Appendix A: EPA’s evaluation of cost of Flue Gas Desulfurization (FGD) controls

Nebraska Public Power District (NPPD) Gerald Gentlemen Station (GGS), Units 1 and 2

The following is an analysis of the cost effectiveness of the GGS BART analysis for dry 

scrubbers. Although we did not review the GGS BART analysis for wet scrubbers, we note that 

many of the same issues we discuss herein may apply to that analysis as well. We also note that 

with regard to the efficiency of wet scrubbers, “SO2 removals of 95% are common and removals 

as high as 98% can be attained.”1 This is a much higher efficiency than Nebraska assumed for 

the GGS in its BART analysis.

Based on EPA’s re-evaluation of Nebraska’s cost estimates, we do not consider GGS’s 

cost calculation for dry scrubbers to be cost prohibitive. However, we noticed some errors in 

that cost analysis, and believe it is appropriate to correct them. In so doing, it should be noted 

that this review is not intended to be comprehensive, and is only intended to address some of the 

more significant errors. There are several more cost items (e.g., 10% profit, 5% general and 

administrative, labor, levelized outage cost, etc.) we may possibly address in a future analysis. In 

addition, we were hampered by the absence of some information that would have resulted in a 

more comprehensive analysis, such as the vendor quotes GGS apparently relied upon for its 

capital costs, and most design information (e.g., water, lime, electricity). Lastly, we note that in a 

BART analysis, the cost effectiveness in terms of annualized cost divided by tons of SO2

removed ($/ton) must be balanced against the projected visibility benefit. However, Nebraska 

assessed the visibility benefit of the installation of dry scrubbers assuming a SO2 reduction to 

0.10 lbs/MMBtu. As we discuss below, greater levels of control are achievable. Consequently, 

we believe it is likely that the visibility benefit, if properly assessed, would be greater than what 

Nebraska has modeled.

1. Engineering Procurement and Construction

GGS assumes an Engineering Procurement and Construction (EPC) fee of 20% of the 

total cost, but does not provide any discussion or explanation for this cost. The EPC fee for Units 

1 and 2, and the auxiliary power do calculate to 20% of the total cost. However, the EPC fee for 

the common facilities, calculated on the basis of 20% of their total costs, calculates to 

$25,478,000, not $30,754,000 which is what GGS calculates. This unexplained deviation is 

carried through to the EPC calculation of $100,367,000 for the total station. This could be a 

result of a note in the common facilities estimate (pdf26) that states “SEE AUX POWER EST” 

for an electrical cost. However, all electrical costs appear to be already included in the auxiliary 

power and fans costs. Adjusting the EPC fee to be 20% of total project would result in the total 

EPC fee to be $95,092,000 as opposed to GGS's calculation of $100,367,000. 

Nevertheless, this fee is high in comparison to other BART analyses we have seen such 

as the Oklahoma Gas and Electric Sooner and Muskogee BART analyses, also performed by 

GGS’s contractor, Sargent and Lundy (S&L). In that cost analyses, S&L estimated engineering 

 1

 Wet Flue Gas Desulfurization Technology Evaluation, Project Number 11311-000, Prepared For National Lime 

Association, January 2003, Prepared By Sargent and Lundy, page 13.
and procurement, an "indirect capital cost," as 6.5% of the total direct costs2

, which if applied 

here, would result in a much lower figure. In addition, the Control Cost Manual3estimates 

engineering and procurement as 10% of the purchased equipment cost (as opposed to the total 

cost GGS employs), which would also result in a much lower figure. Although not supplied, 

GGS indicates in its BART analysis that all the major equipment items are based on vendor 

quotes.4 Vendor proposals typically contain engineering and procurement costs associated with 

the equipment that is supplied. We have no reason to conclude that is not the case here, but 

invite GGS to provide documentation to the contrary, should it believe this to be in error. The 

following items are identified by GGS as being supported by vendor quotes (retaining GGS’s 

designations and numbering for these items) in Appendix A to its BART analysis:

1. Lime Handling common to both Units

2. Lime Preparation per Unit

3. Absorber Area per Unit

4. Recycle Area per Unit

5. Baghouse Ash Handling System common to both Units

16. Baghouse Modifications per Unit

26. New booster ID fans-All

The above items, therefore, should not be a part of the EPC calculation. Similarly, the 

following items are identified by GGS as not being supported by vendor quotes and would be 

expected to be a part of the EPC calculation:

6. Flues including support steel per Unit

7. Control System Modifications per Unit

8. Rail Yard Extension common to both Units

9. Subsurface and Foundation Work- All

10. Civil Work- All

11. Construction Work- All

12. Pipe Racks common to both Units

13*. Chimney per Unit

 2

 Appendix A, Revised BART Cost-Effectiveness Analysis for Flue Gas Desulfurization at Coal-Fired Electric 

Generating Units in Oklahoma: Sooner Units 1 & 2 Muskogee Units 4 & 5 Northeastern Units 3 & 4 Final Report, 

October 2010.

3

 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002 4

 Dry FGD And Id Fan & Auxiliary Power Conceptual Design Costs Conceptual Cost Estimate Prepared For 

Nebraska Public Power District Gerald Gentleman Station, Units 1&2, Project No. 12194-001, February 7, 2008. 

See pdf pages 8-12.
17. Demolition and Relocation

18. CEMS per Unit - no change, use existing CEMS in chimney

19. Water Treatment common to both Units

20. Instrument air compressor and dryer common to both Units

21. Field Painting – All

22. Performance Testing- All

23. Construction Support- All

24. Piping per Unit

25. Installation- All

27. Electrical-All

*Note, GGS does not include any items numbered from 14 to 15, inclusive in the above list.

Furthermore, we have no reason to believe that the EPC fee should be 20%, as opposed to 

the 6.5% employed by S&L in its Oklahoma Gas and Electric (OG&E) BART cost evaluation 

for the Sooner and Muskogee facilities. Therefore, we have recalculated the EPC fee to be 6.5% 

of the above items that are not supported by vendor quotes. This calculation appears in line 27 

of appendix C to our TSD. We invite GGS to provide clarification as to why the EPC percentage 

for units 1 and 2 should be higher that its vendor employed for the BART cost estimation for the 

OG&E units.

2. Bond Fees

On pdf page 6 of Appendix A, GGS states that indirect costs include bond fees, and on 

pdf page 7, GGS states they are equal to 2.5% of $200M, which would be $5M. However, GGS 

does not state what this $200M figure represents. We agree that utilities incur some costs in 

issuing debt, but this cost is normally imbedded in the interest rate. However, in this case we 

cannot determine whether the interest rate GGS uses in its computations (5.25% nominal) 

includes those costs. As we state in our response to comments in our Federal Implementation 

Plan (FIP) for Oklahoma: 5

In most cases, the issuer of corporate debt does not pay the underwriters 

directly for their service, but instead sells the bonds to the underwriters at 

a discount. The underwriters’ compensation comes from the difference 

between the price they pay for the bonds and the price at which they can

sell them. Hence, the debt issuance costs do not represent a cash payment 

at the time the plant is built, but a small increment in the repayment at 

maturity, twenty or thirty years in the future. Thus, bond costs are usually 

 5 Response to Technical Comments for Sections E. through H. of the Federal Register Notice for the Oklahoma 

Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA-R06-OAR-2010-0190, 

12/13/2011, page 19.
included as part of the cost of debt, rather than the capital cost of the 

project. 

We also question why the pollution control equipment cannot be financed in part with 

Pollution Control Bonds, at very low tax-exempt interest rates. Therefore, we exclude these costs 

from our revised cost analyses by subtracting $5M from the indirect costs for units 1 and 2 of 

$47,452,000. This calculation appears in line 31 of appendix C to our TSD. We invite GGS to 

provide documentation of these costs, which should include a detailed breakdown of the Capital 

Recovery Factor (CRF), which itself includes the interest rate. 

3. Escalation

GGS incorporates an escalation cost of $120,449,000, which it states on pdf page 7 of 

Appendix A, was estimated on the basis of 5.0% for Equipment, 7.0% for Material, 4.0% for 

Labor and 6.0% for Indirects. As we have discussed in our response to comments in our FIP for 

Oklahoma,6 the Control Cost Manual employs the overnight cost method, which is the cost of a 

construction project as if the project is completed overnight in current dollars. Thus, escalation 

of current dollars to future dollars is never valid under the Control Cost Manual overnight cost 

approach. Consequently, we have excluded escalation from our revised cost analysis. This 

calculation appears in line 32 of appendix C to our TSD. 

4. Contingency

GGC incorporates a contingency cost of $148,745,000, which it states on pdf page 7 of 

Appendix A, was estimated at 20% of equipment, material, labor and indirect costs. No 

information was provided to justify the need for this rate. As we note earlier, GGS states that the 

lime handling and preparation, the absorber area, the recycle area, the baghouse ash handling 

system, the baghouse modifications, and the booster id fans are all supported by vendor quotes. 

Thus we would expect that the need for contingencies for these cost items would be minimized. 

As we discuss in our response to comments in our FIP for Oklahoma,7

Under the overnight cost estimating method in the Cost Control Manual, 

contingency has a specific definition: "A contingency factor should be 

reserved (and applied to) only those items that could incur a reasonable 

but unanticipated increase but are not directly related to the demolition, 

fabrication, and installation of the system. For example, a hundred year 

flood may postpone delivery of materials, but their arrival at the job site is 

not a problem unique to a retrofit situation."8

The Control Cost Manual definition for the equipment included in the Manual that is 

most similar to the proposed controls is a wet scrubber for acid gases (similar to the spray dryer 

absorber) and a baghouse (included in a spray dryer absorber system). In both of these cases, the 

 6

 Ibid, page 14-15, and elsewhere. 7

 Ibid, page 20. 8

 Control Cost Manual, Sec. 2.5.4, p. 2-30. 
Control Cost Manual specifies the contingency as 3% of the purchased equipment cost.9

Therefore, we revised our cost analysis to incorporate a contingency of 3% of the purchased 

equipment cost. This calculation appears in line 34 of appendix C to our TSD.

5. Allowance for Funds Used During Construction

GGS incorporates an Allowance for Funds Used During Construction (AFUDC) cost of 

$83,302,000, in the “Other Cost” category, which it states on pdf page 7 of Appendix A as being 

estimated to be 5% from 2009. As we discuss in our response to comments in our FIP for 

Oklahoma,10

AFUDC is the cost of capital that is incurred to finance the project during 

the construction period. The overnight cost method is the cost of a 

construction project if no interest is incurred during construction, as if the 

project is completed overnight. Thus, AFUDC is never valid under the 

Control Cost Manual overnight cost approach. Neither is AFUDC a “site 

specific design or other condition[s]11” that can be considered under the 

RHR and the Control Cost Manual.

Therefore, we exclude these costs from our revised cost analyses by subtracting 

$83,302,000 from the other costs category. This calculation appears in line 35 of appendix C to 

our TSD. 

6. Capital Recovery Factor

GGS does not include its calculation of a Capital Recovery Factor (CRF), which is 

necessary to calculate annualized (levelized) costs. However, using its real interest rate of 5.25% 

(which we adopt, but on which we form no opinion here), and its amortization life of 20 years, 

we can duplicate GGS’s capital cost of $80,875,000, using a CRF we calculate of approximately 

0.08195.12 See line 40 of appendix C. However, applying the same formula to the levelized 

capital cost to GGS’s case in which the fan is sized to accommodate only the dry scrubber, 

should yield a figure of $80,444,000, instead of the $80,013,000 GGS calculates. 

Nevertheless, we take issue with GGS’s assumption of a 20 year amortization life, which 

equates to an assumption that the dry scrubber has an operational life of only 20 years. As we 

discuss in our response to comments in our FIP for Oklahoma,13 the annualization period should 

equal the projected service life of the equipment:

In the section of the Control Cost Manual on the capital recovery factor, 

the subject of this comment, control equipment lifetime is clearly defined 

as the entire life of the control. For example, on page 2-19, the Control 

 9

 Control Cost Manual, Section 5.2, Post-Combustion Controls, Chapter 1: Wet Scrubbers for Acid Gas, Table 1.3 

and Section 6, Chapter 1: Baghouses and Filters, Table 1.9. 

10 Ibid, pages 15-19. 11 70 FR 39166. 12 CRF=(0.0525*(1.0525^20))/(1.0525^20-1) = 0.08195. Levelized Capital Cost = CRF*Total Capital Cost. 13 Response to Technical Comments for Sections E. through H. of the Federal Register Notice for the Oklahoma 

Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA-R06-OAR-2010-0190, 

12/13/2011, pages 36-39.
Cost Manual states: “For each alternative: calculate a discounting factor 

each year over the life of the equipment....” and on page 2-21: “In 

essence, annualization involves establishing an annual "payment" 

sufficient to finance the investment for its entire life, using the 

formula...[CFR]...where PMT is the equivalent uniform payment amount 

over the life of the control, n, at an interest rate, i.”14 The variable n in 

the CRF equation used to annualized total capital investment is thus the 

actual life of the control, as we used in our revised cost analysis, and not 

the economic life as argued in this comment. 

While Table 2.3 in the Control Cost Manual does mention an "economic 

life," the text proceeding the table defines "economic life" as "useful life."15 The 

term "useful life" as used in the Control [Cost] Manual is the same as the actual 

service life, at the end of which the equipment is replaced. See, for example, page 

2-18: “While payback considers both projects to be equal, the second project 

would actually cost more over the ten year period because it would have to be 

replaced at the end of its useful life.” See also page 2-20: “So, instead of paying 

up front for all the future costs of installation, maintenance, and operation of a 

pollution control device (NPV analysis), what if the payment could be equalized 

(in constant net present value dollars) over the life of the control?”16 Thus, under 

the Control [Cost] Manual definition, equipment is replaced at the end of its 

useful life and is synonymous with service life or equipment life.

In addition, in our response to comments referenced above, we reviewed 

information we presented in our proposal in which we demonstrate that the 

service life of a dry scrubber is easily 30 years. GGS has not offered to execute 

an enforceable commitment to shut down after 20 years. Thus, we adopt a dry 

scrubber service life here of 30 years in our calculation of the CRF, which equates 

to approximately 0.06691.17 We use this CRF in our recalculation of GGS’s 

levelized costs. This calculation appears in line 40 of appendix C to our TSD.

7. Operation and Maintenance

GGS employs a levelized fixed O&M cost of $7,812,000 and a levelized variable O&M 

cost of $19,994,000. Although GGS does not document the individual cost items contained in the 

fixed O&M cost, we can duplicate the fixed O&M cost by using the information contained in 

the financial model cases 13 and 14 on pdf 4 and 5. 

However, we cannot duplicate the levelized variable O&M cost. GGS states on page 16 

of its BART analysis,18 that variable O&M costs include, “ the cost of consumables, including 

reagent (lime or limestone), by-product management, bag replacement for the baghouse, water 

consumption, and auxiliary power requirements. Auxiliary power costs reflect the additional 

 14 Control Cost Manual, pp. 2-19, 2-21, emphasis added. 15 Control Cost Manual, p. 26. 16 Control Cost Manual, pp. 2-18, 2-20. 17 CRF=(0.0525*(1.0525^30))/(1.0525^30-1) = 0.06691. 18 REVISED Best Available Retrofit Technology (BART) Analysis for Units 1 & 2 Gerald Gentleman Station, 

Sutherland, Nebraska, February, 2008.
power requirements associated with operation of the new FGD control system, including 

operation of any new ID fans as well as the power requirements for the absorber pumps, reagent 

handling, reagent preparation, and by-product handling.” Adding the individual costs for these 

items from the financial model cases 13 and 14 does not result in the variable O&M cost GGS 

lists on pdf page 3 of Appendix A. 

There are no calculations provided to support the lime, water and waste disposal costs. 

Furthermore, we note that the financial model cases 13 and 14 list the annualized tons of SOx

removed to be 40,426 for unit 1 and 41,003 for unit 2. Because as we discuss below, each one of 

these unit reductions exceeds the total historical SO2 emission of both units 1 and 2 together, we 

have reason to doubt the validity of the O&M costs that were apparently based on these 

reductions. Therefore, although we adopt these O&M costs in our analysis, we invite GGS to 

provide documentation for them. Furthermore, because these costs were calculated based on an 

assumed 20 year amortization period (20 year scrubber service life), as discussed above, they 

must be adjusted to a more reasonable 30 year period. We note that GGS uses the same CRF of 

approximately 0.08195 in model cases 13 and 14. Therefore, we adjust the levelized capital, 

outage, and O&M costs by multiplying GGS’s figures by the ratio of our CRF to their CRF.19 

This calculation appears in lines 47-51 of appendix C to our TSD.

Later, we discuss how we further adjusted GGS’s levelized variable O&M cost to 

account for the smaller amount of SO2 removed, due to our adjusted SO2 baseline.

8. SO2 Emission Baseline

On page 15 of its BART analysis, GGS calculates its SO2 emission baseline based on 

applying what it states is a 24 hour maximum emission rate of 0.749 lbs/MMBtu (2001-2003) to 

a maximum heat input of 15,175.5 MMBtu/hr, based on a 100% capacity factor. This results in a

emissions baseline of 49,785 tons/yr.20 We believe this calculation does not appropriately 

represent GGS’s SO2 emission baseline, and is in fact too high.

The Regional Haze Rule provides the following regarding the calculation of the BART 

emissions baseline:

The baseline emissions rate should represent a realistic depiction of 

anticipated annual emissions for the source. In general, for the existing 

sources subject to BART, you will estimate the anticipated annual 

emissions based upon actual emissions from a baseline period. When you 

project that future operating parameters (e.g., limited hours of operation 

or capacity utilization, type of fuel, raw materials or product mix or type) 

will differ from past practice, and if this projection has a deciding effect in 

the BART determination, then you must make these parameters or 

assumptions into enforceable limitations. In the absence of enforceable 

limitations, you calculate baseline emissions based upon continuation of 

past practice.

 19 EPA’s levelized costs = GGS’s levelized costs * (0.06691/0.08195). 20 (0.749 lbs/MMBtu) * (15,175 MMBtu/hr) * (8,760 hrs/yr) * (ton/2,000 lbs) = 49,785 tons/yr.
We see no indications that the GGS’s future operating practices are projected to deviate 

from the past. Therefore, similar to our action with regard to the emission baseline of the Four 

Corners Power Plant,21 we adjust GGS’s SO2 emission baseline to better reflect its historical 

emissions. GGS states on page 2 of its BART analysis that it used a baseline period of 2001-

2003, which was the baseline emission rate period for BART modeling in Nebraska. We have 

downloaded emissions data for GGS from our Clean Air Markets web site22and have calculated 

the average total station SO2 emissions for GGS Units 1 and 2 to be 31,513 tons/yr for the three 

year period of 2001-2003. We note that based on GGS’s stated nameplate capacity of Units 1 

and 2 (665 and 700 MW, respectively), we calculate capacity factors for Units 1 and 2 to range 

from 89% to 94% and 77% to 85%, respectively, from 2001-2003. Our analysis assumes this 

historic usage is not significantly altered in the future. A summary of this data appears in 

appendix B to our TSD.

9. SO2 Emissions Reduction

On page 15 of its BART analysis, GGS calculates that as a result of the installation of dry 

scrubbers at both units 1 and 2, its SO2 emission baseline of 49,785 tons/yr would be reduced to 

9,970 tons/yr, resulting in a reduction of 39,815 tons of SO2 annually. This assumes an 

uncontrolled SO2 emission rate of 0.749 lbs/MMBtu and a controlled SO2 emission rate of 0.15 

lbs/MMBtu, which equates to a scrubber efficiency of approximately 80%. Because, as noted 

above, we propose to find the SO2 emission baseline of 49,785 tons/yr to be too high, we must 

correspondingly adjust the projected emission reduction. 

Using the same emissions data described above from the three year averaging period of 

2001-2003, we have calculated the three year average annual SO2 emissions for units 1 and 2 of 

the GGS to be 0.565 lbs/MMBtu.23 Reducing this to a controlled SO2 emissions level of 0.15 

lbs/MMBtu results in a scrubber efficiency of approximately 73.5%. Applying this level of 

control to our adjusted GGS SO2 emission baseline of 31,513 tons/yr would reduce it to 8,366 

tons/yr, resulting in a reduction of 23,147 tons of SO2 annually. Applying the same approximate 

80% level of reduction GGS assumes to our adjusted GGS SO2 emission baseline of 31,513 

tons/yr would reduce it to 6,311 tons/yr, resulting in a reduction of 25,202 tons of SO2

annually.24 However, as we have demonstrated in our Oklahoma FIP decision, which also 

involved the cost effectiveness calculation of dry scrubbers on boilers burning a similar Powder 

River Basin coal, dry scrubbers are capable of much greater control efficiencies than the 80% 

level that GGS assumes.25 We see no reason to believe that the GGS is not capable of the same 

level of control. Therefore, for the purpose of calculating the cost effectiveness of dry scrubbers 

at the GGS, we have assumed the same SO2 emission limit of 0.06 lbs/MMBtu, which results in 

a scrubber efficiency of approximately 89.4%. Applying this level of control to our adjusted 

 21 74 FR 44321. 22 http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=emissions.wizard 23 See Attachment B to our TSD. Based on adding the station total pounds of SO2 emissions from 2001-2003 and 

dividing by the station total heat input from 2001-2003. 24 (39,815/49,785)*31,513 = 25,202. 25 Response to Technical Comments for Sections E. through H. of the Federal Register Notice for the Oklahoma 

Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA-R06-OAR-2010-0190, 

12/13/2011, Section II., Comments Relating to Our SO2 BART Emission Limit, and elsewhere.
GGS baseline of 31,513 tons/yr would reduce it to 3,347 tons/yr, resulting in a reduction of 

28,166 tons of SO2 annually. 

In order to calculate the cost effectiveness in terms of the annualized cost (total levelized 

capital, outage, and O&M cost) divided by the tonnage of SO2 reduced, we must further adjust 

GGS’s calculation of the variable O&M cost, to account for the reduced mass of SO2 that would 

be treated by the scrubber due to the reduction in the SO2 baseline. In other words, we assume 

GGS instructed its vendors to cost a dry scrubber system capable of removing 39,815 tons of 

SO2, which as stated above, it indicates in its BART report would be the tonnage reduced from 

its baseline. This would require an amount of lime and water sufficient to treat this mass of SO2,

with a commensurate cost for waste disposal. Because we have reduced the GGS SO2 baseline to 

a more realistic value, under all the treatment scenarios discussed above, the mass of SO2

reduced would be much less that the 39,815 tons/yr GGS assumed. Therefore, as the variable 

O&M costs include the cost of lime, water, and waste disposal costs, we believe it is reasonable 

to reduce those costs accordingly. However, GGS has not disclosed its design criteria for these 

items. Therefore, we approximate the reduction in the variable O&M costs in the treatment 

scenarios discussed above, by multiplying GGS’s variable O&M costs by the ratio of the 

corresponding EPA SO2 reduction divided by GGS’s SO2 reduction.26 Should GGS believe this 

approach is overly conservative, we invite it to provide the proper design criteria to enable this 

adjustment to be made more accurately.

10. Cost Effectiveness

We calculate the cost effectiveness for these various scenarios in appendix C to our TSD. 

These results are summarized here:

Range of GGS Dry Scrubber Cost Effectiveness

SO2

Baseline

Uncontrolled 

SO2 Emission 

Level 

(lbs/MMBtu)

Controlled 

SO2

Emission 

Level 

(lbs/MMBtu)

Percent 

Reduction

SO2

Emission 

Reduction 

(tons)

Cost 

Effectiveness 

($/ton)

GGS 49,785 0.749 0.15 80% 39,815 2,726

EPA 31,513 0.565 0.15 73.5% 23,147 2,310

EPA 31,513 0.565 0.11 80% 25,202 2,156

EPA 31,513 0.565 0.06 89.4% 28,166 1,972

We find that the cost effectiveness of SO2 scrubbers for units 1 and 2 of the GGS facility 

should range between $1,972/ton and $2,310/ton. 

 26 For example, baseline = 31,513, SO2 emission limit = 0.15, reduction = 23,147 tons SO2: Variable O&M = GGS 

variable O&M*(23,147/39,815).