# Appendix 10.13

Reference 17:

Appendix A of NPPD’s letter dated March 15, 2011 to the NDEQ.HDR Eng ineering, 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 St ation, Units 1 & 2, Sutherland, NE

Supplemental BART Assessment – Dry Sorbent Injectio n (DSI)

INTRODUCTION

In February 2011 the Nebraska Department of Environ mental Quality (NDEQ) requested that Nebraska Public Power District (NPPD) supplement the 2008 BA RT Analysis for Gerald Gentleman Station (GGS) Units 1 & 2. The 2008 BART Analysis considered var ious technologies for the control of nitrogen oxide s (NO
x ) and sulfur dioxide (SO 2 ) emissions. The BART determination of NDEQ contai ned in the December 2010 draft Nebraska Regional Haze SIP is t hat BART for these emission units is the application of low-NOx burners and overfire air (LN B/OFA) to meet an average (of both units) NO
x emission limit of 0.23 pounds per million British t hermal units (lb/MMBtu) of heat input, and continue d use of low sulfur coal with respect to SO 2 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, whi ch were evaluated in the 2008 BART Analysis. Because the possible implementation timing of SO 2 emission control retrofits for any of these technologies would be farther in the future than or iginally assessed, NPPD requested Sargent & Lundy t o perform the cost analysis for a hypothetical implem entation 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 escala ted the earlier costs for dry and wet FGD to the year 2016, and also used 2016 for DSI cost estimati on, to provide the most reasonable side-by-side comparison of the various control technologies. HD R has used the Sargent & Lundy cost estimates, together with CALPUFF dispersion modeling results f or visibility improvement with DSI, to calculate th e 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 analy sis of DSI proceeds in a five-step process, as
follows:

STEP 1—Identify All Available Retrofit Control Tech nologies,

STEP 2—Eliminate Technically Infeasible Options,

STEP 3—Evaluate Control Effectiveness of Remaining Control Technologies,

STEP 4—Evaluate Impacts and Document the Results, a nd

STEP 5—Evaluate Visibility Impacts.Page 2

STEP 1—Identify All Available Retrofit Control Tech nologies

This step is fairly obvious for the current analysi s, as NPPD has been asked to assess just one additi onal control technology for SO 2 emissions control, that being DSI. However, the B ART guidelines state that:

“In identifying “all” options, you must identify th e 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 con trol levels that exist for a given technology—the list is complete if it includes the maximum level o f control each technology is capable of achieving.”

This is a challenging aspect of the current DSI eva luation, because the technology has not been applie d on
similar units such that we can have confidence in k nowing what “maximum level of control” to assume for the technology. On the one large boiler propos ed for DSI application, a unit rated at 584 MW at t he Boardman Power Plant in Oregon, the applicant propo sed 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 SO 2 emission rate depending on the success of pilot tes ting. Also, as discussed in the more detailed tech nical assessment provided by Sargent & Lundy (see Appendi x A), the temperatures in the ductwork where sorbent could be injected on GGS Units 1 & 2 are no t optimum, which would make it more difficult to achieve high SO 2 removal rates.

Given the great uncertainty in applying DSI for the first time at a large coal-fired boiler, this anal ysis has
identified a theoretical controlled emission rate o f 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 sligh tly 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 o f this size and type.

By using the emission rate of 0.36 lb/MMBtu for thi s DSI analysis, NPPD is not committing to this number as a potential permit limit. This is only b eing used as a potential control level to produce a n estimate of the costs and resultant impacts for DSI implementation. Given the uncertainties, it would take a significant amount of GGS-specific facility model ing and testing studies accompanied by enforceable contractual vendor performance guarantees to be con fident about meeting any particular emission rate.

STEP 2—Eliminate Technically Infeasible Options

Based on lack of DSI implementation on similar size d PRB-fired coal boilers, NPPD’s engineering consultant, Sargent & Lundy considers DSI not “tech nically feasible” as defined under the BART guidelines. In its discussion of technical feasibi lity under the BART guidelines, EPA states:

Vendor guarantees may provide an indication of comm ercial availability and the technical feasibility of a control technique and could contri bute to a determination of technical feasibility or technical infeasibility, depending on circumstan ces. 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 suffici ent justification that a control option or anPage 3

emissions limit is technically infeasible. Generall y, you should make decisions about technical feasibility based on chemical, and engineering anal yses (as discussed above), in conjunction with information about vendor guarantees.

NPPD does not have a contractual emissions performa nce guarantee from any vendors of DSI technology. Obviously, such a vendor has much to gain in sorben t sales if their technology is implemented successfully, but also has much to lose if a guaran tee cannot be met, and will be reluctant to make su ch a guarantee without substantial pilot studies on unit s of similar size and characteristics to the units being
considered for controls. Given the fact that DSI f or control at any given outlet emission rate has no t been demonstrated on a unit similar to GGS Unit 1 & 2, S argent & Lundy considers DSI to be an undemonstrated technology for these units at this t ime. However, because of the NDEQ request that NPPD evaluate DSI as if it were a technically feasi ble control option for GGS, NPPD is carrying the DS I technology evaluation (assuming 0.36 lb/MMBtu outle t SO 2 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 o r technologies being considered. EPA expresses in the BART guidelines that the control level should be sp ecified in a metric that relates to the process rat e or product produced, which in the case of boilers is t ypically specified in units of lb/MMBtu. In this c ase, 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 ba sed on both a similar control level used in the Boardman Power Plant DSI BART analysis, and a very aggressive removal rate for GGS, an SO 2 control
level of 0.36 lb/MMBtu has been selected for this a nalysis.

STEP 4—Evaluate Impacts and Document the Results

The fourth step in the BART analysis evaluates A) c osts of compliance, B) energy impacts, C) non-air quality environmental impacts, and D) remaining use ful life.

With respect to “remaining useful life,” this facto r is considered only if the source unit(s) being ev aluated have a relatively short life until expected permane nt shutdown, such that a typical amortization perio d for control equipment (e.g., 10-20 years) means that BA RT controls would not be useful for at least a norm al 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 Uni ts 1 & 2, factors A), B) and C) above have all been assessed by Sargent & Lundy (see Appendix A) in ter ms of their effects on potential costs to NPPD. Th e 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 th e 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 t he 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 SO 2 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 SO 2 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 i s not a large percentage of plant output, so it is not expected to require substantial replacement generat ion. However, the energy aspect of this analysis t allies 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, l and-filling the additional waste product, or obtain ing replacement material for the coal ash product curre ntly being consumed for beneficial reuse. The ener gy costs for off-site Trona production and delivery ac tivities are inherent in the delivered cost of the sorbent
at the site.

The non-air environmental impacts are primary due t o construction and operation of an additional landf ill that would be needed to hold the new waste product. In addition to the Trona-related mass of waste, t he 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 sam e CALMET/CALPUFF modeling system and software version numbers, and the same modeling protocol app roved for the 2008 BART Analysis for GGS and other BART-related modeling in Nebraska. HDR execu ted the CALPUFF model and post-processors for the DSI scenario, assuming baseline emissions of NO
x and PM components, and using an SO 2 emission
rate based on an emission factor of 0.36 lb/MMBtu a nd at maximum permitted heat input rate.Page 5

The DSI technology would not be expected to signifi cantly alter stack exhaust parameters, so these wer e kept the same as for the baseline scenario for inpu t to CALPUFF. An updated table of emission rates a nd stack parameters with the DSI scenario added is inc luded as Appendix B of this document.



### To provide the visibility impact modeling results i n a format that is most convenient for NDEQ use, we have copied the tabular summary of SO 2 

### BART control options and modeling results from Table 10.14 of the draft December 2010 NDEQ St ate 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 doll ars/year/change in deciviews ($/yr/  dV). All the edits to Table 10.14 for addition of the DSI op tion and for clarifying the data are shown in gray highlights in the edited table and its footnot es 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 meteorol ogy) cost/benefit metric, or cost effectiveness measured as $/yr/  dv, is presented in Table 2 for dry sorbent injecti on (DSI) of
Trona with SO 2 

### controlled to 0.36 lb/MMBtu, and for the two contr olled emission levels (0.15 lb/MMBtu and 0.10 lb/MMBtu) with wet flue gas desul furization (FGD), updated to year 2016
annualized costs. Note that the estimated annualiz ed 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 SO 2 

### 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 $ 142,860,500Page 6 

### Table 10.14: Incremental Visibility Effectiveness ( SO 2 

### Controls)
2001 2002 2003 Control Option Class I Area with Greatest Impact

from GGS Badlands Badlands BadlandsBaseline(no SO2Control) 

### SO 2 

### Modeled Emission Rate (lb/MMBtu) 0.749 0.749 0.749

Modeled 98 th 

### Percentile Value (dV) 2.845 2.828 3.121

Number of Days Exceeding 0.5 dV 54 55 60DSI Control Added(0.36 lb/MMBtu) 

### Modeled 98 th 

### 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 ImprovementFGD Control Added(0.15 lb/MMBtu) 

### Modeled 98 th 

### 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 $3,177,787FGD Control Added(0.10 lb/MMBtu) 

### Modeled 98 th 

### 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 impa irment improvement compared to baseline.

[2] The control can be achieved without additional cos ts, so total annualized cost/the overall incrementa l impairment improvement is calculated.

[3] Total annualized cost (capital + O&M) of DSI estima ted 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 Imp airment Improvement Cost” for each year of modelin g. 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 (differenc e 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 FG D options.

CONCLUSIONS

Based on the side-by-side comparison of SO 2 emission control with DSI technology to both dry a nd 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 uncertain ty in the ability of DSI to remove SO 2 emissions at any specified control level, and it i s concluded that DSI can
not be considered as BART for GGS Units 1 & 2.

## APPENDIX ANebraska Public Power District Project No. 12681-002

Gerald Gentleman Units 1&2 March 11, 2011

SL DSI Cost Analysis for GGS 03-11-2011 (2).doc Page 1 of 8

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 Retr ofit 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 retro fitting emissions control technologies to lessen the impact of Gerald Gentleman Station (GGS) on visib ility 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 SO 2 control and Low NO

x burners (LNB) and Selective Catalytic Reduction (SCR) for NO

x 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 applica tion at GGS. At Nebraska Public Power District’s (NPPD’s) request, Sargent & Lundy prepared a letter dated Januar y 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 consi deration, 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 techni cally 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. HD R 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 SO 2 reduction at GGS was based on the following:

Selection of a “target” stack SO 2 emission rate Selection of a sorbent type for reduction of SO 2 Selection of a sorbent stoichiometric ratio based on the SO 2 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.Nebraska Public Power District Project No. 12681-002

Gerald Gentleman Units 1&2 March 11, 2011

SL DSI Cost Analysis for GGS 03-11-2011 (2).doc Page 2 of 8 2.1 Selection of “Target” Stack SO 2 Emission Rate

DSI technology has demonstrated the capability of removing moderate amounts of SO 2 . However, DSI has not demonstrated that it can remove as much SO 2 as conventional wet or dry utility grade FGD technologies. In the 2008 BART Analysis, the candidate FGD technologies (conventional wet limestone and lime s pray dryer) were evaluated as being able to reduce SO 2 emissions to less than 0.15 lb/MMBtu for coals having as much as 2.27 lb SO 2 /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 rep resents a removal efficiency of about 93%. S&L’s expectation for a cost effective application of the DSI t echnology would be at a considerably lower efficiency and a much higher resultant SO 2 emission rate.

From publicly available information, we are aware that a recent BART analysis prepared for Boardm an Power Plant contained an evaluation of the use of DSI to lower emissions to 0.4 lb SO 2 /MMBtu subject to the results of pilot testing that would prove or disprove this capability. Also, it should be not ed 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 t o favor low capital and high operating cost technologies such as DSI.

Selection of a target SO 2 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 SO 2 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) SO 2 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 SO 2 /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 ultim ate emission limitation dependent on pilot testing. Without extensive GGS-specific modeling and actual fie ld 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 SO 2 than is lime; therefore lime is rarely evaluated for SO 2 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 SO 2 than a pound of Trona. However, bicarbonate is effective in a more limited flue gas temperature range making it less f lexible 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 need ed 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 woul d be a problem for GGS as will be discussed in the section of this report on stoichiometry. Second, GGS would consumeNebraska Public Power District Project No. 12681-002

Gerald Gentleman Units 1&2 March 11, 2011

SL DSI Cost Analysis for GGS 03-11-2011 (2).doc Page 3 of 8 such a large portion of the current total market production capability that bicarbonate’s avai lability 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 li kely 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 fig ure 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 compari son 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 stoic hiometric ratio to effectively deal with the selected emission rate. The normalized stoichiometric ratio i s defined in the literature and represents the amount of Trona injected to remove a selected amount of SO 2 . In the DSI industry, the stoichiometric ratio is correlated to removal efficiency and is usually presented in cu rves 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 limi ted. 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 requ ired at GGS. In addition, the curves are based mainly on industrial plant experience. Industrial plants perform significantly different fr om 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 t o conduct extensive modeling and field testing at GGS.Nebraska Public Power District Project No. 12681-002

Gerald Gentleman Units 1&2 March 11, 2011

SL DSI Cost Analysis for GGS 03-11-2011 (2).doc Page 4 of 8 Figure 1: Normalized Stoichiometric Ratio versus SO 2 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 injec tion location, the uniformity of injection across the ductwork, and the time of contact (i.e. residence time). Choosi ng the stoichiometric ratio is dependent on the aforementioned unit-specific parameters. As noted, the siz e of the Trona particle impacts the stoichiometric ratio and DSI suppliers have shown in recent tests th at smaller, not larger, Trona particle sizes are more effective in capturing SO 2 . 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. Th e reaction of Trona relies on the ability of the SO 2 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 SO 2 molecules. Trona has a characteristic that it will calcine (“popcorn”) and become more porous when injected at temperatures between 275 o F and 800 o F. If it is injected at greater than 800 o F or below 275 o F, then each Trona particle is not as effective, and more Trona is needed, to collect a given amount of SO 2 . The temperature profiles at GGS are not ideal (see discussion below) for this situation and, therefore, the Figure 1 curves do not accurately rep resent 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 optimist ic 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 temperat ure downstream of the secondary air preheater is below 275 o F for 74% of the operating hours. The temperatures upstream of the air heater are determined by the economizer outlet temperature. The Unit 1 economiz erNebraska Public Power District Project No. 12681-002

Gerald Gentleman Units 1&2 March 11, 2011

SL DSI Cost Analysis for GGS 03-11-2011 (2).doc Page 5 of 8 outlet temperature is above 800 o F for 29% of the operating hours and, if considering greater than 80% load, is above 800 o F for 36% of the operating hours. The Unit 2 data indicates the temperature downstream of the secondary air preheater is below 275 o F for 100% of the operating hours and the economizer outlet temperature is above 800 o F 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 applicati ons, the expectation for both removal efficiency and stoichiometry shown on this curve should be considered v ery 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 show n in Figure 2. This relationship is superimposed over the Solvay curve in Figure 1.

Figure 2: Normalized Stoichiometric Ratio versus SO 2 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 cost s 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 2 016 as the initial operation date and includes escalation.Nebraska Public Power District Project No. 12681-002

Gerald Gentleman Units 1&2 March 11, 2011

SL DSI Cost Analysis for GGS 03-11-2011 (2).doc Page 6 of 8 The capital costs are presented as several components (construction direct, other construction, i ndirect, 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, m illing, 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 upgrade s 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 applicat ion capital cost estimate uses 30% contingency (vs. 20% used in the FGD cost estimates) because the DSI order

of-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 SO 2 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 applic ation 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 per formance 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 a nd 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 permea bility soil, installation of a geomembrane, and placement of a protective cover for closure of the landfil l.

The DSI application will have an impact on the operation of the baghouse. The significant increa se in the solids loading to the baghouse will require the bags to be cleaned more frequently. Bag cleaning frequen cy has a direct impact on the life of the bag. The increased cleaning frequency will lessen the bag l ife 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 estimat es for each option considered escalated to 2016.Nebraska Public Power District Project No. 12681-002

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SL DSI Cost Analysis for GGS 03-11-2011 (2).doc Page 7 of 8 The data in Exhibit 3 is close to the side-by-side comparison that NDEQ requested, but is based on a DSI outlet SO 2 emission rate of 0.36 lb SO 2 /MMBtu, not the 0.15 lb SO 2 /MMBtu value used for FGD technologies. Evaluating the DSI technology at an outlet loading of 0.15 lb SO 2 /MMBtu and a corresponding SO 2 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 SO 2 ) 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 k eeping 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 SO 2 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. T he 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 wast e 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 whil e the sorbent is in transit. Finally, the handling of the baghouse waste streams have the potential to generate fugi tive 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 sol id waste quantity, there will be three times the amount of haul truck traffic which will also increase fugit ive emissions. All of these solids handling systems have the potential to increase fugitive dust emissi ons and must be controlled with additional dust control hardware and systems which increase both the capital requirement and O&M requirement.

4.0 Conclusion

I t 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 tha t required for either of the FGD technologies evaluated in the 2008 BART Analysis, the operating costs for the DSI sy stemNebraska Public Power District Project No. 12681-002

Gerald Gentleman Units 1&2 March 11, 2011

SL DSI Cost Analysis for GGS 03-11-2011 (2).doc Page 8 of 8 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 SO 2 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 1Dry 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% SO 2 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** 

Dr y Sorbent T ype Tron a Desi g n Removal Efficienc y 80% SO 2 Removal
Particulate Collecto r Ba g house

Annualized Variable O&M Cost : Bag Replacement Cos t $/y r 578,000 $ Dry Sorbent Cost $/y r 54,238,000 $ Waste Disposal Cos t $/y r 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 Cos t $/ y r 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 Cos t $/y r 1,200,000 $
TOTAL ESTIMATED ANNUALIZED O&M $2011 $/y r 61,105,000 $
TOTAL ESTIMATED ANNUALIZED O&M TO 2016$ $/y r 69,135,000 $**Nebraska Public Power District Gerald Gentleman Units 1&2** EXHIBIT 3Modification of Table 4 from 2008 BART Analysis, SO2 Cost of Compliance**Project No. 12698-002 March 11, 2011** **Dry FGD Wet FGD Dry Sorbent Injection Emission Rate (lb/MMBtu)** **0.15 0.15 0.36 Emission Reduction (tpy)** **39,815 39,815 25,857 Capital Costs ($)** **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 $** Eacalation factors to convert the above Table 4 to the below revised Table 4**Capital Escalation Rate (%) 2.5% 2.5%** **O&M Escalation Rate (%) 2.5% 2.5%** **Years of Escalation (#) 3** **3**Theoretical Normalized Stoichiometric Ratio**3.0**The above Table 4 but Escalated to 2016 1st year operating date (total for both Units)**Emission Rate (lb/MMBtu) 0.15 0.15 0.36** **Emission Reduction (tpy) 39,815 39,815 25,857** **Capital Costs ($) 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** **$***** 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.**DescriptionTechnology Options