1

Appendix G: Responses to comments and revisions to EPA’s evaluation of cost of Flue Gas 

Desulfurization (FGD) controls at Nebraska Public Power District (NPPD) Gerald 

Gentlemen Station (GGS), Units 1 and 2

This appendix responds to comments made about our evaluation of the cost estimation for dry

FGD control at GGS. 

1. Comment: NPPD objects to our lowering of the SO2 emissions baseline at GGS Units 1 and 2 

from 49,785 tons/yr to 31,513 tons/yr as part of our analysis of the cost of FGD controls. 

NPPD states that GGS is configured to be able to burn coal from any of the various mines in 

the Powder River Basin of Wyoming. Such coals can vary in sulfur content from a low of 

about 0.28% sulfur to a high of about 1.0% sulfur. Any future modifications to GGS, states 

NPPD, including the installation of FGD control technology, would be required to preserve 

this capability. In objecting, NPPD cites our Oklahoma Regional Haze SIP decision, in which 

we determined that the SO2 baseline should be increased for essentially the same reasons 

they now cite. In fact, NPPD states that in EPA’s Oklahoma final decision, we argued that it 

would be in the owner's best interest to build an FGD based on design fuel characteristics 

that allow the facility to utilize a range of coals, "as it is not only more cost effective, but it 

provides greater flexibility in future operations.” NPPD claims our statements in paragraph 8 

of Appendix A to the TSD are contradictory to the position advocated by EPA in Oklahoma, 

in which we apparently increased the baseline SO2 emissions and thereafter took credit for 

the additional tons of SO2 removed in EPA's calculation of control system cost effectiveness.

Response: In our proposed cost evaluation of dry scrubbers for GGS, we noted that 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. Based on emissions data for GGS from our 

Clean Air Markets web site, we calculated the average total SO2 emissions for GGS Units 1 

and 2 to be 31,513 tons/yr for the three year period of 2001-2003. We further noted that the 

regional haze rule states that the baseline emissions rate should represent a realistic depiction 

of anticipated annual emissions for the source, and that we saw no indications that the GGS’s 

future operating practices are projected to deviate from the past. In section 9 of Appendix A 

of our TSD, we calculated that this adjustment of the SO2 baseline would also lower the 

projected SO2 reductions from GGS’ projection of 39,815 tons/yr to either to 23,147 tons/yr 

based on a controlled SO2 emission limit of 0.15 lbs/MMBtu or 28,166 tons/year, based on a 

controlled SO2 emission limit of 0.06 lbs/MMBtu. As we also discuss in Section 9 of 

Appendix A, our adjustment of the SO2 baseline required a further adjustment to the O&M 

costs to account for the reduced lime, water, and waste disposal costs. As our BART 

Guideline cost effectiveness metric is expressed in terms of dollars per ton of pollutant 

removed ($/ton), our lowering of GGS’s SO2 emission baseline had the conservative effect of 

decreasing the cost effectiveness. However, taking NPPD’s objection into account, and 

increasing our SO2 baseline of 31,513 tons/yr to NPPD’s desired level of 49,785 tons/yr has 

the effect of increasing our calculated cost effectiveness from $2,310 to $1,515/ton for the 
2

0.15 lbs/MMBtu control case; from $2,156 to $1,446/ton for the 0.11 lbs/MMBtu control 

case; and from $1,972 to $1,371/ton for the 0.06 lbs/MMBtu control case.1

2. Comment: NPPD, through another contractor, Burns and McDonnell (BMcD), objects to our 

revising the Engineering Procurement and Construction (EPC) fee of 20% of the total cost of 

the dry scrubber estimate made by NPPD’s original contractor, Sargent and Lundy (S&L). 

NPPD objects to our changing the value of this charge from 20% to 6.5% for those 

components of the estimate for which there is no indication that vendor quotes were 

obtained. NPPD states this approach is flawed because the "EPC Fee" is not an engineering 

charge, and thus should not be removed from any particular line item of the cost estimate 

simply because that line item was based on a vendor quote. NPPD states the EPC fee does 

not represent an engineering charge but an overall cost premium associated with that 

contracting approach and is a real cost to the project. NPPD states this is well established in 

the industry and the EPC contractor will typically increase the value of the "fixed price" bid 

for a project such as this to account for the risk of price increases that may occur after the 

subcontracts are awarded. Whether the individual components of the equipment and material 

for the project have been estimated based on "vendor quotes" or not, states NPPD, this risk 

still exists and is real. So, given that the basis of the cost estimate has been clearly defined to 

include the assumption of "EPC contracting approach", concludes NPPD, it is not appropriate 

for us to eliminate this charge from those items for which the estimate indicates a vendor 

quote was the basis for the cost estimate. NPPD then outlined how it determined S&L’s 

actual engineering fees through an examination of that contractor’s accounting methodology

and concluded the estimated costs for the various engineering functions appeared reasonable 

when compared to similar projects. NPPD then stated the Control Cost Manual uses the 

following percentages that are based on the purchased equipment cost rather than the direct 

cost as shown above: Engineering: 10%; Construction and field expenses: 10%; Startup: 1%; 

Performance Test: 1%. When adjusted for the differences between purchased equipment cost 

and direct cost, NPPD's comparison indicates that the values used in its contractor’s cost 

estimate for Dry FGD at GGS are lower than the above percentages allowed by our Control 

Cost Manual.

Response: Contrary to NPPD’s assertion, we did not confuse EPC costing methodology with 

an engineering charge. We are aware that an EPC contract is a costing mechanism in which a 

contractor assumes the risks and responsibility for all elements of engineering, procurement, 

and construction, in exchange for a cost premium. 

We stated that NPPD assumes an EPC fee of 20% of the total cost, but did not provide any

discussion or explanation for this cost. We also concluded this fee was 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 NPPD’s contractor S&L, which estimated 

engineering and procurement, an "indirect capital cost," as 6.5% of the total direct costs. 

Furthermore, we noted that the Control Cost Manual estimates 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 cost. We stated that although not supplied, GGS indicates 

 

1 These corrections are provided in Appendix C - revised, although additional adjustments we make to the cost 

effectiveness in response to other comments alters these values. 
3

in its BART analysis that all the major equipment items are based on vendor quotes, which 

typically contain engineering and procurement costs associated with the equipment that is 

supplied. We invited GGS to provide documentation to the contrary, should it believe our 

adjustment to be in error. 

NPPD did not provide the additional information necessary to address any of these issues 

discussed in the proposal. The information provided did not justify the 20% fee to the cost of 

the project, and did not explain why this fee was high in comparison to other projects 

NPPD’s contractor had estimated. Additionally, NPPD did not provide evidence that 

engineering, planning, and construction was not included for those items covered by its 

vendor quotes. Instead, assuming we confused the EPC fee with fees for engineering, it 

presented a summary of its interpretation of the engineering fees in the GGS dry scrubber 

cost analysis prepared by S&L, and presented information it believes justifies those 

engineering fees. Lacking this information, EPA has determined that the addition of the 20% 

fee to the total cost of the dry scrubber estimate, which amounts to over $100 million is 

unjustified, and not acceptable. Thus, we see no reason to modify our proposed adjustment 

to this cost.

3. Comment: NPPD objects to our elimination of the bond fee, which amounts to $5 million. 

NPPD states that our implied assumption that this cost was associated with the issuance of 

debt is incorrect. NPPD states that the Nebraska Statutes at Section 52-118 require a political 

subdivision, such as Nebraska Public Power District, that enters into a contract for the 

erection of a public building or structure, to obtain a payment bond in the amount of the 

contract, conditioned on the payment of the costs for the laborers, materials and rented 

equipment used during the performance of the contract. NPPD explains under the provisions 

of the Nebraska Statutes at Section 70-641, the penal sum of the contractor's bond required 

under Section 52-118 shall be the lesser of the contract amount or $200 million. NPPD 

anticipates this contract that will exceed $200 million, so the cost for a bond in the amount of 

$200 million was included in the project cost estimate. NPPD’s experience has shown that 

the cost of such a payment bond for contractors in good standing is expected to be 2.5% of 

the amount of the contract, which is typical for a payment bond for a project of this type. 

NPPD concludes the required payment bond in the amount of $5 million is a legitimate 

component of the cost estimate, and should not have been disallowed by us.

Response: In our proposal, we disallowed this cost because NPPD did not state what the $200 

million bond represented, and suspected it was a part of the financing of the project. We 

invited NPPD to provide documentation of these costs, which they have now done. We 

accept NPPD’s explanation for this cost and add it back into our cost evaluation for dry

scrubbers at GGS. These corrections resulted in only a minimal impact on the cost 

effectiveness, and are present in EPA Appendix C - revised.

4. Comment: NPPD objects to our disallowance of escalation, stating that we are in error that 

the Control Cost Manual never allows escalation of current dollars to future dollars within 

the context of what we term the "overnight cost method." NPPD states the term "overnight 

cost method" does not appear in the Control Cost Manual. NPPD states that the purpose of 

the BART economic evaluation is to allow comparison of costs (and therefore control cost 

effectiveness) between projects so that an "apples to apples" comparison can be made. 
4

NPPD’s view is that in order to make such a comparison between projects having cost 

estimates based in different years, it will be necessary to use a combination of escalation and 

de-escalation so that the costs of two or more projects can be evaluated on a common basis. 

NPPD states it made such a comparison,2to remove the effect of escalation, and to remove 

the effects of other factors including the EPC fee, Allowance for Funds Used During 

Construction (AFUDC), and escalation. NPPD concludes the comparison shows that the cost 

estimates for wet FGD and dry FGD for NPPD's GGS Units 1 and 2 are representative of 

cost estimates for similar projects at similar utility units for which FGD retrofits were done.

Response: As we stated in our proposal, GGS incorporates an escalation cost of 

$120,449,000, which it states on page 7 of Appendix A of the BART analysis, 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 proposal, 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 see no 

reason to conclude our proposed exclusion of escalation from our revised cost analysis was 

incorrect, and make thus no change regarding it. 

5. Comment: NPPD, through its contractor, BMcD, objects to our reduction to the contingency

cost of 20% of equipment, material, labor and indirect costs to 3% of the purchased 

equipment cost. NPPD states that apparently we believe that the inclusion of contingency at 

the level of "3% of purchased equipment cost" must be universally applied simply because it 

is found in the Control Cost Manual Table 1.3, "Capital Cost Factors for Gas Absorbers" in 

Section 5.2, Chapter 1 and in Table 1.9, "Capital Cost Factors for Fabric Filters" in Section 6, 

Chapter I. NPPD states we fail to mention that in other sections of the Control Cost Manual 

contingency factors much higher than 3% are applied in "Capital Cost Factor" tables 

analogous to the two cited by us. NPPD cites to Table 1.4, "Capital Cost Factors for an 

SNCR Application" (Section 4.2, Chapter 1), and Table 2.5, "Capital Cost Factors for an 

SCR Application" (Section 4.2, Chapter 2) where two contingency factors higher than 3% are 

used. First, states NPPD, a contingency factor of 5% of Total Direct Capital Costs is applied, 

then a second contingency factor of 15% of the sum of Direct Capital Costs and Indirect 

Installation Costs is applied. NPPD concludes it is not true that the Control Cost Manual 

consistently uses a 3% contingency.

NPPD states we took a quote from the Control Cost Manual out of context to support our 

reduction in its contingency cost. NPPD states that this is the section of the Control Cost 

Manual that deals with a discussion of "retrofit factors" and differentiates retrofit factors 

from "contingency factors" in the instance when both factors are used in a single cost 

estimate. Because, states NPPD, its cost estimate for Dry FGD at GGS Units I and 2 does not 

use "retrofit factors," its contingency serves the same function as the "retrofit factor" as 

discussed in section 2.5.4.2 of Section 1, Chapter 2 of the Control Cost Manual:

 

2

 NPPD states the presentation file is available in the docket for this rulemaking as document EPA-R07-0AR-2012-

0158-0008, in the attachment titled "Gerald Gentleman BART". Within this 146 page attachment the presentation 

slides are reproduced on pages 3 through 27. Slide 23 (pg. 25).
5

However, the retrofit factor is a kind of contingency factor and the cost 

analyst must be careful to not impose a double penalty on the system for 

the same unforeseen conditions. Retrofit factors should be reserved for 

those items directly related to the demolition, fabrication, and installation 

of the control system.

NPPD states that S&L, in developing its cost estimate, has followed the 

instruction of the Control Cost Manual by including not only what S&L calls 

a contingency factor, but which has the characteristics of a retrofit factor as it 

is defined in the Control Cost Manual. Section 2.5.4.2 of Section 1, Chapter 2 

of the Control Cost Manual explains retrofit factor as follows:

To quantify the unanticipated additional costs of installation not directly

related to the capital cost of the controls themselves, engineers and cost 

analysts typically multiply the cost of the system by a retrofit factor. The 

proper application of a retrofit factor is as much an art as it is a science, in 

that it requires a good deal of insight, experience, and intuition on the part 

of the analyst. The key behind a good cost estimate using a retrofit factor 

is to make the factor no larger than is necessary to cover the occurrence of 

unexpected (but reasonable) costs for demolition and installation. Such 

unexpected costs include - but are certainly not limited to - the unexpected 

magnitude of anticipated cost elements; the costs of unexpected delays; 

the cost of re-engineering and re-fabrication; and the cost of correcting 

design errors. The magnitude of the retrofit factor varies across the kinds 

of estimates made as well as across the spectrum of control devices. At the 

study level, analysts do not have sufficient information to fully assess the 

potential hidden costs of an installation. At this level, a retrofit factor of as 

much as 50 percent can be justified. Even at detailed cost level (± 5 

percent accuracy), vendors will not be able to fully assess the uncertainty

associated with a retrofit situation and will include a retrofit factor in their 

assessments. For systems installed at the end of the stack, such as flares, 

retrofit uncertainty is seldom a factor. In these cases, an appropriate 

retrofit factor may be one or two percent of the TCI. In complicated 

systems requiring many pieces of auxiliary equipment, it is not uncommon 

to see retrofit factors of much greater magnitude can be used. Since each 

retrofit installation is unique, no general factors can be developed. A 

general rule of thumb as a starting point for developing an appropriate 

retrofit factor is: The larger the system, the more complex (more auxiliary

equipment needed), and the lower the cost level (e.g. study level, rather 

than detailed), the greater the magnitude of the retrofit factor.

Thus, concludes NPPD, S&L, in preparing its cost estimate, included a "contingency" that 

serves the same function as the "retrofit factor." In selecting the value of this contingency, 

S&L took into account the complexity of the Dry FGD retrofit to the existing facility at GGS 

and its prior experience in the execution of similar utility scale Dry FGD retrofit projects. 

NPPD states our contention is that S&L (or any other estimator) should only have been 

allowed to use the 3% contingency factor cited in Table 1.3 "Capital Cost Factors for Gas 
6

Absorbers" (Section 5.2, Chapter I). However, states NPPD, we fail to acknowledge the 

stated limitation of this Section of the Control Cost Manual:

This section presents the procedures and data necessary for estimating 

capital costs for vertical packed bed gas absorbers using countercurrent 

flow to remove gaseous pollutants from waste gas streams. Equipment 

costs for packed bed absorbers are presented in Section 1.4.1, with 

installation costs presented in Section 1.4.2. Total capital investment, TCI, 

includes equipment cost, EC, for the entire gas absorber unit, taxes, freight 

charges, instrumentation, and direct and indirect installation costs. All 

costs are presented in third quarter 1991 dollars. The costs presented are 

study estimates with an expected accuracy of ± 30 percent. It must be kept 

in mind that even for a given application, design and manufacturing 

procedures vary from vendor to vendor, so costs vary. All costs are for 

new plant installations; no retrofit cost considerations are included.

NPPD states we would have them believe that it was the intent of the Control Cost Manual to 

blindly apply the factor of "3% contingency" from a section of the Manual that is not at all 

related to Dry FGD and admittedly excludes any retrofit considerations, despite the fact that 

elsewhere in the Manual they are advised that a retrofit factor of as much as 50 percent can 

be justified. NPPD submits that our reduction of the contingency (which S&L has used in the 

same context that the Control Cost Manual describes for a retrofit factor) from 20% to 3% is 

not reasonable and is not supported by a correct and full reading of the Control Cost Manual.

Response: First, we believe that a cursory reading of Section 4 of Appendix A to our TSD, 

where we discuss our adjustment to NPPD’s contingency costs, will reveal we did not in fact 

state or imply that a contingency cost of 3% of the purchased equipment cost should be 

universally applied, as NPPD alleged several times in its comment. 

In fact, we stated that 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. Further, we referenced our response to comments for our 

Oklahoma FIP:

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." 

Then, we stated 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 Control Cost Manual specifies the contingency as 3% of the purchased 
7

equipment cost. Lastly, we revised our cost analysis to incorporate a contingency of 3% of 

the purchased equipment cost. 

Thus, we (1) noted that NPPD has apparently secured vendor quotes covering most of its 

major capital costs, (2) we reaffirmed the Control Cost Manual’s caution that contingency

costs should be reserved for only certain items that could incur a reasonable but unanticipated 

increase, and (3) we applied the Control Cost Manual’s contingency cost from the section 

that is most similar to the proposed controls.

Here, NPPD now argues that its contingency costs were also meant to cover a retrofit factor, 

in addition to contingencies. NPPD also states that it has followed the instruction of the 

Control Cost Manual by including not only what S&L calls a contingency factor, but which 

has the characteristics of a retrofit factor as it is defined in the Control Cost Manual. 

However, NPPD apparently overlooks the fact that the Control Cost Manual treats 

contingencies and retrofit factors separately: 

Contingencies are not the same thing as uncertainty and retrofit factor 

costs, which are treated separately in this chapter.3 

The Control Cost Manual provides further insight on the differences between contingencies 

and retrofit factors and how they should each be applied, which NPPD’s incomplete 

reference, “the retrofit factor is a kind of contingency factor,” above, does not fully clarify. 

The full quote is actually (with italicized text defining the portions of the quote left out by

NPPD):

Due to the uncertain nature of many estimates, analysts may want to add 

an additional contingency (i.e., uncertainty) factor to their estimate.

However, the retrofit factor is a kind of contingency factor and the cost 

analyst must be careful to not impose a double penalty on the system for 

the same unforeseen conditions. Retrofit factors should be reserved for 

those items directly related to the demolition, fabrication, and installation 

of the control system. 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. [emphasis added].4

Thus, despite NPPD’s apparent belief that the Control Cost Manual meant that contingencies 

can include retrofit factors, the Control Cost Manual is clear that they are intended for 

different things, and that they be treated separately.

We are also mindful that although the BART Guidelines advise that, “In order to maintain 

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

 

3

 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002, section 2.3, page 19.

4

 Ibid., section 2.5.4.2, page 44
8

Manual, where possible,”5it also advises, “The cost analysis should also take into account 

any site-specific design or other conditions identified above that affect the cost of a particular 

BART technology option.”6Typically, retrofit factors for pollution controls have varied from 

1.0 to 1.5, although higher retrofit factors have occasionally been used. In its report outlining 

revisions to the IPM model for dry scrubber costs,7 which was funded by EPA, NPPD’s 

contractor, S&L, defines a retrofit factor of 1.0 to be “average retrofit difficulty”.8 Thus, we 

reviewed NPPD’s BART report and other information in the record in order to ascertain the 

degree of difficulty that S&L anticipated for the retrofit of dry scrubbers in relation to other 

similar retrofits. However, although the work to be performed was outlined, no information 

was found that would have described the difficulty of the retrofit in comparison to other 

similar dry scrubber retrofits.

Another comment submitted by S&L, however, does provide some insight into the 

anticipated retrofit difficulty, although it does not shed light on whether this difficulty is less 

than, average, or greater than other similar retrofits. S&L states:

With respect to dry FGD controls on GGS Units 1 & 2 for example, the 

preferred general arrangement locates the spray dryer absorber (SDA) 

vessels east the existing Unit 1 & 2 baghouses. Because flue gas must go 

through the SDA before it enters the baghouse, the inlet plenum of the 

baghouse would have to be reversed. Reversing the inlet plenum requires 

the roof of the plenum be cut from the plenum side walls and a new roof 

installed. Bypass dampers between the inlet and outlet plenum would also 

have to be modified and reconnected after the inlet is reversed, and three 

new inlets would need to be cut into the back side of the existing baghouse 

casing for the modified inlets. Furthermore, the existing baghouses at GGS 

are designed to handle continuous operating pressure up to -35 inches 

water column (in. w.c.).Addition of a dry FGD would add up to 10-12 in. 

w.c. of negative pressure before the flue gas enters the baghouse. The 

existing baghouses would not be able to handle this additional negative 

pressure and would need to be reinforced as part of the dry FGD project. 

In addition to the absorber vessels and baghouse modifications, the dry

FGD system includes lime unloading, bulk storage, lime preparation 

(slaking and grit removal), recycle ash handling and storage, and fly ash 

handling. The preferred general arrangement requires the existing GGS 

warehouse to be demolished and a new warehouse built directly north of 

the main GGS plant warehouse. The existing fly ash silos would also have 

to be demolished to make room for the Unit I SDAs. These design features 

are unique to the GGS dry FGD control system and represent significant 

retrofit challenges. Costs associated with the retrofit challenges, including: 

(1) demolishing and rebuilding existing equipment and structures in order 

 

5

 70 FR 39166.

6

 Ibid.

7

 IPM Model – Revisions to Cost and Performance for APC Technologies, SDA FGD Cost Development 

Methodology, Final, August 2010, Project 12301-007, Perrin Quarles Associates, Inc., Prepared by Sargent & 

Lundy

8

 Ibid., page 3.
9

to make room for the retrofit technology; (2) replacing or supplementing 

existing fans to overcome additional pressure loss associated with the 

technology; (3) rebuilding or reinforcing existing vessels and ductwork to 

withstand increased operating pressures; and (4) lost revenue associated 

with extended outages needed to construct and tie-in the retrofit 

technology, all add significantly to the overall costs of an FGD control 

system project.

Because NPPD has not compared this work to other similar dry scrubber retrofits, our 

challenge then becomes one of first attempting to identify which aspects of the work fall 

under the Control Cost Manual’s definition of a retrofit factor, “to cover the occurrence of 

unexpected (but reasonable) costs for demolition and installation.” Secondly, we must 

attempt to identify which aspects of the work are not already covered by vendor quotes. 

These vendor quotes are not in the record, but the work covered by them is described in 

Appendix A of the GGS BART analyses.9Therefore, lacking evidence to the contrary, we 

make the reasonable assumption that any work that is listed as being supported by vendor 

quotes has been comprehensively described in full, unless otherwise noted by NPPD. 

All of the above described work that S&L discusses is certainly available for the application 

of a retrofit factor. However, there is nothing in the record that would lead us to conclude 

that the retrofit difficulty is greater than average, or that it justifies a retrofit factor greater 

than 1.0. Nevertheless, in order to be conservative, we have taken the approach that we will 

retain our proposed determination that contingencies should be computed at the rate of 3% of 

the purchased equipment cost for those capital costs that are supported by vendor quotes, and 

we will increase the contingency to 20% for the remaining purchased equipment costs that 

are not directly supported by vendor quotes. In so doing, because the baghouse 

modifications described above were apparently based on “[v]endor input from Siemens 

(WAPC),”10 as opposed to vendor quotes, we calculate that contingency based on 20% of the 

purchased equipment cost. The following table illustrates this calculation:

Capital Cost 3%

Contingency

20%

Contingency

Spray Dryer Absorber Area X

Reagent Preparation System X

Waste Recycle System X

Reagent Handling System X

Fly Ash Handling Modifications X

Booster Fans X

Civil/Site Work X

Flue Gas System/Ductwork X

Baghouse Modifications X

Common Structures/Buildings X

 

9

 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, Sargent & Lundy, Project No. 12194-001

February 7, 2008, pdf 8-12.

10

 Ibid., pdf 10
10

Track Ladders and Switches X

Miscellaneous Mechanical Items X

Pipe Rack X

Instruments and Controls X

Electrical Modifications X

Spare Parts X

These corrections resulted in only a minimal impact on the cost effectiveness, and are present 

in Appendix C - revised.

6. Comment: NPPD states we incorrectly rejected the inclusion of an Allowance for Funds Used 

During Construction (AFUDC) from our dry scrubber BART cost calculation. NPPD states 

that AFUDC is listed as a cost factor in both Table 1.4 "Capital Cost Factors for an SNCR 

Application" [Section 4.2, Chapter I] and Table 2.5 "Capital Cost Factors for an SCR 

Application" [Section 4.2, Chapter 2]. NPPD concludes that if it were the intent of the 

Control Cost Manual to disallow AFUDC in all cases, these line items would never have 

been included in these two tables of Capital Cost Factors. NPPD also notes that these two 

tables appear in two of the sections that have most recently been added to the Control Cost 

Manual.

Response: We disagree. As explained in our FIP for Oklahoma,11 it has long been EPA's 

practice to exclude AFUDC from regulatory cost effectiveness analysis, because the 

overnight costing methodology used in these analyses, does not include AFUDC. 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]12” that can be considered under the RHR and the Control Cost Manual. 

Further, if an alternate costing approach is used, based on all-in costs, the range of costs used 

to assess the reasonableness of the resulting estimate must be adjusted to the same basis, i.e., 

AFUDC and other all-in costs must be added to the projects that make up the range used to 

determine reasonableness. Nevertheless, it is our position that the Control Cost Manual only

allows the overnight cost method for a BART analysis for scrubbers. NPPD also states that 

the inclusion of zero AFUDC in the sections of the Control Cost Manual dealing with SCR 

and SNCR implies that a non-zero AFUDC could also be applied. As AFUDC accounts for 

the cost of capital to finance a project during the construction period, there would always be 

a finite financing charge for any length of construction under the all-in cost method that 

NPPD employs. The fact that the Control Cost Manual explicitly sets AFUDC to zero for 

SCR and SNCR is clear evidence that the Control Cost Manual is following the overnight 

costing method. In fact, the Control Cost Manual indicates that the zero AFUDC is included 

for clarity, not for simplification. The Control Cost Manual reference to SCR AFUDC 

occurs in a section entitled “Indirect Capital Costs,” the text of which states:

 

11

 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 15. Our Oklahoma FIP contains additional insight into the overnight costing method and AFUDC.

12

 70 FR 39166.
11

Indirect installation costs are those associated with installing and erecting 

the control system equipment but do not contribute directly to the physical 

capital of the installation. This generally includes general facilities and 

engineering costs such as construction and contractor fees, preproduction 

costs such as startup and testing, inventory capital and any process and 

project contingency costs. As explained in the Manual Section 1 

Introduction, average values of indirect installation factors are applied to 

the direct capital cost estimate to obtain values for indirect installation 

costs. These costs are estimated as a percentage of the TCI. The equations 

for indirect installation costs are presented in Table 2.5.13

The same list appears in Section 1, Figure 2.2. The Control Cost Manual discusses the scope 

of indirect costs at least eleven times (Section 1, p. 2-5 and Figure 2.2; Section 2, Table 3-14; 

Section 3.2, p. 1-27 and Table 2.8; Section 4, p. 1-32, Table 1.4, p. 2-43, and Table 2.5; 

Section 5.2, Table 1.3; Section 6, Table 3.20). None of these lists of indirect costs includes 

AFUDC.

Thus, the intent of the Control Cost Manual is to compute and compare cost-effectiveness on 

the basis of overnight costs. While AFUDC is a valid cost under the all-in cost estimating 

NPPD employs, it is not a valid cost under the Control Cost Manual methodology, which is 

based on the overnight costing method. We therefore see no reason to revise our exclusion of 

AFUDC from our dry scrubber cost analysis.

7. Comment: S&L states that our position that the calculation of the capital recovery factor 

should be based on an annualization period equal to the entire life of the control system 

rather than an economic life is inconsistent with the financial models described in the Control 

Cost Manual. S&L states that in financial models, the annualization period used to calculate 

the levelized cost of a capital asset equates to the asset's useful or economic life. S&L asserts 

that equipment life, as that term is used in financial models, represents that period of time 

when it is economically favorable to use a capital asset. At the end of the asset's equipment

life, annualized capital recovery costs are no longer incurred, but annual operating, repair, 

and maintenance costs required to maintain the equipment will increase and become more 

significant. Useful life of an asset varies according to the type of control system and with the 

severity of the environment in which the control system is installed. At the end of an asset's 

useful life, the owner/operator should evaluate whether it is more economical to expend 

additional capital to replace the asset, or to continue to incur increased operating, 

maintenance, and repair cost. However, explains S&L, this does not mean, as we suggest, 

that capital assets are necessarily replaced at the end of their useful life.

S&L states our argument that "[t]he 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" is 

inconsistent with the use of the term in financial modeling, and inconsistent with the 

financial models described in the Control Cost Manual. As we concede in our comments, 

notes S&L, several examples in the manual equate useful equipment life to "economic life." 

 

13

 Control Cost Manual, Section 4, p. 2-43.
12

For example, Table 2.3 in Section I, Chapter 2 of the manual, lists "economic life" as one of 

the control device parameters needed to calculate the annualized cost of capital. This 

definition, states S&L, is reiterated in cost estimating examples throughout the manual:

Section 2 (Generic Equipment and Devices), Chapter I (Hoods, Ductwork 

and Stacks): "The 'CRF' term in the capital recovery equation is the capital 

recovery factor, which is a function of the economic life of the ventilation 

system and the interest rate charged to the total capital investment." (pg. 1-

52, emphasis added).

Section 2, Chapter 3 (Permanent Total Enclosures): "The capital recovery

factor (CRF) is a function of the economic life of the equipment and the 

interest charged on the total capital investment previously discussed in this 

Manual." (pg. 3-33, emphasis added). 

Section 4.2 (NOx Post-Combustion), Chapter I (Selective Noncatalytic 

Reduction): "Capital recovery factor was defined in Section I as [equation 

1.34] where i is the assumed interest rate and n is the economic life of the 

SNCR system." (pg. 1-38, emphasis added).

S&L states that in the examples referenced above, as is typical in financial analyses, the 

useful life of a control system is considered to end when operating, repair, and maintenance 

costs of the equipment become more significant. The term "useful life" as used in economic

impact analyses, notes S&L, is not the same as the entire physical life of the control system. 

Taking such an approach would require the financial analyst to predict how long the physical 

asset may exist at the facility, and requires the analyst to ignore increased control system 

operating, maintenance and repair costs. All financial models, concludes S&L, equate useful 

life of a capitalized asset to the asset's economic or useful life.

S&L states that although the Control Cost Manual does not have a specific chapter for FGD 

control systems, requiring NPPD to use a 30-year service life to calculate the capital recover 

factor is inconsistent with other examples in the Control Cost Manual and inconsistent with 

our approach in other BART determinations. The Control Cost Manual does not have a 

chapter specific to wet or dry FGD control systems designed for SO2 removal, and, in fact, 

the manual "does not directly address the controls needed to control air pollution at electrical 

generating units (EGUs).” However, the Control Cost Manual assumes a 20 year useful life 

for other large air pollution control systems. For example, the cost estimating example 

provided in the Control Cost Manual for fabric filter baghouse control systems assumes a 20 

year useful life (Section 6, Chapter 1, page 1-46). Similarly, the manual assumes an 

equipment life of 20 years for selective catalytic reduction (SCR) control systems (Section 

4.2, page 2-48); and the manual assumes an equipment life of 15 years for a packed tower 

wet acid gas scrubber (Section 5.2, Chapter 1, page 1-40).

Furthermore, requiring NPPD to annualize capital costs of the FGD control systems over the 

entire physical life of the equipment departs from the approach used by EPA in other BART 

determinations. For example, in its comments to PPL Montana regarding the BART 

assessment for the Colstrip Generating Station, EPA Region 8 stated:
13

[PPL's analysis] used 11 years for the remaining useful life for all the 

[SO2] control technologies. However, the typical useful life of these 

control technologies is expected to be 15 years based on information from 

the EPA Control Cost Manual (EPA 2002, Section 5.2, Chapter 1, pg. 1-

28).

Because PPL's coal-fired boilers were expected to have a useful life beyond 20 years, EPA 

Region 8 required PPL to "reanalyze the annualized costs for the control technologies using 

fifteen years as provided in the EPA Control Cost Manual.

Calculating the capital recovery factor based on the actual physical life of the capital asset is 

inconsistent with financial modeling, and inconsistent with the approach used by EPA to 

evaluate the financial impact and cost-effectiveness of SO2 scrubbing systems at other BART 

eligible sources. One of the reasons EPA published its BART Determination Guidelines 

(Appendix Y to 40 CFR Part 51), and recommended using the Control Cost Manual 

methodology where possible, was to "maintain and improve consistency" of the control 

system cost estimates to allow cost comparisons across multiple units. Requiring NPPD to 

annualize capital costs using an actual physical equipment life rather than a useful equipment 

life or economic life, is not consistent with the approach used by EPA to evaluate SO2 costeffectiveness at other BART eligible sources.

Response: As we discuss in our proposal, control equipment lifetime is clearly defined in the 

Control Cost Manual as being equal to the entire life of the control. Therefore on this point, 

we see no reason to adjust our calculation of the Capital Recovery Factor (CRF).

S&L also states that our requiring NPPD to use a 30-year service life to calculate the capital 

recover factor is inconsistent with other examples in the Control Cost Manual and 

inconsistent with our approach in other BART determinations.

As we referenced in our proposal, we presented information in our response to comments for 

our Oklahoma FIP that demonstrates that an operational life of 30 years for a dry scrubber is 

appropriate. For example, some of the support for a 30 year operational life we noted in our 

Oklahoma FIP included the following:

 We noted that scrubber vendors indicate that the lifetime of a scrubber is equal to the 

lifetime of the boiler, which might easily be well over 60 years. 

 We identified specific scrubbers installed between 1975 and 1985 that are still in 

operation today.

14

 

 We cited to standard cost estimating handbooks,15 and published papers,16 that report 30 

years as a typical life for a scrubber. 

 

14

 See, for example, EPRI, A Review of Literature Related to the Use of Spray Dryer Absorber Material: 

Production, Characterization, Utilization Applications, Barriers, and Recommendations, December 6, 2006, Table 1-

2.

15

 William M. Vatavuk, Estimating Costs of Air Pollution Control, Lewis Publishers, 1990, p. 198. 

16

 J. Warych and M. Szymanowski, Optimum Values of Process Parameters of the “Wet Limestone Flue Gas 

Desulfurization System, Chemical Engineering & Technology, v. 25, 2002, pp. 427-432.
14

 We pointed to the BART determination for Big Stone Unit 1, on-line in 1974, which 

assumed a 30 years scrubber life.17

 Finally, we note that the Kaplan report, cited by Sargent & Lundy in its comments 

regarding our Oklahoma FIP proposal, reported the "book life" of scrubbers as 30 years 

and the "tax life" as 20 years.18

 We noted that we have assumed a 30-year lifetime for scrubbers since at least 1981.19

S&L directs us to assumptions EPA Region 8 has made regarding the remaining useful life of 

PPL Montana, J.E., Corette Generating Station, and Holcim, for which it states assumptions 

of 15 years for the remaining useful life were made. S&L also directs us to the Oklahoma 

State BART determination for the American Electric Power, Northeastern Power Plant, and 

the BART Five Factor Analysis, Kansas City Power & Light, LaCygne Generating Station, 

August 2007, for which it states assumptions of 20 years for the remaining useful life were 

made.

We note the Montana regional haze action by EPA Region 8 is a proposal,20 as opposed to 

the final actions we have taken in our Oklahoma and New Mexico FIPs, in which we 

assumed 30 year operational lives. All aspects of this proposal are subject to comment, 

including the remaining useful life assumptions made in the BART evaluations. Therefore, 

we cannot speculate on the final outcome of these BART determinations at this time. 

However, S&L is incorrect in that that EPA Region 8 did not assume the remaining useful 

life for all three facilities was 15 years, but 20 years. In addition, it should be noted that 

Holcim is a Portland cement plant, and thus has different considerations regarding its 

operational life than does the GGS units. The Oklahoma State BART determination S&L

references was the subject of our FIP, and thus was found to unapprovable, in part dues to its 

BART cost evaluation, which partially depended on the 20 year remaining useful life 

assumption that S&L notes. In any case, the remaining useful life of a BART sources is an 

individual assessment, in which site-specific factors may well influence the decision. 

Lastly, when the lifetime of the scrubber effects the BART determination, as here, we would 

require a federally-enforceable restriction preventing further operation after a date certain, 

i.e., the requested 20 years.21 Such a date has not been adopted and submitted by Nebraska as 

part of the BART determination. In fact, NPPD states in its BART analysis, “The useful 

remaining life of GGS 1 & 2 is greater than 20 years under the current NPPD energy

resource plan.”22 Thus, we find that our original determination that the dry scrubbers for the 

GGS units should have a 30-year useful life remains correct.

 

17

 Otter Tail Power Company, Big Stone Generating Station, Unit 1, Best Available Retrofit Technology Analysis,

November 2, 2009. Available at http://denr.sd.gov/des/aq/aqnews/RHAppendixC.pdf

18

 Kapland et al., Retrofit Costs of SO2 and NOx Control at 200 U.S. Coal-Fired Power Plants, Presented at the 

1990 Pittsburgh Coal Conference, September 11, 1990.

19

 EPA/TVA (T.A. Burnett and K.D. Anderson,), Technical Review of Dry FGD Systems and Economic Evaluation 

of Spray Dryer FGD Systems, Prepared for U.S. EPA, Report EPA-600/7-81-014, TVA EDT-127, February 1981, 

pp. xxvii, xxxiv, 84 (30-year economic and tax life for a dry FGD/FF).

20

 77 FR 23988.

21

 70 FR 39169 (July 6, 2005). Where the date that a facility permanently stops operation affects the BART 

determination, "this date should be assured by a federally- or State-enforceable restriction preventing further 

operation."

22

 BART evaluation for Gerald Gentleman Station, Appendix 10.6 of the SIP. 
15

8. Comment: Regarding our variable O&M cost calculation, S&L outlined the procedure we 

used to adjust the calculations and states that variable O&M costs are directly proportional to 

the quantity of exhaust gas processed by the control system. Variable O&M costs associated 

with an FGD control system include the reagent (lime or limestone), byproduct handling and 

disposal, water consumption, and auxiliary power requirements. S&L states that cost 

estimates provided to support the GGS BART determination included costs for all of these 

items for both wet and dry FGD control system options. Unit costs for each of these 

consumables were provided in Table 1 of the Revised BART Analysis for GGS Units 1 & 2, 

and levelized annual costs were provided in the attached conceptual cost estimates.

S&L described how it calculated variable O&M costs: For the GGS dry FGD control system 

cost estimate, reagent (lime) consumption was calculated based on the following control 

system design parameters: (1) inlet SO2 loading to the spray dryer absorber (SDA); (2) SO2

removal efficiency; (3) a calcium-to-sulfur (Ca:S) stoichiometric ratio of 1.4; and (4) an 

assumed lime purity of 90% calcium oxide (CaO). Water required to hydrate the lime 

reagent was calculated based on the lime consumption rate, an inlet temperature to the SDA 

of 350 degrees F, and an outlet temperature of 30 degrees F above adiabatic saturation. FGD 

byproduct disposal costs, which are also a function of inlet SO2 loading and the Ca:S 

stoichiometric ratio, were calculated based on the quantity of FGD byproduct generated by 

the control system and a disposal cost of $5.00/ton. Auxiliary power requirements for the dry

FGD include the increased fan power to account for the additional pressure drop across the 

SDA, and power required to operate the slurry preparation and slaking processes. Auxiliary

power costs were calculated based on pressure drop calculations for the SDA control system, 

and a power cost of $46.00/kWh. S&L states that all of these costs, including the technical 

basis for each and the assumptions that went into the cost estimates, were included in the 

conceptual cost estimates provided as part of the Revised BART Analysis for GGS Units 1 & 

2.

S&L criticizes our calculation of variable O&M costs: S&L states that adjusting the levelized 

variable O&M costs based on the ratio of capital recovery factors, as we did is incorrect. 

Variable O&M costs are independent of the useful equipment life used to calculate the 

capital recovery factor. S&L describes how we revised the variable O&M costs for GGS 

Units 1 & 2 by multiplying GGS's variable O&M costs by the ratio of its capital recovery

factor (discussed in response to Comment 6 and calculated using a 30-year scrubber service 

life) and NPPD's capital recovery factor (calculated using a 20-year equipment life). This 

reduced variable O&M costs from $19,994,000/yr to $16,325,807 [i.e., $19,994,000 X 

(0.06691/0.08195)]. However, states S&L, there is no connection between levelized O&M 

costs (calculated using the constant dollar approach described in the Control Cost Manual) 

and the capital recovery factor. The capital recovery factor is used to annualize capital costs 

over the useful life of the control system, and is completely unrelated to the calculation of 

variable O&M costs. Thus, concludes S&L, our first adjustment (i.e., adjusting the variable 

O&M costs by the ratio of the capital recovery factors) is incorrect.

S&L states that requiring GGS to calculate its levelized variable O&M costs for the FGD 

control system based on actual average SO2 emissions during the baseline period is 

inconsistent with the approach we took in our recently published Oklahoma Regional Haze 
16

FIP. S&L states that variable O&M costs are a function of SO2 loading to the scrubber and 

the tons of SO2 removed by the system; thus, as we suggest, variable O&M costs will 

decrease as the baseline SO2 emissions decrease. To account for lower baseline SO2

emissions, we reduced the levelized variable O&M costs by multiplying GGS's variable costs 

by the ratio of tons of SO2 removed. This adjustment reduced variable O&M costs from 

$16,325,807/yr to $9,491,233/yr [i.e., $16,325,807 X (23,147 tpy / 39,815 tpy)]. However, 

states S&L, this approach is not consistent with the approach we recently took in our BART 

determination for several coal-fired generating units in Oklahoma. In fact, states S&L, in our 

response to technical comments to the proposed Oklahoma Regional Haze PIP, we actually

increased baseline SO2 emissions to match the design fuel characteristics, and then 

subsequently took credit for the additional tons of SO2 removed in its calculation of control 

system cost effectiveness. This is precisely the approach that GGS took in its BART 

determination, and which we now criticize.

Nevertheless, and for comparative purposes only, S&L calculated the variable O&M costs, 

and the cost effectiveness of dry FGD controls on GGS Units 1 & 2 using our baseline SO2

inlet rate of 0.565 lb/MMBtu (31,513 tpy) and a controlled emission rate of 0,15 lb/MMBtu 

(or 8,366 tpy). Adjusting the variable O&M costs to reflect a reduction in total annual SO2 

emissions of 23,147 tpy (i.e., 31,513 tpy - 8,366 tpy), S&L calculates the total levelized 

annual O&M costs to be $7,246,000/yr. Accepting all of our revisions to the February 2008 

capital cost estimate, the total levelized annual cost of the control system (capital recovery

costs plus fixed and variable O&M) is $51,335,000/yr.

Response: As we state in our proposal, we could not duplicate NPPD’s variable O&M costs 

because of apparent conflicts in the data supplied, and due to the fact that NPPD did not 

provide any calculations for these costs. For instance, we noted that the financial model cases 

13 and 14 list the annualized tons of SO2 removed to be 40,426 for Unit 1 and 41,003 for 

Unit 2, each one of which exceeded the total historical SO2 emission of both Units 1 and 2 

combined, giving us reason to doubt the validity of the O&M costs that were apparently

based on those reductions. Although we treat the issue of the SO2 baseline below, we note 

briefly here that these figures together total 81,429 tpy, which even greatly exceeds NPPD’s 

desired SO2 baseline of 49,785 tpy, further reinforcing our conclusion that any O&M costs 

based on them are incorrect.

Also, we recognized that NPPD’s fixed O&M costs are simply the sum of the “levelized” 

fixed O&M costs in its financial tables. However, although very close, the variable levelized 

costs are not similarly equal to the sum of the levelized variable O&M costs in NPPD’s 

financial tables. Because they are listed as levelized costs, we simply adjusted the fixed 

O&M costs by multiplying them by the ratio of our and NPPD’s CRF (before secondarily 

adjusting them for the differences between our and NPPD’s SO2 reductions). S&L did not 

object to this adjustment in its comment. However, despite the apparent similarity in 

methodology, S&L has objected to our adjusting the variable O&M costs using this 

approach. We recognize, as S&L points out in its comment, variable O&M costs are 

dependent on the amount of SO2 the scrubber system is assumed to treat—that was the 

reason for our secondary adjustment. Now in its comments, S&L broadly outlines how it 

actually calculated the variable O&M costs. S&L states that all of these costs, including the 

technical basis for each and the assumptions that went into the cost estimates, were included 
17

in the conceptual cost estimates provided as part of the Revised BART Analysis for GGS 

Units 1 & 2. However, the actual calculations do not appear in the Revised BART Analysis 

and S&L still has not provided them. Therefore, we have no choice but to continue to 

estimate these costs, using our best judgment, and the information that is in the record. 

Although NPPD does not provide how it calculated the variable O&M costs, it has provided 

the final number for one of our proposed control cases in which we assumed a SO2 baseline 

of 31,513 tpy, and a controlled SO2 emission rate of 0.15 lbs/MMBtu that resulted in a SO2

reduction of 23,147 tpy. S&L states that “for comparative purposes only” and “[a]ccepting 

all of EPA’s revisions,” the total levelized annual O&M costs are $7,246,000/yr and the 

annualized cost is $51,335,000. These costs are lower than our own calculated costs of 

$9,491,233 and $53,480,426, respectively. Consequently, because we calculate cost 

effectiveness on the basis of annualized cost divided by tons of SO2 removed ($/ton), 

although S&L objects to our adjustment to the variable O&M costs, its own adjustment 

results in a lower (more cost effective) calculation in terms of dollars per ton of SO2

removed, all else being equal. Nevertheless, as S&L objects to our adjusting it based on a 

ratio of ours versus NPPD’s CRF, we will forego that adjustment, as its effect on cost is 

minimal. This adjustment appears in our TSD Appendix C-revised.

However, we feel that we can retain our approach for secondarily adjusting the variable 

O&M costs upward to compensate for the increased SO2 gas processed by multiplying them 

by the ratio of our SO2 reduction versus GGS’s SO2 reduction. As S&L itself states, 

“[v]ariable O&M costs are directly proportional to the quantity of exhaust gas processed by

the control system.” Although S&L states this method is not correct, it has failed to provide a 

verifiable alternative. In addition, we have demonstrated that our approach is conservative, 

resulting in a higher dollars per ton calculation (less cost effective).

Lastly, S&L states that requiring GGS to calculate its levelized variable O&M costs for the 

FGD control system based on actual average SO2 emissions during the baseline period is 

inconsistent with the approach we took in our recently published Oklahoma Regional Haze 

FIP. As we state elsewhere in our response to comments, our BART Guideline cost 

effectiveness metric is expressed in terms of dollars per ton of pollutant removed ($/ton). 

Therefore, our lowering of GGS’s SO2 emission baseline had the conservative effect of 

making the cost effectiveness less cost effective. Based on NPPD’s objection to this 

adjustment, we will increase our SO2 baseline of 31,513 tons/yr, to NPPD’s desired level of 

49,785 tons/yr, thus making S&L’s objection to this particular issue moot.