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 SO 2 emissions baseline at GGS U nits 1 and 2 from 49,785 tons/y

r to 31,513 tons/y

r as part of our anal ys is of th e 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 Wy oming. Such coals can vary in sulfur content from a low of about 0.28% sulfur to a high of about 1.0% sulfur. A ny 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 SI P decision, in which we determined that the SO 2 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 fa cilit y 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 apparentl y i ncreased the baseline SO 2 emissions and thereafter took credit for the additional tons of SO 2 removed in EPA's calculation of control sy stem cost effectiveness.

Response : In our proposed cost evaluation of dry scrubbers f

or GGS, we noted that GGS calculates its SO 2 emission baseline based on apply ing 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 emissi ons data for GGS from our Clean Air Markets web site, we calculated the average total SO 2 emissions for GGS Units 1 and 2 to be 31,513 tons/yr for the three ye ar 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 th e 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 SO 2 baseline would also lower the projected SO 2 redu ctions from GGS’ projection of 39,815 tons/y r to either to 23,147 tons/y r based on a controlled SO 2 emission limit of 0.15 lbs/MMBtu or 28,166 tons/y ear, based on a controlled SO 2 emission limit of 0.06 lbs/MMBtu. As we also discuss in Section 9 of Appendi x A, our adjustment of the SO 2 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

r emoved ($/ton), our lowering of GGS’s SO 2 emission baseline had the conservative effect of decreasing the cost effectiveness. However, taking NPPD’s objection into account, and increasing our SO 2 baseline of 31,513 tons/y r to NPPD’s desired level of 49,78 5 tons/y r has the effect of increasing our calculated cost effectiveness from $2,310 to $1,515/ton for the2

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, Sar gent 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 an y 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 t his is well established in the industry

and the EPC contractor will ty picall y increase the value of the "fixed price" bid for a project such as this to accou nt 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 clearl y 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 indica tes 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 func tions 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 a nd 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 t han 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 ass umes 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 anal ys es we have seen such as the Oklahoma Gas and Electric Sooner and Muskogee BART anal ys es, also performed b y NP PD’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 employ s), 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 a lters these values.3

in its BART anal ys is that all the major equipment items are based on vendor quotes, which ty picall y contain engineering and procurement costs associated with the equipment that is

su pplied. 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 an y of these issues discussed in the proposal

. The information provide d did not justify th e 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 ha d estimated . Additionally , NPPD did not provide evidence that engineering, planning, and construction was not included for those items covered b y 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 anal ys is prepared b y 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 scrub ber 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 state s 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 contrac t for the erection of a public building or structure, to obtain a pay ment bond in the amount of the contract, conditioned on the pay ment of the costs for the laborers, materials and rented equipment used during the performance of the contract. NPPD explain s 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 pay

ment bond for contractors in good standing is expected to be 2.5% of the amount of the contract, which is ty pical for a pay

ment bond for a project of this ty pe. NPPD concludes the required pay ment bond in the amount of $5 million is a legitimate component of the cost estimate, and should not have been disallowed b y us.

Response : In our proposal, we disall owed 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 esca lation, 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 i n or der to make such a comparison between projects having cost estimates based in different y ears, 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 sta tes it made such a comparison, 2 to 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

es timates 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 anal ys is, 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 employ s 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 analy sis was incorrect, and make thus no change regarding it.

5. Comment : NPPD, throu gh 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 apparentl y we believe that the inclusion of contingency at the level o f "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" i n 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, "Capit al 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% o f 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 Iand 2 does not use "retrofit factors," its contingency serves the same func tion 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 anal ys t must be careful to not impose a double penalty on the s ys te m for the same unforeseen conditions. Retrofit factors should be reserved for those items directly

related to the demolition, fabrication, and installation of the control s ys tem.

NPPD states that S&L , in developing its cost estimate, has followed the inst ruction of the Control Cost Manual by including not onl y 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 Ma nual 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 anal ys ts t ypically multiply the cost of the s ys tem by a retrof it 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 anal ys t. 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 certainl y not limited to

- the unexpected magnitude of anticipated cost eleme nts; the costs of unexpected delay s; 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, anal ys ts 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 ), v endors will not be able to fully assess the uncertainty associated with a retrofit situation and will include a retrofit factor in their assessments. For s ys tems installed at the end of the stack, such as flares, retrofit uncertaint y is seldom a factor. In these cases, an appropriate retrofit factor may

be one or two percent of the TCI. In complicated
sy stems requiring man y pieces of auxiliary equipment, it is not uncommon to see retrofit factors of much greater magnitude can be used. Since each retrofit i nstallation 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 s ys tem, the more complex (more auxiliary equipment needed), and the lower the cost le vel (e.g. stud y 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 va lue of this contingency
, S&Ltook 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 Gas6

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 b ed 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. Itmust be kept in mind that even for a given application, design and manufacturing procedures var y 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 appl y the factor of "3% co ntingency " 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 justifi ed. 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 shoul d be universally

applied, as NPPD alleged several times in its comment.

In fact, we stated that lime handling and preparation, the absorber area, the recy cle area, the baghouse ash handling sy stem, 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 FI P:

Under the overnight cost estimating method in the Cost Con trol 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 directl y related to the demolition, fabrication, and install ation of the sy stem. For example, a hundred y ear 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 dry er absorber) and a baghouse (included in a spray dry er absorber sy stem). In both of these cases, the Control Cost Manual specifies the con tingency as 3% of the purchased7

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 apparentl y 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 se ction 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 Manua l by

including not onl y 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 actuall y (with italicized text defining the portions of th e 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 anal ys t mu st be careful to not impose a double penalty on the s ys tem for the same unforeseen conditions. Retrofit factors should be reserved for those items directly

related to the demolition, fabrication, and installation of the control s ys tem. A contingency fact or 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 de livery 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 Contro l Cost Manual is clear that they are intended for different things, and that they be treated separatel y.
We are also mindful that although the BART Guidelines advise that, “In order to maintain and improve consistency , cost estimates should be based on th e 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 448

Manual, where possible,” 5 it also advises, “The cost anal ys is should also take into account
any site

- specific design or other conditions identified above that affect the cost of a particular BART technology

option.” 6 Ty

picall y, retrofi t 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 I PM model for dry scrubber costs, 7 which was funded b y 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 difficult y that S&L anticipated for the retrofit of dry scrubbers in relation to o ther 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, how ever, 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 dry er 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. By

pass dampers between the inlet and outlet plenum would also have to be modified and reconnected after the inlet is reve rsed, 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 s ys tem includes lime unloading, bulk storage, lime preparation (slaking and grit removal), recy cle ash handling and storage, and fly ash handling. The preferred genera l arrangement requires the existing GGS warehouse to be demolished and a new warehouse built directly north of the main GGS plant warehouse. The existing fl y ash silos would also have to be demolished to make room for the Unit I SDAs. These design feature s are unique to the GGS dry FGD control sy stem 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 AP C 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 assoc iated with extended outages needed to construct and tie

- in the retrofit technology , all add significantly to the overall costs of an FGD control
sy stem 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 m ust attempt to identify

which aspects of the work are not alread y covered b y vendor quotes. These vendor quotes are not in the record, but the work covered b y them is described in Appendix A of the GGS BART analy ses. 9 Therefore, lacking evidence to the co ntrary , 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 certainl y availab le for the application of a retrofit factor. However, there is nothing in the record that would lead us to conclude that the retrofit difficult y 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 b y vendor quotes, and we will increa se 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 oppo sed 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 Dry er Absorber Area X Reagent Preparation Sy stem X Waste Recy cle S ys tem X Reagent Handling Sy stem X Fly Ash Handling Modifications X Booster Fans X Civil/Site Work X Flue Gas S ys tem/Ductwork X Baghouse Modifications X Common Structures/Buildings X

9 Dry FGD And ID Fan & Auxiliary Power, Conceptual Design Costs, Conceptual Cost Es timate, Prepared for Nebraska Public Pow er District, Gerald Gentleman Station, Units 1&2, Sargent & Lundy, Project No. 12194

- 001 February 7, 2008, pdf 8

- 12.
10 Ibid., pdf 1010 Track Ladders and Switches X Miscellaneous Mechanical I tems 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 incorrectl y 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 SNC R 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 recentl y 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 anal ys is, because the overnight costing methodology used in these anal yses, does not include AFUDC. AFUDC is the cost of capital that is incurred to finance the project d uring 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 r easonableness 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 Man ual 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 AFUD C accounts for the cost of capital to finance a project during the construction period, there would alway s be a finite financing charge for an y length of construction under the all

- in cost method that NPPD employ s. The fact that the Control Cost Manual exp licitly 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 clarit y, 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 Regist er 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 sy stem equipment but do not contribute direct ly to the phy sical capital of the installation. This generall y includes general facilities and engineering costs such as construction and contractor fees, preproduction costs such as startup and testing, inventory capital and an y process and project conti ngency

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; Se ction 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 employ s, it is not a valid cost under the Control Cost Manual methodology , which is based on the overnight c osting method. We therefore see no reason to revise our exclusion of AFUDC from our dry

scrubber cost analy sis.

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 sy stem rather than an economic life is inconsistent with the financial models described in the Control Cost Manual. S&Lstates that in financial models, the annualization period used to calculate the levelized cost of a capit al 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 economicall y 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 ty pe of contr ol s ys tem and with the severit y 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 con tinue 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&Lstates 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 Contro l 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 param eters 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 t he capital recovery equation is the capital
recovery factor, which is a function of the economic life of the ventilation
sy stem and the interest rate charged to the total capital investment." (pg. 1

- 52, emphasis added).

Section 2, Chapter 3 (Permanent Tot al 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

- Combu stion), Chapter I(Selective Noncatal yt ic Reduction): "Capital recovery factor was defined in Section Ias [equation 1.34] where i is the assumed interest rate and n is the economic life of the SNCR sy stem." (pg. 1

- 38, emphasis added).

S&Lstates that in the examples referenced above, as is ty pical in financial anal ys es, the useful life of a control s ystem 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 anal ys es, notes S&L, is not the same as the entire phy sical life of the control s ys tem. Taking such an approach would require the financial anal ys t to predict how long the phy sical asset may exist at the facility , and requires the analy st to ignor e increased control sy stem 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&Lstates that although the Control Cost Manual does not have a spe cific chapter for FGD control sy stems, requiring NPPD to use a 30

- ye ar 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 s ys tems designed for SO 2 removal, and, in fact, the manual "does not directly address the controls needed to control air pollution at electrical generating units (EGUs).” Howeve r, the Control Cost Manual assumes a 20 y ear useful life for other large air pollution control sy stems. For example, the cost estimating example provided in the Control Cost Manual for fabric filter baghouse control s ys tems assumes a 20
ye ar useful life (S ection 6, Chapter 1, page 1

- 46). Similarly , the manual assumes an equipment life of 20 ye ars for selective catal yt ic reduction (SCR) control systems (Section 4.2, page 2

- 48); and the manual assumes an equipment life of 15 y ears 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 sy stems over the entire ph ys ical life of the equipment departs from the approach used b y EP A in other BART determinations. For exa mple, in its comments to PPLMontana regarding the BART assessment for the Colstrip Generating Station, EPA Region 8 stated:13

[PPL's anal ys is] used 11 y ears for the remaining useful life for all the [SO 2 ] control technologies. However, the t ypical useful life of these control technologies is expected to be 15 y ears 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 bey ond 20 y ears, EPA Reg ion 8 required PPLto "reanal yz e the annualized costs for the control technologies using fifteen ye ars as provided in the EPA Control Cost Manual.

Calculating the capital recovery factor based on the actual phy sical life of the capital asset is inconsiste nt with financial modeling, and inconsistent with the approach used by EPA to evaluate the financial impact and cost

- effectiveness of SO 2 scrubbing s ys tems 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
sy stem cost estimates to allow cost comparisons across multiple units. Requiring NPPD to

annua lize capital costs using an actual phy sical equipment life rather than a useful equipment life or economic life, is not consistent with the approach used b y EPA to evaluate SO 2 cost

effectiveness 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&Lalso states that our requiring NPPD to use a 30

- ye ar 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 pr oposal, we presented information in our response to comments for our Oklahoma FI P that demonstrates that an operational life of 30 y ears for a dry scrubber is appropriate. For example, some of the support for a 30 year operational life we noted in our Okl ahoma FI P 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 easil y be well over 60 years.

 We identified specific scrubbers installed between 1975 and 1985 t hat are still in operation today

. 14

 We cited to standard cost estimating handbooks, 15 and published papers, 16 that report 30
ye ars as a ty

pical 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, Tab le 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 ye ars 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 y ears and the "tax life" as 20 years. 18

 We noted that we have assu med a 30

- ye ar lifetime for scrubbers since at least 1981. 19

S&Ldirects us to assumptions EPA Region 8 has made regarding the remaining useful life of PPLMontana, J.E., Corette Generating Station, and Holcim, for which it states assumptions of 15 y ears fo r 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 Analy sis, Kansas City Power & Li ght, LaC ygne Generating Station, August 2007, for which it states assumptions of 20 y ears for the remaining useful life were made.

We note the Montana regional haze action b y 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 y ear 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 th is 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. I n addition, it should be noted that Holcim is a Portland cement plant, and thus has different consi derations 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 y ear remaining useful life assumption that S&Lnotes. 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.

Lastl y, when the lifetime of the scrubber eff ects the BART determination, as here, we would require a federall y

- 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 dete rmination. I n fact, NPPD states in its BART anal ys is, “The useful remaining life of GGS 1 & 2 is greater than 20 ye ars under the current NPPD energy resource plan.” 22 Thus, we find that our original determination that the dry scrubbers for the GGS units sh ould have a 30

- ye ar useful life remains correct.

17 Otter Tail Pow er 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., Retrof

it Costs of SO2 and NOx Control at 200 U.S. Coal

- Fired Pow er 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 Dry er 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&Loutlined the procedure we used to adjust the calculations and states that variable O&M costs are directly proportional to the quantity

of exhaust ga s processed b y the control system. Variable O&M costs associated with an FGD control sy stem include the reagent (lime or limestone), by product handling and disposal, water consumption, and auxiliary power requirements. S&L states that cost estimates provid ed to support the GGS BART determination included costs for all of these items for both wet and dry FGD control sy stem options. Unit costs for each of these consumables were provided in Table 1 of the Revised BART Analy sis for GGS Units 1 & 2, and levelize d annual costs were provided in the attached conceptual cost estimates.

S&Ldescribed how it calculated variable O&M costs: For the GGS dry FGD control sy stem cost estimate, reagent (lime) consumption was calculated based on the following control
sy stem d esign parameters: (1) inlet SO 2 loading to the spray dry er absorber (SDA); (2) SO 2 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 h yd rate 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 by product disposal costs, which are also a function of inlet SO 2 loa ding and the Ca:S stoichiometric ratio, were calculated based on the quantity of FGD b yproduct generated b y the control sy stem 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 Anal ys is for GGS Units 1 & 2.

S& L criticizes our calculation of variable O&M costs: S&Lstates 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 b y multiply ing 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

- ye ar scrubber service life) and NPPD's capital recovery factor (calculated using a 20

- ye ar equipment life). This reduced variable O&M costs from $19,994,000/y r to $16,325,807 [i.e., $19,994,000 X (0.06691/0.08195)]. However, states S&L, there is no conne ction 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 sy ste m, 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 b y the ratio of the capital recovery factors) is incorrect.

S&Lstates that requiring GGS to calcula te its levelized variable O&M costs for the FGD control sy stem based on actual average SO 2 emissions during the baseline period is inconsistent with the approach we took in our recently published Oklahoma Regional Haze16

FIP. S&L states that variable O&M cos ts are a function of SO 2 loading to the scrubber and the tons of SO 2 removed by the s ys tem; thus, as we suggest, variable O&M costs will decrease as the baseline SO 2 emissions decrease. To account for lower baseline SO 2 emissions, we reduced the levelized variable O&M costs by multiply ing GGS's variable costs by the ratio of tons of SO 2 removed. This adjustment reduced variable O&M costs from $16,325,807/y

r to $9,491,233/y

r [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 recentl y took in our BART determination for several coal

- fired generating units in Oklahoma. I n fact, states S&L, in our response to technical comments to the proposed Oklahoma Regional Haze PI P, we actually increased baseline SO 2 emissions to match the design fuel characteristics, and then subsequently

took credit for the additional tons of SO 2 removed in its calculation of control
sy stem cost effectiveness. This is precisely the approach that GGS took in its BART de termination, and which we now criticize.

Nevertheless, and for comparative purposes onl y, S&L calculated the variable O&M costs, and the cost effectiveness of dry FGD controls on GGS Units 1 & 2 using our baseline SO 2 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 SO 2 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/y r. Accepting all of our revisions to the February 2008 capital cost estimate, the total levelized annual cost of the control sy stem (capital recovery costs plus fixed and variable O&M) is $51,335,000/y r.

Response : As we state in our proposa l, 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 an y calculations for these costs. For instance, we noted that the financial model cases 13 and 14 list the annualized tons of SO 2 removed to be 40,426 for Unit 1 and 41,003 for U nit 2, each one of which exceeded the total historical SO 2 emission of both U nits 1 and 2 combined, giving us reason to doubt the validity of the O&M costs that were apparently based o n those reductions. Although we treat the issue of the SO 2 baseline below, we note briefl y here that these figures together total 81,429 tpy, which even greatl y exceeds NPPD’s desired SO 2 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 b y multiply ing them by the ratio of our and NPPD’s CRF (before secondaril y adjusting them for the differ ences between our and NPPD’s SO 2 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 SO 2 the scrubber s ys tem is assumed to treat

—that was the reason for our secondary

adjustment. Now in its comments, S&Lbroadl y outlines how it actuall y 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 included17

in the conceptual cost estimates provided as part of the Revised BART Analy sis for GGS Units 1 & 2. Howe ver, the actual calculations do not appear in the Revised BART Anal ys is 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.

Althoug h 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 SO 2 baseline of 31,513 tpy , and a controlled SO 2 emission rate of 0.15 lbs/MMBtu that resulted in a SO 2 reduction of 23,147 tp y. S&Lstates that “for comparative purposes only ” and “[a]ccepting all of EPA’s revisions,” the total levelized annual O&M costs are $7,246,000/y r and the annualized cost is $51,335,000. These costs are lower than our own calc ulated costs of $9,491,233 and $53,480,426, respectivel y. Consequently, because we calculate cost effectiveness on the basis of annualized cost divided by tons of SO 2 removed ($/ton), although S&L objects to our adjustment to the variable O&M costs, its ow n adjustment results in a lower (more cost effective) calculation in terms of dollars per ton of SO 2 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 secondaril y adjusting the variable O&M costs upward to compensate for the increased SO 2 gas processed b y multipl yi ng them by the ratio of our SO 2 reduction versus GGS’s SO 2 reduction. As S&L itself states, “[v]ariable O&M costs are directly proportional to the quantity of exhaust gas processed by the control sy stem.” Although S&L states this method is not correct, i t 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).

Lastl y, S&L states that requiring GGS to calculate its levelize d variable O&M costs for the FGD control sy stem based on actual average SO 2 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 commen ts, our BART Guideline cost effectiveness metric is expressed in terms of dollars per ton of pollutant removed ($/ton). Therefore, our lowering of GGS’s SO 2 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 SO 2 baseline of 31,513 tons/y r, to NPPD’s desired level of 49,785 tons/y

r, thus making S&L’s objection to this particular issue moot.