents 

which are candidate sorbents, for DSI applications. To present a side-by-side comparison of DSI and the 

FGD options used in the 2008 BART Analysis, we used the same design coal as for the dry and wet FGD 

options already evaluated as part of the 2008 BART Analysis. Based on the Boardman Plant DSI BART 

analysis and a very optimistic Solvay projection for control efficiency (approaching 80%) and using the 

design basis coal for GGS, we have selected an outlet (stack) SO2 emission rate of 0.36 lb/MMBtu for this 

assessment. This is a more aggressive removal efficiency than proposed for Boardman where 0.36 lb 

SO2/MMBtu would represent a removal efficiency of only 40%. Note that even with this relatively low

efficiency for the Boardman BART, Portland General Electric requested flexibility in the ultimate emission 

limitation dependent on pilot testing. Without extensive GGS-specific modeling and actual field testing, and 

a contractual performance guarantee from a vendor, the analysis of DSI for GGS presented here must be 

considered theoretical. 

2.2 Selection of Sorbent Type 

Sorbents that can be used in the DSI technology include Trona, sodium bicarbonate, or lime. Sodium 

compounds (Trona and bicarbonate) are more reactive with SO2 than is lime; therefore lime is rarely 

evaluated for SO2 removal in DSI technology applications. Trona is more available than bicarbonate, but 

bicarbonate is more effective in that a pound of bicarbonate can remove more SO2 than a pound of Trona. 

However, bicarbonate is effective in a more limited flue gas temperature range making it less flexible in the 

dynamic operating condition of a typical power plant. Finally, bicarbonate is more expensive. 

Table 1 shows (1) the order-of-magnitude consumption rates for Trona and bicarbonate that would be needed 

for applications of the technology at GGS, (2) the relative costs of the sorbents, and (3) the domestic 

supplier’s production capacity. 

Bicarbonate was not selected as the sorbent of choice for GGS for two reasons. First, bicarbonate needs to 

be injected into the flue gas stream within a tighter temperature range than Trona which would be a problem 

for GGS as will be discussed in the section of this report on stoichiometry. Second, GGS would consume 
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such a large portion of the current total market production capability that bicarbonate’s availability to GGS 

would be in question. In addition, there are only three suppliers of bicarbonate so GGS would have little 

leverage on the suppliers and this situation would result in bicarbonate costs that would very likely escalate 

at a higher rate than other FGD sorbents, including limestone and lime. For these reasons, sodium 

bicarbonate is not considered to be an effective sorbent for the GGS units. 

Table 1: Comparison of Consumption and Production Capacities for Trona and Bicarbonate 

Trona Sodium Bicarbonate 

GGS approximate consumption 

(million tons/yr) 

0.6 0.5 

Suppliers’ production capacity 

(million tons/yr)

Solvay = 4.5 

FMC = 4.0 

Dwight = 4.0 

Total = 12.5 

Solvay = 0.15 

FMC = 0.25 

Dwight = 0.35

Total = 0.75 

GGSs’ consumption as a percent 

of total suppliers’ production 

capacity* 

5% 67% 

Price ($/ton) $145 by rail $200 by rail 

*Assumes the suppliers’ production capacity of Trona and Bicarbonate is all available and does not figure in 

the amount already committed to others. 

As can be seen from the Table 1, the current production of Trona comes from three suppliers and GGS would

be consuming approximately 5% of the market. With only three suppliers competition would be low. This 

could create a higher rate of escalation in reagent price than what was used in this analysis. For comparison 

purposes, there are over 21 companies that produce lime (used in FGD technologies) and GGS would 

consume less than 1% of the lime market. 

Trona is the sorbent type selected for this cost analysis. 

2.3 Selection of Stoichiometric Ratio 

After selection of a sorbent and an emission rate for GGS, the next step was to select a stoichiometric ratio to 

effectively deal with the selected emission rate. The normalized stoichiometric ratio is defined in the 

literature and represents the amount of Trona injected to remove a selected amount of SO2. In the DSI 

industry, the stoichiometric ratio is correlated to removal efficiency and is usually presented in curves such 

as that shown in Figure 1. The curve in Figure 1 is publicly available and is presented frequently in DSI

literature. However, the curves are very broad, which implies that their accuracy is limited. In other words, 

the curves show a general relationship between stoichiometric ratio and efficiency, but they are not so 

accurate that they could be used to define the stoichiometric ratio which would be specifically required at 

GGS. In addition, the curves are based mainly on industrial plant experience. Industrial plants perform 

significantly different from utility plants. In S&L’s opinion, these curves must be viewed as optimistic 

projections that should only be used for general information. The only way to develop a meaningful 

stoichiometric ratio versus efficiency relationship specifically for GGS would be to conduct extensive 

modeling and field testing at GGS. 
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Figure 1: Normalized Stoichiometric Ratio versus SO2 Removal Efficiency (From Solvay) 

The relationship between Trona stoichiometric ratio and removal efficiency is highly dependent on the Trona 

particle size (milled versus un-milled), the flue gas temperature at the Trona injection location, the 

uniformity of injection across the ductwork, and the time of contact (i.e. residence time). Choosing the 

stoichiometric ratio is dependent on the aforementioned unit-specific parameters. As noted, the size of the 

Trona particle impacts the stoichiometric ratio and DSI suppliers have shown in recent tests that smaller, not 

larger, Trona particle sizes are more effective in capturing SO2. However, smaller sized Trona particles 

cannot be shipped over long distances, therefore, the typical method of applying Trona is to deliver un-milled 

Trona to the site and then process it through an in-line mill that reduces the Trona particle size to about 20-25 

microns. S&L used this approach in the GGS cost estimate analysis. 

The flue gas temperature at the injection location impacts the stoichiometric ratio. The reaction of Trona 

relies on the ability of the SO2 molecules to be captured in the pores of the Trona material. The more porous 

the material is the more sites that are available to capture SO2 molecules. Trona has a characteristic that it 

will calcine (“popcorn”) and become more porous when injected at temperatures between 275oF and 800oF. 

If it is injected at greater than 800oF or below 275oF, then each Trona particle is not as effective, and more 

Trona is needed, to collect a given amount of SO2. The temperature profiles at GGS are not ideal (see 

discussion below) for this situation and, therefore, the Figure 1 curves do not accurately represent the 

stoichiometric ratio needed at GGS. In S&L’s opinion, because much of the experience with this technology 

comes from industrial scale applications, the removal efficiencies shown by the curves are very optimistic for 

use at GGS. 

Sorbent can be injected upstream or downstream of the unit’s air preheaters. The GGS Unit 1 and Unit 2 

temperature profiles upstream and downstream of the air preheaters were evaluated to determine the best 

injection location and the impact of temperature on stoichiometric ratio. The Unit 1 flue gas temperature 

downstream of the secondary air preheater is below 275oF for 74% of the operating hours. The temperatures 

upstream of the air heater are determined by the economizer outlet temperature. The Unit 1 economizer 
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outlet temperature is above 800oF for 29% of the operating hours and, if considering greater than 80% load, 

is above 800oF for 36% of the operating hours. The Unit 2 data indicates the temperature downstream of the 

secondary air preheater is below 275oF for 100% of the operating hours and the economizer outlet 

temperature is above 800oF for 25% of the hours. Therefore, both units have a poor temperature profile and 

the required stoichiometric ratio would be greater than shown in Figure 1 for any removal efficiency. 

Finally, because much of the experience with this technology comes from industrial scale applications, the 

expectation for both removal efficiency and stoichiometry shown on this curve should be considered very 

optimistic for the large utility boiler systems at GGS. 

The stoichiometric ratio relationship selected by S&L for this analysis for the GGS units is shown in Figure 

2. This relationship is superimposed over the Solvay curve in Figure 1. 

Figure 2: Normalized Stoichiometric Ratio versus SO2 Removal Efficiency for GGS 

2.4 Capital Cost Estimate Determination 

The basis of the cost estimates used in this analysis is the same as that used in developing the costs for the 

2008 BART Analysis, with one exception: The initial startup date for the technologies is now calendar year 

2016 rather than 2013. The costs from the 2008 Analysis and this analysis of the DSI technology have been 

annualized for startup in 2016 and this change puts all technologies on the same economic basis. This 

change is necessary to allow time for the dry and wet FGD technologies to be built on an achievable 

schedule, rather than expecting they could be installed and made operational two years from the present, 

which is not achievable. The change to the startup date required that the FGD costs be escalated such that 

the first year of operation is 2016, rather than the 2013. The capital for the DSI technology also uses 2016 as 

the initial operation date and includes escalation. 

 
Nebraska Public Power District Project No. 12681-002 

Gerald Gentleman Units 1&2 March 11, 2011

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The capital costs are presented as several components (construction direct, other construction, indirect, 

etc...) as shown in Exhibit 1. The DSI application for each Unit is designed for 87,500 lbs/hr (which 

represents the selected stoichiometry) and includes milling equipment, as previously described. 

The direct construction components shown were developed using S&L in-house cost information. The 

capital cost estimate for the DSI application includes rail unloading, storage, transfer, milling, and injection 

subsystems. In addition to the DSI system cost estimate information, Exhibit 1 shows direct construction 

costs for rail upgrades to allow for receiving of Trona on site and includes costs for expanding the ash 

storage system due to the increased quantity of solid waste from the spent Trona. The rail upgrades and ash 

storage upgrades were also included in the FGD system cost estimates for the 2008 BART Analysis when 

appropriate. 

The remainder of the capital cost components were added using the same bases that were used for the 

previously submitted FGD capital costs, with one exception: The contingency for this DSI application 

capital cost estimate uses 30% contingency (vs. 20% used in the FGD cost estimates) because the DSI orderof-magnitude costs were developed with minimal engineering analysis as compared to the detailed analysis 

performed for the 2008 BART Analysis. 

2.5 O&M Cost Determination 

Because it proved not to be practical to develop a true side-by-side comparison of the FGD and DSI 

technologies for GGS, the O&M costs were developed for a hypothetical case of reducing SO2 emissions 

from the design coal used for the 2008 BART Analysis to meet an emission limit of 0.36 lb/MMBtu. This 

case is hypothetical because: 1) there are no precedents in the electric power industry of application of DSI to 

a boiler of this size and type, 2) there are no GGS-specific field modeling trials and testing of either Unit 

which have different designs and different boiler manufacturers, and 3) there are no contractual performance 

guarantees for GGS. Because it is unknown whether the DSI technology could meet this emission level in 

the case of GGS, such an application would, by definition, be hypothetical and experimental in nature. 

The O&M cost estimate for the DSI implementation as described above is detailed in Exhibits 2a and 2b, and 

includes the calculation of the first year O&M cost and the annualized O&M cost for each unit, respectively. 

Consistent with the 2008 BART Analysis, a 20-year amortization period was used for the DSI system. The 

cost of the reagent and waste disposal are the predominant annual operating costs for the DSI technology. A

new landfill cost is included in this evaluation because a new landfill would be needed for the DSI 

technology waste. The landfill includes costs for site preparation, placement of low permeability soil, 

installation of a geomembrane, and placement of a protective cover for closure of the landfill. 

The DSI application will have an impact on the operation of the baghouse. The significant increase in the 

solids loading to the baghouse will require the bags to be cleaned more frequently. Bag cleaning frequency 

has a direct impact on the life of the bag. The increased cleaning frequency will lessen the bag life by 10% 

to 20%. 

2.6 Annualized Cost Determination 

Exhibit 3 presents the annualized costs for the FGD technologies as presented in the 2008 BART Analysis. 

As previously addressed, these costs were based on a 2013 operating date which is no longer reasonable. 

Therefore, Exhibit 3 also presents the same FGD costs escalated to calendar year 2016 to accommodate a 

normal engineering, construction and startup schedule. The exhibit also includes the DSI cost estimates for 

each option considered escalated to 2016. 
Nebraska Public Power District Project No. 12681-002 

Gerald Gentleman Units 1&2 March 11, 2011

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The data in Exhibit 3 is close to the side-by-side comparison that NDEQ requested, but is based on a DSI 

outlet SO2 emission rate of 0.36 lb SO2 /MMBtu, not the 0.15 lb SO2 /MMBtu value used for FGD 

technologies. Evaluating the DSI technology at an outlet loading of 0.15 lb SO2/MMBtu and a 

corresponding SO2 removal of 91% would represent an extrapolation of available data well beyond 

practicality. Even when evaluated at a lower removal efficiency and a higher outlet loading, the DSI 

technology annualized cost ($/yr) and normalized cost ($/ton SO2) is higher than the FGD cost from the 2008 

BART Analysis. 

3.0 Other Retrofit Impacts 

3.1 Energy Usage 

The DSI application is expected to consume about 0.1 kW of the station’s power for every 1 lb/hr of sorbent 

feed. For both units at full capacity, this equates to 16 MW, which is 1.2 % of the stations gross capacity. 

Most of the power is consumed by pneumatically handling the Trona, cooling the transport air, and keeping 

the stored Trona dry. The dry and wet FGD technologies consume 1.9 % and 2.7 %, respectively, of the 

station’s gross power.

3.2 Disposal of Liquid 

The DSI application does not use water to improve the mass transfer of SO2 as is the case with dry and wet 

FGD technologies. The FGD technologies consume between 1,700 and 2,200 gpm of water. 

Some water is used in DSI application to wash the Trona mills as a part of required daily maintenance. The 

Trona mills are filled with water to dissolve the deposits of sodium that accumulate on the mill internals. 

The water used for this purpose averages less than 10 gpm on an annual basis. The resulting liquid waste is 

high in sodium and, therefore, must be properly disposed of. 

 

3.3 Potential Fugitive Emissions 

The DSI application will have the potential to generate fugitive emissions as the dry sorbent is pneumatically 

transferred from the rail cars to the storage silos, from the storage silos to the day silo, and from the day silo 

to the injection subsystems. In addition, the rail delivery generates fugitive emissions while the sorbent is in 

transit. Finally, the handling of the baghouse waste streams have the potential to generate fugitive emissions 

as they are pneumatically transferred to the waste silos and unloaded to haul trucks. Also, since the solid 

waste generation rate associated with the DSI application will be about 3 times the current solid waste 

quantity, there will be three times the amount of haul truck traffic which will also increase fugitive 

emissions. All of these solids handling systems have the potential to increase fugitive dust emissions and 

must be controlled with additional dust control hardware and systems which increase both the capital 

requirement and O&M requirement. 

4.0 Conclusion 

It remains S&L’s judgment that the DSI technology has not been proven on any power plant the size of the 

GGS units and, therefore, should not be considered “technically feasible” as the term is defined in the

Regional Haze rule. Even so, as requested by NPPD, S&L developed the cost estimates for the application 

of the DSI technology on both GGS units to be as close to a side-by-side comparison to the previously 

analyzed dry and wet FGD technologies as is practical and reasonable. 

Although the initial capital requirement for a DSI system at GGS is considerably less than that required for 

either of the FGD technologies evaluated in the 2008 BART Analysis, the operating costs for the DSI system 
Nebraska Public Power District Project No. 12681-002 

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SL DSI Cost Analysis for GGS 03-11-2011 (2).doc 

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at GGS, over the 20 year amortization life, resulted in an annualized cost of nearly 34% greater for the DSI 

system. Also, the cost to capture a ton of SO2 with the DSI system is over twice as expensive as that 

required with either of the FGD technologies evaluated in the 2008 BART Analysis.
Nebraska Public Power District

Gerald Gentleman Units 1&2

EXHIBIT 1

Dry Sorbent Injection Capital Cost

Project No. 12681-002

March 11, 2011

GGS Unit 1 GGS Unit 2

Construction Direct

Rail Unloading, Tracks and Switches 1,995,000 $ 1,995,000 $ 

New Waste Silos 4,676,000 $ 4,676,000 $ 

DSI System 35,960,000 $ 35,960,000 $ 

Other Construction 

Engineering and Construction Management (5%) 2,132,000 $ 2,132,000 $ Per Diem, Premium (5%) 2,132,000 $ 2,132,000 $ 

Profit (10%) 4,690,000 $ 4,690,000 $ 

EPC Fee (20%) 10,317,000 $ 10,317,000 $ 

Total Construction 61,902,000 $ 61,902,000 $ 

Indirect

Owners Engineer 500,000 $ 500,000 $ 

Bond Fees (2.5% of first $200,000,000) 2,500,000 $ 2,500,000 $ Owners Cost (2%)* 2,944,000 $ 2,944,000 $ 

Escalation 5,091,000 $ 5,091,000 $ 

Sales Tax (5.5% equip/material) 1,362,000 $ 1,362,000 $ 

Contingency (30%) 21,882,000 $ 21,882,000 $ 

Total Project Cost 96,181,000 $ 96,181,000 $ 

AFUDC 7,984,000 $ 7,984,000 $ 

GRAND TOTAL COST ($2016) 104,165,000 $ 104,165,000 $ 

Notes:* Includes 2 weeks of sorbent injection testing.
Nebraska Public Power District

Gerald Gentleman Units 1&2

EXHIBIT 2A

Budgetary DSI O&M Cost Estimate (per Unit)

Project No. 12681-002

March 11, 2011

Dry Sorbent Type Trona

Design Removal Efficiency 80% SO2

 Removal

Particulate Collector Baghouse

Input Data for System Analysis:

Fuel PRB

Gross Capacity MW 745

Capacity Factor % 80

Heat Input to Boiler at Full Load MMBtu/hr 7,047

Fuel Heating Value Btu/lb 8,124

Fuel Sulfur Content lb/MMBtu 1.72

Fuel Ash Content % 5.42

Ash Removal in Boiler % 30.00

Dry Sorbent Injection Analysis:

Dry Sorbent Requirement lb/hr 87,500

Dry Sorbent Requirement t/yr 383,250

Dry Sorbent Consumption lb/hr @ CF 70,000

Dry Sorbent Consumption t/yr @ CF 306,600

Waste Disposal Analysis:

Flyash Production (Leaving the Boiler) lb/hr 32,910

Sorbent Waste Rate lb/hr 67,495

Total Waste for Disposal (Ash + Sorbent) lb/hr 100,405

Total Waste for Disposal (Ash + Sorbent) t/yr 439,775

Total Waste for Disposal (Ash + Sorbent) t/yr @ CF 351,820

Auxiliaries Analysis:

Increase in Auxiliary Power Consumption -

Full Load kW 8,750

Economic Parameters:

Total number of Bags 16,474

Replacement Bag Cycle years 6

Bag Replacement Cost $/bag 172.00

Dry Sorbent Cost $/t 145.00

Waste Disposal Cost $/t 5.64

Revenue from Flyash Sale $/t 1.35

Power: Energy Charge (Auxiliary Power) $/MWh 45.65

Power: Capacity Charge $/kW/year 46.00

Labor Rate $/hr 40.60

Variable O&M Cost:

Bag Replacement Cost $/yr 473,000 $ 

Dry Sorbent Cost $/yr 44,457,000 $ 

Waste Disposal Cost $/yr 1,984,000 $ 

Revenue from Flyash Sale $/yr - $ 

Power: Energy Charge Cost (Auxiliary Power) $/yr 2,800,000 $ 

Power: Capacity Charge $/yr 402,500 $ 

SO2 Allowance Sale $/yr (1,016,000) $ 

Total Estimated Variable O&M Cost $/yr 49,100,500 $ 

Fixed O&M Cost

Additional Operating labor no. 4.5

Additional Operating labor $/yr 382,000 $ 

Additional Maintenance Material $/yr 240,000 $ 

Additional Maintenance Labor $/yr 360,000 $ 

Additional Administrative labor $/yr - $ 

Total Estimated Fixed O&M Cost $/yr 982,000 $ 
Nebraska Public Power District

Gerald Gentleman Units 1&2

EXHIBIT 2B

Budgetary DSI Annualized O&M Cost Estimate

Project No. 12681-002

March 11, 2011

Dry Sorbent Type Trona

Design Removal Efficiency 80% SO2

 Removal

Particulate Collector Baghouse

Annualized Variable O&M Cost:

Bag Replacement Cost $/yr $ 578,000

Dry Sorbent Cost $/yr $ 54,238,000

Waste Disposal Cost $/yr $ 2,421,000

Revenue from Flyash Sale $/yr - $ 

Power: Energy Charge Cost (Auxiliary Power) $/yr 3,416,000 $ 

Power: Capacity Charge $/yr 492,000 $ 

SO2 Allowance Sale $/yr (1,240,000) $ 

Total Estimated Annualized Variable O&M Cost $/yr $ 59,905,000

Annualized Fixed O&M Cost:

Additional Operating labor $/yr 467,000 $ 

Additional Maintenance Material $/yr 293,000 $ 

Additional Maintenance Labor $/yr 440,000 $ 

Additional Administrative labor $/yr - $ 

Total Estimated Annualized Fixed O&M Cost $/yr $ 1,200,000

TOTAL ESTIMATED ANNUALIZED O&M $2011 $/yr $ 61,105,000

TOTAL ESTIMATED ANNUALIZED O&M TO 2016$ $/yr $ 69,135,000
Nebraska Public Power District

Gerald Gentleman Units 1&2

EXHIBIT 3

Modification of Table 4 from 2008 BART Analysis, SO2 Cost of Compliance

Project No. 12698-002

March 11, 2011

Dry FGD Wet FGD Dry Sorbent Injection

Emission Rate (lb/MMBtu) 0.15 0.15 0.36

Emission Reduction (tpy) 39,815 39,815 25,857Capital Costs ($) 981,592,000 $ 1,029,819,000 $ 

Annualized Capital Cost ($) 80,013,000 $ 83,965,000 $ 

Annualized Operating Cost ($) 27,806,000 $ 24,485,000 $ 

Annnualized Outage Cost ($) 698,000 $ - $ 

Total Annualized Cost ($) 108,517,000 $ 108,450,000 $ 

Normalized Cost ($/ton SO2 reduced) 2,726 $ 2,724 $ Eacalation factors to convert the above Table 4 to the below revised Table 4Capital Escalation Rate (%) 2.5% 2.5%O&M Escalation Rate (%) 2.5% 2.5%Years of Escalation (#) 3 3

Theoretical Normalized Stoichiometric Ratio 3.0

The above Table 4 but Escalated to 2016 1st year operating date (total for both Units)Emission Rate (lb/MMBtu) 0.15 0.15 0.36Emission Reduction (tpy) 39,815 39,815 25,857Capital Costs ($) 1,057,068,000 $ 1,109,003,000 $ 208,330,000 $ 

Annualized Capital Cost ($) 86,166,000 $ 90,422,000 $ 17,500,000 $ 

Annualized Operating Cost ($) 29,945,000 $ 26,368,000 $ 138,270,000 $ 

Annnualized Outage Cost ($) 752,000 $ - $ - $ 

Total Annualized Cost ($) 116,863,000 $ 116,790,000 $ 155,770,000 $ 

Normalized Cost ($/ton SO2 reduced)* 2,935 $ 2,933 $ 6,024 $ 

Description* Calculated based on the maximum actual 24-hour SO2 emissions realized over the 3-year baseline period (2001-2003) that was used in the 2008 BART Analysis.

Technology Options